Innovation in Global Power - Parsons Brinckerhoff

A technical 

journal by 

Parsons 

Brinckerhoff 

employees 

and colleagues 

Heat 

Map of 

Hot 

Rocks 

Issue No. 68 • August 2008 

http://www.pbworld.com/news_events/publications/network/ 

NuGas Steam Cycles 

Innovation 

in Global 

Power 

3 MW Mini Hydro Station 

Also in this Issue: PB Redesigns Composting Machine; 

Laying out a Swim Lane Diagram Using Microsoft Powerpoint or Visio; 

Working with Text in Adobe Acrobat

Innovation in Global Power 

TABLE OF 

CONTENTS 

Guest Editors for this 

issue: Katherine Jackson 

and Arthur Ekwue. 

Guest Technical Reviewers: 

John Douglas, Ferrel Ensign, 

Steve Loyd, Chris Meadows, 

Brian Van Weele, and 

John Wichall. 

Special thanks to Paul Kenyon 

and Matthew Chan for their 

assistance. 

Cover photo (lower right): 

©Tony Mulholland 

Note: Soon after distribution, 

this issue will be available 

on the Web at http://www. 

pbworld.com/news_events/ 

publications/network/ 

Issue_68/68_index.asp 

Introduction (Burton) ...........................................................3 

GENERATION 

THERMAL – ACHIEVING NEW EFFICIENCIES, 

REDUCING CARBON EMISSIONS 

Best Practices Across a Range of Technologies (Kenyon)..4 

The Effect of Carbon Capture and Storage and 

Carbon Pricing on the Competitiveness of Gas 

Turbine Power Plants (Cook)..................................................5 

The NuGas TM Concept: Combining a Nuclear Power 

Plant with a Gas-fired Plant (Willson, Smith).................8 

PB Inspections Help To Ensure Power Plant Safety 

(Gray) .................................................................................................11 

Project Brief: Using Monte Carlo Techniques to 

Size a Power Station (Emmerton).....................................13 

Project Brief: Energizing Singapore’s Economy (Gill)........13 

Combined Heat and Power for USA’s Largest 

Residential Development (Bautista, Swensen)............14 

Ensuring Continual Power Supply for New York 

City Hospitals (Krupnik, Andrews) ....................................16 

Changes to Chiller, Boiler and HVAC Lower Energy 

Consumption at a University Campus (Choi)............18 

Power Terminology: Units and Conversions 

(Ebau) .................................................................................................20 

HYDROPOWER – NEW TECHNOLOGIES, NEW 

CONSIDERATIONS 

Does Hydro have a Future? (Wichall).......................................21 

Pumped Storage Technology: Recent Developments, 

Future Applications (McClymont, Reilly)........................22 

Planning for Mini Hydro in Distributed Generation 

(Mulholland)....................................................................................25 

Developing, Engineering and Licensing a New 

Hydropower Dam (Chan, Schadinger)...........................27 

Developing Hydropower Resources in Greenland 

(Kropelnicki,Tucker, Shiers).....................................................30 

Successful Relicensing of a Federally Regulated 

Hydropower Project (Bynoe, Shiers, Williamson, 

Plizga)..................................................................................................32 

Using OASIS Software to Model Water Allocation 

for Hydropower Generation Projects 

(Shiers, Williamson,Tsai)..........................................................35 

Dam Safety: State-of-the Art Methodology 

Demonstrates that Costly Dam Remediation is 

Not Needed (Greska, Mochrie).........................................38 

Deck Slot Cutting and Tainter Gate Remediation 

Extend Safe Operations of a Hydroelectric 

Dam (Buratto, Plizga, Shiers).................................................41 

RENEWABLES – THE RISKS, CONCERNS AND 

POTENTIAL 

The Growing Power of Renewables (Loyd).............44 

Renewable Energy—Sustainable Economy? (Cook)........45 

Test Bed to Turnkey: Introducing New Thermal 

Renewable Energy Technologies (Burdon) ...................48 

Realising the Power Potential from Hot Rocks 

(Curtis) ..............................................................................................51 

Project Brief: Tidal Power (Kydd) .........................................53 

Converting Landfill Gas to High Btu Fuel (Lemos)...........54 

Photovoltaics, With a Focus on Spain* (Lejarza)..........56 

TRANSMISSION AND DISTRIBUTION 

TRANSPORTING POWER ACROSS THE GRID 

Electricity Transmission, Building on 120 Years of 

Experience (Ekwue)...................................................................58 

Meeting the Need for Reliable, Cheaper and Nonpolluting 

Electricity in Cambodia (Parkinson, Roe).........59 

Rehabilitation and Reconstruction of Abu Dhabi 

Transmission Network (Jayasimha) ...................................62 

HVDC Transmission Strengthening in Southern 

Africa (Tuson)......................................................................................63 

Assessing Transmission Network Condition: 3D 

Data Capture and Reporting (Reynolds)......................66 

DISTRIBUTING POWER TO USERS 

The Wide Range of Distribution (Douglas)....................68 

Research & Innovation: Using Dynamic Thermal 

Ratings and Active Control to Unlock Distribution 

Network Capacity (Neumann)...........................................69 

Upside Down! How Innovation in Distribution 

Networks is Challenging Tradition (Neumann) .........72 

A Survey of Power System Packages for Distribution 

Network Analysis (Ekwue, Roscoe, Lynch) ..................75 

Improving 11 kV Network Performance in Al Ain 

(Nikolic).............................................................................................77 

Energy Demand Management Programs in 

Western Sydney (Duo)............................................................79 

PLANNING AND THE ROLE OF REGULATORS 

Planning and Regulating Power Infrastructure 

in a World of Change (Stedall) ...........................................81 

Asset Replacement: The Regulator’s View (Douglas)...........82 

New Zealand Energy Strategy–A Plan for a 

Sustainable Nation (Barneveld)...........................................86 

Power Articles in PB Network, NOTES, and 

Powerlines (Chow) ...................................................................89 

DEPARTMENTS 

Networking: PB Redesigns a Composting Machine 

for Improved Operations (Altés)* ....................................91 

Water Factory Will Help to Address Water 

Shortage Concerns (Hodgkinson) ....................................94 

Swim Lanes Part 2: Laying Out a Swim Lane Diagram 

using Microsoft PowerPoint or Visio (Sloan)................94 

Computer Tutor: Working with Text in Adobe 

Acrobat Pro: Copy text to other software 

applications, use built-in OCR, make corrections 

with the TouchUp Text tool (Hinshaw) ..........................99 

PlanetWise: Going Green: Walking the Walk!! 

(Sammut).......................................................................................101 

In Future Issues/Call for Articles................................102 

The Net View: Fishing Power (Clark)....................104 

* La edición en lengua española del presente artículo está disponible en la dirección Web de PB Network. 

PB Network #68 / August 2008 2


Innovation in Global Power 

This issue of PB Network focuses on the power expertise that PB provides to clients around the 

world. There continues to be a rapid rate of change in the global power industry as it responds 

to a range of external drivers, including governmental and regulatory targets, fuel price changes, 

rising equipment costs and environmental pressures. These changes are happening at the same 

time that the demand for electrical power world-wide continues to accelerate at unprecedented rates. 

PB’s ability to innovate has become increasingly important to power clients looking for solutions 

and a competitive advantage in this rapidly changing environment. Reducing carbon emissions 

through using more efficient and lower carbon forms of generation, a greater interest in extending 

the lifetime and capacity of existing power assets, and a requirement to squeeze more into 

existing land space must all be key to helping ensure a sustainable future 

One of PB’s stated values is “to work with our clients to contribute to their success,” and 

a number of the articles demonstrate how we are using innovation to do this, including: 

• Information about the advice we are currently providing to the UK government on carbon 

capture and storage 

• The creation of the NuGas concept that can improve thermal efficiencies to unprecedented 

levels by combining nuclear power generation with a small combined cycle gas fired plant 

• The development of designs for high-temperature hot dry rock power generation in Australia 

• PB’s role in the research and development of a distribution network active thermal controller 

that uses local meteorological data to calculate real time equipment ratings and control network 

power flows. 

Other articles demonstrate how PB’s engineers have successfully applied novel thinking to solving 

problems on a range of projects, including: 

• Increasing the lifetime of hydropower dams 

• Ensuring that New York City hospitals continue to operate during power blackouts 

• Developing a 3D asset data capture system for transmission networks; and developing demand 

reduction strategies. 

Another of PB’s stated values is to “share knowledge with our colleagues to deliver professional 

excellence.” PB Network and the Practice Area Networks (PANs) all assist with achieving 

this goal, and I would like to thank all of the PANs, authors, reviewers and the editing team who 

have contributed to this issue. In the spirit of sharing knowledge with our non-power colleagues, 

we have included a list of standard power terminology, definitions, and conversion factors (Ebau, 

page 20). Colleagues have shared over 30 other power articles in recent PB Networks, NOTES, 

and Powerlines (see list on pp. 89-90). 

Katherine Jackson and Arthur Ekwue were the guest editors who compiled all the articles and 

developed the framework for the publication. The guest reviewers who helped hone the technical 

content were John Douglas, Steve Loyd, Chris Meadows, John Wichall, Paul Kenyon, Brian Van 

Weele, and Ferrel Ensign. This issue was sponsored by PB’s Power business units globally and 

by four of PB’s power PANs (conventional thermal generation; high voltage transmission and 

distribution; power system planning, analysis, and restructuring; and renewable energy sources). 

Eric Burton 

Managing Director, Power International 

Newcastle, UK 

INTRODUCTION 

3 PB Network #68 / August 2008

GENERATION: 

Thermal – Achieving New Efficiencies, Reducing Carbon Emissions 

Best Practices Across a Range of Technologies 

The public awareness of climate change and energy issues has risen dramatically in the last two to 

three years. There appears to be growing acceptance of the need to be energy smart and to 

reduce carbon emissions. 

An example is the identification of energy savings by finesse of thermal cycle. The NuGas 

concept and the energy efficiency projects at Co-op City and the SUNY campus in Brockport, 

New York combine an already efficient plant in a way that gains an extra advantage. The process 

for cleaning the steam and evaporator units at the Keppel Energy Plant in Singapore reduced 

on-site time and improved steam and water quality during commissioning. These are elegant 

no-cost or low-cost solutions that were developed by thinking that went the extra step. 

The demand for increasing thermal efficiencies in our power plants is pushing up temperatures, 

making it even more important to ensure safe design and operation of these facilities. Stewart 

Gray has developed an expertise in hazardous areas engineering due, in part to having witnessed 

many instances of people not understanding the rules and vocabulary involved, and he knows of 

the severe consequences that can result. His article highlights some of the steps engineers can 

take a various stages to help ensure such disasters do not occur. 

The paper on carbon capture and storage gives insight to a dilemma facing many of PB’s clients. 

The world-wide management of carbon dioxide emissions to the atmosphere is crucial to slowing 

the rate of global warming. This can be achieved by combinations of improved efficiency in 

combustion of fossil fuels, moves to low-carbon or carbon-free fuels, or carbon capture. At present 

carbon capture is not mandated but this may arise, just as happened with reduction of nitrogen 

oxides emissions (NO and NO2). As with Renewable Energy Certificates, a market may develop 

to provide incentives to “clean” operators, funded by penalties on those with less clean processes. 

PB is well placed to assist its clients in this topical and important area of technology. 

The use of Monte Carlo techniques is a novel approach to optimize generation capacity for a 

random load profile. The team went beyond traditional engineering analysis, reduced uncertainty 

and provided the client with increased confidence in PB’s appraisal. Other PB teams can adopt 

this approach to determine the most economical technical solution yet minimize the risk of a 

shortfall in installed capacity. 

The emergency power generation project for hospitals in New York City applied PB expertise 

and good practice to solve a real and serious issue with old and inadequate life-safety 

equipment. The projects required improvement work to progress on old, dispersed, 

sometimes poorly documented infrastructure without disruption to essential services. 

These articles illustrate projects and technologies with a range of complexity, but each team has 

a depth of expertise and knowledge to assist clients in its sector. 

Please see page 89 for a list of many additional thermal generation and carbon reduction articles 

from past PB publications. 

Paul Kenyon 

Engineering Manager, Newark, New Jersey 




The Effect of Carbon Capture and Storage and 

Carbon Pricing on the Competitiveness of Gas 

Turbine Power Plants By Dominic Cook, Newcastle-upon-Tyne, UK, 44 191 226 2203, cookDo@pbworld.com 

Carbon capture and storage 

presents an opportunity for 

the continued use of fossil 

fuel in power generation 

whilst mitigating its contribution 

to carbon emissions. 

But at what cost? Will electricity 

still be affordable? 

Will the technology be 

attractive to investors? 

The author explains the 

capture and transport/ 

storage processes, explores 

the answers to these questions, 

and tells about some 

considerations clients will 

face when deciding whether 

or not to implement CCS. 

Figure 1: Effectiveness of Carbon 

Capture. 

Current thinking is that atmospheric CO2 concentrations must be stabilised at 450 parts per 

million by volume if we are to at least slow down, if not stop, global warming. This goal will 

require a reduction in greenhouse gas emissions by a factor of four to five in the industrialised 

nations. Whilst there is a continued and necessary focus on the development, improvement 

and implementation of renewable and carbon-neutral power generation technologies and the 

adoption of energy efficiency measures, there is a large gap in the short and medium terms 

in the level of carbon reductions that can be delivered through these routes alone. 

The power generation industry produces about half the world’s CO2 emissions, so it offers 

considerable opportunity for introducing large-scale emission reduction technologies. Current 

global debate is focussing on the development of carbon capture and storage (CCS), which 

can extract 85 percent to 95 percent of the CO2 produced by a fossil-fuel power generation 

facility. Even though carbon capture reduces a plant’s thermal efficiency, meaning that the use 

of fuel per unit of electricity produced increases, the overall carbon reduction is still high— 

about 80 percent to 90 percent. The effectiveness of carbon capture technology on power 

plant emissions is illustrated in Figure 1. 

CCS technologies impact the cost of electricity generation, however, so if we are to move 

forward with this technology, it is important that we consider the impact of carbon pricing on 

lifetime costs, the attractiveness of the technology to investors, and how varying the carbon price 

will affect the competitiveness of gas turbine plant with other methods of power generation. 

Carbon Capture Technologies 

The main carbon capture technologies under development are classed as either 

pre-combustion or post-combustion. The one pre-combustion and two post-combustion 

options available, which represent the first generation of commercial carbon capture, are 

shown in Figure 2 and reviewed below. 

Pre-combustion. The fuel is first reformed into more basic constituents by its reaction 

with oxygen. The fuel can be solid, such as coal, petcoke or biomass; liquid, such as a heavy 

fuel oil; or gas, such as natural gas. The resultant product, known as syngas (synthetic 

gas), contains mainly carbon monoxide and hydrogen. Other constituents include some 

methane, some carbon dioxide, hydrogen sulphide and many other minor compounds 

including ash if a solid fuel is used. Ash is usually in a fused form and easily separated 

from the syngas. The syngas is treated to convert the carbon monoxide to carbon dioxide 

that is removed in a chemical absorption process, leaving a predominantly a high purity 

hydrogen gas stream suitable for compression, transportation and long-term sequestration. 

The main plant components of the pre-combustion reformation and capture stages are considered 

to be proven technologies, although there will be some process engineering required to bring 

these to the scale required for large scale CCS. Some further operational 

proving of the gas turbine for use on hydrogen fuel is required before 

the process can be regarded as being a normal operational procedure. 

Figure 2: Carbon Capture 

and Storage Schematic. 

Post Combustion. A post combustion carbon capture plant can 

use the same fuels as a pre-combustion capture plant. The fuels are 

combusted in either conventional boiler plant or, if suitable, in gas 

turbine plant. The flue gases are treated to remove particulate matter 

 




and sulphur dioxide, and to reduce nitrogen oxides before 

entering the carbon capture process. The carbon dioxide is 

absorbed into a chemical solution 1 to remove it from the flue 

gas, which is then emitted to atmosphere. The carbon dioxide 

gas is removed from the absorbent, compressed and transported 

for long-term sequestration. The challenge with this 

technology is the need to scale up to utility-size capture. 

Oxyfuel. An oxyfuel plant is one in which the fuel is 

combusted in oxygen supplied by an air separation plant 

rather than air. The resulting flue gases are purified to remove 

particulate matter and sulphur dioxide, and to reduce nitrogen 

oxides. Some of the captured carbon dioxide is recycled and 

mixed with the oxygen feed to the boiler plant to control 

combustion temperature. The remaining carbon dioxide is 

then purified, compressed and transported to long-term storage. 

The aim of oxyfuel development is to use as much of the 

existing and proven equipment as possible; although some 

issues remain relating to the control of combustion temperatures 

within the boiler and the scaling up of air separation 

plant to the size necessary for use in power plant applications. 

Carbon Dioxide Transport and Storage 

Transport. Captured carbon dioxide is transported to a longterm 

storage location by either pipeline, truck, train, or boat, 

although only pipeline would be feasible for the quantities 

resulting from large-scale power generation—millions of tonnes 

per year. The pipeline could transport carbon dioxide in the 

gaseous phase, at pressures below 71 bar, or at higher pressures 

where the carbon dioxide is present as a supercritical 

fluid giving benefits from lower frictional losses. The scale is 

such that a new pipeline infrastructure would be needed. 

Storage. Storage of carbon dioxide is assumed to be in 

geological formations, such as depleted oil and gas reservoirs, 

deep saline aquifers and unmineable coal seams. These 

formations need to provide storage with negligible leakage 

to ensure that the carbon is sequestered over geological 

timescales—thousands, if not tens of thousands of years. 

The estimated global potential for the storage of CO2 in 

these various sinks is detailed in Table 1. As would be expected, 

the capacities for the oil/gas and coal storage options are 

considerably smaller than those for the saline aquifers. 

Even with the present global carbon dioxide emissions of 

about 25 billion tonnes per year, the available storage capacity 

extends for about 55 years to about 435 years. Whilst 

this is not a solution, it does provide us with a temporary 

breathing space in which to find and implement alternative 

means of energy provision to satisfy human, social and 

economic aspirations. 

Technology 

Analysis and 

Lifetime Cost of 

Generation 

For the purposes of 

reviewing the position 

of gas turbine technology 

within a carbon 

constrained world, it was 

necessary to identify those 

power generation technologies where gas turbines will 

continue to have a use and, importantly, the competitor 

technologies. The technologies reviewed included: 

• Coal supercritical pulverised fuel plant with flue gas 

desulphurisation with and without carbon capture 

• Coal integrated gasification combined cycle plant (IGCC) 

with and without carbon capture 

• Gas fired combined cycle plant with low NOx burner 

technology with and without carbon capture 

• New generation nuclear power plant. 

Table 1: Estimated Capacity of 

CO 2 Storage Options. 

(Source: IEA-GHG, 2004) 

Our analysis considered the impact of carbon and capital 

on the lifetime cost of electricity generation. The extent to 

which carbon pricing ‘feeds through’ to the cost of electricity 

generation depends on the amount of free allocations 

provided by government to individual plants. Given that 

different allocation methodologies will be adopted in different 

countries globally, it was considered to be of more value to 

assume no allocations and that the full cost of carbon flows 

through to the end electricity generation cost. 

The level of carbon captured within the carbon capture 

options will be specific to each plant’s detailed design. The 

costs associated with the transport and storage of carbon 

were based on various reference sources—an indicative 

value of $10/ton CO2 sequestered was used. 2 The Capital 

costs and operation and maintenance costs were based on 

those observed in the market and included adjustments for 

the recent increases in the underlying materials costs, such as: 

• Steel: 35 percent increase since 2002 

• Copper: 400 percent increase since 2002 

• Nickel: 400 percent increase since 2002. 

The analysis showed that the addition of carbon capture 

and associated transport and storage charges added about 

35 percent to 63 percent to the lifetime cost of electricity 

generation. Introducing a carbon cost payable by the 

generation plants for all CO2 emitted increased the electricity 

costs across the board, as would be expected. For example, 

if a $25/ton charge were placed on all CO2 emissions, the gap 

between non-carbon capture and carbon capture would be 

narrowed to 6 percent to 22 percent due to the proportionately 

larger impact the carbon cost has on the non-CCS plant. 

1 A number of possible chemicals can be used. Amine, ammonia, and potassium bicarbonate are just a few. 

2 Imperial College, Potential for Synergy between renewables and Carbon Capture and Storage. 




across the board, as would be expected. For example, if a 

€25/ton charge were placed on all CO2 emissions, the gap 

between non-carbon capture and carbon capture would be 

narrowed to 6 percent to 22 percent due to the proportionately 

larger impact the carbon cost has on the non-CCS plant. 

Figure 3 shows that the carbon costs incurred by unabated 

generation increase the cost of generation significantly whilst 

maintaining the mix of generation technologies to coal, gas 

and nuclear. There did not appear to be a clear winner. 

Figure 3: Relative costs of plant with and without carbon capture. 

Where Are We Now? 

A number of CCS projects of varying sizes are underway 

around the world. The European Union (EU) projects are 

shown in Figure 4. As can be seen, only three are identified 

as being operational with the bulk being in the ‘planned’ stage. 

Figure 4: Carbon Capture projects in the European Union. 

These projects will be implemented at various times up to 

2015, with the majority scheduled for delivery around 2010. 

The fact that these development projects are moving forward 

is a step in right direction; however, there is a need to accelerate 

this if we wish to contain the global concentrations of 

atmospheric CO2 below the 450 ppmv level that is presently 

given as our target. 

Other Opportunities 

A carbon capture plant had been considered to date as 

being inflexible in its operation and less able to respond to 

short-term changes in electricity demand. This view is changing, 

however, with recent studies considering the specific capabilities 

of the power generation plant and the carbon capture plant 

separately. With this new view comes the potential to 

include additional carbon storage on post-combustion capture 

plants, a change that will allow additional power to be provided 

from the generator in response to system events, such as 

transmission system faults, power station forced outages, or 

spikes in demand. This change could provide valuable flexibility 

services to the transmission system operator when rapid 

response to system events is required. 

In the case of pre-combustion plant, whether the fuel is coal 

or gas, the hydrogen fraction of the syngas could provide the 

beginning for establishing a hydrogen economy. This would 

be prior to the commercial realisation of nuclear fission. It 

would also be applicable in countries that do not have sufficient 

insolation (incident solar radiation) or available land area to 

drive large solar plant that could be used to generate hydrogen. 

Summary 

The technology relating to carbon capture is progressing 

and reaching a point where it is at a pre-commercial stage. 

The mechanisms to allow the costs associated with carbon 

emissions to incentivise investment in carbon capture plant 

are beginning to emerge, but they will need a strong political 

will to ensure that the costs associated with carbon emissions 

become sufficient to tip the balance in favour of carbon 

capture. This political decision will need to take into 

account the extent to which the end customer incurs 

additional charges and the rate at which any additional costs 

are introduced into the economy. This is a balancing act 

and it will have a time constant associated with it. It must 

be remembered, however, that: 

CCS IS NOT A SOLUTION — IT’S A STOP GAP! 

Dominic Cook has 20+ years of utility and consultancy experience in the power industry. He has been involved in regulatory audits and the development of power 

generation plant, and in providing advice to financial institutions. His publications included “Powering the Nation” in June 2006 and he is presently involved with the 

UK government on the carbon capture competition. 

Note: This article was adapted from a paper presented at the annual conference of the Institute of Diesel and Gas Turbine Engineers (IDGTE) in November 2007. 




The NuGas TM Concept: Combining a Nuclear Power 

Plant with a Gas-Fired Plant 

By Paul Willson, Manchester, UK, 44 161 200 5210 willsonPa@pbworld.com; and Alistair Smith, 44 161 200 5114, smithAlistair@pbworld.com 

Nuclear power is experiencing 

renewed interest 

around the world because 

of its low carbon emissions 

and affordability. As with 

other thermal generation 

technologies, however, its 

thermal efficiency is limited. 

PB has developed a new 

concept that combines 

current nuclear technology 

with combined cycle gas 

turbine technology to 

achieve unprecedented 

levels of thermal efficiency. 

The authors explain how 

it works and how it can be 

implemented in new installations 

or in retrofitting 

existing nuclear stations. 

PB’s power specialists in the UK have developed and patented a completely new concept 

for high-efficiency electricity generation. This ground-breaking development, called NuGas TM , 

combines the advantages of nuclear power generation with a smaller combined cycle gas turbine 

(CCGT)-based power technology to create a low-cost, highly reliable hybrid system that: 

• Increases output and thermal efficiencies to levels that are far higher than even the most 

ambitious forecasts 

• Achieves a simple, safe and effective interface between the cycles. 

Improved performance comes from better use of heat in the steam cycles of the CCGT and 

nuclear plant where currently unavoidable large temperature differences prevent the maximum 

work being obtained from the heat. By linking a CCGT with the low-temperature steam cycle 

typical of a nuclear power plant, these temperature differences can be reduced significantly, 

releasing additional power output without going outside conventional design conditions. 

Because NuGas TM enhances thermodynamic cycle design rather than changing operating conditions 

to improve efficiency, it introduces no new technology risks in its implementation. This is a 

significant advantage over the more complex and unproven technologies being introduced for 

new gas turbine designs as engineers pursue ever higher temperature operation. 

NuGas TM can be used either for retrofitting existing nuclear stations or for new-build installations. 

While the new-build design allows for maximum optimization, the retrofitted option will 

enable rapid return on investment with minimal impact on normal day-to-day operation 

of the existing nuclear plant during construction of the CCGT unit. 

Improving Thermal Efficiency 

When analyzing a nuclear power station design, the question often asked by non-engineers or 

scientists is ‘why can’t you convert all the heat generated in the reactor into electricity?’ For 

example, the thermal efficiency of the latest pressurized water reactors (PWRs) is just 37 percent. 

Even if there were no losses in the system, the maximum Ideal Efficiency would still be well 

below 100 percent. For a PWR operating at an upper steam temperature of 540°F (280°C), 

the maximum possible efficiency would be just 45 percent. The way to push the Ideal Efficiency 

up is to increase the upper temperature in the cycle, which is why gas-cooled high temperature 

reactors are again being considered. 

Temperatures have been pushed up also in fossil fuelled power plants, and the most modern 

coal-fired super-critical boilers can achieve a thermal efficiency of 44 percent. This level is now 

being exceeded when two cycles are combined, such as the CCGT, where temperatures are 

around 2300°F (1200°C) and a thermal efficiency of 57 percent can now be achieved. The 

desire to raise system efficiencies beyond current levels has proven challenging, however. 

Despite considerable investment in research and development, it appears that significant 

incremental improvements are becoming more expensive and harder to achieve without 

sacrificing reliability. 

By combining current nuclear and CCGT technologies. NuGas TM raises thermal efficiencies to 

unprecedented levels. Under this concept, the two separate power generation systems can operate 

in tandem as a single combined unit on the same site. In the case of breakdown or planned 

maintenance, either the nuclear plant or the gas turbine-powered unit can revert to independent 

operation, thereby maximizing availability of power and minimizing upset to the power networks. 




The basic concept would allow a large nuclear power plant 

with a typical output of 800 to 1700 MWe to be combined 

with a 300 MW CCGT generating unit. Linking the steamcycles 

of the two plants enables them to operate as an 

integrated power production unit and reduces losses of 

potential output, increasing total efficiency. Cycle efficiency 

gains enable the CCGT to contribute an increased output for 

no additional fuel, with the efficiency of converting the energy 

in the gas to electricity increased to about 62 percent. 

How NuGas TM Works 

Although a CCGT system has a high thermal efficiency, it 

relies on using the heat from the exhaust gases of the gas 

turbine to boil water to produce steam that drives the 

turbine. As the exhaust gases cool, water is evaporated in 

the boiler tubes but temperature differences of up to 400ºF 

(200ºC) arise in the boiler due to the large amount of heat 

needed to evaporate the water. These temperature differences 

limit the potential work that can be extracted from the 

steam, reducing the output of the steam cycle. 

The NuGas TM cycle overcomes this limitation by ‘borrowing’ a 

small proportion (typically 10 percent) of the steam from the 

nuclear steam cycle (point ‘A’ on Figure 1). The dry saturated 

steam is superheated using the exhaust heat of the gas 

turbine. The high temperature steam (‘B’) is then used to 

drive a separate conventional condensing steam turbine to 

provide additional output from the plant. Superheating steam 

rather than boiling water enables a much lower temperature 

difference to be maintained in the heat recovery system, 

maximizing the value of the energy recovered. 

The heat in the gas turbine exhaust flow between about 

570ºF and 320ºF (300ºC and 160ºC) is recovered via a high 

temperature economizer (‘C’) to generate high temperature 

Figure 1: Schematic Combination of the Steam Cycles. 

feedwater, which is returned to the nuclear cycle (‘D’), 

ensuring that the inlet temperature to the steam generator 

is maintained close to the design value. 

The heat in the gas turbine exhaust below about 320ºF (160ºC) 

(‘E’) is used to heat part of the condensate from the high 

temperature steam turbine (‘F’) before it is deaerated and 

returned to the nuclear cycle feed pumps (‘G’). The remaining 

condensate from the high temperature steam turbine is 

returned to the nuclear cycle condensate system (‘H’). 

The flows of energy around the cycle differ somewhat to 

those in a conventional CCGT. Figure 2 shows a simplified 

Sankey diagram for the NuGas TM cycle, including the energy 

exchanges between the CCGT and PWR cycles shown along 

the lower edge of the diagram. 

Identifying the separate performance of the CCGT cycle 

when it is linked to the PWR cycle requires that the design 

PWR energy balance be maintained. Thus, the CCGT returns 

power to the PWR to compensate for the reduction in 

output due to the ‘borrowed’ steam and returns rejected 

heat in the CCGT cooling water to the PWR to account 

for the reduced heat rejection from the nuclear turbine 

condenser. The diagram therefore shows the additional 

energy input, the additional losses and the additional power 

generated by the cycle, demonstrating its high efficiency. 

Safety Considerations 

Downstream failure is limited. The extraction of steam 

from the main steam system has the potential to disturb 

reactor operating conditions. However, the PWR system is 

designed to allow for a 10 percent step change in flow to the 

main steam turbine without exceeding the appropriate limits 

for a frequent operating condition. It is likely, nevertheless, 

Figure 2: Simplified Sankey Diagram for NuGas Cycle. 

 




that a suitably qualified shut-off valve and additional bypass 

valves would be needed to limit the potential impact of any 

downstream failure in the NuGas TM cycle. 

Installation risks are minimized. The interconnection 

design minimizes installation risks and ensures that the main 

plant is unaffected by maintenance of the NuGas TM plant and 

that CCGT operation can continue independently of reactor 

operation. This is fundamental, as significant costs would be 

charged by the grid operator for increasing the loss of generation 

resulting from a single fault. In addition, the project 

economics would be adversely affected if the availability of 

either plant was to be degraded by the linking of the cycles. 

Safety case is maintained. NuGas TM raises overall efficiency 

by enhancing the thermodynamic cycle rather than changing 

operating conditions, so in addition to being inexpensive, it 

introduces no new technology risks in its implementation. 

The plant design incorporates additional systems to control 

high temperature steam flows linking the nuclear and CCGT 

units, ensuring that the integrity of the nuclear safety case is 

maintained. 

To ensure that all the additional hazards associated with the 

introduction of the CCGT are assessed, a full HAZOP has 

been carried out to ensure that risks are well within the 

currently assessed fault scenarios. 

New Build 

Currently, the two leading candidate PWR designs for new 

nuclear construction are the Evolutionary Pressurized Water 

Reactor (EPR) from AREVA with a nominal power rating of 

1600 MWe and the Westinghouse AP1000 reactor with an 

output of around 1140 MWe. Either the EPR or AP1000 

could be integrated with a NuGas TM cycle to offer extra 

capacity with the highest possible efficiency for fossil fuel 

conversion without significantly increasing the loss of output 

in the event of a reactor trip. 

If the NuGas TM concept was applied to an AP1000 with a 

nuclear plant electrical output of 1140 MW, the combined 

plant would have an output of approximately 1470 MW for an 

additional capital cost of around $250 million ($800 to $1000 

per incremental kW). The cost of the NuGas TM integration is 

approximately $50 million, which can be considered to offer 

additional capacity with no additional fuel burn. Pessimistically 

at a fuel price of $7/MMBTU, a cost that is conservatively 

below current levels and below recent longer term forecasts, 

the investment to combine the plants would have a typical 

payback time of less than three years. At higher gas prices, 

the benefits are increased and the payback period 

correspondingly reduced. 

Backfit 

The renaissance of interest in new nuclear power plants will 

mean that by 2015 and beyond more nuclear plants will be 

brought on-line, but for the next seven years utilities waiting 

for their new nuclear plants to be licensed and built may be 

faced with a generating capacity gap. Some utilities are, 

therefore, considering building interim plants with a low capital 

cost and rapid construction times, characteristics of the 

CCGT. Building a CCGT and combining it with an existing 

nuclear power plant can provide a rapid method for increasing 

power generation capacity with exceptionally high thermal 

efficiency, making it far more profitable than stand-alone 

CCGTs. The necessary connections to the nuclear steam 

cycle can be readily made during the refuelling outages on 

the nuclear plant, thereby minimizing disruption and cost. 

A further key advantage for the NuGas TM concept arises 

where the nuclear plant has increased operating margins 

such that more heat can be emitted by the reactor. In some 

cases this extra output cannot be converted to electricity 

as the existing steam system cannot operate at significantly 

higher rates. Because the NuGas TM cycle increases steam 

utilization capability by at least 10 percent, it can use excess 

steam without expenditure or shutdowns for costly steam 

cycle upgrades, making the NuGas TM conversion even more 

attractive financially. 

Conclusion 

By re-examining power generation options and focusing on 

improving efficiency to reduce carbon emissions, it has been 

possible to developing a novel concept that brings together 

the best aspects of nuclear and gas-fired power generating 

technologies. The concept is now being developed with 

utilities and plant vendors, with a target of going into service 

before 2013. 

 

Paul Willson, Deputy Director of Engineering, Generation within PB’s power and energy business in Manchester, has worked for PB and its predecessors for more than 25 

years. He leads the Development and Emerging Technology Group, which is responsible for independent power and water project development and for innovations. Paul 

is co-inventor of the NuGas technology. 

Alistair Smith, Director of Nuclear Services for PB based in Manchester, has worked in the nuclear power industry for 27 years and has worked on all phases of the 

nuclear plant lifecycle covering design, construction, operation and decommissioning. He is the chairman of the UK Institution of Mechanical Engineers Nuclear Power 

Committee, chairman of the Nuclear Industry Association’s industrial group, and is a spokesman for the UK nuclear industry. 




PB Inspections Help to Ensure Power Plant Safety 

By Stewart Gray, Bangkok, Thailand, 66 (0) 2343 8866, gray.stewart@pbworld.com 

The author provides some 

insight into the application 

of engineering to prevent 

explosions and fire in highly 

hazardous areas of power 

plants fuelled by oil or gas. 

Acronyms/Abbreviations 

IEC: 

International 

Electrotechnical 

Commission 

Figure 1: Schematic of the 

principle of a flameproof 

enclosure. 

In modern thermal power plants fuelled by either oil or gas, fuel handling processes give rise 

to situations where electrical equipment could cause an explosion due to a hot surface or a 

spark. Indeed, there have been several incidents in the past where lives have been lost and 

plant destroyed. Places where these situations arise are termed “hazardous” or “classified areas.” 

Special engineering practices designed to prevent explosions in these areas are available. 

These practices are often misunderstood and applied incorrectly, however, expert supervision 

should always be used at a project start-up to ensure such engineering practices are implemented 

properly. The following information is based on the experiences of some of PB’s 

workers in this field, particularly our assessments of power plant installations and our ensuring 

that relevant codes and practices, local statute and insurance requirements are adhered to. 

Applicable Codes or Practice 

The code or practice applicable to each installation is normally determined by its locality, 

although the several different practices applied worldwide have many similarities. The most 

commonly applied codes are International Electrotechnical Commission (IEC) 60079 “Electrical 

apparatus for explosive gas atmospheres” and National Fire Protection Association (NFPA) 70 

“National Electrical Code.” Both define sets of special precautions (types of protection) required 

for electrical equipment in hazardous/classified areas using some very definite vocabulary. 

Choice of Types of Explosion Protection 


principle of increased safety. 


principle of intrinsic safety. 

It is important to establish the extent of hazardous areas that exist at an early stage of any 

plant’s design. These areas are customarily delineated using a plan called a “hazardous areas 

layout drawing.” While it is always best to install the electrical equipment elsewhere, doing so 

is often unavoidable. 

All electrical equipment installed in a hazardous area requires explosion protection. IEC 

60079 defines nine types of such protection. Of these, the three types of protection most 

commonly found in modern power plant are: 

• Flame proof enclosure (type d). This technique limits the effect of an explosion. Parts 

that could cause an explosion are placed inside a special enclosure that is strong enough to 

contain an internal explosion (Figure 1). The resulting hot gasses exit through a specially 

machined path that is relatively long and narrow. As they exit they are cooled sufficiently 

to avoid spreading the explosion outside. 

The main uses for this type of protection are electrical power equipment, switches, etc. 

While this is a well known technique, it is somewhat less readily available than others. It 

is also expensive and requires special installation rules. 

• Increased safety (type e). This technique (Figure 2) prevents explosions. Parts that could 

cause an explosion are made with a superior degree of safety, including long creepages and 

clearances, and temperature limitations. Its main use is for junction boxes. This technique is 

well known, readily available, and inexpensive. Its use requires observation of special design 

and installation rules. 

• Intrinsic safety (type i). This technique (Figure 3) also prevents explosions. The circuit 

is arranged so the amount of energy that can flow into the hazardous area is limited and 

incapable of causing an ignition. Normally, energy limiting “barrier” devices used in the safe 

area contain zenner diodes or optical isolators to achieve the energy limitation. Care needs 

to be taken to ensure that the hazardous area part of the circuit cannot store large amounts 

of energy (i.e., use of low capacitance cables). 

 




The main uses of type i are for instrumentation, telecommunication 

devices, and similar equipment. It is well 

known, inexpensive and readily available, but special design 

and installation rules need to be followed. Two categories 

of intrinsic safety are available. Category ia, which provides 

the highest degree of explosion protection available, 

ensures safety under two faults. Category ib ensures safety 

under a single fault. 

Design and Assembly Stage Inspections 

Inspections of the installation need to be conducted throughout 

the stages of its life cycle in accordance with IEC 60079. 

Design Stage. Inspections should start at the design stage 

by means of design review because mistakes identified at this 

stage are almost always easier and less costly to rectify. 

Factory Assembly Stage. When factory assembly of skid 

mounted equipment is completed and after the factory has 

conducted its own inspection, an inspection done by our 

team is advantageous. Whilst this does not present a 

comprehensive picture of the final installation, it can often 

show mistakes, and corrective measures can be planned 

during shipping to the construction site. 

Final Construction Inspection 

A final construction inspection, along with possible rectification 

of any mistake, is mandatory before explosive fluid can 

be introduced to the plant. The objective of the inspections 

is to verify the installation complies with the applicable code 

of practice. In the case of IEC 60079, this requires ensuring 

that the appropriate components were selected and that 

they were installed correctly. Discovery of an installation 

mistake at this stage may lead to project time delay. 

Verification of Explosion Protection. The first part of 

any inspection work is to make sure that the equipment is 

explosion protected in conformance with IEC 60079. Whilst 

it may be labelled with compliance information, a visual check 

of labelling is not enough. It is necessary to obtain a copy 

of the original certificate of conformance and use this as 

the inspection start-point. The inspector should check 

the certificate validity, cross check the certificate against 

equipment labels and verify the installation method complies 

with the requirements as stated in the certificate. 

Use of Check Sheets. It is good practice to record the 

outcome of the inspection using check-sheets. The minimum 

points to be considered are peculiar to each type of protection, 

as summarised in the box below. In addition, the check-sheets 

should contain a record of each item’s certificate number. 

The methods used are straightforward; however, each item of 

plant has its own peculiarities and some of these are often 

overlooked. The importance of this matter dictates that an 

expert lead the inspection at this stage. 

 

Minimum Check Points for Installation of 

Three Common Types of Explosion Protection 

Flame proof enclosure installation (type d). 

• The EEx d label is correct. 

• The cover has been fitted correctly. 

• The serial number on the cover and base unit match (if applicable). 

• Cable entries are by means of EEx d certified gland (special rule 

for enclosure > 2 litre size), EEx d certified plug or stopper, EEx d 

certified cable bushing/termination or sealed conduit. 

• All conduits are wrench-tight with at least five full threads engaged. 

• Any reducer used is certified. 

Increased safety installation (type e). 

• The EEx e label is correct. 

• Any breather is of an approved type (see certificate schedule). 

• Any breather is installed in correct face. 

• Any unused cable hole is sealed properly. 

• All terminal screws are tightened, including spare terminals. 

• Insulation is within 1 mm (0.04 inch) of the terminal throat. 

• If mineral-insulated copper clad (MICC) cable is used, an EEx e 

gland is applied. 

• The glanding technique maintains IP54 (washers may be used). 

• There is no more than one conductor per clamp, unless a special 

joint is used. 

• Terminal creepages and clearances are within specifications. 

• Terminal temperatures will not exceed the temperature of the 

component certificate. 

• All terminals and accessories have been installed per the 

manufacturer’s recommendations. 

• Terminal ratings do not exceed their label. 

Intrinsic safety installation (type i). 

• The barrier is installed in safe area (may be in zone 1 area if inside 

EEx d enclosure). 

• The EEx marking is correct on the barrier and device, if applicable. 

• Wiring has been segregated. 

• Enclosures are protected to at least IP20. 

• Earthing has been connected in accordance with the EEx certificate. 

• Wiring properties are consistent with EEx certification. 

• If a colour code is applied, the colour used is light blue. 

Related Web Sites: 

Additional information about the use of electrical equipment in 

hazardous areas is publicly available at numerous certification body 

and specialist manufacturer’s Web sites, including: 

• http://www.baseefa.com/ • http://www.mtl-inst.com/ 

• http://www.ptb.de/index_en.html • http://www.stahl.de/en/start.html 

Stewart Gray is a principal engineer with more than 30 years’ project engineering experience, including 10 in a construction-based consulting role. With his detailed knowledge 

of the subjects of safety and inspections, he has identified a variety of hazardous area installation errors on behalf of several clients before their plants went into service. 

In most cases, these errors were attributable to incorrect material selection or inappropriate installation techniques. 




Project Brief: Using Monte Carlo Techniques to 

Size a Power Station By Mike Emmerton, Hong Kong, 65 6290 0737, emmertonM@pbworld.com 

1 Two earlier PB Network articles 

tell how Monte Carlo techniques 

were used in risk management. 

Please see: 

• “Project Risk Management and 

Madrid’s New Airport” by Paul 

Callender, Issue 51, January 2002, 

pp. 56-58 and on line at http:// 

www.pbworld.com/news_events/ 

publications/network/issue_51/ 

51_24_callenderp_madrid 

airport.asp. 

• “A Risk Assessment and Analysis 

for an Existing Water Conveyance 

Tunnel” by Kyle Ott and Joe Wang, 

Issue 51, January 2002, 

pp. 38-40, 43 and on line at 

http://www.pbworld.com/news_ 

events/publications/network/ 

issue_51/51_17_ottk_risk 

assessmentanalysistunnel.asp 

In early 2007, PB was selected to assist one of the world’s largest port owner-operators to 

determine the least-cost approach to meeting the power needs of a proposed container port 

development in Pakistan. The major electrical loads of a container port are the quay cranes 

used for loading and unloading container ships. The client required our power specialists to 

determine whether a stand-alone power station would be more economical than using on-board 

quay crane diesel motors. The key challenge in sizing the power station was to deal with the 

uncertainty associated with the loading pattern of 16 quay cranes. The electrical loads of 

these cranes vary with their duty cycles, and the total load varies with the number of cranes 

in operation In turn, this, is dependent on the rate of arrival/departure and the capacity of the 

container ships. 

Our team combined engineering and Monte Carlo techniques to successfully deal with this 

problem. Monte Carlo is a method of analyzing stochastic processes, which are those governed 

by laws of probability, that are so difficult that a purely mathematical treatment is not practical. 1 

Client feedback indicated that this technique was the most convincing method they had seen 

used in the industry, whereas solutions based on traditional engineering methods only were 

judged to be unreliable or conservative. 

 

Mike Emmerton is a management consultant who has been with PB since 2004. 

Project Brief: Energizing Singapore’s Economy 

By Kamaljit Gill, Singapore, 65 6533 7333, gillK@pbworld.com 

PB acted as owner’s engineer to Keppel Energy for its development of the Keppel Merlimau 

Cogen power plant, a 500 MW combined cycle facility on Jurong Island in southwest Singapore. 

The plant now supplies power to the Singapore grid, and has provision to feed process steam 

to chemical plants that are due to be part of the evolving petrochemical industry on the island. 

Construction began in March 2005. Our management team ensured that everything was in 

place well ahead of the schedule set by the turnkey contractor, an effort that helped lead to 

the plant seeing provisional acceptance in April 2007. 


• http://www.keppelenergy.com/ 

• http://www.ema.gov.sg/ 

• http://www.pbworld.com/ 

The project adopted the acid cleaning method, which replaced the usual steam-blow procedure. 

This resulted not only in a shortened timetable, but in improved qualities of steam and water 

for commissioning. 

Our team also helped to meet stringent regulatory requirements. The plant was the first 

independent power project to comply with Singapore’s Energy Market Authority (EMA) rules 

following deregulation of the country’s electricity market in 2003. 

 

Kamaljit Gill is a senior mechanical engineer who has been with PB since 2005. He was the lead mechanical engineer supervising the installation and construction of GTs, 

ST, HRSG, piping, tanks and balance of plant equipment on site, including chemical cleaning, steam blowing and performance testing of turnkey systems. He was also reviewing 

engineering design documents and drawings from contractors, monitoring schedules and quality of execution during site implementation to ensure that the plant complies 

with contractual requirements. Kamaljit was also a member of the commissioning team, supervising, internal commissioning activities - conducting internal and regulatory 

testing, reliability runs and performance guarantee testing. 




Combined Heat and Power for USA’s Largest 

Residential Development 

By Dennis Bautista and Eric Swensen, New York, New York, 1-212-613-8840, swensen@pbworld.com 

The project described in 

this article started as 

refurbishment of a central 

heat/chill plant to include 

combined heat and power 

(CHP) for a baseload of 

approximately 26 MWe. 

The majority of CHP in USA 

is heat matched with top-up 

electrical power from the 

utility provider. Our team 

identified benefits for an 

over-size (40 MWe) CHP 

plant able to export up to 

16 MWe to the utility grid. 


• New York State Energy 

Research and Development 

Authority (NYSERDA): 

http://nyserda.org/default.asp 

• Riverbay Corporation: 

http://www.riverbaycorp.com/ 

newrb 

PB was engaged as prime consultant to upgrade the central boiler/chiller plant at the largest 

cooperative residential development in the USA, which is named Co-op City. Located in 

New York City’s borough of the Bronx, Co-op City is home to approximately 55,000 residents. 

It consists of 15,372 residential units in 35 high-rise buildings and seven clusters of townhouses, 

three shopping centers, parking garages, schools, and houses of worship (Figure 1). 

Riverbay, the corporation that manages Co-op City for the residents, wanted to make a number of 

improvements for “greening” the complex. These included: upgrading the central plant, improving 

the buildings’ energy efficiency, extending the existing waste recycling schemes, and introducing 

water-conserving technologies. The objectives of the central plant upgrades were to reconfigure 

the systems to optimize steam and energy utilization during peak and off peak seasons; 

make the development self-sufficient for heating, cooling, and power; and lower emissions. 

The Existing Boiler/Chiller Plant 

The existing plant had been configured as a thermal plant with electric generation to provide 

for the parasitic loads of the plant. As studied, the plant comprised the following, all of which 

were fired on No. 6 (residual) fuel oil: 

• A central boiler plant with combined gross steam generating capacity of approximately 

442 tonne/hour (975,000 lbs/hr). 

• One high-pressure boiler 34.5 barg (500 psig) with rated capacity of 138 tonne/hour 

(305,000 lbs/hr). 

• Two low-pressure boilers. 

• Four multistage steam turbine driven centrifugal chillers, each with original rating of 

6,250 tons refrigeration. 

During spring and fall when there is little requirement for heating or cooling, the steam 

demand may be as low as from 4,536 kg/hr to 13,608 kg/hr (10,000 lbs/hr to 30,000 lbs/hr), 

while winter peak heating demand can be more than 226,800 kg/hr (500,000 lbs/hr). Steam 

is used for domestic water heating all year round, chilled water production in the summer, 

and space heating in the winter. The old 7.5 MVA steam turbine generator (STG) had not 

been operational since 1996, and the superheated steam from the high-pressure boiler was 

now directed to the pressure reducing/de-superheater station and 

low-pressure header to supplement the low pressure boilers’ 

steam supply. 

The electrical loads were supplied from Consolidated Edison 

Company of New York, Inc. (Con-Ed), the local utility. The load 

ranged from an annual average demand of 12 MWe to a peak 

demand of 23 MWe. 

Configuration Study and Critical Analysis 

Figure 1: View from the refurbished cooling tower showing 

some of the Co-op City’s 35 high rise buildings in the 

background. 

PB provided a configuration study and critical analyses that 

recommended installation of combined cycle gas turbine (CCGT) 

cogeneration plant to replace the existing electrical supply from 

Con-Ed and to meet the thermal demand of the complex. 

Included were a combined heat and power (CHP) study, chiller 

upgrade study, cooling tower study and miscellaneous plant upgrades. 




The CCGT system selected by the client from options 

presented by PB went beyond the straight replacement of 

plant. It was designed for flexibility of operation and retained 

usable equipment where possible. Although the majority of 

CHP in the USA is heat matched, an “oversize” (40 MWe) 

plant with power-export capability was selected. This oversize 

system (Figure 2) included: 

• Two new 13 MWe gas turbine generators, each with a 

heat recovery steam generator (HRSG), fired on natural 

gas as primary fuel or No. 2 (distillate) oil as back up fuel. 

• A new 15 MWe extraction condensing steam turbine 

generator. This generator uses the existing condenser, 

which has a maximum steam capacity of 29,483 kg/hr 

(65,000 lb/hr). Consultation with the original equipment 

manufacturer confirmed sufficient capacity. 

• The two existing central plant low-pressure boilers, which 

will continue to operate on No. 6 (residual) fuel oil. 

• A new dual fuel (gas/oil) packaged boiler rated at 68 tonne/hr 

(150,000 lbs/hr) that will provide further flexibility. 

Figure 2: 

Combined cycle 

gas turbine 

(CCGT) plant 

representative 

of installation 

at Co-op City. 

minimized the impact on the existing system. The primary 

features of the existing central chiller plant were: 

• Chillers. Four Worthington multistage steam turbine 

driven, centrifugal chillers, each with original rating of 

6,250 tons refrigeration. 

• Turbine Drives. The multistage steam turbine drivers 

were each rated 2,289.3 kW (3,070 hp), designed for 

10.3 barg (150 psig) steam supplied from the existing 

central boilers. 

• Performance. Design chilled water flow rate was 37 8 

liter/minute (10,000 gpm) each. 

The main components of the chiller plant upgrade were: 

• Replacement of the chiller unit driveline to a more efficient, 

single-stage turbine. The new driveline lowered the output 

of each chiller to 5,000 tons (total combined capacity of 

20,000 tons), but improved chiller efficiency by 33 percent. 

• New high efficiency tubes for the evaporators, condensers 

and steam condensers. 

• A new digital control system. 

The chilled water plant configuration study and engineering 

was undertaken in September 2004. The upgrade of the 

chiller plant commenced in summer of 2006 and was completed 

a year later. The final EPC cost was $12 million. The chiller 

plant efficiency was improved from the existing steam rate 

consumption of approximately 15 lb/ton-hr to 10 lb/ton-hr 

Other Supporting Tasks 

The PB CHP study started in May 2004 and was completed 

in October 2004. Following the study and configuration 

analysis, PB performed owner’s engineering services to procure 

the gas turbine and award an engineer, procure, construct 

(EPC) contract. The contract was awarded April 2006 and 

construction commenced in June 2006. The installation was 

completed in early 2008 and, at the time of writing, was 

ready for testing and final Con-Ed approval of the interconnection 

arrangements. The final EPC cost was $67 million. 

Chiller Upgrade 

The other major component of our plant work was a 

configuration study and engineering services to upgrade 

the existing central chiller plant. The goals were to 

increase efficiency and reliability with construction that 

Several other tasks included in our scope supported Riverbay 

Corporation’s goal to increase efficiency and reduce emissions. 

Some of them are discussed here briefly. 

Cooling Tower. The existing five-cell Marley mechanical 

draft evaporative cooling tower was refurbished to address 

the additional heat rejection from the new cogeneration plant. 

Switchgear. A short circuit and protection relay coordination 

study indicated that upgrading of the existing switchgear was 

required. The new 13.2 kV switchgear includes individual 

generator circuit breakers, connection to the new plant 

switchgear and parallel operation with the Con-Ed utility. 

The switchgear was installed by the client. 

Financial Grants. We investigated the availability of grants 

and successfully applied to the New York State Energy 

Research and Development Authority (NYSERDA), a public 

benefit corporation created in 1975 to help reduce New 

York State’s fossil fuel consumption. 

 

Dennis Bautista was lead mechanical engineer on the Co-op City project. He is a former PB employee. 

Eric Swensen, an assistant vice president and senior engineering manage, has extensive experience in power engineering, ranging from initial feasibility studies and 

conceptual design, through detailed design, construction, and commissioning. 




Ensuring Continual Power Supply for New York 

City Hospitals By Ross Krupnik, New York, New York, 1-212-613-8889, krupnik@pbworld.com; and 

Warren Andrews, Atlanta, Georgia, 1-404-364-2650, andrewsW@pbworld.com 

Several of New York City’s 

hospitals and diagnostic 

and treatment centers 

needed upgrades to their 

power systems to ensure 

they would maintain services 

during power outages. The 

author tells about much of 

the research and planning 

PB conducted for these 

upgrades and, equally 

important, for ensuring that 

interruptions to power 

were minimized during 

construction. 


• Dormitory Authority of the 

State of New York: 

www.dasny.org 

• New York City Health and 

Hospitals Corporation: 

www.nyc.gov/hhc 

Ross Krupnik, an electrical engineer, 

has a B.S. degree with a double majorelectrical 

and computer engineering, 

and biomedical engineering. He 

completed his advanced studies in 

electrical engineering in June 2008. 

Ross joined PB in 2006 and served as 

an engineer on the hospital studies 

covered in this article. 

Warren Andrews, a senior engineering 

manager and PB vice president, was 

program manager for the New York 

City hospitals project. He specializes 

in power design. Warren has been 

with PB since 1997. 

1 Level 1 trauma centers offer the 

most comprehensive emergency 

medical and surgical services 

available to patients suffering 

traumatic injuries. 

The Northeast Blackout of 2003, the largest power outage in North American history, revealed 

poorly performing stand-by emergency generators and emergency power distribution systems 

at some of New York City’s hospitals. This event led NYC Health and Hospital Corporation 

(NYC HHC), the owner, to have feasibility studies performed for upgrading emergency power 

systems at several of its major hospitals and diagnostic and treatment centers. The following 

year the Dormitory Authority of the State of New York (DASNY), which acts as NYC HHC’s 

agent, retained PB to validate the aforementioned feasibility studies and to develop design and 

construction documents for upgrading the emergency systems at nine hospitals—Bellevue, 

Coler, Elmhurst, Goldwater, Gouverneur, Harlem, Lincoln, Queens and Woodhull—and three 

diagnostic and treatment centers—Cumberland, Segunda Ruiz Belvis, and Morrisonia. 

Bellevue, Elmhurst, Harlem and Lincoln Hospitals received priority over the other facilities 

because they serve as Level 1 trauma centers. 1 At the time of writing (May 2008), Bellevue 

and Elmhurst Hospital projects were in the middle of the contractor bidding process. 

PB’s role was similar for each hospital: 

• Investigate the site. 

• Measure and record existing running loads. 

• Perform load analysis. 

• Provide a study report to document findings and recommendations to address system 

deficiencies. 

• Meet and correspond with local utility companies to request upgrades in utility services. 

• Provide bid documents and construction support services to upgrade emergency 

systems, including replacing and adding generators; synchronizing generator switchgear; 

and incorporating bypass isolation type transfer switches, emergency distribution 

switchboards and panelboards. 

• Provide bid documents and construction support services to address code violations 

associated with the existing emergency systems and to connect code-required HVAC 

equipment to emergency power. 

Design Challenges 

General Challenge. Implementing electric power upgrades within active hospital facilities 

is challenging, and it is essential that electric power be maintained during construction. Even a 

partial loss of power can cause severe operational problems along a chain of activities: 

• Power loss to lighting systems can make it impossible to dispense medicine accurately, 

carry out precise medical laboratory work or perform surgical procedures. 

• Power loss to refrigerators storing tissue, bone or blood can leave the facility without 

crucial resources. 

• Power loss to essential life support equipment, such as heart pumps, medical vacuum 

pumps, dialysis machines, and ventilators, can result in loss of life. 

Developing design and construction documents that virtually eliminate interruptions to 

electric power during construction was paramount. Thorough up-front planning was essential 

so that these documents incorporate effective strategies for minimizing the impact of 

construction on hospital operations. 

We exercised just such careful planning for the NYC HHC facilities, and included language for 

sequencing construction into design and construction documents for each one. During the 




planning phase, our team: 

• Performed detailed surveys and consulted with facility 

administrators, maintenance and operation staff and other 

personnel to gain a thorough understanding of specific 

functions in each area of each facility 

• Identified and documented the location of all essential 

equipment, and critical and life-safety loads 

• Identified the local source of normal and emergency power 

serving all these loads 

• Identified areas in each facility that would serve as “swing 

space” for locating temporary power distribution equipment. 

This planning allowed us to produce drawings specifying 

construction phasing for accurate, detailed equipment 

removals and relocations and for temporary power. It also 

enabled us to identify windows of opportunity for scheduled, 

short-duration interruptions of power to minimize impacts 

on facility operations. 

Bellevue Hospital. After our analysis of the existing and 

planned electrical loads, we discovered that the hospital’s 

existing four 400 kW generators and one 600 kW generator 

could not accommodate a total failure of the normal electrical 

power feed from the local utility. We proposed: 

• Replacing the 400 kW generators with four new 725 kW 

generators and one 1500 kW generator to provide 

enough power for the existing and future loads. These 

would be installed and synchronized with the remaining 

600 kW generator. 

• Replacing the existing emergency switchgear. 

• Modifying and upgrading 35 of the 47 existing automatic 

transfer switches (ATSs) to accommodate future loads. 

• Upgrading various systems, including the fire pump, fire 

detection system, fire alarms, and alarms for medical gas 

and vacuum systems. 

Various components of the emergency electrical equipment 

are located throughout the hospital rather than at centralized 

locations. Further, Bellevue Hospital is America’s oldest 

public hospital, and now has little room for larger equipment. 

We collaborated with facility management and the manufacturer 

of the switchgear, ATSs, and generators to fit the equipment 

in the available space. (For example, once we determined 

how much space was available for switchgear, manufacturers 

worked within those restrictions to develop switchgear 

frames (boxes) that fit.) The four 725 kW generators will 

be installed on the 13th floor close to the existing 600 kW 

generator, while the 1500 kW generator was planned to be 

installed in the sub-cellar. The paralleling switchgear for these 

generators is on the 13th floor. 

Toward the end of the design process, DASNY asked that we 

revise our design for the sub-cellar 1500 kW generator to 

offer it more protection against flood damage. We raised the 

generator six feet (2 m) and placed it on a new platform. It will 

be supported in an areaway next to an on-ramp along the 

FDR Drive, a heavily traveled highway on Manhattan’s east side. 

The 47 ATSs are located in electrical rooms throughout the 

hospital. Our engineers had to arduously examine the available 

riser space to determine where the replacement switches 

could be located. This effort required the engineers to visit 

each floor of the hospital and venture into areas that required 

special security by the hospital or NYC Department of 

Corrections because of the patients that occupied those areas. 

Elmhurst Hospital. As was the case at Bellevue, Elmhurst 

Hospital’s current generators could not accommodate a total 

failure of the normal electrical power feed from the local utility. 

We proposed installing generators at three locations, each with 

different setups, and making additional upgrades, as follows: 

• Replacing one 350 kW generator with a new 600 kW 

generator and synchronizing it with an existing 400 kW 

generator 

• Replacing another 350 kW generator with a new 600 kW 

generator 

• Synchronizing three existing 600 kW generators with one 

new 1500 kW generator 

• Upgrading 16 of the 30 existing ATSs and adding five new 

ATSs to accommodate future loads 

• Upgrading various systems, including the fire pump, fire 

detection system and fire alarms. 

The generators at the three locations will be activated based 

on the particular load that was lost and the size of the 

power outage. If for some reason the local generator cannot 

supply enough load, it will activate and synchronize with the 

1500 kW generator. This built in redundancy helps to assure 

that patients, doctors, and hospital staff will not notice the 

change from normal to emergency power. 

While Elmhurst is not as tall a building as Bellevue and has its 

emergency power equipment at three centralized locations, 

these locations are located at nearly opposite ends of the 

hospital. This configuration requires that cable between the 

generators and paralleling switchgear be run through the 

cable support system in the sub-basement. The conduit runs 

are layered many times over and noticeably reduce the height 

of portions of the sub-basement corridors. An electrician at 

this hospital told us that the supports for the conduit had to 

be replaced recently because the weight of the conduit caused 

the supports to buckle. This reduced the available space for 

new conduit and made it more challenging to run new feeders. 

PB worked closely with facility management and its electricians 

to make the most efficient use of the hospital’s remaining 

space for new feeders and equipment. 

 




Changes to Chiller, Boiler and HVAC Lower Energy 

Consumption at a University Campus 

By Damee Choi, New York, New York, 1-212-613-8835, choiD@pbworld.com 

New York State has a goal 

of cutting energy use 

in schools and other 

government facilities by fifteen 

percent by 2015. Our 

work at the State 

University of New York 

campus in Brockport illustrates 

how PB is helping 

the state meet this goal. 

Improvements to the boiler 

system and other energy 

saving measures resulted 

in a six percent reduction 

in energy consumption. 


AC: Air conditioning 

ECM: Energy conservation 

measures 

HVAC: Heating, ventilation, air 

conditioning 

LED: Light-emitting diode 

NYPA: New York Power 

Authority 

SUNY: State University of 

New York 

VAV: Variable air volume 

VFD: Variable frequency 

drive 


• http://www.brockport.edu/ 

• http://www1.eere.energy.gov/ 

femp/ 

• http://www.astm.org/ 

• http://www.nyserda.org/ 

programs/state.asp 

PB’s power specialists have been working with New York Power Authority (NYPA) for more 

than a decade to undertake energy conservation designs for college campuses, municipality 

buildings and state office buildings throughout New York State. At the State University of New 

York (SUNY) campus at Brockport, New York, we developed improved systems and plant that 

reduced energy consumption, enhanced the reliability of campus systems and increased the 

comfort and safety of building occupants. Some of the key features of this work included: 

• Introducing a distributed chilled water loop that linked individual chillers in various 

buildings to increase part-load efficiency 

• Linking boilers in individual buildings to improve their use and extend boiler life by 

reducing cycling. 

Getting Started 

The Brockport campus is comprised of 40 buildings, most of which are 30 to 50 years old. 

We assessed these buildings and their chiller, boiler, and heating, ventilation and cooling 

equipment for potential energy conservation measures. Our team conducted an extensive 

data collection on the campus equipment to perform cooling and heating load calculations. 

An economic analysis (life-cycle cost analysis) was performed using Building Life-Cycle Cost 

(BLCC) 5.2 software, which was developed by the National Institute of Standards and Technology 

under the Federal Energy Management Program (FEMP). The software methodology complies 

with American Society for Testing and Materials (ASTM) international standards related to 

building economics as well as FEMP guidelines for economic analysis of building projects. 

We developed a number of energy conservation measures (ECMs) that were subsequently 

ranked based on payback and client preference. The college approved seventeen of them, 

and PB provided the detailed design and construction management for the work. 

Distributed Chilled Water Loop 

A key energy savings was obtained on the chiller system providing air conditioning (AC) for 

the buildings. The campus had eight electricity-driven water-chillers located in individual buildings. 

Many of the chillers were either oversized or inadequate for the required duty. By their nature, 

constant speed chillers operate most efficiently when the cooling load is close to the chiller 

capacity. They become less efficient in part load use, which is the majority of the cooling season. 

We designed an underground chiller water loop running in concrete tunnels to connect the 

individual chillers into a distributed chilled water plant. This technique, normally adopted only 

in centralized plant systems, improved utilization of the installed capacity and increased the 

seasonal efficiency. Fewer chillers run during partial load conditions, so the lives of individual 

machines will be prolonged and efficiency increased. System redundancy improved also, and it 

was possible to install additional air handling units without the addition of new chillers. 

Installation of underground piping is always a challenge and this case proved to be no exception. 

Although we had the campus underground utility records, we asked the contractor to investigate 

pipe routing with ground penetration radar. We had to confirm that we would not encounter 

abandoned asbestos piping that was not shown on any drawings, gas distribution lines that 

were not active, or stone foundations of old houses along the way. 




Improving Kitchen Steam Boiler Operation 

The original boiler was sized to meet the kitchen load 

demand, but over time part of the steam kitchen equipment 

had been converted to direct gas or electric fired equipment, 

so the boiler had become oversized, resulting in extreme 

short cycling and a drop in efficiency. We installed a steamto-water 

heat exchanger up stream of a direct fired gas 

domestic hot water heater serving the kitchen. The system 

was arranged to meet the kitchen steam demand first and, 

if steam was available, to then feed the new heat exchanger. 

Cold water to the domestic hot water heater passes first 

through the new heat exchanger and is heated there by the 

excess steam. It then flows to the direct fired heater. If the 

available steam is adequate for domestic hot water production, 

then the heater does not fire. If the steam boiler capacity 

cannot meet the demand at this moment, then the heater 

fires and heats the water to the desired temperature. 

Wide Range of Additional Energy Conservation 

Measures 

The following energy conservation measures that we implemented 

can often be applied to other projects. 

Water Pump Control. In a number of buildings, we installed 

variable frequency drives (VFDs) on the water pumps and 

outside air fans to minimize the water pumping cost and 

outside air conditioning costs. For example, the Tuttle North 

building had five constant speed pumps that served the 

heating system. VFDs were installed at these pumps and 

the three-way heating coil control valves were converted to 

operate as two valves to support the variable flow operation. 

During the occupied hours, the pumps modulate flow to the 

coil, which reduces power consumption particularly at partial 

load conditions. When the building is unoccupied, the flow is 

maintained at 20 percent to avoid coil freezing. 

CO2 Sensors. The majority of buildings featured air handling 

units that operated with a fixed amount of fresh air intake 

that was independent of the building occupancy. This mode 

of operation, common for building design until several years 

ago, results in unneeded energy consumption. We introduced 

CO2 sensors (indoor air quality sensors) that reduce the 

fresh air intake, and consequently, the heating and/or cooling 

energy consumption, particularly when the building is only 

partly occupied. 

The CO2 sensors are located in the return air ducts of 56 air 

handling units. They have automatic controls to modulate 

their outside air dampers and exhaust dampers to suit building 

occupancy. The CO2 sensor readings fluctuate depending on 

building occupancy levels. The outside air is set to a minimum 

rate required for the building minimum exhaust. 

HVAC Upgrade. At the Metro Center, which has class rooms 

and lecture halls, the HVAC system was upgraded to include a 

new variable air volume (VAV) system with summer economizer. 

This replaced the old high pressure air handling units and 

window mounted direct expansion (DX) units. Fin tube radiation 

installed at the building perimeter improved occupant 

comfort and eliminated the need for costly reheating systems. 

The chiller was replaced with a new, high efficiency unit. 

We replaced the constant volume/reheat AC system at the 

faculty office building, which comprised seven old rooftop 

units. The new VAV system, which has superior efficiency 

and provides better air distribution/occupant comfort, will 

be controlled by the campus building management system. 

Heat Recovery. Because there are many heat generating 

HVAC systems on the campus and needs for the heat 

throughout the campus, we implemented a heat recovery 

system where it made economical sense. One example is 

the Tuttle North sports complex, where heat from the 

computer room A/C condenser was dissipated by a cooling 

tower. This heat will now be recovered to heat the Olympicsize 

swimming pool water. Other energy savings at the pool 

include a roll-over cover to conserve heat when the facility is 

not in use and VFDs for the water recirculation pumps. 

Vendor Misers. Lights on the large number of vending 

machines throughout the campus operated around the clock, 

as did the compressors for soda vending machines. We 

introduced vendor-misers, which are proximity sensors that 

activate the lights on vending machines when approached by 

a potential user. Shortly after a machine dispenses its product 

and the buyer walks away, the vendor-miser shuts the power, 

vastly reducing the energy consumption of the unit. 

Other Measures. Other measures that contributed to the 

energy savings and are worth mentioning include: 

• Replacement radiator steam traps and float and thermostat 

traps at steam risers in the steam supply mains in several 

buildings and the elimination of steam leaks 

• Air-air heat recovery units for building exhaust 

• A thermal ice-storage system for the sports complex 

• Water meters 

• Lighting motion sensors in several locations 

• Replacement of incandescent lights and T-12 compact 

fluorescent lights with low wattage compact fluorescent 

lights and T-8 or T-5 compact fluorescent lights with 

electronic ballasts 

• LED-type exit signs 

• Double-pane windows in the campus library and 

administrative complex 

• Improved roof insulation and weather stripping for 

exterior doors. 

 




Savings and Benefits 

NYPA’s Energy Services Program, established in 1990 to fund 

energy-efficiency improvements, finances energy conservation 

projects for schools and other government facilities in New York 

State so they have no up-front costs. The SUNY Brockport 

project benefited from NYPA assistance with capital costs 

and also grant assistance from New York State Energy 

Research and Development Authority (NYSERDA) for the 

energy-efficiency improvements. The ECMs implemented 

provided an estimated annual savings of 2,132,328 kWh 

($212,600 at the current rate of $0.0997/kWh) and 553,570 

therm ($566,900 at the current rate of $1.024/therm). 

Currently, the NYSERDA Enhanced Commercial/Industrial 

Performance Program (C/IPP) incentive amounts to $180,000 

based on the projects’ demand reduction of 650 kW and 

electricity consumption reduction of 1,175,000 kWh per year. 

Perhaps even more important is the significant energy savings 

to be realized by the measures our team introduced at 

SUNY’s Brockport campus—energy savings that will help 

New York State meet its conservation goals. 

 

Damee Choi is a senior mechanical engineer specializing in power systems and energy conservation design. She has been involved also in all phases of engineering design 

projects, from inception to construction. Damee has been with PB for more than eight years. 

Power Terminology: Units and Conversions 

Compiled by Cristian Ebau, Godalming, UK, 44 148 352 8932 ebauC@pbworld.com 

The following information 

is included to help readers 

who are not power specialists 

understand the units 

of measures and terminology 

used in some articles, 

particularly for expressing 

various forms of energy. 

Units 

A Ampere MPa Mega Pascal 

barg Bar gauge MVAr Mega Volt-Ampere reactive 

Btu British Thermal Unit MW Megawatt 

dyn Dyne MWe Megawatt electrical 

gn 

GWh 

Standard Gravity 

Gigawatt hour 

MWh 

N 

Megawatt hour 

Newton 

J Joule Nm 3 Normal cubic metre 

kp Kilopond psi Pound-force per square inch 

kV Kilovolts psig Pound-force per square inch gauge 

kVA Kilovolts-Ampere V Volt 

Mmscfd Million standard cubic feet per 

day (of gas) 

VAr 

W 

Volt-Ampere reactive 

Watt 

Btu. One Btu is approximately 1054-1060 joules, or 252-253 calories. 

Calorie. One calorie is the amount of heat (energy) required to raise the temperature of one gram of water by 1ºC 

(1 cal = 4.1868 J). 

Joule. One joule is the work done, or energy expended, by a force of one newton moving one metre along the direction 

of the force. In lay terms, one joule is the energy required to lift a small apple 1 m (3 feet) straight up (1 J=1 N·m=1 

Kg·m 2·s –2 = 0.23885 cal). 

Kilowatt. The kilowatt (kW) is typically used to state the power output of engines and power consumption of tools machines. 

An electric heater with one heating element might use 1 kW. A typical automobile engine produces mechanical energy at a 

rate of 25 kW while cruising. 

Megawatt. The megawatt (MW) is used mainly to state the transfer or consumption of energy of, for example, large electricity 

motors, lightening strikes, and engineering hardware. A large residential or retail building may consume several megawatts in 

electricity power and heating energy. 

Megawatt electrical (MWe) and Megawatt thermal (MWt). Megawatt electrical (MWe) is the term used by engineers to 

distinguish the electricity output of a thermal power station versus the larger thermal output, which is described by megawatt 

thermal (MWt). For example, a nuclear power plant uses a fission reactor to generate 2109 MWt (heat), which creates steam 

to drive a turbine, which generates 648 MWe. The difference is heat lost. 

Ton (refrigeration). One ton of refrigeration = 12,000 BTU/hour, or 3526 W. 

Watt-hour (Wh). Watts multiplied by a period of time equals energy. If a 100 W light bulb is turned on for one hour, then the 

amount of energy used is 100 Wh, or 0.1 kWh (1 Wh = 3600 J). 

 

Cristian Ebau joined PB in April 2006. He worked as a planning technician in the Power Networks department until October 2007, when he joined the Energy & Utility 

Consulting department. Christian is currently under training as a power systems engineer. 


GENERATION: 

Hydropower - New Technologies, New Considerations 

Does Hydro Have a Future? 

Hydropower has been around for centuries and hydro-electric power has been providing 

clean energy since electro-magnetic generators first became available. The U.S. Department 

of Energy (http://www1.eere.energy.gov) claims the first use of a hydro-electric supply in 

1880 for “Michigan’s Grand Rapids Electric Light and Power Company, generating electricity 

by dynamo belted to a water turbine at the Wolverine Chair Factory.” Wikipedia 

(http://en.wikipedia.org) claims, “The world’s first public electricity supply was provided in late 

1881, when the streets of the Surrey town of Godalming in the UK were lit with electric 

light.” Coincidentally, I write this introduction from PB’s Westbrook Mills office in Godalming, 

which some say was the site used for the original hydro station. 

So is hydropower an outdated technology with nothing new to offer? Is it too big, too costly 

and too ugly? Is it a threat to indigenous peoples, river life, the rain forests, the ozone layer, 

apple pie, motherhood and life as we know it? Does it have a future? 

The critics of hydropower and dams more generally have used most, though probably not all, 

of the arguments above in recent years. As colleagues’ articles clearly show, PB is finding novel 

solutions to old problems and, with its work on relicensing of existing stations and licensing of 

the new developments in the USA, is bringing a broad range of skills and professionalism to 

issues of safety, environmental impact, stakeholder interests and techno-economic viability. It 

is particularly heartening to note the work on the Massena Grass River Project, where a new 

dam and power house will replace a 200-year-old weir and restore a lake-side aspect to the 

town. That the Tapoco Project, first licensed in 1955, may now continue to operate until 

2045, is a significant achievement for PB’s team and a good indicator of the worth of 

hydropower as a long-term, cost-effective source of clean energy. 

The range of hydro work described by colleagues demonstrates that hydropower comes in 

many sizes and types, from mini-hydro applications to the massive and complex pumpedstorage 

schemes handled by our teams in Christchurch, New Zealand. Most definitely in 

the large and complex category is the study being handled by our hydro specialists in Boston 

for the Greenland aluminum smelter project, comprising three underground power houses, 

which together may require ten dams, three canals and seven tunnels. 

The articles that follow clearly show that hydro is not a “one-size-fits-all” technology, far less 

that it has “had its day.” PB is using an exceptional range of expertise to find modern solutions 

that address both the practical engineering problems posed by a project and the hearts and 

minds issues that are vital for project success. 

So does hydro have a future? With oil at $250 a barrel, the growing pressures to reduce 

global carbon emissions and an estimated 4000 to 6000 TWh/year worldwide of untapped 

energy from hydro, absolutely! 

John Wichall 

Engineering Manager, Godalming, UK 


Hydropower – New Technologies, New Considerations 


Pumped Storage Technology: Recent Developments, 

Future Applications 

By Ian McClymont, Christchurch, New Zealand, 64 3 963 1501, mcclymontI@pbworld.com; and Paul Reilly, 64 3 356 3048, reillyP@pbworld.com 

The authors introduce 

pumped storage technology, 

highlighting its benefits 

and the role it is likely to 

play in power generation in 

the future. They then tell 

how their team is helping 

to enhance the efficiency 

of pumped storage 

facilities and advance the 

design of these facilities. 

Pumped storage technology has been around since early last century and is generally used 

today for power systems that have either no conventional hydro plant or a high thermal-tohydro 

generation mix. Its primary purpose is to smooth the generation requirements of thermal 

plants, offering an alternative to relatively expensive gas turbine peak generation and lessening 

load fluctuations on coal-fired steam plants. 

PB’s core hydropower experts in Christchurch have attained significant experience in pumped 

storage projects over the last ten years, particularly from pre-feasibility to tender design. 

Recent assignments include work in South Africa, Philippines, Indonesia, Scotland and Australia. 

Scheme sizes have ranged from 300 MW to a recent 1332 MW scheme in South Africa. 

Pumped Storage Offers Technical, Environmental and Economic Benefits 

Pumped storage schemes typically comprise a high-level reservoir and a low-level reservoir 

linked by a waterway, and a powerhouse. The waterway can be penstocks on the surface, 

tunnels or a combination of both. The powerhouse comprises one or more reversible pumpturbines, 

each connected to a motor-generator. In pumping mode, the unit spins the runner 

(impeller) in one direction to pump water from the low to the high reservoir, consuming 

electricity during off-peak times, when it is relatively cheap. In generation mode, the unit acts 

as a turbine/generator, spinning in the opposite direction as water runs from the high-level to 

the low-level reservoir, supplying electricity at peak times of the daily load demand cycle. 

By its nature, pumped storage results in a net loss of energy. Typically approximately 70 to 

75 percent of the imported energy is returned to the grid (known as the cycle efficiency), with 

the rest lost due to friction, efficiency losses, and parasitic losses (energy used to operate the 

station lights, cooling, drainage pumps, etc.). Therefore, the price differential between peak and 

off-peak electricity pricing needs to be sufficient to cover the energy loss, operating cost, and 

asset capital recovery costs if the pumped storage station is to be adequately profitable. 

While the main benefit of pumped storage is smoothing of the grid, the stations offer other 

benefits, including: 

• Frequency regulation and reserve generation. 

• Load following to balance the mismatch of power supply and demand at the ‘shoulders’ of 

the daily power demand profile. 

• Voltage support to the transmission network. 

• Black start capability (the ability to start generating without external power from the grid). 

• Potential overall reduction in CO2 generation. Although the pumped storage station is a net 

generator of CO2 if supplied by fossil sourced energy, its inclusion in a grid potentially allows 

thermal plants to operate with a higher overall efficiency, resulting in a net reduction in CO2 

for the whole system. 

• Lower overall operating costs of the power grid. Even though pumped storage results in a 

net increase of system generation overall to serve the power demand of the pumped storage 

plant, it can result in an overall lower system fuel cost by: 

– Avoiding or reducing alternate gas turbine and diesel peak generation 

– Enabling other thermal generating plant to run with lower reserve generation allocation 

– Enabling steam plants to operate at a higher average efficiency 

– Reducing other sub-optimal operations, such as overnight hot standby and cold starting 

of steam sets. 



Key Differences From Conventional Hydropower 

Studies for pumped storage have similarities with conventional 

hydro; however, some important differences that must be 

considered, many of which can make pumped storage more 

desirable, include the following: 

• Hydrology is often of much less significance and is often 

related only to the initial filling of the reservoirs, make up 

of losses, riparian flow releases or flood considerations. 

• Market conditions play a significant role in pumped storage, 

with key issues being demand for power, price differential 

between peak and off-peak power, transmission restrictions, 

and possible forms of power purchase agreements. 

• An established spot market for reserve generation and 

other transmission ancillary service can enhance the 

commercial feasibility of the project. 

• There is possibly more freedom in site selection for 

pumped storage schemes; however, the ratio of horizontal 

distance to height between the reservoirs needs to be low 

to reduce losses and improve the cycle efficiency. 

Advancing Pumped Storage Design 

Our team has been involved in two recent pumped storage 

projects for which we made significant contributions and 

boosted our expertise in the process—a tender design in 

South Africa and a pre-feasibility design in Asia. 

Tender Design for South Africa Project. The South 

African project, called Ingula (previously Braamhoek), is a 

1332 MW underground scheme being developed by Eskom, 

South Africa’s main power utility. The station contains four 

single-stage reversible units located in a single underground 

cavern, with a second cavern containing the transformers. PB 

was subcontracted to a joint venture to undertake the tender 

design of the scheme, with our role being powerhouse 

mechanical and electrical designer, and we provided some 

above-ground electrical design. This assignment covered the 

main generating plant and most of the auxiliary plant. 

As part of the work, we undertook the following studies: 

• Comparative study of gas-insulated system (GIS) vs. 

oil-immersed transformers. The former posed environmental 

risks (SF6 gas is highly ozone depleting) but offered 

significant benefits, particularly for an underground powerhouse 

cavern, of no explosive or fire risk. The traditional 

oil-immersed type transformer was selected, however, on 

the basis of cost and manageable risk and because it was a 

known commodity, whereas the SF6 was new technology 

with limited proven application for the operating voltage. 

Measures were incorporated in the design to reduce the 

risk of fire and explosion, such as containment walls, smoke 

extraction, and protection devices. Our team developed a 

subjective valuation assessment matrix to quantify the merits 


and risks of the transformer options. Our knowledge on 

this particular GIS application—suitability, environmental 

impact and fit for purpose issues—increased immensely. 

• Pump turbine setting. The client wanted minimal cavitation 

risk on the pump-turbine runner (impeller). Cavitation is the 

phenomenon where vapour bubbles form in low-pressure 

regions. If these vapour bubbles collapse near the surface 

of the runner, they can cause pitting of the runner surface 

that, over time, causes a reduction in efficiency and is 

expensive to repair. The occurrence of cavitation is a 

function of the depth of the runner below the tailwater 

level, known as submergence. The greater the submergence, 

the less possibility of cavitation, however the trade off is 

increased civil construction costs. A conservative setting 

of the runner elevation with a 4-m (13-foot) margin, 

based on a simultaneous four-machine pump load uptake 

operation, was the criterion adopted to avoid the hydraulic 

condition that is conducive to cavitation. 

• Hydraulic transient analysis. Together with a third party 

we undertook waterway transient modelling (a computer 

study of surges and water hammer within the waterways). 

Our team developed the scenarios and start conditions 

for the model, advised on how to improve the runner 

characteristics, and reviewed the model outputs for sensibility. 

• Reservoir operation modelling. We developed a 

computer model of the scheme reservoirs to verify three 

primary requirements were met: 

– Energy storage provided for the 21,000 MWhr needed 

by the client 

– Full-load reserve generation was still available at the end 

of any given week 

– A 4-hour emergency reserve was always available, as 

were buffer storage for riparian stream releases and 

evaporation loss compensation during the dry season. 

A dynamic simulation software package using SimApp, developed 

by Buesser Engineering, was used to model the nonlinear 

reservoir volume, waterway head loss, pump-turbine flow, 

seasonal variations for evaporation loss replacement, riparian 

releases, and power characteristics; and to simulate their 

interactions with an hourly station operating mode profile 

over a weekly period. The simulation took the total waterto-wire 

energy conversion. We considered this to be a more 

appropriate method than a spreadsheet model to determine 

the imported and exported energy through out the weekly 

cycle. It was commercially important that the model was 

re-run through the development to check that the 

requirements were always met. 

• Removal of the turbine runner without removing the 

generator. We conducted a study to determine if the 

runner could be removed sideways from the turbine without 

removing the generator rotor to reduce the duration of 

turbine refurbishment. This required a wider-than-normal 



access way into the turbine pit, with an unsymmetrical load 

distribution. The integral design of the generator support 

bracket foundation with the turbine pit wall was complex 

and fraught with constructability issues to ensure that the 

machine alignment during a worst case operating scenario 

would not exceed generator design tolerances. The alternative 

of supporting the generator thrust bearing directly 

off the pump-turbine head cover would have negatively 

impacted on the access to the pump-turbine for routine 

maintenance and deemed no overall reduction in the total 

unit outage for major pump-turbine overhauls. A partial 

compromise was reached by ensuring there was enough 

height in the turbine pit to temporarily lift and suspend 

the headcover to work on the turbine. 

• Pump starting system. The client specified originally 

a dual static frequency converter system (SFC). These 

devices act like a variable speed drive to start the unit in 

pumping mode. In conducting a reliability cost benefit study 

for the forecasted pump duty, we verified that a single SFC 

system with 50 percent redundancy resulted in considerably 

lower plant and powerhouse construction costs. 

Pre-Feasibility Design for Asia Project. This project, 

which is for an independent power producer (IPP) and is 

confidential, is a 300 MW two-unit pumped storage scheme. 

We recently completed the pre-feasibility conceptual design 

stage, for which we developed two interesting solutions: 

• Ring dyke embankment. We located a suitable location 

for the lower reservoir, which fit in well with other desirable 

features at the selected location. There was no natural 

depression for the upper reservoir, however, particularly 

at a high enough elevation to offer an attractive economic 

solution. We investigated placing a ring dyke embankment 

on top of the hill to create the upper reservoir. This 

option gave a more attractive ratio of head to horizontal 

distance between reservoirs, a key survey requirement for 

identifying potentially economic reservoir locations. 

• Deep silo powerhouse. Instead of the conventional 

underground scheme, we proposed a deep silo powerhouse 

approximately 130 m (427 feet) deep (Figure 1). Silo 

powerhouses have been used on other projects, but we 

could not find any example of one as deep as this one. 

The silo powerhouse eliminates many of the tunnels 

required for an underground powerhouse such as those 

for vehicle access and ventilation, and hence was intuitively 

cheaper when considering the local topography.This concept 

was adopted for the purposes of costing the scheme in parallel 

with a market and economic study to verify in principle 

that there was a potential commercially viable project. 

Both of these solutions will be tested at the feasibility stage 

when geological drilling is performed to better understand 

the site conditions and an alternative underground scheme 

will be studied and priced to verify the better option. 


The Future of Pumped Storage 

The advances mentioned above and others in pumped storage 

technology, plus the fact that underground schemes are often 

desirable because they minimise visual impacts, will continue to 

make pumped storage an important part of power generation 

schemes in the future. For example, a scheme with the sea as 

the lower reservoir (i.e., pumping sea water) is in operation in 

Japan. This type of scheme may be suitable in other locations 

around the world. In addition, variable speed generators 

have been installed in some pumped storage plants to obtain 

the best turbine efficiency in generating and pumping modes. 

Traditional large pump storage will benefit from the renewed 

interest in nuclear power generation expansion, as such plants 

operate at a constant load and need to be complemented 

with other more dynamic and flexible generators to suit the 

varying power system load demand. Finally, pumped storage 

will play a key role also in “alternative” power generation 

schemes. For example: 

• Pumped storage has significant advantages in networks 

with a high proportion of wind power. 

• Disused deep open cast and underground mines could be 

adapted for pump storage. 

• There are benefits to be gained from combining tidal 

generation with pumped storage to optimise power 

delivery when the tidal pattern is out of phase with 

the power demand. 

 

Acknowledgements. The authors wish to thank Mr. F. Louwinger of Eskom Holdings 

Ltd for his consent to the publication of this article and for his useful comments. 

Ian McClymont is an electrical engineer with more than 30 years experience on 

hydro-electric power development and refurbishment projects. He has considerable 

experience with pre-feasibility and tender designs of pumped storage schemes. 

Paul Reilly, a mechanical engineer, heads the hydro group in Christchurch, which 

provides a range of services including new development design, refurbishment/ 

enhancement, owner’s engineer, and due diligence. He has worked for more than 

14 years on numerous international and New Zealand hydro projects. 

Figure 1: Conceptual design of a deep silo powerhouse. 




Planning for Mini Hydro in Distributed Generation 

By Tony Mulholland, Christchurch, New Zealand, 64 3 963 1514, mulhollandT@pbworld.com 

©PHOTOGRAPHER: TONY MULHOLLAND 

Mini hydro generation is on 

the rise around the world 

for two primary reasons— 

recover energy and meet 

growing demands for 

distributed generation. 

Tapping into his expertise in 

hydro scheme development, 

the author outlines some 

primary considerations for 

planning and developing a 

mini-hydro facility, which is 

defined broadly as 100 kW 

to 10 MW. 

Figure 1: A 3 MW mini hydro 

station connected to an existing 

dam outlet works. 

We in the Christchurch office have seen a renewed interest in small hydro by owners seeking 

to increase revenue by recovering potential or kinetic energy in waterways from existing and 

new plant (Figure 1). Typical applications include: 

• Energy recovery from water storage and water supply pipeline outlets 

• Replacement of inline pressure reducing valves (as found in industrial process plant and 

municipal water distribution pipework) 

• Environmental release turbines at water storage dams 

• Irrigation canal outlet structures and drop structures 

• Lock gates 

• Even old watermills. 

Small hydro is also key to distributed generation, which is seen as increasingly important in 

future power generation. Financial incentives are available in many countries to supply green 

energy, which can significantly increase the value of hydro energy sales. The author has 

experience of schemes in Australia and UK that achieve almost double the value for their 

energy when compared to energy from fossil fuels. 

When considering a mini hydro facility, a large range of options and engineering factors need 

to be taken into account. The following discussion is based on our extensive experience in 

hydro scheme development—starting in the pre feasibility stage and 

continuing through design, construction, operations and maintenance. 

Planning for Mini Hydro: Concept Design 

The usual approach to planning a mini hydro is to begin with a 

pre-feasibility study to: 

• Evaluate the energy resource that can be recovered (in MWh) 

• Find out critical information about the site, such as the head and 

flow durations, transmission connection point, and voltage. 

• Establish the number of generating units and unit capacity (kW or MW). 

Normally the first estimate of the number of units and capacity is obtained by selecting the 

arrangement that provides the maximum net present value (NPV). This is done by evaluating 

the financial value of the energy recovered and the corresponding capital costs for various sizes 

of generating plant. Depending on turbine type and site flow duration, a further complexity 

to this process is that more units may provide a better efficiency over the flow range. 

From information gained in the pre-feasibility study, a preferred concept design can be prepared. 

This design will later form the basis for the specifications/detail design for tendering. 

In the distributed generation case, the mini hydro will generally be connected to a local power 

network. A connection usually requires permission from the network owner, who will be 

particularly interested in the type and size of generator being selected, and will have a list of 

requirements for connection, such as protection requirements. Early in the study the engineer 

should clarify with the network owner that the generator can be connected to the network 

and discuss what, if any, modifications are required of the existing transmission network. Sites 

that are remote from an existing network may make the scheme not viable because of the 

level of investment required in transmission infrastructure. 

Developers and owners generally prefer induction generators for mini hydro because they 

are cheaper and simpler than synchronous generators. Induction generations do have a 

 



disadvantage, however, particularly in larger sizes, where 

they can cause large variations in voltage and power factor 

on the local network. For this reason, the network owner may 

have rules about the maximum size of induction generators 

allowed to connect, and require power factor correction. 

Technical and Economic Feasibility 

Once a concept design has been completed and the 

transmission aspect investigated, the engineer can confirm 

whether the scheme is technically feasible. Next should 

follow the consideration of economic feasibility. We strongly 

recommend that an engineer prepares the first cut of this 

analysis given that engineering knowledge is important to the 

application of the costs in the analysis. In addition, the analysis 

process provides important feedback to the engineer on 

the design, and may force a rethinking of some aspects of 

the project. 

PB has recently undertaken a scoping study for Tillegra Dam 

in New South Wales, Australia, to determine what options 

are available to recover energy from the environmental flow 

discharge. This study has shown that the environmental flow 

can be accommodated by a small hydro turbine for minimal 

project cost (comparatively speaking); however, a larger turbine 

may also be justified to recover energy from some of the 

water that would otherwise be spilled past the dam in periods 

of high lake inflows. 

Specifications and Conditions of Contract 

Specifications should be written by someone who is well 

experienced in hydro and understands what information is 

required by the tenderers. There is much to be considered 

in the detail that is beyond the scope of this article; however, 

a few key decisions should be made before beginning. 

Q and A 

Question: 

Would a smaller unit be 

sourced as a package? 

John Wichall, Senior Consultant, 

PB Network Guest Technical Reviewer 

Answer: 

This is often the case, although 

for a recent 250kW unit 

the utility preferred a 

particular supplier and could 

buy the generator 

(a Siemens product) 

for significantly less money 

than the supplier’s 

chosen brand. 

The first choice is to decide 

how the equipment will be 

supplied. This includes 

decisions on whether: 

• The turbine and generator 

will be separate packages 

and matched together 

at site 

• The control and auxiliary 

systems will be included 

with turbine or generator 

or be a completely 

separate package 

• The contract will be an 

equipment supply, or 

supply and install, or supply 

and supervision type. 


Conditions of contract cause many an engineer to run for cover. 

For the value of the contracts considered here, standardised 

conditions such as those within the International Federation 

of Consulting Engineers (FIDIC) or the joint IMechE/IEE 

Committee Model Forms of General Conditions of Contract 

(e.g., MF1 or MF2) should be used. It is strongly recommended 

that no modifications be made to the standard conditions, 

and that any particular issues be covered only in the special 

conditions. The special conditions should cover penalties for 

non-performance and must be reasonable, otherwise they will 

adversely impact the tendered prices. 

Overall the commercial conditions should not substantially 

outweigh the technical specifications. A lightweight specification 

will not be fixed by heavy-handed commercial clauses and 

general ignorance of the requirements for a successful mini hydro. 

In the last year, we completed the technical specification for 

the turbine and generator for the Gippsland Water Factory 

in Victoria, Australia. 1 The turbine will replace a pressure 

reducing valve that is currently used to dissipate the energy 

in the raw water supply before returning it to a reservoir. 

This project is an example of how existing infrastructure can 

be modified at relatively low cost to capture the otherwise 

wasted energy and convert it to electricity. Some of the 

generated energy is then used at the nearby water factory. 

When completed, this project will provide a sustainable energy 

source that will reduce energy costs at the facility and, in the 

long run, will benefit the community. 

Tenders and Tender Evaluation 

Tenderers must be given sufficient time to write their 

tenders. This should be a minimum of one month for small 

jobs, and up to several months for more complex jobs, 

such as those requiring civil works or the supply and install 

of the entire scheme. 

We believe economising on the turbine/generator set is unwise. 

As with most electromechanical equipment, increased quality 

and efficiency is matched by increased price. There are some 

very good manufacturers who maintain the latest in computational 

fluid dynamics (CFD) programs and hydraulic test 

programs. In general, their equipment will be more efficient 

then that produced by manufacturers with less sophisticated 

design and equipment. Economic analysis of the capital and 

life time operating costs, as mentioned earlier, is essential to 

discern whether additional revenue from higher efficiency 

and reliability is compensated by the higher capital cost. 

Readers are warned to beware of suppliers claiming efficiency 

in the top of the range that large turbines typically 

(page 37) 

1 To learn more about the Gippsland Water Factory, see "Water Factory Will Help 

to Address Water Shortage Concerns" by Tony Mulholland, pp.94-95. 




Developing, Engineering and Licensing a New 

Hydropower Dam 

By Matthew D. Chan, Boston, Massachusetts, 1-617-960-5009, chanM@pbworld.com; and Stefan Schadinger, 1-617-960-4976, 

schadinger@pbworld.com. 

A number of challenges 

faced PB’s team when 

developing a new hydropower 

dam in the eastern 

USA. These included 

managing a new FERC 

licensing process, providing 

ice control in the river, and 

addressing several aquatic 

life environmental concerns. 

Acronyms 

FERC: Federal Energy 

Regulatory 

Commission 

HEC-RAS: Hydrologic 

Engineering 

Center — River 

Analysis System 

ILP: Integrated 

Licensing Process 

MED: Massena Electric 

Department 

NYS DEC: New York State 

Department of 

Environmental 

Conservation 

The Town of Massena Electric Department (MED) has proposed to construct the Massena 

Grasse River Multipurpose Hydroelectric Project (Project), which will provide hydropower, a 

reservoir (creating town waterfront), ice management, and other benefits. Located in upper 

New York State, this will be one of the first new hydropower dam projects in the eastern USA 

to use the Federal Energy Regulatory Commission’s (FERC’s) new Integrated Licensing Process 

(ILP) at an undeveloped site. 1 PB was retained by MED to develop, license, and engineer the dam. 

The Grasse River 

The Grasse River is a moderate-sized river with a medium gradient. It is characterized as a 

cool/warm water river with an estimated average flow of 31.1 m 3 /s (1,100 cubic feet per second, 

or ft 3 /s) and median flow of 19.5 m 3 /s (690 ft 3 /s). The drainage area as measured at the 

proposed dam incorporates 93 percent of the basin (Figure 1). 

The Grasse River is dammed 72.4 km (45 miles) upstream of the proposed project by a small 

run-of-river operation, and it had been dammed in the village of Massena by a low-head weir 

for nearly two centuries until a breach during the spring of 1997 (Figure 2). This breaching 

caused loss of aesthetic value and loss of the waterfront amenities that three local communities 

enjoyed. Generally, the Grasse River is unaltered in its physical form except downstream of 

the proposed dam, where an old power canal joins the river and distinguishes the beginning 

of the lower river, which has been dredged. 

Scope of Work 

The project will consist of a new concrete gravity dam with an integral powerhouse (Figure 3). 

The powerhouse will include a single turbine generator and is expected to produce an average 

annual energy of 10,000 MWh. The surface area of the impoundment will be approximately 

120 ha (300 acres) and 13 km (8 miles) long and, except for the 

Figure 3: Aerial view of the Town of Massena and the proposed dam location 

on the Grasse River. 

Figure 1: The Grasse River Watershed. 

Figure 2: Remnants of the low-head concrete dam. The new 

hydropower dam is proposed downstream of the old dam. 

1 The integrated license process is one of three licensing alternatives offered by FERC, the others being 

the alternative and traditional licensing processes (ALP and TLP). ALP is discussed in a following 

article, “Successful Relicensing of a Federally Regulated Hydropower Project” by Kareem Bynoe et al. 



addition of the lower 1.3 km (0.8 miles) of new impoundment, 

would restore the previous reservoir footprint. The project 

would operate in an instantaneous run-of-river mode where 

discharge equals inflow; i.e., without provision for water 

storage or regulation of downstream flow. It would also 

provide ice control measures to prevent the formation of 

ice “dams” downstream, which could result in bottom 

scouring and re-suspension of contaminated sediment. 

PB’s overall scope covers: 

• Project management, including planning, budgets, 

scheduling and project control systems 

• Licensing, including coordinating the FERC ILP, managing 

environmental studies, applying for the U.S. Army Corp 

of Engineers Clean Water Act Section 404 Permit and 

the New York State Department of Environmental 

Conservation (NYS DEC) Clean Water Act Section 401 

Water Quality Certification Permit and, finally, applying 

for the FERC license 

• Engineering, including feasibility studies for structural, geotechnical, 

hydrology and hydraulics, and electrical analyses 

• Specialty tasks/interests, including fish passage, 

HEC-RAS modeling of river hydraulics, stability analyses, 

and ice management. 

Regulatory Challenge: FERC ILP 

FERC initiated the ILP in 2003 and it became the default 

process in July 2005. The first license issued under ILP was 

granted in December 2007. The ILP attempts to streamline 

the licensing process by providing a predictable, efficient, and 

timely process while maintaining adequate resource protections. 

Its three fundamental principles are to: 

• Identify issues and resolve study needs early in the process 

to fill information gaps and thereby avoid studies after 

license filing 

• Integrate other stakeholder (non-federal agencies) permit 

process needs into the FERC process 

• Set a time frame to complete all steps of the ILP for all 

stakeholders, including FERC. 

To date, we have managed the project successfully through 

the following ILP steps: 

• Preliminary permit application (PPA). This permit is 

used to reserve the right to develop a site while owners/ 

developers investigate the potential for dam construction. 

It is limited to three years and developers must demonstrate 

to FERC that sufficient development progress is ongoing or 

the permit may be revoked. 

• Multiple six-month preliminary progress reports. 

These reports to FERC demonstrate that a developer 

is making progress towards filing a license application. 

• Notice of Intent (NOI). This indicates than an existing dam 


owner intends to re-apply for a license or a developer 

intends to apply for a new license. 

• Preliminary application document (PAD). Prepared 

by the owner or developer, the PAD brings together all 

existing, relevant, and reasonable information about the 

existing dam or proposed dam site. It identifies information 

gaps and proposes studies needed to address them, and it 

includes a finalized licensing process plan and schedule. 

• Scoping process. FERC conducts site visits to the existing 

dam or proposed project site, holds public meetings, and 

discusses the project with stakeholders to refine the issues. 

Stakeholders make study requests and then FERC issues a 

scoping document outlining issues related to the project. 

• Study planning. The project owner or developer submits 

a draft study plan to address issues identified during the 

scoping process. Stakeholders comment on the draft 

study plan, and the owner/developer submits a revised, 

final study plan. FERC then determines if the final study 

plan is adequate or requires changes. Certain stakeholders, 

i.e., agencies, have a right to dispute the FERC determined 

study plan, which starts a trial-like process for determining 

if the studies are needed. 

• Study types. The types of studies that are typically 

required for the ILP include fish passage, instream habitat 

assessments, rare, threatened, or endangered species, 

macroinvertebrate insects, recreational and cultural resources, 

wetlands and aquatic vegetation, and birds. Studies may 

require collection of surveys or field data or, when possible, 

may use existing information compiled into a report. 

Challenges during the ILP process to date have included: 

• A lack of understanding of the ILP by stakeholders. 

• The fast pace and demanding schedule of the ILP on all 

stakeholders. 

• Difficulty stakeholders seemed to have transferring the 

ILP to decisions on a new dam. Prior to this project, 

the ILP has been primarily used for relicensing existing 

hydropower projects. 

• A study dispute panel process, which was initiated by a 

stakeholder. 

The new FERC dispute panel process is a trial-type proceeding 

used within the ILP to resolve study disputes. In this case, NYS 

DEC disputed several FERC-approved study plans. Our team 

worked directly with NYS DEC officials to resolve several 

issues deemed “disputes of methods” within proposed study 

plans that all parties (FERC, MED and NYS DEC) accepted in 

general (as opposed to “disputes of plans,” whereby parties 

disagree on the need to conduct a study). For example, 

while everyone agreed a study of lake sturgeon movements 

was needed, the NYS DEC wanted three continuous radio- 



receiver monitors and only two had been proposed. We 

agreed to install a third monitor and worked with NYS DEC 

to identify the site for the monitor and NYS DEC withdrew 

its dispute. In this way, our team resolved many disputes of 

methods prior to the panel convening, leaving only a few 

issues that required a FERC ruling. At the conclusion of the 

dispute panel process, FERC determined that the NYS DEC 

disputed studies were not required. This ruling was consistent 

with PB’s assessment and in favor of MED, saving the client 

substantial resources. 

Engineering Challenge: Ice Control 

The Town of Massena and Village of Massena waterfront 

properties are exposed seasonally to the effects of high flows 

in ice cover conditions and ice pack flowage events, both of 

which affect areas proposed for re-development in local 

community revitalization plans. Further, ice dam formation 

(also referred to as ice jams) in the lower river has been 

identified as a mechanism by which contaminated river 

sediments can be re-suspended. 

Options to address the impacts of ice jam related sediment 

scour are being considered as part of the evaluation of longterm 

remedial options. One possible solution is the MED 

project itself, into which we have integrated ice control into 

the engineering design as an option. Higher springtime flows 

will pass through deep-set, bottom-opening flood release 

gates instead of passing high flows over a spillway, a typical 

feature of many dams. Using bottom-opening gates will 

retain ice behind the dam. 

A careful analysis of upstream effects associated with retaining 

the ice behind the dam, including computer modeling, is being 

performed and is under evaluation by independent, leading 

international ice-experts and the U.S. Army Corp of Engineers 

Cold Regions Research and Engineering Laboratory (Hanover, 

New Hampshire). PB is working with this team to ensure that 

any upstream impacts are accounted for in both the design 

and operations of the project. Draft study results indicate 

that ice retention at the dam could effectively eliminate 

conditions under which ice jams form in the lower river. 

Environmental Challenges 


The successful development of this project will depend on 

regulatory acceptance of engineering and dam operation 

plans to address key natural resource impacts. Issues beyond 

fish passage mitigation include habitat and population 

impacts, and potential impacts to: 

• New York State-threatened fish (lake sturgeon and eastern 

sand darter) 

• Fishes of concern (chinook salmon, walleye, muskellunge, 

American eel, Atlantic salmon) 

• Freshwater mussels of concern (pocketbook, elktoe, 

yellow lampmussel, and black sandshell) 

• Water quality (dissolved oxygen, temperature) 

• Macroinvertebrate communities 

• Fisheries communities 

• Wetlands 

• Submerged aquatic vegetation. 

PB is overseeing field studies of these issues as part of the ILP. 

Project Status 

In 2008 the project will enter the first official field season 

of the FERC ILP pre-filing steps. Sometimes two years are 

required for field studies, but the MED team pursued a 

strategy of pre-license field work in 2006 and 2007 to 

reduce the overall project schedule. We anticipate FERC 

accepting some of that work in lieu of required FERC 

approved studies in 2008. 

When field work has been completed and accepted by the 

FERC, we will prepare a Preliminary License Proposal (PLP), 

followed later by a License Application. The analysis of the 

river hydraulics will be complete and the conceptual 

engineering designs will be 30 to 40 percent complete at 

the filing of the PLP. Filing of the PLP will depend on the 

FERC ruling that all studies have been completed to its 

satisfaction. 


• www.ferc.gov 

• www.med.massena.ny.us 

• http://www.ferc.gov/industries/hydropower/gen-info/licensing/ilp/ flowchart.pdf 

Matthew Chan joined PB in January 2008 as a supervisory environmental scientist after six years of consulting on hydropower projects with a nationally recognized 

environmental consulting firm. Matt holds a doctorate degree in Fisheries Science, and has 16 years’ experience of specialized knowledge of river ecology, habitat, and 

flow regimes. 

Stefan Schadinger is a lead engineer with PB’s Boston Hydropower Group. He has 13 years’ experience in hydropower engineering, eight of them with PB. Stefan’s 

expertise is structural engineering and he has much practical experience on dams, dam gates and power plant components. 




Developing Hydropower Resources in Greenland 

By Jesse Kropelnicki, Boston, Massachusetts, 1-617-960-4975, kropelnicki@pbworld.com; Gillian Tucker, Boston, Massachusetts, 

1-617-960-4993, tuckerG@pbworld.com; and Paul Shiers, Boston, Massachusetts, 1-617-960-4990, shiers@pbworld.com 

The authors tell about their 

work in determining the 

feasibility of a hydropower 

facility that will use glacial 

runoff as its water source. 

This work included calculating 

the power potential and 

costs and performing a risk 

assessment. 

In May 2007, the Greenland Homerule Government signed a Memorandum of Understanding 

with Alcoa Inc. for the evaluation and potential implementation of an aluminum reduction 

(smelter) plant in western Greenland, near either Nuuk, Maniitsoq or Sisimiut. Alcoa chose 

PB to act as owner’s engineer for the feasibility stage of the development of hydropower 

resources and transmission facilities needed to provide low-cost electricity to the plant. We 

expect that two to three hydropower developments will be needed. 

About Greenland 

Greenland, also known as Kalaallit Nunaat (meaning “Land of the Greenlanders” in Kalaallisut, 

an Eskimo-Aleut language), is a self-governing Danish province, and it is the world’s largest 

island. It has an area of 2,166,086 km 2 (836,109 square miles), 81 percent of which is covered 

by the Greenland ice sheet. All of its towns and settlements are located along the ice-free 

coast, with approximately half of the 57,000 inhabitants settled along the west coast in Sisimiut 

and Maniitsoq in the north and Nuuk and Paamiut in the south. 

The principal income in Greenland derives from the shrimp fishery, although publicly owned 

enterprises and the municipalities also play a dominant role in the economy. Tourism has 

the potential to create economic growth, but it is constrained by Greenland’s short warm 

season and high travel costs. 

Project Overview 

The project will use glacial runoff as its water source for two to three major hydro sites. With 

there being one peak period each year during which the reservoir fills up—late spring and 

summer—a very large reservoir volume is required to capture and maintain the water needed 

to generate power for the smelter year round. The project will also require: 

• Nine to ten dams 

• Two to three canals 

• Six to seven tunnels 

• An underground power plant for each hydro site. 

Figure 1: The conceptually 

similar Kárahnjúkar Dam in Iceland 

during its construction. 

Combined, these sites would have an installed capacity of 600 to 750 MW. The largest dam 

would be 40 m (130 feet) high, and the estimated total length of tunnels will range from 60 

to 85 km (37 to 50 miles). The length of transmission line required may be as high as 700 km 

(435 miles). Civil infrastructure, including harbors, camps, roads and heliports will also be 

developed to support construction of the project. The project cost is currently estimated at 

$1.5 billion US. 

The Greenland hydro project will be similar conceptually to the 

Kárahnjúkar Hydroelectric Project (Figure 1) in Iceland (owned by 

Landsvirkjun), which uses glacial runoff to generate nearly 4,600 

GWh/year (based on installed capacity of 690 MW) for Alcoa’s 

Fjarðaál Fjarõaál aluminum smelter in the port of Reyðarfjörður. Reyõarfjörõur. This project 

was completed recently and is is discussed in in National Geographic 

magazine (March 2008) and currently on the magazine’s Web site 

(see Related Web Sites). 

In 2007, we completed various field studies with the assistance of 

outside consultants and several technical analyses, including: 



• Geotechnical and hydrologic investigations 

• Field measurements of flow and sediment 

• Transmission line conceptual design and cost 

• Office studies of scope and cost of each of the site 

developments 

• Aerial survey and topographic mapping. 

The field studies were a challenge to carry out due to the 

very short viable weather season and limited in-country 

resources. We met these challenges through careful logistics 

planning and by using the help of technical specialists from 

Iceland and Greenland, with those from Iceland having had 

recent similar experience with the Kárahnjúkar Hydroelectric 

Project. We also had PB staff in Greenland for various parts 

of the study period to help with the coordination of activities 

and carry out the geological studies. 

Based on the findings from the field studies, we then: 

• Carried out conceptual engineering for the dams, tunnels, 

canals, roads and transmission lines 

• Calculated the power potential for each site under 

consideration, and did an economic analysis of power costs 

• Assessed project risks. 

Power Potential and Costs. As part of this effort, we did 

extensive work on maximizing the power potential available 

from increased inflows to reduce overall project and power 

costs. This optimization was a particular challenge, but it was 

required to help create an efficient construction cost of 

power for Alcoa. This effort involved a review of the geologic 

conditions on site, hydraulic inflow data, and aerial survey 

data. With this information we were then able to configure 

the project structures in a way that created the maximum 

power possible given the inflow conditions and terrain. The 

evaluation also dealt with projected long-term increases in 

average annual inflow, where hydro development to date 

looked at historical flow records over a long period of time 

and evaluated wet and dry years during this period, as well 

as long-term average flow, and assumed these trends would 

continue in the future. 

Risk Assessment. As part of this effort, we assessed the 

project upsides and identified potential fatal flaws. This study 

included a preliminary evaluation of natural hazards, such as 

seismic impact on the project structures, drift ice and avalanche 

hazard on transmission lines, reliability and redundancy of the 

transmission lines, and geotechnical evaluation of the project 


civil structure foundation areas. These studies were carried 

out by use of the aerial survey photos and on-site geologic 

field survey of the expected civil works areas. Our results, 

together with input from various consultants, gave us an initial 

view of the project natural hazard potential. For example, 

analysis of drift ice and avalanche hazard will directly influence 

the final selection of routes for transmission lines. In turn, 

the available, reliable transmission line routes influenced the 

potential sites for optimal dam locations and the smelter 

facility, as well as project costs. 

Conclusion 

On February 21, 2008, the Greenland Development, LLC, 

identified Maniitsoq (Figure 2) as the favored location for the 

smelter. To reach this decision, Greenland, in coordination 

with Alcoa and PB, considered many project aspects such 

as construction costs, nature and environmental issues, and 

regional development. 

Figure 2: Maniitsoq, the town selected as the preferred site. 

At the time of writing, we are planning for the 2008 field 

studies required for the project. These studies will provide 

information that will enable us to further develop the 

cost/schedule estimates and advance the project design. If 

the project continues forward, construction is expected to 

start in 2010 and be completed in five years with aluminum 

production commencing at the end of 2014. This project is 

expected to help Alcoa meet its global business objectives 

while dramatically boosting the economy of Greenland and 

enhancing the country’s profile in the rest of the world. 

 


• http://www.aluminium.gl/content/us 

• http://ngm.nationalgeographic.com/2008/03/iceland/del-giudice-text 

Jesse Kropelnicki is the lead engineer for the Greenland project. He is a structural engineer with almost ten years’ experience in hydropower, water resources and thermal 

power projects. Jesse’s expertise includes detailed structural analysis and coordination of technical efforts. 

Gillian Tucker is a civil engineer whose experience includes various aspects of hydroelectric dams and facilities. Her specific hydroelectric experience includes the preparation 

of Part 12 safety inspection reports, supporting technical information documents (STIDs) and potential failure mode analysis (PFMA) reports in accordance with FERC. 

Paul Shiers is a PB vice president with 38 years’ experience in hydroelectric power and water resource engineering. He is qualified as an independent consultant and PFMA 

facilitator for FERC Part 12 safety inspections under the new FERC DSPMP requirements. Paul has served as project manager for multiple hydropower projects, and completed 

an assignment as principal engineer for work performed under a multi-year continuing services agreement with FERC as the senior technical resource for hydro relicensing 

and compliance tasks. 




Successful Relicensing of a Federally Regulated 

Hydropower Project 

By Kareem Bynoe, Boston, Massachusetts, 1-617-960-4977, bynoe@pbworld.com; Paul Shiers, 1-617-960-4990, shiers@pbworld.com; 

Shirley Williamson, 1-617-960-4995, williamsonSh@pbworld.com; and Tony Plizga, 1-617-960-4972, plizga@pbworld.com 

In this article the authors 

tell how they helped to 

manage the complex 

relicensing process of the 

Tapoco Project, a 380 MW 

hydropower facility in North 

Carolina and Tennessee. 

Their focus is on meeting 

statutory requirements that 

did not exist at the time the 

first license was issued, 

particularly those regarding 

stakeholders’ concerns about 

natural resources and the 

need to reach consensus 

among all parties involved. 

This article is the first of 

three about Tapoco. The 

next one is about water 

allocation modeling for the 

relicensing and the third is 

about dam safety. 

Acronyms 

ALP: Alternative Licensing 

Process 

FERC: Federal Energy 

Regulatory Commission 

1 You can read about the Integrated 

Licensing Process in a preceding 

article, “Developing, Engineering, and 

Licensing a New Hydropower Dam” by 

Matthew Chan and Stefan Schadinger. 

Also, see Related Web Sites for links to 

more information about FERC’s three 

licensing procedures. 

The Federal Energy Regulatory Commission (FERC) regulates non-federal hydropower projects 

on waterways within the USA by issuing operating licenses and then monitoring their compliance. 

Many licenses, which extend for 30 to 50 years, were issued in the 1950s and 1960s, so a 

large number of hydro projects are currently undergoing relicensing. 

The multistage relicensing process can take as long as a decade to complete. It is expensive 

and difficult to manage, and “unsuccessful” outcomes can result from either schedule or cost 

overruns during relicensing, or from settlement agreements that sacrifice too much project 

value during stakeholder negotiations. 

New Licensing Requirements 

Public expectations for hydropower projects and their effects on the environment have 

changed during the last 30 to 50 years. Consequently, FERC now has statutory requirements 

to give equal consideration to: 

• Developmental values, including energy generation, irrigation, flood control and water supply 

• Non-developmental values, such as fish and wildlife resources, visual resources, cultural 

resources, recreational opportunities and other aspects of environmental quality. 

With these new requirements comes a more significant role for public input in the relicensing 

process. A large number of participants can be involved now, including federal and state 

agencies, local governments, non-governmental organizations and other interested parties. 

Further, FERC’s current license conditions can place new requirements on project owners 

that have long term-cost implications. These are in addition to the cost of the relicensing 

process itself. It is critical, therefore, that owners build broad-based stakeholder support for 

the new license terms in order to: 

• Relicense a project with reasonable license terms 

• Complete the relicense procedure on schedule and within budget 

• Avoid the prescription of costly license conditions by FERC. 

The Tapoco Project 

In March 1955, FERC issued a 50-year license to the Tapoco Division of Alcoa Power Generating 

Inc. for the Tapoco Project, which includes four hydroelectric dams in North Carolina and 

Tennessee and has an installed capacity of 380 MW. Environmental features abutting the 

project include the Great Smoky Mountains National Park, the Cherokee National Forest, 

and the Nantahala National Forest. The project’s license extended through February 2005. 

Tapoco hired PB in 2000 to serve as owner’s engineer responsible for providing regulatory, 

environmental science, engineering and economic consulting services. We teamed with Long 

View Associates, a regulatory, environmental consultant. Of FERC’s three licensing processes— 

alternative, traditional and integrated—our team recommended and Tapoco accepted the 

alternative licensing process (ALP) because it lends itself to settlement agreements. 1 Under 

the ALP, the project owner, stakeholders, and agencies are encouraged to develop study plans 

and license applications in a collaborative fashion. The ultimate goal is to increase efficiency 

and avoid the later-stage disputes that can be common in the other license processes. 

Managing Large Amounts of New Information 

The major technical challenge in relicensing has two parts: 

• Quantify the effects of new license conditions on the developmental and non-developmental 



costs and benefits (again, with developmental meaning 

the hydro project’s future energy generation capacity 

and revenues, and non-developmental meaning the 

environmental and social resources) 

• Make these costs and benefits understandable and credible 

to a stakeholder group comprised of technical agency staff 

and laypersons. 

Two critical aspects of this challenge presented challenges of 

their own, which were to: 

• Manage the evolving body of knowledge about the project 

that develops during relicensing 

• Understand the interrelated effects of new information on 

the environmental resource requirements and the economic 

viability of the project. 

New information generated during the relicensing process 

includes studies required to address information gaps on 

environmental issues. This new information then generates a 

new understanding of project impacts on the environment 

for all stakeholders and on the economics of the project, 

which change because of the costs associated with steps 

needed to protect those resources. The results of these 

studies also drive the costs of relicensing and of implementing 

the license conditions that, depending on the results, may 

require mid-process corrections in engineering design, proposed 

operations or relicensing strategy. We continually scrutinized 

these new studies to ensure that they did, in fact, address the 

information gaps and that the new information could be fed 

back into the relicensing process to help stakeholders assess 

potential impacts and then make informed decisions. 

Ensuring Stakeholder, Owner and Agency 

Collaboration 

The ALP requires that study plans and license applications be 

developed in a collaborative fashion. Collaboration can be 

time-consuming and labor-intensive, however, and consensus 

can be difficult to reach. Some of the challenges we faced 

and the steps we took to meet them are as follows. 

Consultation. We made continuous efforts to identify, involve, 

and communicate with resource agencies, municipalities, 

tribes, non-government organizations, and the interested 

public. At the outset of the process we established: 

• A formal stakeholder communications protocol, which was 

an agreement with the stakeholders on how the group would 

interact over the multiyear process, including topics such as 

a standard of courtesy, what behavior constituted the basis 

for participation, and how the group defined consensus. 

• Technical workgroups by resource area, which were subgroups 

of stakeholders who were recognized by the larger 

group as technical specialists in each area and were 

authorized to review and recommend acceptance of the 

technical study scopes and results to the larger group. 


• A master stakeholder meeting schedule, which included 

full stakeholder meetings and smaller technical workgroup 

meetings to help ensure that key stakeholders were available. 

Natural Resource Concerns. It was important that we 

consider the broadly stated public “concerns” about natural 

resources, but in doing so that we identify those that were 

relevant in conjunction with stakeholders who focused on 

the core issue. The critical steps we took here were to: 

• Sort out those concerns that had project relevance from 

those that did not 

• Translate the relevant concerns into study goals 

• Develop study plans to meet the goals 

• Define the appropriate metrics by which project effects 

would be measured 

• Define a scale describing the magnitude of the environmental 

or social effects (e.g., very adverse, adverse, neutral, beneficial, 

very beneficial). 

Open Study Approach. We conducted studies in an open 

and cooperative manner with key public agencies and their 

technical experts to ensure that we provided highly credible 

resource information in a way that was cost-effective. We 

met this goal over time by using the following techniques: 

• Meeting with the stakeholders early and often to establish 

a professional rapport, and then maintaining it by keeping the 

key people involved over the multi-year life of the process 

• Addressing all stakeholders’ questions and taking every 

opportunity to inform them of new information 

• Enlisting regionally experienced specialty subconsultants to 

perform the environmental and social resource studies 

• Using the same study protocols and methodologies that 

the stakeholders would have used where possible 

• Inviting stakeholders into the field to observe the studies. 

Stakeholder Expectations. It was important that the 

stakeholders recognized that not all resource values and uses 

could be optimized simultaneously, and that they acknowledged 

resource constraints and balance trade-offs among various 

project aspects and among other stakeholders. The best 

example of this was our use of OASIS, a water allocation 

model, to illustrate during meetings how the lake recreational 

users’ desires to keep the lakes at full-pond level all year long 

was in direct conflict with the fisheries biologists, who wanted 

increased flows released downstream of the project to 

support aquatic life. 

Operating Policy. Most natural resource protection, mitigation, 

and enhancement measures reduce the owner’s flexibility to 

generate electricity when power, and its value, are at a premium. 

Our challenge was to craft an operating policy that addressed 

the stakeholders’ interests without causing excessive revenue 

loss. To accomplish this goal, we used OASIS to develop a 



water allocation model to simulate the protection, mitigation 

and enhancement measures and quantify their effects on 

both future power generation and revenues, and on reservoir 

levels and downstream flows. 2 

Over a three-year period we met with the stakeholder group 

each month and presented the model as it was developed, 

calibrated and verified. Once the model was ready to simulate 

operating alternatives, the stakeholders were allowed to define 

alternative operating policies that they wanted to simulate. 

PB conducted the simulations and presented the results, 

illustrating the trade-offs among alternatives to the group. 

Significant Accomplishments 

The most significant and important accomplishment was 

FERC’s issuance of a new 40-year license to extend Tapoco’s 

operations through 2045. This was accomplished through a 

Relicensing Settlement Agreement that was negotiated by 

our client and our team, executed with numerous agencies 

and non-governmental agencies, and accepted by FERC with 

minimal supplement conditions. The components that made 

the license significant were the: 

• Settlement agreement. This agreement included the 

following protection, mitigation and enhancement measures 

and terms: 

– Higher reservoir levels for longer summer reservoir 

recreation, increased head for power generation, and 

water storage for drought mitigation 

– Increased flow releases to enhance downstream aquatic 

habitat and improve downstream water quality and 

quantity by increasing dilution of downstream effluents. 

– A low-inflow protocol that is triggered during agreedupon 

low-flow conditions to override the normal 


operating policy and “share the pain” among all of the 

stakeholders to reduce the impact of droughts. 

• Land exchange. Our team and the National Park Service 

executed a land exchange agreement allowing FERC to license 

the project and accompanying lands. Large contiguous tracts 

of land were placed under conservation easement, and new 

areas and sensitive habitats are now protected, providing 

significant environmental benefits to the Great Smoky 

Mountain National Park and East Tennessee. PB’s geographic 

information system (GIS) capabilities supported this effort 

and helped the team to bring the parties into agreement. 

Although not a term of the relicensing process, another 

accomplishment that is significant and worth noting is that 

the new license supports continued employment of more 

than 2,700 people at Alcoa’s aluminum smelting facility. It 

does so by maintaining low-energy input costs to the products 

manufactured at the facility and, thereby, ensuring the business’s 

economic competitiveness. 

Conclusion 

The new Tapoco Project license is long-term, mutually beneficial 

to all parties and socio-economically beneficial to the eastern 

Tennessee region. It was considered a “successful” license for 

three primary reasons: 

• It had broad-based external stakeholder support. 

• It was completed on schedule, meaning time extensions 

were not required from FERC’s allotted five- to seven-year 

timeframe, and within budget. 

• Environmental issues were addressed in meaningful ways 

that reflected value to the stakeholders and avoided prescriptive 

solutions that might have been applied by FERC. 


• FERC licensing processes: http://www.ferc.gov/industries/ 

hydropower/gen-info/licensing.asp 

• Tapoco Project: http://www.alcoa.com/tapoco/en/home.asp 

2 See the following article, “Using OASIS Software to Model Water Allocation for Hydropower Generation Projects” by Paul Shiers, Shirley Williamson and Chii-Ell Tsai for more 

information about how PB used OASIS to estimate Tapoco’s future power generation and revenues. 

Kareem Bynoe is a senior engineer currently working on the relicensing of Alcoa Power Generation, Inc.’s Yadkin Project. He is also managing the development of a GIS 

database to support the feasibility study of hydroelectric developments in Greenland. 

Paul Shiers is a PB vice president with 38 years’ experience in hydroelectric power and water resource engineering. He has served as project manager for multiple 

hydropower projects, and completed an assignment as principal engineer for work performed under a multi-year continuing services agreement with FERC as the senior 

technical resource for hydro relicensing and compliance tasks. 

Shirley Williamson is a senior supervising civil engineer with 29 years’ experience in hydropower. She has been responsible for NEPA-based environmental assessments 

ranging in size from the 38 plant system of the Tennessee Valley Authority to an individual 2.5 MW facility under FERC jurisdiction. In addition, Shirley has developed and 

implemented reservoir operations studies, drought protocols, flood studies, and project safety response plans and training programs for owners of hydroelectric facilities. 

Tony Plizga is a senior principal engineer with 36 years’ experience in civil-structural engineering and design. Since joining PB in 2000, he has worked on various hydroelectric 

projects within the Boston Office Hydro Group. Tony is currently responsible for the FERC safety related tasks on the Tapoco and Yadkin Projects, which include a 

total of eight hydroelectric developments. 




Using OASIS Software to Model Water Allocation 

For Hydropower Generation Projects 

By Paul Shiers, Boston, Massachusetts, 1-617-960-4990, shiers@pbworld.com; Shirley Williamson, 1-617-960-4995, williamsonSh@pbworld.com; 

and Chii-Ell Tsai, 1-617-960-4974, tsai@pbworld.com 

Relicensing the Tapoco 

hydropower facility meant 

that balance had to be 

achieved between stakeholders’ 

concerns and the 

owner’s concerns about 

the natural resources 

involved. Water allocation 

modeling was critical to 

illustrating the effects of 

alternative operating policies 

and helping all parties 

involved reach consensus 

in a timely fashion. 


• http://www.hydrologics.net/ 

oasis.html 

The Tapoco Project, introduced in the preceding article, 1 includes four hydroelectric dams in 

North Carolina and Tennessee—Santeetlah Dam on the Cheoah River, and Cheoah, Calderwood, 

and Chilhowee Dams on the Little Tennessee River. As part of Tapoco’s relicensing process, it 

was important that the owner and stakeholders reach agreement on operational policies for 

the dams that: 

• Protected the reservoirs and natural resources in a way that met National Environmental 

Policy Act (NEPA) assessment requirements 

• Ensured sufficient energy generation, flood control and water supply. 

In February 2003,Tapoco participated in negotiations with stakeholders to review alternative 

operating policies and determine which policy met these goals best. The aim was to develop a 

comprehensive settlement agreement to submit as the preferred alternative for FERC’s NEPA 

assessment of Tapoco’s relicensing application. Negotiations focused on operational alternatives 

at two reservoirs: 

• Santeetlah Reservoir, regarding Santeetlah’s reservoir guide curve and various supplemental 

flow releases into the bypassed section of the Cheoah River. (A reservoir guide curve 

describes the optimal water storage and usage based on inflow models for a project.) 

• Calderwood Reservoir, regarding a range of supplemental flow releases into Calderwood’s 

bypass reach. 

PB used the water-allocation model OASIS, by HydroLogics, Inc., to develop and evaluate 

the operational alternatives and to quantify the effects of alternatives on reservoir water 

levels, stream flow, electricity generation, and the value of such generation. Using OASIS 

in real-time settlement discussions with stakeholders was critical in moving forward toward 

a negotiated agreement. 

OASIS Model Overview 

PB and Tapoco chose OASIS, a generalized modeling program for water resource systems, 

because of: 

• Its robust modeling capabilities for optimizing power dispatching, water allocation, energy 

generation, and energy value on an hourly basis 

• Its commercial availability and compatibility with personal computers 

• The regulator’s familiarity with the model 

• The ability to run the model in a real-time setting. 

1 The Tapoco project is a 380 MW 

hydropower facility owned by the Tapoco 

Division of Alcoa Power Generating Inc. 

Its 50-year Federal Energy Regulatory 

Commission (FERC) license was set to 

expire in February 2005, and PB was 

hired in 2000 to manage the relicensing 

process. The preceding article, 

“Successful Relicensing of a Federally 

Regulated Hydropower Project” by 

Kareem Bynoe and others tells about 

how the PB-led team managed the 

relicensing process. 

OASIS simulated the routing of water through the project, represented by a system of nodes 

arcs and inflows (defined below), by solving a linear program. OASIS operating rules were 

expressed as either constraints or goals: 

• Constraints defined physical rules in the project, such as flow continuity, and had to be obeyed. 

• Goals were rules that OASIS tried to meet. By their nature, goals were in competition with 

other goals, so typically all goals could not be satisfied. Goals were given relative priorities 

to describe their importance among other goals. 

OASIS never lost or created water in its accounting because every node had a continuity of 

flow constraint. 

 



Using OASIS for the Tapoco Project 

Input: Schematic, Inflows, and Site Specific Information. 

We defined the physical layout of the project by a system 

schematic (Figure 1) composed of: 

• Nodes, which are points of interest, such as a reservoir 

(nodes 110, 120, 130, and 140) 

• Arcs, which convey water between nodes 

• Inflows, which allow water to enter from outside the 

project system, such as a tributary. 

Figure 1: Tapoco Project 

OASIS Schematic. 

Santeetlah Reservoir (node 110) exhibited the schematic 

components typical of all reservoirs, including tributary inflow 

and four outflows—flows to the hydropower units, spill at 

the dam, environmental flows (supporting aquatic habitat and 

river geomorphological processes); and recreational boating 

(whitewater) flows. Inflows to Cheoah Reservoir were 

regulated flow releases by Tennessee Valley Authority’s 2 

Fontana Dam and unregulated tributary inflow. These 

included the effects of evaporation, which were calculated 

from Tapoco historical records. 

Model Calibration and Verification. Before using the 

model, we verified its ability to represent existing operations 

accurately, including the dispatch of water among the reservoirs 

and conversion of water into energy. To do so, we: 

• Collected data from three representative years to reflect 

the historical range of hydrologic conditions. 

• Used the model to simulate historical operation, comparing 

computed reservoir elevation and outflow with historical 

data, and verifying the model’s ability to simulate accurately 

the movement of water through the system and the energy 

generated at each of the four plants. 


• Calibrated the model to set the proper priority regarding 

generation among the four reservoirs consistent with their 

historical operation. 

The verified model was shown to simulate historical project 

generation to within ±1 percent annually and to within ±2 

percent monthly. 

Facility Characteristics. Prior to running OASIS, we defined 

certain reservoir and powerhouse characteristics. The starting 

elevation of each reservoir and the reservoir elevation at which 

flood gates operated were specified. Storage-versus-elevation 

relationships were required for each reservoir in order to 

satisfy the continuity of flow constraint of reservoir nodes. 

Operating Rules. OASIS also required that reservoir operating 

rules (goals) be prescribed for each dam and prioritized. 

Under its existing license, Cheoah, Calderwood and Chilhowee 

were operated in a modified run-of-river mode, while Santeetlah 

was operated in a store-and-release mode in accordance with 

an elevation guide curve. Tapoco generally operated the 

hydro plants during peak power hours to maximize the value 

of generation. To simulate this policy, OASIS was configured 

to dispatch water hourly to maximize the value of energy. 

The value of generation was assigned from a time series of 

hourly energy values based on historical hourly energy values. 

Station Performance. Power station performance or the 

conversion from water to energy, was defined for each hydro 

plant. At Cheoah, Calderwood, and Chilhowee, where the 

head is relatively constant, the power station conversion 

was defined simply as a function of plant flow. At Santeetlah, 

where the head varies 10 to 20 feet (3 to 6 m) annually, 

plant output was defined as a function of both head and 

flow. In addition, the minimum and maximum discharges per 

hour for each plant were defined. 

Alternatives. To model the alternatives being considered 

for Tapoco’s license submittal, OASIS had to model revisions 

to the reservoir elevation guide curve at Santeetlah and 

releases from Santeetlah and Calderwood Dams. We considered 

several non-power releases from Santeetlah, including 

aquatic minimum flow releases, disturbance flow releases, and 

recreational boating flow releases. We also considered continuous 

minimum environmental flow releases at Calderwood. 

During settlement discussions, the owner and the stakeholders 

agreed that under the proposed preferred NEPA alternative to 

FERC, the new project license would allow for the dispatch 

of water at Santeetlah with the following priorities, to which 

the model was configured: 

1. Release minimum flow and release disturbance flow 

2. Maintain reservoir elevation according to proposed 

guide curves 

3. Release recreational boating flows 

4. Generation. 

2 Created by a U.S. Congressional charter in 1933, Tennessee Valley Authority (TVA) is the USA’s largest public power company, providing electricity to nearly 8.5 million customers. 



The OASIS model and how it was used evolved during the 

consultation process. Initially,Tapoco and the stakeholders 

developed alternatives independent of the model and evaluated 

the alternatives in an office setting. We first used the model 

to simulate a “base case” condition, which was the Tapoco 

project with current operating rules in effect. Next, we 

simulated alternative operating scenarios and the results for 

each alternative (estimated reservoir water levels, stream 

flows, generation, and value of generation) were compared 

to the base case. 

As Tapoco moved into formal negotiations with stakeholders, 

OASIS was used more in real-time discussions. During 

negotiations, the stakeholders discussed the model results 

and requested modifications to the alternatives. We made 

modifications and ran OASIS real-time at meetings, and 

presented and discussed the preliminary results. After the 

meetings, we verified the preliminary results and obtained 

final results. If there were any notable differences between 

the two, then the final results were distributed to stakeholders 

via e-mail within a few days. This approach kept the 

pace moving quickly for all those involved in the 

settlement process. 


Using OASIS to evaluate alternative operating scenarios in 

a real-time environment proved to be key to reaching a 

negotiated settlement between Tapoco and the stakeholder 

coalitions. FERC issued a new license implementing the 

agreement in January 2005. This license and the associated 

settlement agreement were critical to Alcoa’s continued 

operation of the smelter facility located at Alcoa,Tennessee. 

Paul Shiers is a PB vice president with 38 years’ experience in hydroelectric 

power and water resource engineering. He is qualified as an independent consultant 

and PFMA facilitator for FERC Part 12 safety inspections under the new FERC 

DSPMP requirements. He has served as project manager for multiple hydropower 

projects, and completed an assignment as principal engineer for work performed 

under a multi-year continuing services agreement with FERC as the senior technical 

resource for hydro relicensing and compliance tasks. 

Shirley Williamson is a senior supervising civil engineer with 29 years’ experience 

in hydropower. She has been responsible for several NEPA-based environmental 

assessments ranging in size from the 35-plant Tennessee Valley Authority system to 

an individual 2.5 MW facility under FERC jurisdiction. In addition, Shirley has 

developed and implemented reservoir operations studies, flood studies, and project 

safety response plans and training programs for owners of hydroelectric facilities, 

including interfacing with owners and public safety agency staff. 

Chii-Ell Tsai is a supervising engineer with 44 years’ engineering experience. 

His water resources activities have include: OASIS modeling; spillway adequacy 

evaluation and stability analysis; water profiles and evaluation of power and 

energy for a proposed hydroelectric project; the preparation of emergency action 

plans for dam failure; and studies of energy consequences of modified reservoir 

operation policies on generation. 

Planning for Mini Hydro... (continued from page 26) 

achieve. These suppliers are more than likely exaggerating 

their machines’ capabilities. Unfortunately, efficiency claims 

are difficult to verify before the asset is installed because 

model efficiency tests are simply not cost effective for 

machines of this capacity. Ideally, the supplier has either built 

a turbine close to the head and flow available at the site 

from which the efficiency can then be based on, or has completed 

a model test of a similar turbine as part of the development 

process. In any case, tenderers should be asked how 

they derived the efficiency figures presented in the tender. 

In most cases, verification to site efficiency test codes, such 

as IEC600041, can occur only once the turbine is at site. The 

measurement accuracy can be expected to be about 2 percent 

at best. Compensation from the supplier for an underperforming 

turbine will normally be capped at a maximum of 10 percent 

of the value of the contract, which may not provide adequately 

for the lost revenue over the life of the equipment. This point 

further emphasises the need for caution when evaluating tenders. 

Conclusions 

Hydro is an essential part of the renewable generation mix of 

the future, even though some consider it to be “old technology.” 

As we know, planning is the key to the success of a project. 

I hope this article has provided useful insight into the 

development in small hydro. 

 

Q and A 

Question: 

What measures were adopted in the selection of bidders, 

specification or bid evaluation process to screen our 

poor quality or performance? 

John Wichall, Senior Consultant, PB Network Guest Technical Reviewer 

Answer: 

That is a bit of a complex subject to get into here, 

as this topic could be an article in itself. As a minimum, 

bid evaluation should focus on reputation, referees, technical 

compliance with the specification, and performance 

(weighted efficiency) of the turbine for the smallest turbines. 

Then many other factors need to be considered, such as 

long-term operating cost, non-price attributes etc. 

Non-price attributes generally cause havoc with tender evaluation, 

and I am a subscriber to the view that if you can’t ascribe 

a value or potential value, then it should not be included 

in your evaluation (e.g., no points system). The non-price attributes, 

cost adjustments, plus the performance evaluation can be 

added to the tender price to identify the “best” tender. 

Tony Mulholland, a mechanical engineer who has been with PB for more than two 

years, has played a key role in all phases of several mini-hydro facilities, being 

involved in planning, design, and construction. He also has extensive experience in 

other hydro-electric projects, and has a keen interest in renewable energy sources. 




Dam Safety: State-of-the-Art Methodology 

Demonstrates that Costly Remediation is 

Not Needed 

By Jay Greska, Boston, Massachusetts, 1-617-960-5021, greska@pbworld.com; and Bryce Mochrie, 1-617-960-4971, mochrie@pbworld.com. 

Updated federal regulations 

require owners of hydroelectric 

dams in the USA to 

evaluate the safety of their 

facilities under all potential 

failure modes. In the case 

of one of the Tapoco Project 

dams where there was 

concern about potential 

scour, the authors based 

their investigation on 

recent research that 

applies specifically to jet 

streams, versus gradually 

varied flow. This approach 

was used successfully on this 

project and is applicable to 

other scour impact areas 

subjected to free falling water. 

Figure 1: Santeetlah Dam Looking Upstream. 

Plunge jets from overflow spillways are capable of eroding the bedrock upon which many dams 

are founded. Over time, this process can lead to undermining and eventual dam failure, 

especially if the bedrock is weathered or of poor quality. Comparing the stream power of 

the plunging jet at the point of impact to the erodibility index of the bedrock enables us to 

determine the scour threshold of a dam’s foundation and the dam’s overall susceptibility to scour. 

Overview of Tapoco Project’s Santeetlah Dam 

Constructed in 1928, Santeetlah Dam is a concrete gravity and arch structure 321.3 m 

(1,054 feet) long with a maximum height of 60 m (197 feet) (Figure 1). It is one of four dams 

comprising the Tapoco Project, a 380 MW hydropower facility in North Carolina and Tennessee 1 . 

The dam is located roughly 72 km (45 miles) south of Knoxville,Tennessee, and includes: 

• An integral intake section 

• Left and right non-overflow gravity sections 

• Two 42.7-m (140-foot)-wide thrust blocks 

• A 97-m (318-foot)-long arch section connecting the two thrust blocks 

• An 8-km (5-mile)-long pipeline to the 45 MW generating station. 

Santeetlah’s six Tainter gates 2 in the two thrust blocks are used to pass floods. They have a 

combined capacity of approximately 532.4 m 3 /s (18,800 cubic feet per second, or ft 3 /s) at 

the 553.8-m (1,817-foot) full-pool elevation (Tapoco datum), which is the crest elevation. 

Historical flood flow discharges have generally been limited to the Tainter gates, with little 

or no flow overtopping the arch. 

At reservoir levels above full pool, flow is regulated by a combination of the Tainter 

gates and the arch, which acts as an ungated spillway during floods. Spills over 

the arch create a rectangular jet that plunges at low flows onto a concrete apron 

constructed in 1938 to absorb the energy of such spills. The apron, located just 

below the arch between the thrust blocks, extends downstream from the toe of 

the arch for a distance of 19.8 m (65 feet) at an average elevation of 496.8 m 

(1,630 feet). When total flows at the dam exceed approximately 849.5 m 3 /s 

(30,000 ft 3 /s), the plunge jet would land beyond the apron, potentially eroding 

the exposed bedrock in the riverbed (Figure 2). This flow level (849.5 m 3 /s) 

represents a relatively “small” overtopping flood event compared to the 5,776.7 m 3 /s 

(204,000 ft 3 /s) probable maximum flood (PMF). 

The wedge-shaped area just below the arch backs up the water and acts like a 

plunge pool during flood events, with the arch and thrust blocks forming the sides 

of the pool and the apron at the upstream portion being the bottom. The plunge 

pool provides some protection for the concrete and bedrock, with water depths 

increasing as the arch discharge increases. This is due to the 32.9-m (108-foot)- 

wide constriction between the two spillway toes, which controls tailwater depths 

as reservoir elevations exceed full pool and water is discharged over the arch. 

Figure 2: Arch Dam Elevation Showing Jet 

Trajectories. 

1 The Tapoco Project is the focus of the two preceding articles, which are about its relicensing by the Federal 

Regulatory Energy Commission in 2005, a project for which PB served as owner’s engineer. 

2 A Tainter gate is a type of radial-arm floodgate used in dams and canal locks to control water flow. See also the 

following article, “Deck Slot Cutting and Tainter Gate Remediation Extend Safe Operations of a Hydroelectric 

Dam” by Marc Buratto et al for more information about Tainter gates. 



The Need to Investigate Potential Foundation 

Erosion During Overtopping Floods 

Under FERC’s new Dam Safety Performance Monitoring 

Program, owners of hydroelectric dams must evaluate the 

safety of their facilities under all potential failure modes. As 

such, the hydraulic performance of high hazard dams, such as 

Santeetlah, whose failure could endanger lives or property, 

must be evaluated to the PMF level. Because spillway overtopping 

during a high-flow event had eroded more than 9.1 m 

(30 feet) of bedrock depth at Tapoco’s nearby Calderwood 

Dam during construction, FERC had become concerned about 

the potential for foundation erosion at Santeetlah Dam, stating: 

The consultant should provide an appraisal of potential 

foundation erosion during overtopping. The erodibility of the 

rock below the arch section should be specifically addressed to 

determine if it could be lost during an overtopping flood event.... 


scour susceptibility based on the concrete’s 

properties. Our results were as follows: 

• Bedrock. A minimum K h was estimated at 3,411 with 

an equivalent applied power of 445 kW/m 2 . 

• Concrete. A minimum K h was estimated at 3,000 with 

an equivalent applied power of 405 kW/m 2 . 

Figure 3: Jet Power at the Base of Santeetlah Dam for Various 

Reservoir Elevations. 

Our Investigation Approach 

Foundation scour from plunging jets is the result of turbulent, 

fluctuating pressures. Under certain conditions, these fluctuating 

pressures are capable of loosening and eventually dislodging 

large blocks of rock. Using the methods in Scour Technology — 

Mechanics and Engineering Practice 3 and FERC’s Engineering 

Guidelines for the Evaluation of Hydropower Projects 

(see Related Web Sites on the following page) we quantified 

the bedrock’s susceptibility to scour and estimated the 

mean and fluctuating dynamic pressures at the bottom of the 

plunge pool for various arch discharges. Power values for the 

plunging jet in kW/m 2 were then determined for various 

reservoir elevations. 

We estimated the likelihood that a scour hole would form 

during any given event by comparing the jet power at the 

bottom of the plunge pool to the threshold value of the 

bedrock or concrete. This methodology differs from 

conventional scour analysis, which involves the estimation 

of shear stress based on flow depth and energy slope, and is 

more suited for laminar, gradually varied flow. Conventional 

scour analysis was not performed because flow conditions 

at the dam, i.e., the plunge jet, were not suitable for this type 

of analysis. 

Estimating the Susceptibility to Scour of 

Bedrock and Concrete 

We estimated the bedrock’s susceptibility to scour using its 

erodibility index, K h , (Figure 3). Then, based on a combination 

of geologic data, field observation and engineering judgment, 

we took a similar approach in quantifying the concrete apron’s 

3 G. W. Annandale. 2006. Scour Technology: Mechanics and Engineering Practice. 

McGraw-Hill, New York, NY. 

Comparing the Power of the Plunge Jet to the 

Susceptibility to Scour 

Downstream hydraulics and plunge jet trajectories were 

investigated at reservoir elevations ranging from a small 

overtopping flood up to a major flood just below the PMF. 

Here we present two examples. 

Small Overtopping Flood. At a reservoir elevation of 

554.7 m (1,819.8 feet), which was 0.9 m (2.8 feet) above the 

spillway crest, the total discharge at the site was 847.9 m 3 /s 

(29,943 ft 3 /s) with 119.7 m 3 /s (4,226 ft 3 /s) overtopping the 

arch dam (assuming all six gates were fully open). The 

wedge-shaped area at the toe of the arch would be filled to 

a depth of 1.3 m (4.3 feet). 

The resulting jet was approximately 0.2 m (0.7 feet) thick 

at issuance and 0.8 m (2.5 feet) thick at impact. It hit the 

tailwater near the downstream edge of the apron 19.0 m 

(62.3 feet) from the toe of the arch with an applied power 

(neglecting aeration) of 894 kW/m 2 . The jet began to break 

up about 6.4 m (21 feet) below the point of issuance, or 

approximately 48.8 m (160 feet) above the water surface, 

however, so the spray that actually hit the tailwater did so 

with only a fraction of the jet’s original power. By the time 

it reached the bottom of the pool, the applied power of the 

jet was reduced to 97 kW/m 2 , well below the 405 kW/m 2 

minimum threshold value of the concrete (Figure 4 on the 

following page). 

 



Major Flood. The PMF would have a duration of approximately 

72 hours and a peak discharge of 5,776.7 m 3 /s (204,000 ft 3 /s). 

It would occur typically during a springtime precipitation 

run-off event, although it could occur any time of year, 

particularly during the summer and fall hurricane season for 

the southeast USA. Because the upper nappe associated 

with this event impacts the bottom of the walkway above 

the arch, thereby reducing its scour potential, it was not 

studied. However, the major flood just below the PMF with 

5,245.0 m 3 /s (185,225 ft 3 /s) was studied. During this event, 

approximately 3,127.6 m 3 /s (110,448 ft 3 /s) overtops the arch. 

This is the maximum discharge at which free flow occurs, and 

thus was assumed to have the highest scour potential. The 

reservoir elevation for this event, 560.3 m (1,838.2 feet), 

was more than 6.4 m (21.2 feet) above the arch crest. The 

resulting plunge jet was 2.0 m (6.6 feet) thick at issuance and 

5.9 m (19.4 feet) thick at impact, and it hit the plunge pool 

45.9 m (151 feet) from the toe of the arch with an applied 

power (neglecting aeration) of 2,780 kW/m 2 . In this case, the 

jet began to break up about 18.2 m (60 feet) below the 

point of issuance, or more than 27.4 m (90 feet) above the 

water surface, so the spray that hit the water did so with 

only a fraction of the jet’s original power. By the time it 

reached the bottom of the pool, the applied power of the 

jet was reduced to 303 kW/m 2 , which is well below the 

445 kW/m 2 minimum threshold value for erodibility of the 

bedrock (Figure 4). 


In summary, the total stream power values at the base of the 

arch varied from 97 kW/m 2 to 303 kW/m 2 , values that are 

well below the 405 ft 3 /s and 445 kW/m 2 minimum threshold 

values of the concrete and bedrock, respectively. 

Conclusions 

Based on our investigation, we determined that Santeetlah 

Dam meets all safety requirements. Overtopping of the 

arch section up to the PMF will not cause scour, which could 

otherwise lead to undermining and possible dam failure. 

Insofar as remediation-whether it be extending the apron 

or constructing a toe dam and permanent plunge pool, 

both of which would have cost several hundred thousand 

dollars-we demonstrated that none was needed. 

This state-of-the-art approach, used successfully to evaluate 

the scour potential of hydraulic discharge chutes, is applicable 

to other scour impact areas subjected to free falling water. 

 


• Federal Energy Regulatory Commission: http://www.ferc.gov 

/industries/hydropower/safety/guidelines/eng-guide.asp 

Figure 4: Scour Estimation for 

Santeetlah Dam Using Annandale 

and Ing Method. 

Jay Greska, P.E., is a lead engineer with PB’s Hydropower & Water Resources Group in Boston. He joined the firm in 2006 and has more than 20 years of experience in 

roadway design, bridge hydraulics, stormwater management and hydraulic modeling of large dams. 

Bryce N. Mochrie, P.E., is a senior principal engineer with PB’s Hydropower & Water Resources Group in Boston. He joined the firm in 2000 and has more than 35 years 

of experience in the civil/structural design, inspection and licensing of water resource and power projects. 




Deck Slot Cutting and Tainter Gate Remediation 

Extend Safe Operations of a Hydroelectric Dam 

By Marc Buratto, Boston, Massachusetts, 1-617-960-4973, buratto@pbworld.com; Anthony Plizga, 1-617-960-4972, plizga@pbworld.com; and 

Paul Shiers, 1-617-960-4990, shiers@pbworld.com 

Cutting expansion slots cut 

into a dam’s concrete spillway 

deck is one of the 

structural repairs that may 

be necessary to ensure 

that aging hydroelectric 

dams operate reliably during 

storm or flood events. PB 

oversaw implementation of 

such a solution for a dam 

where structural movement 

caused problems with gate 

operations. The authors 

tell about the slot cutting 

and gate remediation, and 

measures taken to protect 

water quality during the 

process. 

Figure 1: The Yadkin Project’s 

Narrows Dam in North Carolina. 

1 A Tainter gate is a type of radial-arm 

floodgate used in dams and canal 

locks to control water flow. 

Narrows Dam is one of four dams that comprise the Yadkin Project, a hydroelectric plant 

owned and operated by Yadkin Division of Alcoa Power Generating, Inc. The Narrows facility 

includes four units with a total capacity in excess of 110 MW. It generates more than half the 

hydropower for the Yadkin Project. 

Completed in 1917, Narrows Dam is a concrete gravity structure with a maximum height of 

61 m (200 feet). It consists of a main dam section and a bypass spillway structure (Figure 1). 

The main spillway deck has an integral concrete slab and steel beam support system spanning 

between spillway piers. It is restrained laterally by a non-overflow section at one end and an 

intake structure at the opposite end. No expansion joints were included in the original design 

of the spillway deck. Twenty-two Tainter gates are installed atop the main spillway to release 

surplus water during storm or flood events. Each is 7.6 m (25 feet) wide by 3.7 m (12 feet) 

high. 1 

The lack of expansion joints caused a portion of the deck slab adjacent to the intake to buckle 

under normal thermal conditions in the early 1990s. This buckling caused a redistribution of 

built-up forces in the deck to the nearby piers, resulting in the movement of the pier caps 

towards the intake. As a result, several Tainter gates could not be fully opened during the 

five-year full-open gate testing exercise in 2001, causing concerns about safety. Continuous 

dam safety is mandated by the Federal Energy Regulatory Commission (FERC), the licensing 

agency, so a remediation program was enacted to restore full opening of all the Tainter gates. 

PB was responsible for the engineering and construction oversight of the remediation effort. 

Our recommendation called for cutting new slots into the deck and rehabilitating the gates. In 

addition to the actual slot cutting, the effort involved: 

• Installing instrumentation to monitor deck and pier movements 

• Mobilizing and setting up cutting equipment, environmental 

compliance equipment and support systems. 

• Developing a quality control inspection program to make sure the 

field activities were completed correctly during construction. 

The Slot Cutting 

Three methods of cutting were considered—the diamond wire saw, 

concrete saw, and overlapping drill core methods. Most dam sites use 

an overlapping drill core method to re-establish expansion joints due 

to deck configuration, construction joint layout and other issues, such 

as embedded conduits. In this situation, the configuration of the deck 

and slots ruled out the use of the concrete saw method, and aesthetic 

issues associated with the overlapping drill cores ruled out that 

method. The wire saw method allowed the most favorable option for removing the saw 

cable if binding occurred during cutting due to slot closure. Removal could be accomplished 

by simply making another wire saw cable to cut through the bound cable without significant 

demolition activities adjacent to the cuts. A 1.6-cm (0.625-inch) diamond wire saw was used 

to cut the slots. 

Slot cutting work was confined to the deck of the main spillway, right non-overflow section, 

and the deck between the intake and bypass spillway. One slot was cut first at the right 




the slurry coming directly 

out of the slot cut. In 

addition, the contractor 

installed troughs on both 

sides of the piers under 

the deck to collect water 

that seeped through 

joints to the underside 

of the deck. 

Figure 2: Cross Section View of Pier Slot Cuts. 

non-overflow section to relieve as much of the built-up 

stresses as possible, then six sets of two slots were cut in 

piers along the main spillway. Joints were spaced along the 

spillway deck about four bays apart or at approximately 

120-foot (37-m) intervals. The slot cutting activities occurred 

during the summer months, so a thermal increase of about 

50°F (10°C) was used to evaluate the required width of the 

slot. This thermal change required a minimum slot width of 

about 0.4 inch (1.0 cm). 

The wire slots in the piers on the main spillway extend 

through existing construction joints in the concrete deck to 

a minimum depth of approximately 0.51 m (20 inches) 

across the width of the deck (Figure 2). The concrete deck 

is reinforced, however, the reinforcement does not extended 

into the unreinforced pier through the construction joints. 

In addition, the steel beams also supporting the concrete 

deck did not extend through the existing construction joints. 

Therefore, no steel beams or reinforcement were cut. 

The primary objective of the slots was to provide open 

joints to allow for thermal expansion of the concrete deck. 

Re-cutting was required at only three slots in two different 

piers due to closure of initial cuts. 

The exposed slot cut areas (top and upstream/downstream 

faces) were sealed with a foam backer rod and sealant. Initial 

closure after all slots were cut was approximately 3.0 cm 

(1.2 inches), and the total accumulated available slot closure 

was 200 cm (8 inches). The final slot gap widths ranged 

between 1.5 cm (0.59 inch) and 2.0 cm (0.78 inch). 

Protecting the Water 

A unique challenge we faced during the fix was in meeting 

the client’s request that we prevent the cuttings and the 

resulting cutting slurry from entering the project waters. We 

required that a slurry catch basin (collection bin) be installed 

on the upstream and downstream sides of the piers to collect 

Water was pumped 

from the upstream 

dam reservoir into the 

collection bin until it was 

nearly full. This water 

was then pumped and used as lubrication for the wire for 

the remainder of cutting activities at that pier, being collected 

and re-circulated until the slot cutting was completed. After 

that, the re-circulating water was pumped to a settling tank 

where solids were allowed to settle out. The effluent from 

the settling tank, which was clean water, was discharged to 

the reservoir. 

This method for collecting and processing the slurry and 

fluids from the cutting activities was reviewed and approved 

by the State of North Carolina Department of Water Quality. 

No unanticipated environmentally related incidences 

occurred during the slot cutting activities. 

Instrumentation 

Narrows Dam has an instrumentation program that includes 

manual and automated instruments to monitor the overall 

safety aspects of the site. Prior to the deck remediation 

program, instrumentation included high order survey pins, 

piezometers and seepage measurements. We recommended 

the addition of inclinometers, tiltmeter plates and deck slot 

monitoring pins prior to the start of slot cutting activities 

because it was critical that the dam’s behavior be monitored 

while work was in progress, and equally important that the 

long-term effects of the new expansion slots be monitored. 

Tainter Gate Remediation 

The Tainter gate remediation included: 

• Removing the existing side rollers, which prevented the 

gate skin plate from cutting into and binding on the 

concrete piers 

• Trimming the edges of the Tainter gate steel 

• Installing grooves in the concrete piers 

• Replacing the side seals. 

Tainter gates are illustrated in Figures 3. The side rollers had 

been added to the ends of the top and bottom horizontal 

girders on each side of the Tainter gates in the early 1990s to 



protect the edges of the gates and to facilitate smooth 

operation during opening. The continued tilting of the piers 

during the 1990s led to excessive force buildup, however, 

and local abrasion 

(due to excessive 

frictional forces) of 

the concrete at the 

upper right side 

roller. The visual 

scarring of the 

concrete was 

evidence of the local 

concrete abrasion 

(Figure 4). Although 

the side rollers did 

provide protection 

for the edges of the 

gate, they did not 

stop the gates from 

binding. 

Figure 3: Closed Tainter gate viewed 

looking downstream (top) and upstream 

(bottom). 

Figure 4: Image of local concrete abrasion 

due to excessive frictional forces 

from gate binding. 

The gate clearances 

and the extent of 

pier tilting were 

not the same in 

each spillway bay. 

To ensure that 

appropriate gate 

trimming and 

concrete grooving 

were performed 

on each pier, we 

determined for the 

construction specification 

the tolerances 

and criteria for 

determining which 

Figure 5: Image of gate repaired with 

groove. 


gates needed to be 

trimmed and which 

piers needed to be 

grooved. Twenty 

gates required 

trimming on at least 

one side, and twelve 

required trimming 

on both sides. 

Twelve gates 

required that the 

concrete pier be grooved (Figure 5) on the right side, and 

one required pier grooves on both sides. 

Summary 

At the time of writing, the slot cutting had been completed 

for nearly six years and the Tainter gate remediation for 

more than four years. The deck monitoring pins have shown 

that the concrete decks between the expansion slots expand 

and contract seasonally with an amplitude of about 0.65 cm 

(0.25 inch). All gates continue to operate successfully and 

open fully. We expect that this work will maintain reliable 

hydropower generation for the Yadkin Project long into the 

future by maintaining the associated dam in a safe condition. 

In conclusion, the installation of spillway deck slots, trimming 

of the gate skin plates, and the grooving of the concrete 

piers have significantly extended the useful life of the 86-year 

old Tainter gates at Narrows Dam. 

 


• http://www.alcoa.com/yadkin/en/info_page/relicensing_overview.asp 

Marc Buratto has nearly three decades of experience in the engineering and design of power stations and other types of facilities. Marc’s expertise includes finite element 

stress analysis and stability analysis of existing structures, preparation of FERC safety inspection reports and Potential Failure Mode Analysis (PFMA) Reports as part of the 

new Dam Safety Performance Monitoring Program (DSPMP), concrete and steel design and analysis, and Tainter gate assessments and modifications. 

Tony Plizga has 36 years’ civil-structural engineering and design experience. Since joining PB in May 2000, he has worked on various hydroelectric projects within the 

Boston Office Hydro Group. Major tasks include site inspections and reports, gate upgrades, instrumentation data evaluation, stability analyses, rock anchors, GIS oversight 

and FERC relicensing support. 

Paul Shiers is a PB vice president in hydroelectric power and water resource engineering. Having 38 years of engineering experience, Paul is qualified as an Independent 

Consultant and PFMA facilitator for FERC Part 12 safety inspections under the new FERC DSPMP requirements. 


GENERATION: 

Renewables - The Risks, Concerns and Potential 

The Growing Power of Renewables 

PB has a strong track record in renewable energy projects, including wind power, geothermal, 

biomass, hydropower and solar energy. Given the current worldwide concerns about the 

depletion of fossil fuels and the desire to reduce CO2 emissions, this edition of PB Network 

takes the opportunity to look at some of the range of projects and studies in which PB 

engineers get involved. The articles in this section cover a wide spectrum of new and 

emerging technologies being applied throughout the world. 

In the first, Dominic Cook taps into PB’s experience across the breadth of power generation 

technologies to compare the generation costs of traditional and newer generation technologies. 

This information is key to governments around the world addressing their potential mix of 

power generation technologies. Then, building on PB’s background and expertise as lenders’ 

engineers, Ian Burdon describes those processes required in introducing and financing new 

commercial scale technologies. This topic, too, is key to our understanding of factors that 

impact our power generation future. 

Geothermal energy is an important energy source in Australia, and Allan Curtis describes 

a project in which PB’s design expertise examined different methods of converting this 

heat source to electrical power. The next article shows PB as EPC contractors rather than 

consultants, and Roger Lemos describes the design and construction of a gas processing 

plant in Connecticut. It was designed to collect and process landfill gas, converting a 

waste gas to a high Btu gas of pipeline quality. 

Moving to Europe, Rafael Lejarza gives an insight into photovoltaic (PV) power generation 

and, in particular, PB’s involvement with PV projects in Spain. Finally, Peter Kydd describes 

briefly a tidal power project on the Severn Estuary in south west England. 

This set of articles illustrates PB’s breadth of experience ranging from high level studies to 

designing engineering solutions, all of which will help countries around the world to reduce 

their carbon footprints. 

Please see page 89 for a list of many additional articles on windpower, minewater, geothermal, 

carbon reduction, and other renewable topics from past PB publications. 

Steve Loyd 

Chief Thermal Plant Engineer, Newcastle, UK 

Coordinator of PAN 13, Conventional Thermal Generation 



Renewables – The Risks, Concerns and Potential 

Renewable Energy — Sustainable Economy? 

By Dominic Cook, Newcastle-upon-Tyne, UK, 44 191 226 2203, cookDo@pbworld.com 

This article is based on a 

report produced to inform 

the debate around the 

future mix of power generation 

in the UK during the 

government’s 2006 Energy 

Review by providing an 

independent statement of 

the costs of power generation 

at that time. It not 

only reflects the high level 

of work done by PB’s 

power specialists, it 

provides readers with 

answers to some questions 

clients around the world 

contend with. 

Table 1: Characteristics and 

costs of technologies studied. 

1 These are the estimated 

engineer/procure/construct (EPC) 

costs for each technology excluding 

owners soft costs and contingency. 

Renewable technologies are at differing stages in their development. Onshore wind generation, 

for example, is regarded as being virtually competitive in its own right without external support 

given the right combination of project specifics. This stage of advancement contrasts with those 

of other renewable energy generation technologies that struggle to break out from the prototyping 

stage and find convergence on a single implementation model (for example, wave/tidal). 

The technologies that are considered in this article are: 

• Coal pulverised fuel 

• Gas-fired combined cycle gas turbines 

• Coal IGCC 

• Nuclear 

• Onshore wind 

• Offshore wind 

• Wave 

• Tidal. 

• Biomass 

This list includes technologies that are available currently and those that are considered to 

comprise the next generation of renewable generation. They were compared using a discounted 

cashflow model of the technology capital and operational costs over a typical project life. 

Long-term gas and coal fuel prices were assumed to be 37 pence/therm and $49/tonne. 

Whilst there are local cost factors that affect the analysis, the main factor is the relative price 

for each energy source. 

Technology Summary 

The characteristics of the various power generation technologies reviewed are discussed 

below and summarized in Table 1. 

Coal pulverised fuel. Conventional 

pulverised fuel (PF) combustion is 

a common form of generation 

technology found throughout the 

world. It is well proven and considered 

to be a mature technology. 

The key design features of a conventional 

PF plant are the pressure 

and temperature at which steam is 

generated. The majority of plants 

installed to date operate at subcritical steam conditions; however, supercritical and advanced 

super-critical boilers are becoming the technology of choice for new coal plant construction. 

A new coal-fired PF plant will have to meet environmental legislation to be considered a 

“best available technology” and will have to meet environmental legislation through the fitment 

of emissions control systems. These are important aspects of all types of coal PF plant, and 

the associated costs can be minimised through the specification of the fuel to be burned. 

Combined cycle gas turbine (CCGT). In a CCGT power plant, the hot exhaust gases from 

the gas turbine are delivered to a heat recovery steam generator (HRSG) where heat energy 

in the gases is transferred to water, which is then converted to high-pressure, high-temperature 

steam. This steam is then delivered to a steam turbine. About two thirds of the electrical 

power is derived from the gas turbine and one third from the steam turbine. 

Our study assumed the use of a “state-of-the-art” heavy-duty gas turbine based CCGT because 

of the high cost of gas fuel and the high level of competition between electricity generators. 

 



The exhaust gas emitted from a gas turbine in combined 

cycle mode is the same as from one in open cycle mode; 

however, the quantity of emissions for a notional level of 

output (CO2 per kWh) is greatly reduced owing to the 

higher power output of CCGT plant. 

Coal integrated gasification combined cycle (IGCC). 

Integrated gasification plants offer reduced environmental 

emissions, but at an increased capital cost when compared to 

more conventional combustion technologies. This technology 

allows the use of a wide range of fuel sources that would 

not typically be used in conventional thermal power. It is 

also one of the technologies associated with carbon capture 

and sequestration. 2 The synthetic gas that is derived from the 

fuel gasification can be cleaned prior to combustion, giving 

emissions comparable to those of natural gas plant and thermal 

efficiencies of up to 43 percent. Further, the technology enables 

the carbon fraction in the fuel to be removed prior to combustion, 

when there is a need for carbon capture and sequestration. 

Appropriate treatment of the by-product streams from the 

gasification process and ensuring a safe design means that the 

capital cost of such plants is high. Further, the operational 

experience of these plants is also relatively limited. 

Nuclear. In the UK, nuclear power plants currently account 

for just under 20 percent of total electricity demand, with 

most of this power coming from advanced gas-cooled 

reactors.The older Magnox reactors will have been shut down 

by 2010. Only one reactor, the pressurised water reactor at 

Sizewell B is planned to be in operation beyond 2024. 

The UK government’s Energy Review in 2003 declared that 

new nuclear plants would not be considered, although the 

option would be kept open. The main reason for this view 

was that the abundance of low-cost fossil fuel generation 

(predominantly gas) had led to low-cost base-load electricity 

prices. This was the situation in all countries that had access 

to low-cost fossil fuels. 

This backdrop has changed significantly with much higher oil 

and gas prices, with oil seemingly breaking high price records 

weekly, and the requirements in Kyoto signatory countries to 

reduce carbon emissions. Whilst these factors have changed, 

the issues of long-term solutions for the used nuclear fuel 

and the irradiated plant and equipment from the reactor 

remains, however, and continue to present significant political, 

social and financial challenges. 

A cost estimate of £1.5bn at the end of the operational life 

has been included in our evaluation to account for decommissioning. 

It should be noted that nuclear power plant costs 

2 Please read “The Effect of Carbon Capture and Storage and Carbon Pricing on the 

Competitiveness of Gas Turbine Power Plants,” a preceding article by Dominic Cook, 

to learn about how carbon capture and storage works and what are its prospects in 

the electricity generation market. 


are likely to be the most strongly contested values of all the 

power generation technologies and, therefore, the values 

used in our evaluation were considered to be conservative. 

Onshore wind. Development of onshore wind turbines has 

moved to a point where the plant is considered to be almost 

able to compete on a level playing field in terms of price with 

other more conventional technologies. Its viability remains 

highly dependent on the wind resource in each location, 

however, and this variability in the plant output continues to 

incentivise developments in electricity storage technologies. 

The installed cost of wind power projects has seen a rise over 

recent years due largely to the increase in wind turbine prices 

resulting from increases in energy costs and raw material costs 

(steel, copper and blade materials). Turbine manufacturers 

have also used the upturn in world demand to increase their 

margins on the back of a scarcity of turbine manufacturing 

capacity—the economics of supply and demand. 

Offshore wind. The trend continues towards larger turbines 

with larger rotor diameters. It is expected that these 

advancements will result in reductions in specific costs in the 

longer term, although the present trend is upwards owing to 

continued learning and competitive pressures from oil and 

gas industries for the vessels and personnel necessary for 

installation in a marine environment. Economies of scale are 

likely to be realised as the size of wind farm projects increases. 

Wave and Tidal. Wave and marine generation broadly 

encompasses five types of technology considered to be 

relevant to the UK: 

• Tidal barrages. Seawater flows through constructed 

barrages is used to power turbine generators. 3 

• Offshore tidal current turbine. Energy in the currents 

created by tidal streams is used to generate electricity. 

• “Pelamis” sea snake. When floating on the sea, hinged 

joints between the snake’s semi-submerged articulated 

cylindrical sections move with the waves, powering 

hydraulic motors that then generate electricity. 

• Oscillating hydroplane. Energy in the currents created 

by tidal streams is used to generate electricity using the 

principle of an oscillating hydroplane. 

• Oscillating water column device (OWC). The OWC 

device comprises a partly submerged concrete or steel 

structure, open below the water surface. Air is trapped 

inside above the water-free surface. The oscillation of the 

internal free surface produced by the incident waves makes 

air flow through a turbine that drives an electric generator. 

Significantly, the present status of development of wave and 

tidal generation devices is summarised by the Carbon Trust 

as follows: “Overall, devices are at early stages compared to 

3 Peter Kydd discusses tidal barrages in a following article, “Project Brief: Tidal 

Power.” 




other renewables and conventional plant, and crucially, optimal 

designs have yet to be converged upon. A few large-scale 

prototypes have been built and tested in real sea conditions, 

but no commercial wave and tidal stream projects have yet 

been completed.” 

Biomass BFB technology. Bubbling fluidised bed (BFB) is a 

well-proven technology suitable for small (less than 100 MWe) 

biomass power plants. (Biomass is plant or animal matter or 

biodegradable waste used as fuel.) The BFB provides thermal 

inertia that makes it suitable for combustion of fuels of high 

and variable moisture content and fuels that are difficult to 

pulverise effectively, such as woody materials. 

Base Comparison 

The base assumption is that the cost of carbon is based on 

the European Union Emission Trading Scheme and is based 

on a £25/tonne long-term cost. The quantity of allowances 

provided to the electricity generators is assumed to be 

phased out by 2018, 4 when they will need to purchase 

carbon certificates for their emissions. 

Comparison of the technologies with each other and in 

relation to the present expectation of market forward 

electricity pricing (Figure 1) reveals that there are two 

distinct groups of technologies: 

• Those that are viable (or marginally so) with the present 

market expectations 

• Those that will continue to require support from external 

mechanisms to continue their development towards 

commercial reality. 

Carbon costs are beginning to form a significant portion of 

the overall cost of generation for fossil fired power plants. 

As the allowances provided decrease and the carbon price 

increases, this effect will be more pronounced, with the gap 

between the fossil fired and renewable generation sources 

being reduced. This reduction alone is not sufficient to give 

the commercial incentives to build renewable plant, and 

there will be a continued need for support mechanisms— 

be it through feed-in tariffs, renewable obligation mechanisms 

or other such support schemes. 

Summary 

• Renewable generation will continue to need support 

mechanisms to ensure that the best use of the resources 

is made and that the “best value” is returned in terms of 

carbon reduction and energy delivered. 

• Nuclear plant continues to have uncertainty surrounding 

decommissioning costs and the need for a long-term 

solution for spent fuel from nuclear plant. The expectations 

are that any new build is likely to replace existing nuclear 

capacity only and, therefore, would not result in a net gain 

in carbon savings. 

• Conventional fossil-fired generation plants are likely to 

continue to “feel the pressure” through uncertainty 

surrounding future carbon allocation levels, carbon pricing, 

fuel pricing and security of supply. 

 

Figure 1: 

Comparative Costs 

of Generation. 

Dominic Cook has 20+ years of utility and consultancy experience in the power industry. He has been involved in regulatory audits and the development of power 

generation plant, and in providing advice to financial institutions. His publications included “Powering the Nation” in June 2006 and he is presently involved with the 

UK government on the carbon capture competition. 

4 Phasing out assumed to be 90 percent to 2010; 50 percent between 2013 to 2017 and 0 percent from 2018 onwards. 

5 Standby energy is the cost to provide replacement power when a plant suffers a forced outage. 




Test Bed to Turnkey: Introducing New Thermal 

Renewable Energy Technologies 

By Ian Burdon, Newcastle upon Tyne, UK, 44 191 226 2444, burdonI@pbworld.com 

The step between a 

laboratory-scale research 

project and a full-scale, 

commercially-viable scheme 

that will attract investors is 

large. Considering a generic 

fuel-energy conversion 

process, the author 

describes the commercial 

climate in which such a 

project has to develop, 

grow and survive and the 

types of risk assessment 

needed. This information 

will be useful for those 

assisting organisations 

seeking financial support to 

take an advanced-technology 

process from a proven design 

concept to commercial 

operational service. 

Figure 1: Contractual 

Arrangement for Independently 

Financed Energy Conversion 

Project. 

Governments in many countries are encouraging private sector developers to invest in 

their national electricity systems and sell power to the distribution companies for onward 

supply to consumers. Commercial viability is a fundamental requirement for any process or 

project that is intended to supply electricity to the competitive market place. Expensive new 

technology and that which is unproven or of a small-scale cannot compete with tried and 

tested combined-cycle gas turbine plant fired on plentiful natural gas. Thus, it is suggested 

that these new technologies, such as advanced conversion technology, will be hard pushed 

to find a secure place in a market place where the emphasis is on low capital cost and 

technical efficiency for large-scale power production. 

One area that does offer some chance of success lies in the field of renewable energy. The 

ability of a process to accept a feedstock that is sustainable, such as biomass, or can be 

considered as a renewable can be beneficial for technological development in the context of 

a national renewable energy policy. Such a policy manifests itself, for example, in the UK where 

government has set targets for 10 percent of all electricity production to be from renewable 

energy sources by 2010. Premiums paid for renewable energy can compensate for the inevitable 

high capital cost of the technology and the disadvantages arising from dis-economies of scale. 

In addition to economics is the important issue of competition between rival technologies. 

Factors that developers are likely consider when selecting a particular technology will include: 

• Previous operating experience. If the “technical” process has been developed from 

laboratory prototypes, data will need to be gathered on: 

– Its thermal efficiency in recovering useful energy from the feedstock 

– The production of by-products (and co-products if relevant), particularly discharges to air, 

water and land, which will be of keen interest to the environmental regulatory agency. 

• Scale of process. Those investing in a project where significant scaling-up is needed to 

attain critical “commercial” mass will require evidence that such a scale-up is a practical 

proposition and that the relevant mechanical engineering and thermochemical conversion 

factors have been taken into account. The risks inherent in the scaling-up will be of special 

interest to those involved in the independent project appraisal. 

• Current status of technology. The development status of the technology is interrelated 

with the feedstock type to a large extent. For example, whilst the 

gasification of a coal feedstock is a relatively well understood and 

well tried process, the gasification of many biomass-type wastes is 

not, certainly outside of a research laboratory. 

• Cost/MW of capacity. Significant advantages in terms of 

thermal efficiency or environmental emissions will have to be 

expected if a relatively expensive processes is to catch the 

attention of a developer. 

Financing a Project 

The majority of independent energy projects promoted in 

countries such as the UK, which have a non-parastatal electricity supply industry, 

have been funded on the “project finance” basis, with approximately 80 percent 

of the cost being borrowed and then repaid from the net revenues of the project. 

The remainder of the finance required comprises equity from the project sponsors. 




The project sponsors establish a special purpose company (the 

“energy company”) that serves as the vehicle to take the project 

forward. This company becomes the counter-party to the various 

agreements for goods and services that essentially comprise the 

project. The primary agreements for a typical renewable energy 

project are similar to those for conventional projects. Their essential 

elements are as follows: 

• Fuel or feedstock supply. Agreements as to quantities, quality, 

availability, price, and any related fees or conditions. 

• Heat and electricity off-take. Usually a pro-forma agreement 

with one or other of the generating companies (or perhaps 

electricity supply companies) for a fixed term sometimes at a 

premium price. 

• Design and construction of the facility. A turnkey arrangement 

that obliges the contractor to assume responsibility for completion 

date, final cost and performance of the facility. 

• Operation and maintenance. Agreement with the O&M 

contractor as to the quality assurance system in place, audits, 

and performance targets. 

Secondary agreements cover the lease or sale of land; finance; statutory 

consents, such as planning, integrated pollution control, consents to 

build a power station, licence to generate electricity, etc. 

The primary agreements are written such that each complements the 

others. For example, the specification and quantity of feedstock 

supplied corresponds with that required by the plant to be built 

under the design and construction (D&C) contract to deliver the 

electrical energy output specified in the electricity off-take contract. 

At the same time, the obligations contained within the operation and 

maintenance (O&M) contract require specific levels of fuel conversion 

efficiency and plant availability to be attained by the operator in line 

with the terms and conditions of the electricity off-take contract. 

Risk and Critical Issues 

The majority of risks associated with a given project (Table 1) can 

be covered in the contractual arrangements described above. 

Project financiers will wish to see a suitable spreading of risks and 

mitigation of them (perhaps by insurance) over all the project 

participants. It is highly unlikely that the lending banks will agree 

to bear any of the risks. 

Matters that would typically be regarded by lenders as representing 

a potential risk include: 

• Technology. Lenders will expect an independent engineer to 

report on the technical specification for the plant and require 

evaluation of the appropriateness and track record of the relevant 

technology in the proposed application. Lenders will likely regard 

untried features as unacceptable risk. 

 

Table 1: Categories of Risk In a Typical Renewable Energy Project. 



• Contractors. Lenders will consider the reputations and 

financial strength of the principal contractors when assessing 

risk of default in relation to any function that is material 

to the project’s success. 

• Security of cash flow. Lenders will analyse all factors that 

may have a bearing on the project’s ability to maintain a 

comfortable cash flow beyond the prospective term of the 

borrowing. Such factors include, for instance, the security 

of the fuel supply and contingency arrangement for alternative 

fuel 

• Statutory authorizations. Lenders will check on all 

factors affecting the consents and permits necessary for 

the commencement and continuation of the project. 

Success in structuring and obtaining finance is closely linked 

with developers’ ability to identify risk, design technical solutions 

and allocate contractual responsibility. Often developers 

seek expert advice in each relevant field early on so that 

there is a coherent strategy from an early stage. 

Some of the relevant issues that relate to risk analysis include: 

• Financial model. A crucial test is how the economics of 

a project stand up to the perceived areas of risk. Any 

prospective lender will want to see a financial model that 

shows how the sensitivities of the various parameters at 

risk affect the project economics. 

• Contractual framework. The contractual framework will 

need to take account of the risk factors that are relevant to 

the specific features of the project. Setting up this framework 

involves careful planning on the identity of the contracting 

parties and assessment of their capacity to discharge their 

obligations, the scope of the positive obligations under 

each contract and the effect of limitations of liability. 

• Financial structure. A detailed evaluation of the capital 

requirement and the balance between equity or “risk” capital 

and loans will be required. The proposed “gearing” will 


indicate the potential reward for the providers of equity 

and be an important indication of the way in which the 

developers have considered the allocation of risk. Lenders 

gain confidence in developers if the proposed financial 

structure takes them into account. 

• Insurance. Lenders will require that the insurance cover 

is planned for many of the areas of perceived risk with 

reference to the specific detail of the project. Specialist 

insurance brokers can assist in creating an effective 

insurance programme. 

Conclusions 

Translating thermal conversion research into a full-scale, 

practical, process plant in which technical risks are understood 

and can be quantified is bound to be a difficult task, but 

every new development has to start somewhere. The 

commercial world of electricity supply, in which the thermal 

conversion process hopes to find an application, is changing 

rapidly, and the support and sustenance that prototype 

processes might have received in years gone by from central 

authorities are now vanishing. The requirements today are 

generally for tried and tested, reliable and easily maintained 

technology capable of providing a supply of electricity using 

indigenous fuels. Advanced technologies, not long out of the 

research stage, are unlikely to satisfy such demands. 

The drive to use more non-fossil fuels in electricity production 

to meet climate change accords is likely to change these 

requirements, however, and provide the stimulus to technological 

development of new thermal conversion processes. The 

financing of such projects will require intensive analysis of 

the intrinsic technical risks of the process. The satisfaction of 

such a risk analysis will require the production of comprehensive 

data (and its intensive scrutiny) on operational performance 

and design, particularly in relation to scaling-up from the 

test-bed to the turnkey, commercial, installation. 

 

Ian Burdon is responsible for directing all activities within PB (Power) on sustainable energy developments, including renewable energy, energy from waste, advanced 

energy technologies, such as gasification and pyrolysis, and low and zero-carbon “clean” energy technologies. He has had an involvement as either project manager or 

project director on a wide variety of renewable, waste and other energy projects. Ian is active in the affairs of the Institution of Engineering and Technology, the 

Institution of Mechanical Engineers, the Association for Consultancy and Engineering and the Environmental Services Association. He maintains close contacts with 

developers and banks involved in energy projects for which he often acts as technical advisor. 

Note: This article was based on a paper about thermal conversion technologies for use in waste management that was for presentation at the Chartered Institution of 

Waste Management annual conference, Torbay, UK, June 2008. Copies are available from the author. 

Acknowledgements: Thanks are due to the directors of PB’s power specialists for permission to publish this article. It is emphasized that the opinions expressed are 

entirely those of the author and in no way reflect the corporate attitudes or views of PB. 




Realising the Power Potential From Hot Rocks 

By Allan Curtis, Brisbane, Queensland, 61 7 3854 6852, curtisAl@pbworld.com 

Australia is one of many 

nations that have made 

commitments to reduce 

greenhouse gases and 

change to more renewable 

energy sources. Hot dry 

rocks has the potential to 

make a very significant 

contribution to these aims, 

but also presents many 

engineering challenges. 

PB has developed designs 

to accommodate the 

very severe conditions 

surrounding hot rocks and 

maximise the power that 

can be produced. 

Figure 1: Heat map of 

Australia. 

Hot rocks have been investigated as an energy resource for approximately thirty years; but their 

exploitation for power generation had been hindered until recently by the many significant 

drilling challenges associated with very deep drilling, being able to achieve a sufficiently high 

flow of water through the rocks by hydraulic fracturing, and high pressures and temperatures 

for pumping. Now, the world’s first high temperature hot dry rock development is nearing 

completion at Soultz in Southern France. It is expected to produce about 1.5 MW using an 

organic Rankine cycle plant. (The thermodynamic Rankine cycle converts heat into work.) 

Tapping into Australia’s Hot Rocks 

Australia has considerable quantities of deeply buried radiogenic (hot rock) granites. Figure 1 

shows the potential resource at 5000 m (16,400 feet) below ground. As can be seen, there 

are large areas where rock temperatures exceed 250°C (482°F), but they are all in remote 

areas far from populated areas (Figure 2). 

Geodynamics Ltd, which focuses on developing renewable geothermal energy generation from 

hot rocks, has geothermal rights to approximately 2000 km 2 (772 square miles) of land near 

Innamincka in the Cooper basin where, to date, it has drilled three wells. Testing on its 

Habanero 1 well has revealed that granites at about 4200 m (13,800 feet) below ground 

contain super-pressured saline water (brine) and yield well head pressures and temperatures 

of approximately 33 MPa and 250°C (4,790 psi and 482°F). The presence of brine came as a 

surprise to Geodynamics, but it avoids the need to locate a source of water that can be injected 

down into the high temperature zone. The potential demand for injection water would have 

presented a significant problem in this water-starved area of Australia. 

Geodynamics has just completed drilling Habanero 3 with its new drilling rig, which allows 

them to drill a 215 mm (8.5-inch) hole up to 6000 m (19,700 feet) deep. This new well, the 

largest one of this depth drilled onshore in Australia, will enable circulation testing, which will 

prove (or disprove) the resource and enable Geodynamics to evaluate equipment for full scale 

power plant development. At the measured brine temperatures and the anticipated heat 

extraction rates, the expected net power output from the 2000 km 2 that Geodynamics has 

rights to is in the order of 10 GW. 

PB’s Role: Power Production Technologies 

Geodynamics is seeking to complete the engineering and detailed costing for a nominally 

50 MW power plant by the end of 2008, with an objective to have the plant operational by 

 

Figure 2: Cooper 

Basin location. 



the end of 2010. Their longer term objective is for a rapid 

development of the resource to 500MW generating capacity. 

PB was hired by Geodynamics to evaluate alternative power 

production technologies and prepare a budget costing for a 

proposed modular power plant. To prove the geothermal 

resource, we designed a test facility and a small (1.2 MW) 

pilot-scale power plant using Habanero 3 and Habanero 1 

as production and reinjection wells. 

We considered various options to maximise the potential 

power generation capacity based on 100 percent return of 

geothermal brine to the deep aquifer without depressurisation 

of the geothermal brine or the consequent release of the 

dissolved non-condensable gases, such as methane and carbon 

dioxide. Options evaluated were: 

• Kalina cycle. This technology uses a varying mix of 

ammonia and water around the cycle to maximise the 

energy recoverable. The boiling water and ammonia mixture 

can closely follow the brine temperature in the high-pressure 

heat exchangers. 

• Organic Rankine cycle. This technology uses an organic 

fluid, such as pentane, which is preheated and then vaporized 

in a series of heat exchangers. The high-pressure vapour 

can then be used to drive an expander in a manner similar 

to a conventional steam turbine plant. 

• Flash steam cycle. We developed this new concept after 

early modelling showed that a conventional steam power 

plant in which the water is preheated and then boiled in a 

series of heat exchangers could not realise the full potential 

for heat recovery from the brine. Under the flash steam 

cycle, circulating water is heated so that there is a constant 

temperature differential between the brine and the 

circulating water. The high temperature clean water can 

then be flashed down in two stages to produce steam that 

passes to a conventional steam turbine. The exhaust from 

the turbine is then cooled in an air cooled condenser, and 

this condensate is returned to the circulating water flow. 

A summary of the performance and strengths and 

weaknesses of the various options is shown in Table 1. 

Based on a detailed investigation of power plant options, the 

client elected to proceed with the proposed flash steam cycle. 

Figure 1: Summary of Performance Strengths and Weaknesses 


Power Plant Modular Approach 

Preliminary modelling has indicated that the production and 

reinjection wells should be spaced approximately 1000 m 

(3,200 feet) apart to achieve good long-term output from 

the geothermal resource. The cost of surface piping was 

found to be significantly higher than the marginal additional 

cost of deviated (directional) drilling, so we developed a 

configuration of five production and four reinjection wells 

that could be drilled from a common pad. 

The expected flows from the five production wells total 

approximately 500 kg/s (1100 lb/s) of brine, which will yield 

an average net power output of about 48 MW. This output 

is toward the upper capacity limit available from a standard, 

two-cylinder, low-pressure steam turbine. The deviated 

drilling limitations and steam turbine size limitations both 

suggested that this would be a convenient module size for 

development of the geothermal resource. 

High Pressure Heat Exchangers 

The brine heat exchangers have a very high design pressure 

that is in the range used for super-critical boiler feed 

pre-heaters. Unlike these heaters, however, the brine heat 

exchangers will require full access on the tube side so the 

tubes can be mechanically cleaned to remove scale that can 

result from the brine flowing through. 

We have had considerable difficulty in finding heat exchanger 

vendors who have the technology and experience in such 

high pressure construction and are willing to make an offer to 

design and build. It would seem that there is easily sufficient 

work available for the few experienced vendors available that 

they do not need to pursue comparatively small “one off” 

jobs. To overcome this problem, we have undertaken the 

thermal and mechanical design of the high pressure heat 

exchangers so that otherwise competent vendors are able 

to offer a construction only service. The design that we 

developed uses heavy forged tube plates and channels with 

pressure seal style, flat plate closures to the channels. 

Reinjection Pumps 

A review of available pumping technology for reinjection of the 

high pressure brine revealed that the multi-stage centrifugal 

pumps used in the oil industry represent the best available 

technology. These pumps have been developed to handle 

gassy hot fluids contaminated with sand, and they have given 

very good service.These pumps are offered conventionally in 

a submersible pump configuration that makes the seal design 

comparatively simple. For ease of servicing, however, our 

installation required a horizontal surface mount pump with 

conventional motor drive. 



Such a configuration presents very significant mechanical seal 

problems due to a maximum pump pressure of 45 MPa (6,530 

psi). Schlumberger, the pump vendor, was able to adapt its 

standard horizontal surface pump to take a new tandem seal 

design from Flowserve that uses brine that has been cooled 

through a small air cooler to provide the required seal water. 

Figure 3: Proposed power station. 


Plant Configuration 

The final proposed plant configuration is shown in Figure 3. As 

can be seen, the air cooled condenser dominates the facility. 

This novel variation on a conventional geothermal flash steam 

power plant that PB developed offers many advantages in 

that it: 

• Enables a very high recovery of energy from the geothermal 

resource 

• Utilises well proven technology 

• Provides a low risk solution to our client 

• Maximises the number of potential vendors for key items 

of plant. 

The heavy industrial experience of our staff in the Brisbane 

office has been used to provide a design for the high pressure 

heat exchangers and to overcome the lack of expertise 

with otherwise skilled fabricators in this class of construction. 

We were also able to arrive at a comparatively simple high 

pressure pump design in cooperation with a pump vendor. 

 


• http://www.soultz.net/version-en.htm 

• http://www.geodynamics.com.au 

Allan Curtis has been involved in heavy plant and process engineering for more 

than 35 years. His particular field of specialisation includes boiler and associated 

equipment design. Allan has been a key player in the design of several cogeneration 

plants incorporating biomass fired boilers or conventional gas turbine fired heat 

recovery boilers. 

PROJECT BRIEF: Tidal Power 

By Peter Kydd, Bristol, UK, 44 117 933 9232, kyddP@pbworld.com 

PB leads a consortium appointed by the UK government to 

evaluate options for tidal power generation from the Severn 

Estuary. The different options being studied include tidal 

barrages over 10-miles (16-km) in length spanning the 

English and Welsh coastlines, as well as tidal lagoons, tidal 

reefs and tidal fences. The majority of the options impound 

large volumes of water as the tide rises and then release it 

through turbines once sufficient generating head is created. 

Operation is similar to a hydropower plant, except that 

energy is produced in synchronization with the tides. 

The barrage options would require the construction of a dam 

across the estuary incorporating turbines and sluice gates and 

associated navigation locks. Tidal lagoons are artificial tidal 

impoundments constructed in shallower water areas but 

which do not dam the estuary. Tidal reefs and tidal fences 

are variants that utilize only a proportion of the available 

head but have reduced environmental impacts. With the 

tidal range of the Severn (the vertical difference between 

high and low tide), being up to 14 m (42 feet)—the second 

highest tidal range in the world—an estimated 5 percent of 

current UK electricity demand could be generated at a 

cost of circa US $30 billion. 

In addition to evaluating the engineering and technological 

aspects of the project, the PB-led team is undertaking a 

2-year strategic environmental assessment of the options. 

This is a major element of the overall feasibility study, 

which concludes in mid 2010. 

 

Peter Kydd is director of planning and environment in the Europe and Africa region (EA). He has 30 years’ experience working in the transportation, power, water and 

environmental sectors in the UK, Europe, Africa, Caribbean and the Pacific, primarily in the fields of strategic and planning consultancy. 



Converting Landfill Gas to High-Btu Fuel 

By Roger J. Lemos, Boston, Massachusetts, 1-617-960-4898, lemos@pbworld.com 

Landfill gases can no longer 

be released into the atmosphere 

in the USA. PB 

helped to design two of the 

largest and most sophisticated 

plants that clean 

these gases and convert them 

to a high-quality fuel suitable 

for use in homes, 

industry and energy generation. 

These facilities run 

unattended 24 hours/day. 


Btu: British thermal unit 

kJ/Nm 3 : kiloJoule per normal 

cubic meter 

Mmscfd: Million standard cubic 

feet per day 

Nm 3 /day: Normal cubic meters 

per day 

Figure 1: Greentree Landfill Gas Facility. 

The building housing the gas cleanup 

equipment is flanked by the SulfaTreat TM 

removal tanks on the left and the electrical 

switchgear building on the right. 

Figure 2: Interior of Greentree’s gas processing 

facility. The gas compressors raise the gas 

pressure to 200 psig before it reaches the Air 

Liquide membrane separation equipment. 


PB teamed with EMCOR Energy and Technology of Connecticut, the construction contractor, 

to engineer, procure, and construct (EPC) two high-Btu landfill gas projects for Beacon Energy 

of McLean,Virginia—the Greentree Landfill Gas Project and the Imperial Landfill Gas Project. 

Our role was to engineer and design a gas processing facility that would take raw landfill gas 

from a landfill and clean it through a process of compression, filtering, moisture removal, and 

membrane separation so that it would meet the gas quality requirements of the interstate gas 

transmission system. The product gas is transported via pipeline to the interstate gas pipeline 

system and then sold as green energy. 

These two projects are among the largest and most technologically sophisticated projects of 

their kind ever undertaken. The Greentree Landfill Gas Project (Figures 1 and 2) has the 

capacity to produce 5.38 mmscfd (144,453 Nm 3 /day) of high Btu product gas, and the Imperial 

Landfill Gas Project has the capacity to produce 2.69 mmscfd (72,226 Nm 3 /day) of the same. 

PB was responsible for: 

• Architectural, civil, structural, mechanical, electrical, and controls system design 

• Startup and performance testing of each facility to ensure that the projects met 

the production and quality requirements of the contract. 

Background and Overview of the Projects 

The decomposition of waste in a landfill produces methane gas and carbon dioxide that, if 

not controlled, are released to the atmosphere. US Environmental Protection Agency (EPA) 

regulations require these landfill gases be captured and thermally destroyed to reduce the 

greenhouse gas emissions. All landfills are required to have top and bottom liners and gas 

collection systems to capture the landfill gas. Thermal oxidizers (known as flares) are then 

used to destroy the methane gas. 

The EPA has a program called Landfill Methane Outreach Program that encourages 

the beneficial and productive use of the methane produced by landfills as a fuel 

source. The composition of landfill gas is typically about 50 to 55 percent methane 

and 30 percent carbon dioxide. Water vapor, oxygen, nitrogen, hydrogen sulfide 

and some trace elements make up the remainder of the gas composition. 

The Btu content of landfill gas is low, but sufficient to produce heat in a boiler or 

electricity in a reciprocating gas engine. High-Btu landfill gas projects can raise 

the Btu value of the landfill gas considerably, however, and remove harmful 

contaminants. 

The high-Btu projects we designed increase the methane content to about 

95 percent by removing other elements of the landfill gas by the following 

methods: 

•Carbon dioxide and oxygen: a membrane separation technology provided 

by Air Liquide 

•Water vapor: a series of knock-out tanks, demisters and coalescing filters 

•Hydrogen sulfide: a chemical absorption process. 

The resultant product, or residue gas, has a Btu value of more than 960 

Btu/cubic foot (37,684 kJ/Nm 3 ). It meets all the requirements for pipeline 

quality gas that is used in homes, industry, and energy generation. 



Project Challenges Met on Time 

We started working with the project developer, Beacon 

Energy, in September of 2004 to meet the first challenge of 

this project, which was to get project financing. It was at this 

early stage that we elected to team up with EMCOR Energy 

and Technology. Working with these two firms, we reviewed 

the feasibility of both projects, evaluated technical alternatives, 

visited the project sites, and developed preliminary 

engineering solutions that would meet the technical and 

commercial requirements. These efforts were successfully 

culminated when in July of 2006 the project received $60 

million in non-recourse financing from John Hancock Financial 

Services, Inc. A key factor in obtaining the non-recourse 

financing was the guarantees of schedule, cost, and 

performance in the EPC contract between Beacon Energy 

and EMCOR. 

Engineering and design of the two projects started in July of 

2006 with the execution of the EPC contract. The challenges 

that faced PB during engineering and design included: 

• Specification and procurement of the gas blowers, compressors, 

Air Liquide membrane units, hydrogen sulfide removal 

system, electrical switchgear, and plant control systems 

• Coordination of the plant design with the upgrade of the 

landfill gas collection system, modification to the landfill gas 

flares, pipeline to interstate gas pipeline system, and utility 

electrical interconnection 

• Site civil grading and drainage 

• Building and equipment foundations 

• Mechanical piping systems 

• Electrical power and control systems 

• Plant control system. 

Construction of the Greentree Gas Processing Facility started 

in October of 2006 and was completed in August of 2007; and 

construction of the Imperial Gas Processing Facility started in 

November of 2006 and was completed in September of 

2007. The aggressive construction schedule could not have 

been achieved without the cooperation of the members of 

PB’s civil engineering group and power hydro structural 

group, who were responsible for the site civil, grading and 

drainage, building foundation, and equipment foundation design. 

Project Successes 

Upon the completion of construction, PB conducted the 

performance testing to ensure that each facility was in 

compliance with the performance requirements in the 


contract. They were, and both projects have been operating 

continuously since turnover to the client. They had many 

notable commercial, technical, and environmental 

accomplishments, including those that follow. 

Most Notable Commercial Accomplishment. These are 

the only landfill gas projects that have qualified for long-term 

non-recourse project financing. Project financing was difficult 

to obtain due to the size and complexity of the projects and 

the fact that unproven new technology would be used to 

process the landfill gas. 

Major Technical Accomplishment. The engineering and 

design of the landfill gas processing equipment and control 

systems was the major technical accomplishment. The 

membrane separation technology used to separate the 

methane gas from the landfill gas had never been used 

before at the scale of the Imperial and Greentree Projects. 

PB and EMCOR had to perform extensive engineering and 

design to integrate the gas collection, compression, moisture 

removal, hydrogen sulfide removal, and gas separation 

technologies into a seamless process that could run 

unattended 24 hours a day. A complete and fully automated 

plant control system had to be developed to allow the plant 

to be operated safely. 

Most Impressive Environmental Benefit. Harmful 

greenhouse gases were eliminated from the environment 

and converted into green energy, thereby also reducing 

dependency on foreign sources of energy. A quantification 

of environmental benefits, using the EPA’s Landfill Gas Energy 

(LFGE) Benefits Calculator, yields annual benefits equivalent 

to any one of the following, based on 15,000 standard cubic 

feet/minute (402 Nm 3 /min) of landfill gas being processed: 

• Reducing CO2 emissions by more than 200,000 tons/year 

• Removing emissions equivalent to more than 340,000 vehicles 

• Planting the equivalent of more than 490,000 acres of forest 

• Displacing the use of 4.0 million barrels of oil 

• Producing enough energy to heat approximately 112,000 

homes. 

The significant technical and environmental accomplishments 

were recognized when the EPA’s Landfill Methane Outreach 

Program (LMOP) awarded the Greentree Project the 

2007 EPA Project of the Year Award. 

 


• www.epa.gov/landfill 

Roger Lemos is a vice president with the PB Power group in Boston. Since starting with PB in 1994, Roger has worked on power projects throughout the USA ranging 

from 4 to 640 megawatts. 




Photovoltaics, With a Focus on Spain 1 

By Rafael Mnez. de Lejarza, Barcelona, Spain, 34 93 508 8520, lejarza@pbworld.com 

The author sheds light on 

the growth in solar photovoltaic 

(PV) power generation 

around the world. He 

then tells about some of the 

work PB is doing in Spain, 

which is emerging as one of 

the world’s leaders in PV 

power. This work includes 

geotechnical work, foundations, 

environmental studies 

and yield production 

assessments. 


• RETSCREEN 

http://www.retscreen.net/ 

• PVGIS 

http://re.jrc.ec.europa.eu/pvgis/ 

• European PV IndustryAssociation 

http://www.epia.org 

• Spanish PV Industry Association 

http://www.asif.org/ 

• http://www.pvresources.com/ 

• http://www.solarserver.de/ 

• Spanish association of 

renewable energy producers 

http://www.appa.es 

• http://www.renewableenergy 

magazine.com/ 

Rafael Mnez. de Lejarza has worked 

five years with PB. He has twenty years’ 

professional experience as engineering 

manager and head of energy projects, 

and five years’ experience as systems 

and start-up engineer in nuclear power 

plants. Rafael has worked as an expert 

consultant with the International Atomic 

Energy Agency (OIEA). From the PB 

Barcelona office he leads a staff team 

working on conventional and renewable 

energy power plant developments. 

1 La edición en lengua española del 

presente artículo está disponible en 

la dirección Web de PB Network. 

The photovoltaic (PV) market has grown quickly in the last few years. Worldwide, 1,598 MW 

of photovoltaic power were installed during 2006 and 2,246 MW during 2007, representing 

a more than 40 percent increase in installation activity in one year. Total PV capacity at the 

end of 2007 was 8.7 GWp. Indications are that the solar PV market will keep growing and 

expectations for its future are bright. 

Locations of the world’s large-scale PV plants (those above 200 kWp) are as follows: 

• Almost 80 percent in Europe (700 MWp) 

• Approximately 16 percent (142 MWp) in the USA 

• Just under 4 percent (34 MWp) in Asia, with much of this being in Japan. 

Other areas of the world, namely Africa, South America and Australia, are home to less than 

1 percent of the world’s large PV plants. Nevertheless, we expect to see an increase in PV 

installations in these regions and in China, which has considerable potential for PV generation. 

European Sector 

Western European counties vary in the scope of their adoption of PV installations. For example: 

• Germany has exceeded the predictions for PV installations, with that country now having 

about 60 percent of Europe’s large PV plants. 

• Spain has 35 percent (245 MWp) of Europe’s large-scale PV plants. Spain was also the 

most active market in 2007, installing 451 MW PV power capacity of any type, for a total of 

697 MW PV by the end of 2007. 

• Italy reached 2.4 percent in 2007, with 17 MWp. 

• Portugal and the Netherlands have a bit more than 1 percent. 

• Belgium, Luxemburg and Switzerland have less than 1 percent. 

Decreasing feed-in tariffs are supporting the rise in PV installations. For example, France and 

Italy offer compensation incentives when PV systems are integrated into buildings. The lowering 

tariffs, which will increase the profitability of PV installations, and the high number of hours of 

sunshine in many European countries could make increased investments in PV worthwhile. 

Currently, the Spanish market is regulated by legislation that requires a feed-in tariff, depending 

of the type of plant and power. Changes are expected due to upcoming new binding laws that 

will affect these tarrifs, but what these changes will be is still not clear. Spain’s high interest in PV 

is due in part to its solar radiation, which enables installations to obtain a high output per kWp. 

Spain has now achieved 85 percent of the objective defined in its Renewable Energy Plan (REP) 

2005-2010. Forecasts are that the PV market in Spain will continue to grow after a slight 

slowing down. It is also expected that technological improvements in manufacturing and the 

resultant decreasing prices of PV cells will further encourage investment in Spain’s PV 

installations. 

New Technologies 

PV cell production has increased globally in the last decade. The predominant technologies 

used include the following: 

• Wafer-based crystalline silicon, which is considered the first generation PV technology. 

There are two variants of these cells with different material structures—mono- or multicrystalline. 

About 90 percent of all PV applications are currently silicon wafer-based. 

• Thin-film technologies, or vacuum technologies, where the solar cells are deposited 

directly on a glass or plastic carrier substrate. Thin-film technologies either use a very thin 

coating of silicon, which uses up to 99 percent less silicon than a solid silicon cell, or use no 

silicon whatsoever and rely on other photovoltaic materials. Existing thin-film technologies are: 

– Thin-film silicon (TFSi), which is based on amorphous silicon or silicon-germanium and 



microcrystalline silicon. 

– Copper-indium/gallium-diselenide/disulphide and 

related HII-VI compounds (CIGSS), which have 

the highest efficiency of the thin-film technologies 

– Cadmium telluride (CdT), which is simple and stable 

due to its ionic nature. 

Thin-film production is not very high currently, but it might grow 

by 2010 due, in part, to the advanced thin-film technologies 

being developed. A factor driving such development has been 

the shortage in silicon production, especially during about 

2004 to 2006, coupled with the computer chip industry’s 

high demand for silicon and ability to pay high prices for it. 

Manufacturers are developing new products and solutions for 

using less silicon per MW. An example of this is concentrating 

photovoltaic (CPV), which uses tandem triple-junction cells 

that are reaching higher system efficiencies. 

Projects That Are Helping Spain Meet Its 

Renewable Energy Goals 

A major boost for PV plant development was brought by 

the Spanish Royal Decree 436/2004, which spurred growing 

interest among companies and investors. PB’s power 

specialists in Spain have been involved in several important 

PV initiatives, including the following. 

• Aldover PV Plant. In 2004 we started the complete 

development activities for the 5 MW Aldover PV project 

using fixed PV module technology. Our tasks on this 

project include: 

– Providing advice on the interconnection process with the 

local electricity company and on the PV plant permitting 

procedure 

– Preparing the technical project for the application 

request for the Register of Special Electricity Producers 

(REPE), and for the Administrative Authorization 

– Managing the technical documentation and 

environmental licenses application request. 

In addition, the regional administration obliged our client to 

downsize the available land to implement the PV plant due 

to environmental and landscape issues. In response, we 

investigated how to maximize the installed power within 

the allowed land surface. 

• Juneda PV Plant. In 2006, we started the complete 

development activities for the 0.9 MW Juneda PV project 

with fixed PV module technology, providing services similar 

to those provided for the 5 MW Aldover PV Plant. 

• Capmany PV Plant. In 2006 we commenced the 

development activities for another 0.4 MW photovoltaic 

plant (Capmany PV project), with fixed- and single-axis 

tracking system PV module technology. 

• Central Spain Project. Since the end of 2007 we have 

completed a due diligence of four photovoltaic plants with 

15.9 MW total power, fixed PV module technology in 

central Spain, required for the assessment of the potential 

asset purchase. 

57 PB Network #68 / August 2008 


• Toledo, Spain Project. We performed an independent 

engineer’s study for a 10 MW PV plant with double axis 

tracking system in Toledo, Spain, to be considered in a 

purchase decision. 

Technical Skills and Roles 

As it happens with other renewable energy sources, the process 

of developing a PV plant involves a wide range of technical 

skills and roles. Different actors who are responsible for different 

areas have contributed to our projects from a technical point of 

view and by helping to meet the diverse requirements of 

many state, regional and local agencies that issue all required 

permits. Typical required technical studies we have been 

managing for our clients in Spain include those discussed below. 

Geotechnical studies on the ground conditions. These 

studies require rotary tests with sample core extraction for 

standard penetration tests (SPT) on a sample of locations in the 

PV plant terrain in order to define the geotechnical engineering 

properties of the soil. Field surveys are also required so 

that the geological conditions of the terrain are taken into 

consideration when defining the types of foundations for 

the module structures. 

The foundation type used commonly is a concrete foundation. 

Recently, however, more simple and cost-effective methods 

have been applied by drilling the structure base sheets into 

the ground when the soil conditions are appropriate. Special 

solutions for unstable or unpredictable grounds can be applied 

by drilling to install posts/piles to support the PV module 

structures. This latter method is considered a special solution 

used to sort out later problems that would appear if the PV 

panel structures were mounted in unstable/unpredictable 

soils. In this case, a concrete foundation would be used to 

join the structure base with the posts. 

Environmental impact assessment studies (EIA) and 

landscape studies. These studies are commonly required 

by the environmental departments of the administration. 

The studies were key documents in the permitting process 

for the PV plants mentioned above because environmental 

impacts have become more and more important to the 

public audience, and they are crucial for the regulatory 

authorities that issue the permits. 

Yield production assessment reports. These reports are 

essential for the financial assessment of the project. Software 

used commonly to make such assessments includes PVsyst, 

Censolar or FVExpert. We have used the first two of these 

to carry out yield production estimations for the client. 

A Growing Trend 

Indications are that PVs will become increasingly important in the 

growing renewable energy participation in the energy generation 

mix around the world. Currently we are investigating opportunities 

in southern Europe and northern Africa, areas that are 

showing a growing interest in renewable energies.

TRANSMISSION AND DISTRIBUTION: 

Transporting Power Across the Grid 

Electricity Transmission: 

Building on 120 Years of Experience 

Since 1899, PB has been involved in all aspects of electrical power transmission, ranging 

from feasibility studies and design of industrial and rail transportation systems to large 

power utility systems. The scope of the transmission projects we have undertaken recently 

is vast, and includes: 

• System studies of power flow, fault level, stability and insulation co-ordination; and 

implementation of schemes to maximise power transmission levels 

• Control of system voltage and power flows under normal and faulted situations 

• Design of overhead lines and substations 

• Development and implementation of transmission and sub-transmission projects. 

Some specific projects include the development of the first 500 kV transmission network in 

Indonesia; expansion and refurbishment of the 400, 275, 132 kV networks in Orissa, India; 

specification, approval and supervision of the first 500 kV system in Argentina, the Northern 

Ireland Interconnector 275 kV transmission system; the Merowe Dam Project 500 kV/220 kV 

transmission and substation in Sudan, the; 500 kV transmission line and substation for the 1200 

MW Illijan Power Plant in the Philippines; and the feasibility study for developing an off-shore 

HVDC network to interconnect renewable energy sources for transmission to UK load centres. 

The articles in this section illustrate the breadth of the technical knowledge and expertise 

within PB in creating innovative solutions geared towards the maximisation of existing assets 

necessary in transmitting power across the grid. PB’s role as a lender engineer is demonstrated 

in the first article by Fleur Parkinson about a power transmission project in Cambodia. This 

project enabled PB to draw on one of its strengths: the adoption of a multidisciplinary approach 

and involvement of engineers across different national boundaries to address the challenges 

of that project. The second article by M.R. Jayasimha describes the upgrading of the Abu 

Dhabi transmission network to 400 kV due to increase in load growth. 

HVDC technology has been used to transport powers over long distances using cables. The 

next article by Paul Tuson proposes a possible HVDC transmission link so that the power 

utilities within the South African Development Community countries can take advantage of 

availability of fuel resources to supply power at minimum cost, improve system reliability and 

maximise reserve margins. This section concludes with an article by Conor Reynolds illustrating 

the far-sightedness of some of our specialists who developed an accurate and cost-efficient 

network assessment programme for transmission networks, but can be equally effective for 

other applications within the power industry. 

Please see page 89 for a list of several articles on transmission projects from past PB publications. 

Arthur Ekwue 

Principal Power Systems Engineer, Godalming, UK 

Coordinator of PAN 57, Power System Analysis, Planning & Restructuring 




Meeting the Need for Reliable, Cheaper and 

Nonpolluting Electricity in Cambodia 

By Fleur Parkinson, Hong Kong, 852 2963 7640, parkinsonF@pbworld.com; and Jon Roe, Singapore, 65 6290 0615, roeJ@pbworld.com 

A major new electricity 

transmission project in 

Cambodia helped to lower 

the cost of electricity significantly 

and improve its 

reliability and provision in 

the northwest portion of 

the country. The authors 

summarize PB’s involvement 

in the project and 

discuss the challenges 

faced by the project team, 

including those related to 

performing site work under 

adverse conditions. 

Figure 1: Route of Cambodia’s 

new transmission line in northwest 

region. 

Cambodia has made considerable progress in reforming its power sector, particularly in 

passing the Electricity Law in 2001 and establishing a regulator. The country has had one 

of the lowest electrification rates in Asia, however, with only 12 percent of its population 

(approximately 14 million) connected to a power supply. In addition, Cambodia has some 

of the highest electricity costs in the world. 

The main supplier of electricity is the state-owned Electricite du Cambodge (EDC), which is 

aided by a few local independent power producers (IPP). Generation is provided mainly by 

using diesel generators, so already high costs have increased with rising oil prices. While the 

supply of electricity is fairly reliable in the main towns, its high price has led many large 

consumers to run their own generators (also diesel). Provincial towns and rural areas rely on 

even more expensive and less efficient diesel generating units that provide erratic supply. The 

only power in rural areas and in villages along the transmission lines is generated through the 

use of car batteries that local entrepreneurs charge by using diesel or petrol generators. The 

cost of power in these areas is twice that supplied in the towns, and the discarded batteries 

create a hazardous waste issue. 

Electricity is the main concern for the development of the private sector as the limited supply 

of electricity raises production costs and limits technology development compared with 

neighboring countries. One of the country’s key priorities in the medium term is to alleviate 

shortages of reliable power and reduce electricity costs in order to help develop its economy 

and reduce poverty. To this end, a new transmission project was recently completed that 

imports electricity from Thailand to the northwest region of Cambodia. 

Transmission Project Overview 

Power is imported into Cambodia from the 115/22 kV Aranyaphathet substation located in 

Thailand, 15 km (9 miles) from the Thai/Cambodian border. Power is transmitted to the town 

of Banteay Meanchey, where the line diverges south and east to supply the towns of Battambang 

and Siem Reap (Figure 1). The transmission project aimed to meet the urgent 

need of electrical power in all three regional centers. The need was considered 

especially great in Siem Reap, however, to support a rapidly growing 

tourist industry attracted by the Angkor Wat World Heritage Site. Prior to 

energization of the transmission project, a number of newly constructed 

hotels in the area relied on in-house generators fuelled by imported diesel. 

The project, which will be part of the national grid, includes: 

• Three 115 kV/22 kV substations (at Battambang, Banteay Meanchey and 

Siem Reap) 

• One 115 kV switching station 

• Approximately 221 km (137 miles) of a single-circuit 115 kV transmission 

line traversing three provinces of northwest Cambodia. 

The transmission line uses standard self-supporting reinforced-concrete poles 

22 m (72 feet) high, allowing 80-m (262-foot) spans. The poles are inserted 

into precast concrete foundations with double-circuit 400 mm 2 (0.6 square-inch) 

all aluminum conductor configurations. All line elements follow the standardized 

Thailand design for 115 kV transmission lines using concrete poles and 

steel lattice towers. 

 



The transmission project was built along existing roadways and 

on four plots of land to accommodate the three substations and 

switching station (Figure 2). Some 18 km (11 miles) of the 

transmission line crosses paddy fields through an optimized 

bypass route around Banteay Meanchey to reduce the need 

to acquire land in the town. This section uses self-supporting 

steel lattice 

towers 35 m 

(115 feet) high, 

which allow 

260-m (853-foot) 

conductor spans, 

thus reducing the 

number of towers 

and attendant 

land purchases. 

Figure 2: Transmission towers crossing a 

rice paddy field between Battambang and 

Banteay Meanchey. 

In 2005, a thirtyyear 

concession 

to develop a 

build, operate and transfer (BOT) project was awarded by the 

government of Cambodia through EDC to Cambodia Power 

Transmission Lines (CPTL), a private joint venture between SKL 

Group’s A.S.K. Co., Ltd. and M O Consolidation Service Ltd. A 

power transmission agreement (PTA) was signed between EDC 

and CPTL committing EDC to pay a transmission charge 

calculated from the amount of 22 kV energy received at 

the various delivery points. 

PB’s Involvement 

The transmission project is the first private sector power 

transmission project in Cambodia and one of the country’s 

first commercially financed projects. PB was appointed by 

Asian Development Bank (ADB) to serve as the lender’s 

engineer for ADB and a small group of commercial lenders 

on a US $20 million loan to CPTL. The total cost of the 

project was estimated at US $34 million. 

Our team visited the project on a number of occasions, 

conducting inspections before and during construction, which 

commenced in January 2006, and prior to energization in 

November 2007. In December 2007, we completed the 

technical due diligence by reporting on the design and 

installation of the substation and transmission lines and on 

the outstanding environmental and social issues. 

The project involved the collaboration of PB specialists 

among different disciplines (PB advised ADB on technical, 

environmental and social issues) and across different continents 

(PB specialists were sourced from Australia, Singapore, the 

Middle East, Hong Kong and Thailand). 

Project Challenges 


While the project, being a basic transmission line, was 

appropriately straightforward and did not present particularly 

difficult or innovative technology, working within a country 

that is developing and is largely undeveloped outside the main 

cities proved challenging. Issues that were interesting and somewhat 

unique to this project included those discussed below. 

Former War Zone Challenges. The transmission line 

crossed ‘no man’s land,’ a 600-m (2,000-foot)-wide strip 

between Cambodia and Thailand that was heavily mined 

during Cambodia’s civil war. This well-vegetated area (a result 

of the landmines) is owned by neither Thailand nor Cambodia, 

although both countries wish to keep the land in its current 

state for security reasons. The presence of landmines over 

this wide swath resulted in the design and construction of 

two suspension-type towers 82 m (269 feet) high supported 

by two anchor-type transmission towers 44 m (144 feet) high). 

This design was used previously for crossing the Mekong River. 

The ground below the transmission line close to this border 

had to be cleared of landmines before construction could begin. 

Technical Challenges. We concluded that the substations and 

switching station had been installed and tested to a high standard 

and the components were determined to be well proven and 

of standard design. 

As with all projects, there were local conditions to consider. 

Flooding of the fields in the wet season, for example, 

influenced the materials and structural aspects of the poles. 

We were required to verify whether the poles were of a 

design suitable for the terrain. Concerns were raised following 

two separate incidents in which the concrete poles had 

failed, resulting in the collapse of the several poles. Reasons 

for these failures were: 

• A Caterpillar excavator that was working on a separate road 

upgrade project dug around one of the pole foundations 

and exerted pressure on the exposed foundation. 

• A large mango tree blew onto the line during a heavy storm. 

Our assessment was that the poles had been constructed to 

international standards, but were subjected to undue forces 

that they were not designed for (nor would be expected to 

be designed for) as a result of third party actions and 

extreme weight that was above the design loads. 

Improvements are still being made in order to balance the 

requirements of the transmission project with other development 

infrastructure projects in Cambodia. In one instance a 

temporary road bypass scheme meant that one of the transmission 

poles ended up in the middle of a carriageway with 

cars having to drive on either side of it. In another, a heavy 

vehicle weigh station (from another project) had been built 



directly underneath the line and we were required to assess 

whether any further construction rectification was necessary. 

Our team is currently providing operation and maintenance 

assistance so that prudent international utility practices 

are applied in operation and maintenance and that the 

transmission line is maintained and operated profitably for 

the life of the project loan. 

Environmental Challenges. To satisfy ADB’s terms of lending, 

we conducted a review of the project against both ADB’s 

lending policies and the Equator Principles (2006). The 

transmission project was considered to be a “Category B” 

project and was expected, therefore, to have very minor and 

only temporary adverse environmental and social effects 

during construction and essentially no effect of either kind 

during its 30 years of operation. The low environmental risk 

was assigned to the project mainly due to the small foot 

print of the poles and the fact that approximately 92 percent 

of the transmission line was being built along existing roads’ 

rights-of-way (ROW), with the remainder in paddy fields with 

no requirement for large-scale removal of vegetation. 

The project was also considered beneficial in that it will 

substantially displace the inefficient and polluting generation 

of diesel or bunker oil at the load centers and reduce the 

need to transport fuel on numerous tanker trucks to feed 

those stations. It was estimated that the project would forgo 

the necessity of building an estimated 23 MW to 80 MW in 

additional diesel or fuel oil plants with adverse environment 

and road traffic impact and would reduce carbon emissions 

by at least 32,055 tons a year (assuming 100 GWh of diesel 

consumption a year). 

Social Challenges. In addition to the social due diligence, 

we prepared a Short Resettlement Plan (SRP) for the project 

in accordance with ADB’s lending requirements. Plots of land 

for the base of the steel lattice towers, substation and 

switching station (totaling approximately 5 ha (12 acres) to 

4.5 ha (11 acres) for the substations and switching station and, 

0.5 ha (1 acre) for the steel lattice tower foundations) were 

purchased from willing land owners, who were allowed in most 

instances to continue to use the land to grow rice beneath 

the towers. Compensation was paid for the placement of 

certain poles on land already in use. These were mostly 

encroachments within the ROW even though land was in 

the ROW and not owned by the affected persons. 

The project compensation had been funded initially by the 

local governments, as is common practice with development 

projects. There was little management of the compensation 

monies allocated to the local authorities and practically no 

documentation undertaken. This made it virtually impossible 

to establish if the ADB safeguards had been complied with. 

We undertook an audit of the delivery of compensation to 


determine if affected persons had been compensated and if 

they were satisfied with the compensation. The audit consisted 

of extensive public consultations, site visits and numerous 

household calls. The assessment confirmed that project 

property has been purchased at market rates with willing 

buyers who participated voluntarily in the transactions and 

that people were happy with the compensation (which was 

often in excess of compensated paid by similar development 

projects in Cambodia). 

Conclusions 

With the transmission line now up and running, Cambodians 

are less dependent on the more expensive option of smallscale 

diesel-based generation that emits more carbon dioxide 

and, therefore, has a greater environmental impact. Private 

establishments, such as shops and restaurants, have been able 

to extend operational hours and invest income, previously 

spent on electricity, in their business. A testament to this 

advantage came from a restaurant owner who was able to 

buy a refrigerator because her electricity costs were now 70 

percent lower per month (from US $100 to US $30) even 

though longer operating hours were possible. Furthermore, 

the electricity supply was reliable. 

Although we were employed by ADB, we worked closely with 

both the client and the developer to overcome technical 

challenges as they arose, which meant that we could suggest 

solutions to improve the project as it developed. We are 

currently assisting the client and developer further by 

investigating the possibility of using step-down transformers 

so that rural electrification can be achieved and more 

Cambodians can benefit from the project. 

The transmission project will substantially promote development, 

as it will provide the means by which EDC can import 

least-cost electricity for distribution to underserved regional 

load centers. As demand grows, EDC will be able to use 

larger, more efficient generating units, and eventually reduce 

tariffs to levels competitive with the rest of the region. 


• World Bank (2007): Cambodia Country Information [Accessed 22 April 2008] 

Fleur Parkinson is an environmental consultant based in the Hong Kong office. 

Fleur has experience in completing environmental projects for clients in a number 

of sectors and is currently involved in undertaking energy-related projects in Asia. 

Jon Roe is the environmental consultant for the PB Singapore office. Jon has 

a strong background in environmental impact assessments, construction and 

contaminated land projects in Australia, and has been actively involved in the 

environmental aspects of a wide range of PB’s energy projects in Asia. 




Rehabilitation and Reconstruction of Abu Dhabi 

Transmission Network By M.R. Jayasimha, Abu Dhabi, 971 50 4554907, jayasimhaM@pbworld.com 

The author tells how PB is 

assisting Abu Dhabi Water 

and Electricity Authority 

to further enhance the 

reliability of the emirate’s 

transmission and distribution 

network. He focuses on 

a modification to the 

switchgear and replacement 

of power transformers and 

a substation. 

Abu Dhabi’s electricity transmission network was established in the early 1970s at mainly 

220 kV and 132 kV levels. Since then, the country’s rapid rates of growth and development 

and characteristic high increases in load demand have led to an expansion of the network and 

upgrading to 400 kV. In addition, the Abu Dhabi Water and Electricity Authority (ADWEA) 

initiated a repair and rehabilitation project in 1999 to further enhance the reliability of the 

existing power transmission and distribution network. 1 

PB was selected as consultant for this important and technically complicated project. Once 

we completed the first phase of the project by 2002, we were awarded an extension for the 

second phase, which included new substations and a new scope of services for the rehabilitation 

and replacement of existing switchgear in transmission substations. 

Starting in January 2003, seven construction contracts worth US $70 million were awarded. 

These contracts included: 

• Single to double bus bar modification of 13 2kV gas insulated switchgear (GIS) in five substations 

• Replacement of ten 132/11 kV 40 MVA power transformers 

• Replacement of the existing 132 kV substation in the Taweelah Power Station Complex. 2 

Single to Double Bus Bar Modification 

The single to double bus bar modification of 132 kV GIS in five energised substations 

was a very specific and demanding task. The GIS in these substations was already in 

service for up to twenty years. The modification works required partial and in some 

cases complete shutdowns of the substation. The works were planned during the 

winter season because during the summer in Abu Dhabi maximum system demand 

occurs due to the high air conditioning loads. In one of the substations, the bus bar 

protection was replaced with numerical low impedance busbar protection during the 

modification works. In the other four substations, existing low impedance busbar 

protection was adapted for double bus bar type switchgear. Of the three types of 

switchgear to be modified, manufacturers had discontinued production of two of them. 

The busbar and isolator modules required for this modification were manufactured 

specifically for this purpose by the original equipment manufacturers. Figure 1 shows 

the switchgear before and after the modification. 

Replacement of Power Transformers 

Figure 1: W59 substation before single to 

double bar modification of 132kV GIS (top) 

and after (bottom). 

For the replacement of ten ageing 132 kV/11 kV 40 MVA power transformers, the 

design of the new power transformers was adopted to suit the existing transformer 

compound dimensions and the length of the existing high voltage cables. The 

opportunity was taken to also replace the transformer protection relays with latest 

numerical protection relays. In one of the GIS substations, a bus reactor bay was 

modified to provide a fourth 40MVA transformer. Ten new 11 kV feeders were also 

provided in this substation to receive power from the newly installed transformer. 

Existing 132 kV cables were reused providing new terminations at the transformer end, 

(page 67) 

1 For more information about Abu Dhabi Water and Electricity Authority’s (ADWEA’s) introduction of control systems in its transmission substations and PB’s involvement in this 

work, please read “Experiences and Trends in Automating Transmission Substations in Abu Dhabi” by Oleg Matic in PB Network’s 20th Anniversary issue (Issue 66), pp. 88-89. or 

on the the Web at http://www.pbworld.com/news_events/publications/network/issue_66/pdf/66_37_Matic_ExperiencesAndTrends.pdf 

Another of ADEWA’s projects to augment Abu Dhabi’s electricity supply is covered in “400 kV Interconnection of Abu Dhabi Island” by Walter Bullock, PB Network Issue 65, 

pp.79-80 or on the Web at http://www.pbworld.com/news_events/publications/network/Issue_65/pdf/079.pdf 

2 For information about the use of a PB invention that cut fuel consumption at the Taweelah complex, see “How Innovation Can Open Market Opportunities” by Paul M. Willson, 

PB Network Issue 63, pp 71-72 and on the Web at http://www.pbworld.com/news_events/publications/network/issue_63/63_26_willson_howinnovationcanopen.asp 




HVDC Transmission Strengthening in Southern 

Africa By Paul Tuson, Johannesburg, South Africa, 27-11-787-4141, tusonP@pbpower.co.za 

The author discusses some 

findings from a study PB did 

to help determine the best 

technical/financial solutions 

to improving the electricity 

transmission system in 

southern Africa. He tells of 

potential HVDC projects in 

the region and proposes a 

possible HVDC transmission 

link to the Cape that is 

fed from generation 

sources mostly in the north 

of the country. 

Africa’s electricity system is characterized by dispersed loads and generation sources spanning 

hundreds and in some cases thousands of kilometres. Connecting these generating sources and 

load centres is a challenge. Hired by Eskom, the South Africa electricity public utility, to derive 

the least-cost and best technical solution for strengthening power transmission for the Cape 

in South Africa, we looked into a possible high voltage dc (HVDC) solution to the challenge. 

Eskom plans to spend more than ZAR 345 billion (US $49.5 billion) on generation, transmission 

and distribution capital projects in the next five years. Among its projects underway are: 

• 4800 MW coal-fired Medupi Power Station, for which PB is serving as technical advisor 

and project manager 

• 4800 MW Bravo power station 

• 1400 MW Ingula pumped storage project, for which PB provided engineering services 1 

Similarly, many of the South African Development Community (SADC) countries have major 

generation and transmission projects in progress or at various stages of planning. The power 

utilities in the SADC countries will be seeking to maximize their reserve margins and trade 

any surpluses of power using transmission systems that connect the large new power sources 

with the large load systems in compliance with the South African Power Pool (SAPP). 


ac: alternating current 

dc: direct current 

DRC: Democratic Republic 

of the Congo 

HVDC: High-voltage direct 

current 

SADC: South African 

Development 

Community 

SAPP: South African Power 

Pool 

The Connection Challenge 

Loads in the South African region are growing at an annual rate of between 3 percent and 

6 percent. Eskom’s 2007 maximum demand exceeded the record achieved in 2006 by more 

than 1500 MW. As loads continue to grow in the SADC countries, the challenge will be to 

connect them to new and dispersed generation sources. Figure 1 depicts some possible 

HVDC solutions in the SAPP. The thick, dotted lines depict possible future HVDC transmission 

interconnectors. 

In the figure, dc lines are shown connecting the Capanda hydro generation in northwest 

Angola to the Ruacana hydropower station in northwest Namibia. Another possible dc interconnector 

connects Namibia with Zambia (via a dc link from Gerus substation in Namibia to 

Figure 1: 

Possible dc 

interconnectors 

in the South 

Africa Power 

Pool. 

1 For more about pumped storage technology and the Ingula project, please read 

“Pumped storage technology: recent developments, future applications” a following 

article by Ian McClymont and Paul Reilly. 

63 PB Network #68 / August 2008 

Katima Malilo in the Caprivi strip) and Botswana (via a dc link 

from Auas substation in Namibia to Isang substation in Botswana). 

Other possibilities we identified include the following: 

• A dc transmission link interconnecting the Kariba hydro 

generation in Zambia with South Africa and indirectly connecting 

the DRC hydro generation with South Africa in advance of the 

proposed WestCor Project, which would connect an initial 

4000 MW and eventually 40 GW from the Inga power station 

in the DRC, 3000 km (nearly 2,000 miles) from South Africa, 

to various African countries. 

• A dc system connecting existing and planned hydro generation 

and planned coal-fired thermal generation in the centre of 

Mozambique with Maputo in the South of Mozambique or 

with Richards Bay in South Africa. 

• A dc transmission line connecting Zambia to Tanzania via 

Kabwe or Pensulo substations in Zambia and Iringa or Singida 

substations in Tanzania. 

• Connecting the major generating centre in the north of South 

Africa with large load centres in the Cape and Kwazulu 

Natal areas.


Typical HVDC Configurations 

The following are typical HVDC configurations (a dc line with 

connected converters is referred to as a pole): 

• Monopole with earth return or metallic return (with monopole 

designs, the earth electrode or metallic earth return conducts 

full current during normal operation) (Figure 2) 

• Bipole with earth return or metallic return (Figure 3) 

• Bipole without earth return or metallic return. 

Figure 2: Monopole with earth or metallic return. 

Figure 3: Bipole with earth or metallic return. 

In a bipole configuration, the converter stations are arranged 

to operate at equal but opposite line voltage so that the 

current in the earth return path is very small under normal 

operation. One of the advantages of the bipole dc configuration 

if there is a working earth return path or a metallic 

return is its 50 percent redundancy. With one pole out of 

service, the remaining pole operates in monopole mode and 

can still transmit 50 percent of the link power. Bipoles can 

be designed to transmit up to 75 percent of link power 

for short periods under loss-of-pole contingencies if the 

converter equipment is designed for short-time overload. 

Figure 4 shows some transmission tower configurations for 

monopole and bipole dc solutions. 

• Left drawing shows the simplest monopole earth return 

tower configuration. In this instance, the earth electrodes 

and the earth return operate continuously. 


• Center drawing depicts a bipole configuration without a 

metallic return. 

• Right drawing depicts a bipole configuration on a single 

structure.The advantage of a double-circuit tower bipole 

configuration is the lower cost (one tower and set of foundations 

instead of two). Its disadvantage is its vulnerability 

to common mode failure; e.g., a tower collision can take 

out both lines and, thus, both poles instead of only one line. 

In Africa, where there are semi-deserts or sparsely 

populated areas, monopole earth return configurations may 

be attractive due their low costs (only one overhead conductor 

bundle and one converter is required at each end of the 

dc link). In addition, these dc monopole links may connect 

radial ac systems, so the requirement for dc redundancy or 

for (n-1) operation of the dc link becomes less necessary. 

In some weak African systems, conventional dc converters 

or line commutated converters (LCC) cannot operate as the 

short-circuit-to-power transfer ratios at both converters do 

not exceed the necessary level of three (SCR


Figure 5 depicts the South African generation and transmission 

system in a highly schematic way. The major generation system 

in South Africa, which is located in Mpumalanga, supplies 

Johannesburg, Pretoria, Durban, Richards Bay, Cape Town and 

Port Elizabeth. When and if the Medupi, Mmamabula and 

Mmamantswe power stations are commissioned (in the 

north west of South Africa and in Botswana), capacity on the 

Mpumalanga power stations will be released to supply large 

growing load in the Central Area, Eastern area and the Cape. 

Medupi power station is an Eskom coal-fired power station 

with a design capacity of 4800 MW. Mmamabula and 

Mmamantswe power stations are proposed IPP coal-fired 

power stations north of Gaborone City, in Botswana. 

The dc transmission will not be stranded if large generation 

power stations are constructed in Cape Town because it can 

be used to transmit power from the south to the north 

when large nuclear power stations come on stream in the 

Cape and increase the stability of the transmission link. 

A second option is to strengthen the networks to the Cape 

via a 765 kV ac system from Zeus Substation in Mpumalanga 

to Omega Substation near Koeberg Power Station in the 

Cape (Figure 6). 

Figure 6: 

Proposed ac 

strengthening to 

the Cape. 2012 

765 kV 

Zeus-Mercury- 

Perseus-Gamma- 

Omega. 


Another benefit of a dc link to the Cape, as stated above, 

would be its contribution to system stability, over the very 

long transmission distance (1400 km) between northern 

generation and southern generation systems. 

Conclusions 

Figure 7: 

Proposed dc 

strengthening 

to the Cape. 

2012 

765kV AC 

Solution 

followed by 

DC to Gamma 

from Zeus. 

DC can be a cheaper transmission alternative to ac over long 

transmission distances while also improving system stability 

and providing improved reliability due to the requirement for 

fewer conductor bundles and the redundancy in the dc 

bipole configuration. Depending on the nature of the African 

systems involved, cost effective monopole earth return dc 

options can be investigated. Where more reliable and robust 

transmission systems are required, bipole dc systems can be 

investigated. DC is a credible transmission option for 

strengthening the Cape in South Africa. 

 


• http://www.eepublishers.co.za/view.php?sid=5057 

Figure 7 shows part of the ac system as proposed in the 

previous Cape strengthening option followed by a dc bipole 

system from Zeus Substation to Gamma Substation in the 

Northern Cape. 

A 500 kV 2000 MW bipole solution could be investigated. 

This solution would add 1000 MW power increments in each 

pole of the bipole, matching the power output of single 

Koeberg Power Station units. Operationally, a loss of a single 

pole would only disrupt the system by 1000 MW. The 1000 

MW disruption could be reduced if the remaining pole is 

designed with a short-time overload capability. 

Acknowledgment: I wish to thank fellow engineers and colleagues for their 

assistance and contributions to this article. 

Paul Tuson is a degreed Transmission Studies Specialist with more than 18 

years’ post graduate experience in power electrical engineering in Southern Africa, 

the UK, Australia, the USA and the Middle East for voltages up to 765kV. Key 

experience is in the areas of system analysis and financial/economic evaluation 

of capital projects and aggregate expansion plans. Paul specialises in complex 

system modelling in the areas of loadflow, fault, transient stability and dynamic 

stability, and he is proficient in a range of power simulation software including 

PSS/E, DigSilent, PowaMaster, ReticMaster, ETAP, ERACS, EDSA and CYME. Other 

studies he completed recently include an HVDC and FACTS interconnector study in 

Namibia for NamPower (350kV dc), a 25- year least cost transmission master plan 

for Tanzania (330kV and 220kV), and generation integration studies for various 

utilities in the UK, South Africa and Tanzania. 




Assessing Transmission Network Condition: 

3D Data Capture and Reporting 

By Conor Reynolds, Brisbane, Queensland, 61 7 3854 6431, reynoldsC@pbworld.com 

Electricity transmission 

companies face a continual 

challenge to reduce the 

costs of system operations 

and maintenance while 

increasing network availability 

and reliability. PB is 

involved in developing a 

system that will help them. 

It is accurate and efficient, 

enables more effective 

asset management, and 

accommodates the changing 

ways in which people 

process information. 

Each transmission line and structure is a composite of thousands of components in differing 

conditions and with different remaining lives. The condition of components overall degrades 

as the network ages, yet the condition of individual components upgrades as maintenance 

works are completed. In the past, this information about the condition of Australia’s and 

New Zealand’s electricity transmission line networks had been gathered by field staff using a 

paper-based system. The information was compiled and held by contractors hired to conduct 

the condition assessments. 

The 3D Asset Data Capture System began as a solution to the problems associated with 

managing data coming from the field in this way—those commonly being: 

• Inaccurate recording of which steel components needed to be replaced, resulting in the 

need for a revisit and, in cases, re-inspections. 

• Inability to upload history in the field and have it for reference, resulting in a common 

complaint from clients being that component conditions sometimes seemed to improve 

with time! In reality, this misconception was due to the field staff not knowing what the 

last inspection results were. 

• Too simplistic data gathered at times, so often details about when critical components 

required future maintenance or replacement were not logged. 

• Inability to produce reports quickly once inspections were completed. 

• Cumbersome interrogation of the gathered information at later dates. 

System Overview 

Our system moves the process of network condition assessment from one that was difficult 

and costly to one that is much more accurate and efficient. It is a dynamic 3D graphic model 

of a structure and its components with client-specific defined assessment values (Figure 1). 

The graphic model can access geographic and environmental information through a geographic 

information system (GIS) network. 

Figure 1: A screen shot of the 

3D interface. 

Field staff enter the structure and component condition information via a touch-screen on a 

laptop that is designed for field conditions, known as a ‘tough-book.’ They can upload photos 

to the database via digital cameras and record global positions 

(GPS) of access routes to sites and tower positions for future 

reference, if required. The condition of all key components is 

recorded, whether they are defective or not. 

After the on-site assessment, this information is uploaded to a 

corporate asset database that is held by PB, and then interrogated 

with specialist reporting software. Outputs can be formatted 

as required for each client. As the information is in a digital 

format, it can also be arranged for the client to view and run 

reports as required through a network connection. 

The system provides an excellent overview picture of the 

current condition of the line for corporate planning. At this 

stage of development, the client’s requirements for data scoring 

and reporting are used to match its internal process, but this 

can be reviewed if required for future projects. 



Building a history of this corporate asset data gives 

management new abilities to analyse the data to: 

• Show patterns, such as a replacement pattern for a selected 

component on the whole network 

• Perform predictive modelling, such as planning for future 

maintenance work and replacement dates 

• Improve budgets or costing, such as estimating the cost of 

future works or valuing part or whole of a line network. 

PB is one of three firms involved in this project with Powerlink, 

Queensland’s regulated electricity transmission company. 

Where can this go to from here? 

PB designed the structure of the data base to be as flexible 

as possible for other applications in the power industry that 

require data capture, monitoring and reporting. The data 


base designers used their experience in meeting aviation and 

military requirements to trace small components back to 

their source and history when developing this system. 

We believe that this product can be very powerful, especially 

where power stations and substations are involved. For 

example, a 3D image of a complete substation can be 

developed that enables an operator to view a screen that 

highlights items requiring maintenance or replacement rather 

than having to read through a report that is run from a data 

base or similar format. 

This capability will become ever more important in the future. 

It is understood that the new generation of engineers entering 

the market place are able to understand 3D images better 

than they are able to understand pages and pages of printed 

reports. Emerging systems need to accommodate this 

shift. 

 

Conor Reynolds is a transmission line engineer who has worked in the main three areas of transmission line services, being contractor, client engineer and design consultant. 

He has gained his experience over a career of more than 18 years working for projects and clients including Sizewell B power station construction, Transpower New 

Zealand, and National Grid (UK). He is currently engineer and manager of transmission lines. 

Rehabilitation and Reconstruction of Abu Dhabi Transmission Network (continued from page 62) 

and 11 kV cables from the transformer to switchgear were 

replaced with new ones. 

Replacement of a Substation 

The construction of a new 132 kV GIS substation was 

completed in a power station complex, with a total generating 

capacity of about 400 MW. This effort included diversion 

of the following from the existing substation to newly built 

132 kV substation: 

• The 132 kV feeders, including four generator feeders 

• Two 400/132 kV 500 MVA inter bus transformers 

• Two 132/6 kV 40 MVA transformers feeding the nearby 

desalination plant. 

The 132 kV feeders’ diversion started in December 2005 and 

was completed in April 2007. The works continued during two 

winter seasons, with a long gap in between during summer of 

2006. The emphasis during the 132 kV feeders’ diversion was 

the continuity of the generation and total transfer of the 

feeders’ control to the new substation, including control and 

monitoring of the facility from for National Control Centre. 

A provisional 132 kV cable interconnector between the old 

and new 132 kV substations was established in the initial 

stage of diversion to facilitate the diversion. Also included 

in the project was replacement of 132kV cables from three 

generator transformers to the 132kV switchgear. 

PB’s Role 

PB was the consultant for these projects, responsible for 

feasibility study, site survey, tender documents preparation, 

technical and commercial evaluation, site supervision and 

warranty services. This was the second phase of the project 

for rehabilitation and reconstruction of transmission network 

in Abu Dhabi. Our firm has continuously contributed to 

improvements to the Abu Dhabi transmission network 

conditions during the past ten years, bringing old switchgear 

to the level of the most modern design and equipment 

solutions. All of these works were performed in tight time 

schedules limited to the winter season only with severe 

Health Safety and Environment conditions imposed, and 

with the substations remaining live and supplying power to 

consumers. These conditions required engagement of our 

very experienced engineers’ team familiar with high voltage 

substations design and operation and capable of making 

difficult decisions. 

 

Moola Reddy Jayasimha is a senior electrical design engineer in PB Power Networks Middle East, based in the Abu Dhabi office. He is coordinator of design of high 

voltage and extra high voltage transmission projects, acting as project manager for a 400 kV substation project in Abu Dhabi. He has more than 24 years’ experience, 

of which more than 10 years have been with PB and its predecessors. 


TRANSMISSION AND DISTRIBUTION: 

Distributing Power to Users 

The Wide Range of Distribution 

PB offers considerable expertise, knowledge and engineering capability in the field of electricity 

utility distribution at all voltage levels and on networks as diverse as those supplying high load 

density urban areas to those in rural networks in developing countries. Based at worldwide 

locations, mainly in Australia, Middle East, New Zealand, South Africa and the UK, PB’s 

distribution engineers are skilled in power system planning and analysis and in the engineering 

of overhead line, cable, substation, protection, automation and control projects. Increasingly, 

PB’s attention is turning to future developments to accommodate renewable distributed 

generation on traditional distribution networks, as is reflected in the articles that follow. 

Alex Neumann describes a research project to develop a thermal active controller to exploit 

short and medium term capacities of power network components thereby allowing increased 

utilisation of distribution network assets. In his second article, he reviews how the introduction 

of distributed generation is leading to innovative changes in the traditional design of distribution 

networks.The fast moving facilities provided by proprietary planning packages for distribution 

system analysis are reviewed in the article by Arthur Ekwue, Nicola Roscoe and Charles 

Lynch. The introduction of overhead line equipment to improve the network performance 

and power quality of the 11 kV network supplying Al Ain, Abu Dhabi Emirate, is a pioneering 

project under demanding conditions, as described by Aleksander Nikolic. From Australia, 

Hanzheng Duo’s topical article describes demand side measures (DSM) as applied to a 

network in Sydney to reduce peak demands and so defer or avoid capital expenditure. 

Other recent leading-edge work by PB not mentioned in these articles includes: 

• Advice on the planning of urban distribution networks for Nanjing, to the State Grid 

Corporation of China and the Jiangsu Electric Power Corporation 

• Asset valuations and reviews of forecast expenditure of three electricity distribution 

businesses for the Energy Regulatory Commission of the Philippines 

• Engineering of protection, automation and control schemes to improve the reliability 

of medium voltage networks in Scotland 

• Review of future network architectures to accommodate increasing levels of distributed 

generation for the Electricity Networks Strategy Group in the UK. 

A list of several articles on distribution systems, electricity networks, and substations from 

past PB publications is found on page 89. 

John Douglas 

Specialist Consultant, Energy and Utility Consulting, Newcastle upon Tyne, UK 

Coordinator of PAN 53, High Voltage Transmission & Distribution 



Research & Innovation 

Explore the Possibilities... 

PB leads a team developing 

a new device that will 

exploit the dynamic thermal 

capability of distribution 

system equipment by taking 

advantage of cooling factors 

such as ambient temperature 

and prevailing wind. 

Results to date are positive, 

indicating that when it is 

completed in late 2009, 

this prototype controller 

will facilitate increasing 

connections of distributed 

generation to distribution 

networks. 


CIM: Common Information 

Model 

DG: Distributed generation 

DNO: Distribution network 

operator 

DTR: Dynamic thermal rating 

OfGEM: Office of Gas and 

Electricity Markets 

SOA: Service-oriented 

architecture 

TSE: Thermal state 

estimation 

1 OfGEM’s incentives are offered through 

its Registered Power Zone and 

Innovation Funding Initiatives program. 

2 It should be noted that dynamic thermal 

ratings (DTRs) are the research focus 

of a number of other institutions at 

present, including Electric Power 

Research Institute (EPRI) in the USA 

for security and increased capacity of 

transmission networks; NUON, a leading 

energy company in the Netherlands, for 

coping with load growth and delaying 

infrastructure investment; and Energy 

Networks Strategy Group within the UK 

as an identified short-term solution for 

accommodating DG. 

Using Dynamic Thermal Ratings and 

Active Control to Unlock Distribution 

Network Capacity 

By Alex Neumann, Newcastle, UK, 44 91 226 2460, neumannA@pbworld.com 

The location of the generation resource for optimal energy yield often coincides with sparse 

or electrically ‘weak’ distribution network infrastructure. As a result, there are instances where 

the connection of distributed generation (DG) requires network reinforcement, which is 

sometimes deemed uneconomic to the generator. It is acknowledged that technical barriers 

such as voltage rise, reverse power flows and fault levels, particularly in weak networks, may 

inhibit the size of DG connections. 

To facilitate such generation connections, OfGEM, the UK’s electricity and gas regulator, offers 

incentives to distribution network operators (DNOs) to connect and manage DG via an 

appropriate control scheme. 1 There is the potential to reduce the requirement for expensive 

network reinforcement and new wayleaves, and to allow larger amounts of energy to be 

imported from DG developments by exploiting the short- and medium-term thermal ratings 

of distribution network components, particularly given the intermittency of certain types 

of renewable generation and the effects that prevailing weather conditions can have on 

the rating of outdoor distribution equipment. 

PB Leads Consortium Developing Thermal Controller 

A PB-led consortium in the UK is undertaking the research and development of a distribution 

network active thermal controller that uses local meteorological input to calculate real-time 

equipment ratings and to control network power flows. The group expects to achieve a deeper 

understanding of power system thermal capabilities and to apply this knowledge to developing 

an active controller that can safely and economically exploit the thermal ratings of plant. 

The proposed controller represents a move towards increased automation of distribution 

networks, so the team will also give consideration to the effect of this automation on power 

system operational staff. Their aim will be to ensure an appropriate balance between those 

issues requiring action by the staff and those that can be accommodated by the introduction of 

further intelligence (distributed or centralised) in the network management systems of the future. 

The consortium includes Durham University; Scottish Power Energy Networks; AREVA T&D, 

one of the leading players in power transmission and distribution; and Imass, a leading IT 

company providing custom software applications and services. 2 The consortium’s work is 

part-sponsored by the UK government’s Technology Strategy Board (TSB). PB’s contribution 

has been further supported through its Research & Innovation (R&I) Program. 

The Thermal Controller 

A service-oriented architecture (SOA) 

is being implemented for the thermal 

controller using Web services. SOA is 

a software development technique that 

groups different functionalities into 

atomic services (as shown in Figure 1). 

These services communicate with each 

other by passing data from one service 

to another, or coordinating an activity 

between one or more services. 

 


Figure 1: Service-oriented 

architecture to be adopted 

for the thermal controller. 



Controller Inputs 

Network Management System. It is expected that electrical 

input for the thermal controller will be provided through the 

DNO’s network management system. The input will allow 

faults and network reconfiguration events to be detected 

from the circuit breaker status signals, and power flows through 

system components to be monitored. Other electrical 

measurements, such as generator outputs, network loads 

and voltages, will be used for the simulation task described 

later in this article. 

External Parameter Processor. This service calculates the 

values of external parameters, such as wind speed, wind 

direction, air and soil temperatures, and solar radiation 

around the distribution network. This information will be 

based on signals from a small number of meteorological 

measurement units. Mathematical interpolations will be 

used initially, the accuracy of which will be verified using 

real measurements from the site trial network. Following the 

verification stage, the development team will decide to either 

continue on this path or improve the algorithms to increase 

the accuracy of the parameter estimation. 

Thermal State Estimation (TSE). TSE, the service that 

calculates component ratings from external parameters, is a 

fundamental part of the active thermal control system that 

this project aims to realise. It will: 

• Allow the precise assessment of each component’s 

thermal rating 

• Reduce the number of necessary measurements from 

network instrumentation 

• Increase the reliability of assessments in case of 

measurement or communications failure. 

Component thermal models. An example of the thermal 

model to calculate the component rating for overhead lines 

(OHLs) is presented below. OHLs are the most exposed 

(to wind) power system component, and their DTR offers 

the greatest exploitation opportunity. 

The model for OHL current rating is based on the energy 

balance equation: q c + q r = q s + I 2 R where the heat 

produced by the Joule effect (I 2 R ) and solar radiation (q s ) 

is balanced with the heat dissipated by radiation (q r ) and 

convection (q c ). 

The most important and changeable of the terms presented 

above is the convective heat exchange, which is strongly 

influenced by wind speed. Figure 2 shows the results of 

simulations carried out at Durham University. The ratio of 

dynamic thermal rating (DTR) to nominal rating is shown 

over the period of one year. It was calculated using real 

weather data and the equations presented above for a 

LYNX conductor. 


These results show a large variation in DTRs, with a mean 

ratio of approximately 250 percent of the static rating that is 

currently used. This variation in equipment ratings lends DTRs 

to applications with a control system that can manage the 

power flowing through the particular network components. 

The TSE Algorithm. A probability distribution is calculated 

for component thermal rating, based on probability distributions 

for each meteorological measurement and external parameter 

value. The method is described graphically in Figure 3 with: 

•NM being the number of meteorological measurements 

•NP being the number of meteorological parameters 

•NC being the number of components. 

The weather parameter probability estimates calculated in 

the external parameter processor act as an input to DTR 

algorithms and are used to calculate the rating and associated 

probability for each of the relevant network components. 

Correlation between the external parameter processor 

calculation results and the historical measurements will be 

used to increase the precision and reliability of the estimates, 

and may be applied during measurement and/or 

communication system failures. 

Network Optimisation. Optimisation will take place using 

power flow sensitivity factors that relate changes in 

component power flow to changes in generator output. 

The load-flow engine will be used to simulate the state of 

the network and validate the generation set point(s) proposed 

by the optimisation service, thereby ensuring that the power 

flows across the network are managed effectively. Power 

flow limits and statutory voltage regulations will be adhered 

to following any control action. 

Figure 2: Ratio of thermal to static line rating over one year. 

Figure 3: Thermal State Estimation process. 



The final stage of the active thermal control system response 

is to dispatch a set of suggested operating set points to the 

generation schemes within the jurisdiction of the thermal 

controller. 

The Prototype Controller. It is expected that the natural 

home of the thermal controller application would be within the 

software of the network management system. The prototype 

controller developed as part of this project will, however, be 

hosted on a separate system, taking in some data from the 

network management system and some additional data. 

DTR algorithms use information local to each component and 

may also be used to provide a useful protection function. 

Drawing on AREVA’s experience, we proposed implementing 

these algorithms within AREVA MiCOM protection relays. 

The cubicles housing the relays would act as collection points 

for the relevant data, which would also be passed on to the 

host of the thermal controller. Figure 4 shows the prototype 

controller layout in basic graphical form. 

Under normal operation, the thermal controller and the relay 

would run the same algorithm predicting the thermal limits of 

the component. If for some reason the network management 

system and thermal controller fail to stop a component 

reaching its thermal limit, the relay would trip the circuit 

breaker protecting the component. 

Figure 4: 

Graphical 

representation 

of the prototype 

controller. 

The Site Trial Network 


A section of Scottish Power Energy Networks’ distribution 

network has been made available to the development team 

for the field trials and development of the prototype thermal 

controller. The selected network delivers power from an 

offshore wind farm to the UK’s interconnected power system 

using 33 kV and 132 kV circuits. 

The site trial network will be used as a source of electrical, 

thermal and meteorological data that will be gathered using 

existing and new measurement equipment installed specifically 

for this project. It will be “over-instrumented” so that sufficient 

information can be gathered to validate the thermal algorithms 

that were developed as the initial stages of this project. 

Selected signals will be used for the prototype controller, 

with the validation exercise providing an understanding of 

the number of additional measurements (meteorological, 

electrical and thermal) that will be required to ensure the 

algorithms are capable of providing DTRs of the required 

accuracy and reliability. 

Development Overview and Conclusions 

This project is into its second year and thermal algorithms 

have been developed for overhead lines, underground cables 

and transformers. Encouraging desktop simulation results 

based on actual UK meteorological data suggest appreciable 

headroom exists that may be exploited with the implementation 

of our active thermal controller. These simulations 

considered the site trial network and selected generic UK 

distribution networks, and gave our team an appreciation 

of the potential benefits of applying DTRs on the UK’s 

distribution networks. 

Scottish Power Energy Networks is currently procuring 

thermal and meteorological measurement equipment to 

be installed on the site trial network, which will be 

commissioned during planned network outages during 

mid-2008 (Summer). The model validation and prototype 

development will follow the installation of the measurement 

equipment, with project completion scheduled for 

September 2009. 

 


• http://my.epri.com/portal/server.pt? 

• http://www.iee.org/oncomms/pn/powerca/dg-seminar.cfm 

• http://www.ensg.gov.uk/assets/kel003110000.pdf 

Alex Neumann is a senior power systems engineer specialising in the elements of power system design, analysis and operation. He has been with PB for six years since 

moving to the UK from South Africa, where he worked for the System Operations Division of Eskom Transmission. Alex is currently working as project manager for the 

research project discussed in this article alongside PB’s Ian Burdon, the project leader. 




Upside Down! How Innovation in Distribution is 

Challenging Tradition... By Alex Neumann, Newcastle, UK, 44 91 226 2460, neumannA@pbworld.com 

Towards the end of 2007 

PB’s power specialists in 

the UK undertook a review 

of innovation in distribution 

networks. Northern 

Ireland Electricity (NIE) 

was looking to prioritise its 

internally funded research 

investment spending, and 

tasked us to advise on the 

current innovation work 

across international distribution 

networks. This 

article provides a brief 

summary of some of the 

work that we identified as 

part of this project. 


DFIG: Doubly fed injection 

generators 

DG: Distributed generation 

DNO: Distributed network 

operator 

FCL: Fault current limiter 

IFI: Innovative funding 

initiative 

LV: Low voltage 

OfGEM: Office of Gas and 

Electricity Markets 

RPZ: Registered power 

zone 

SCFCL: Superconducting fault 

current limiter 

1 PB is leading a collaboration project 

to develop a generator controller that 

regulates output based on the thermal 

ratings of the distribution system. 

To read more about this project, 

which is investigating the potential 

headroom that may be exploited on 

distribution overhead lines, cables 

and transformers, please see the 

preceding article, “Thermal Controller 

Project Innovation in UK Distribution 

Networks” also by Alex Neumann. 

With distributed generation (DG) offering a relatively clean and green source of power 

generation, development and deployment of these smaller and dispersed generation technologies 

is being incentivised around the world. Distribution systems of the future must be flexible and 

responsive components. This is a far cry from the traditional design specifications that 

assumed one way power flows to “dumb” loads. 

In 2005 OfGEM, Great Britain’s energy regulator, introduced the Innovation Funding Initiative (IFI) 

and registered power zones (RPZ) as part of its distribution price control aimed at stimulating 

research and development on the UK’s distribution networks. British distribution network 

operators (DNOs) have embraced these schemes, with more than 150 IFI projects and three 

RPZs being registered. A recent extension by OfGEM has confirmed that IFI funding will 

continue up to 2015 to allow projects with timescales greater than five years to maintain their 

momentum. Several of the innovations covered in our review are discussed below. 

Operational Innovations 

Several UK DNOs have reported actual cases where constraint management techniques could 

be applied to their distribution networks to avoid network reinforcements and thereby facilitate 

more efficient generator connections. 

On-line Control. Greece’s Hellenic Transmission System Operator introduced a novel type 

of interruptible contract for wind generators in congested areas of its network. An on-line 

control scheme is used to regulate the output of wind farms and allow increased penetration 

of wind generation, while maintaining network security levels by using a control scheme to 

monitor system bottlenecks. This system can take action by applying either preventative or 

corrective control modes, depending on the desired level of system security. 

Dynamic Thermal Ratings. Dynamic thermal ratings of power network equipment are being 

investigated in R&D projects in Great Britain and Northern Ireland. This active management of 

constrained connections has the potential to unlock additional power transmission capacity at 

times when DG is operating at peak output. 1 Central Networks, the electricity distribution 

company serving central England, has developed an RPZ that applies an active rating to a 132 kV 

overhead line based on real time measurements of ambient temperature and wind speed. 

Fault Current Limiting Devices. Increased levels of DG will result in increased local 

distribution system fault levels. When the network fault level approaches the rating of its 

switchgear, the connection of more generation may result in costly asset replacement or connection 

at higher voltages. Active fault current limiting devices, such as I s limiters and fuses, have been 

developed for low voltage and high voltage distribution applications up to 36 kV. These devices are 

not considered to be failsafe however! We concluded that their installation leads to difficulties 

complying with UK Health and Safety legislation, which is unlikely to change in the near-term. As 

such, it is unlikely that these devices will offer a practical solution to increased network fault levels. 

Newer technologies, such as solid state circuit breakers and superconducting fault current 

limiters (SCFCLs), do offer superior performance, however, when compared with existing 

commercially available FCL devices. The most significant advantage is their automatic recovery 

property, which allows continuous operation of the device on the power system. Some SCFCLs 

are considered fail safe and can be built to exhibit negligible impedance during normal system 

operation. One disadvantage is a power loss under normal operating conditions caused by the 

current leads passing from room temperature to cryogenic temperature. Research associated 

with SCFCL technology is focusing on 110 kV voltage levels and above, positioning the devices 



initially at the more capital intensive power networks where 

the potential financial benefits are more substantial than 

those at lower distribution levels. 

AREVA has developed a prototype magnetic FCL (MFCL) 

for 400 V application. Central Network’s IFI report indicates 

that part of its network will be used to trial the MFCL, 

which it expects is more promising (than SCFCLs) as it 

uses permanent magnet material and is easier to handle. 

The Electricity Networks Association in England has a research 

project underway to develop a “fault level instrument” that 

will provide real time estimation of network fault levels taking 

into account all connected elements (e.g. motors, 

DG, etc.). Scottish Power is participating in this project 

and estimates that this prototype instrument is at 

least three years from adoption. 

Voltage Control. The installation of high voltage/ 

400 V transformers with on-load tap changers 

(OLTC) would improve voltage control of the low 

voltage networks. AREVA is currently developing a 

two-position tap changer for such applications and 

there are plans to trial this on the United Utilities 

network in Great Britain. Series connected power 

electronic single phase LV voltage regulators are 

currently being trialled by United Utilities and 

Scottish Power to solve customer under and 

over-voltage complaints on their networks. Although 

the regulators used were designed initially for single 

phase operation, they have been used also to solve threephase 

voltage complaints on the Scottish Power networks. 

GenAVC is being trialled by EDF Energy and United Utilities 

to optimise network capacity and generation export. The 

GenAVC system uses state estimation techniques to feedback 

nodal voltage level into the substation voltage control 

scheme to reduce or increase the primary busbar volts 

accordingly. This solution is currently being trialled on 

33/11 kV transformers to control 11 kV system voltages. 

Reactive Power Compensation. Reactive power 

compensation can be used to control voltage and increase 

capacity by injecting or absorbing reactive power at the 

point of connection. Dynamic reactive compensation can 

enhance system stability and quality of power supply, providing 

fast reaction to voltage fluctuations and controlled 

damping of oscillations on the networks. The D-VAR is a 

type of static compensator that detects and instantaneously 

compensates for voltage disturbances by injecting leading or 

lagging reactive power at key points on the network using 

power electronic converters. This device can connect to 

network voltages up to 35kV and can inject up to +/- 8MVAr. 

Widespread DG may lead to the formation of power islands 


on power systems following network disconnections. This is 

not permitted in many countries as these islands can give 

rise to safety, power quality and operational problems. The 

UNIFLEX-PM consortium project is aiming to develop and 

experimentally verify new and innovative power conversion 

architectures for universal applications in power networks. 

The converters will be capable of running a standalone power 

system both coupled with the wider distribution network or 

in island mode using islanding detection algorithms, voltage 

and frequency control and energy management using storage. 

A graphical depiction of a future power network utilising the 

UNIFLEX converters is shown in Figure 1. 

Figure 1: Future Active Network with UNIFLEX-PM system. 

Source: J. Clare and F. Iov, F’s UNIFLEX - PM. CIRED 2007, Workshop on Power Converters 

for the Future European Electricity Network presented on 25 May, 2007, (Slide 13). 

Energy Storage Technologies. The need to continually 

balance supply and demand for electricity, coupled with the 

intermittency of DG output and peaky demand curves, 

makes electricity storage a tasty proposition on future 

electricity networks. Energy storage technologies offer a 

local solution by regulating power flows by either employing 

peak load shaving or regulation of power sent out from DG 

installations (e.g., wind farms). Energy storage devices must be 

capable of fast operation to allow participation in fast acting 

energy management schemes of the future. Commercially 

available energy storage technologies are presented in 

Figure 2, categorised by output capacity and supply capability. 

Demand Side Innovations: Smart Meters 

Involving the consumer in the electricity market is a sure way 

of increasing awareness and provides opportunities to increase 

consumer efficiency and incentivise adoption of small scale 

DG technologies. Today, widespread smart meter installation 

is more commonly driven by the cost savings associated with 

the elimination of meter readers as well as more timely 




tariff structures to discourage the use of electricity during peak 

periods. The meters are also fitted with thermal overloads to 

limit the load taken by the customer. In the UK, EdF Energy 

currently has a smart meter trial that will see 3000 smart 

meters being installed over a two-year period. One of the 

aims of the project is to measure how much energy customers 

will save by becoming aware of their consumption habits. 

What Does the Future Hold? 

Figure 2: Characteristics of energy storage technology. 

Source: F. Lov, and F. Blaabjerg’s. “Advanced Power Converters for 

Universal and Flexible Power Management in Future Electricity Network.” 

and accurate billing. Incentives offered by suppliers and system 

operators (e.g., dynamic energy pricing) can be translated 

through smart meters to the energy consumer and, in so 

doing, realise appropriate consumer behaviour; provide 

quick demand response and more efficient energy usage. 

The largest known implementation of smart metering is in 

Italy, where ENEL Telegestore programme has seen smart 

metering installed in 27 million homes, introducing flexible 

Microgrids incorporate the application and control of distributed 

energy resources (i.e., microgeneration, controllable load 

and storage). The idea behind the microgrid concept is to 

reduce the burden on the grid operators by clustering and 

decentralising the operation and control of lower voltage 

distribution networks. A microgrid should able to operate 

safely and efficiently when coupled with the greater distribution 

network, and be capable of islanded operation. The Japanese 

are regarded as the world leaders in microgrid demonstration 

projects, with the New Energy and Industrial Technology 

Organisation (NEDO) providing funding and management 

services for research and development pilots. 

Most of the topics discussed in this article are expected 

to form part of truly active power networks of the future. 

Innovation currently underway will refine and further develop 

the tools required to move from the static distribution systems 

of days gone by towards flexible microgrids of the future. 

Watch this space... 


• Central Networks “Regulatory Report for DG Incentives, RPZ’s & IFI”: http://www.ofgem.gov.uk/Pages/OfGEMHome.aspx 

• Scottish Power energy Networks “Innovation Funding Incentive, Annual Report, Issue 1 - 31st July 2007”: 

http://www.ofgem.gov.uk/Pages/OfGEMHome.aspx. 

• EDF Energy Networks “IFI/RPZ, Annual Report, April ‘06 - March ‘07”: http://www.ofgem.gov.uk/Pages/OfGEMHome.aspx. 

• IFI Annual Report 2006/07: http://www.ofgem.gov.uk/Pages/OfGEMHome.aspx. 

• American Superconductor “Dynamic Reactive Power Compensation. Utilizing State of the Art Power Electronics Technology”: 

http://www.amsuper.com/documents/PES_DVR_01_0804a.pdf. 

• Clare, J. and Iov, F , “UNIFLEX - PM. CIRED 2007, Workshop on Power Converters for the Future European Electricity Network: 

http://www.eee.nott.ac.uk/uniflex. 

• Lov, F and Blaabjerg, F., Advanced Power Converters for Universal and Flexible Power Management in Future Electricity Network: 

http://www.eee.nott.ac.uk/uniflex/. 

• Hatziargyriou, N., Asano, H., Iravani, R and Marnay, C., “Microgrids: An overview of Ongoing Research, Development, and Demonstration Projects,” IEE 

Power and Energy Magazine, July/August 2007: http://www.smartgrids.eu/documents/docs_interest/Nikos_et_al_Power+Energy_jul-aug_07_article.pdf 

Alex Neumann is a senior power systems engineer with the Power Division of PB. He specialises in elements of power system design, analysis and operation. 



A Survey of Power System Packages for 

Distribution Network Analysis 


By Arthur Ekwue, Godalming, UK, 44 (0)148352 8609, ekwueA@pbworld.com; Nicola Roscoe, Manchester, UK, 44 (0)161200 5193, 

roscoeN@pbworld.com; and Charles Lynch, Northwich, UK, 44 (0)16064 7889, calynch@PowerAnalysis.co.uk 

The authors present the 

results of a survey undertaken 

amongst distribution 

network operators around 

the world to identify tools 

that would be suitable for 

the distribution networks of 

the future. Their objectives 

are to share this technical 

information with other 

power engineers within 

PB and to improve the 

awareness within our firm 

of future trends and how 

we are contributing to 

them. 

The global trend to reduce greenhouse emissions is leading to increasing levels of new 

electricity generation from renewable sources and the embedding of this new power 

within electricity distribution networks. These changes will have some implications for 

the electricity distribution networks and their operators (DNOs). For example: 

• The connection of renewable generation could raise the fault levels on existing transmission 

lines to values beyond the capacity of existing switchgear because of the fault contributions 

from the renewable generators themselves. 

• The new generation sources could displace existing conventional methods of generation that, 

historically, have provided the response characteristics needed to maintain the overall 

integrity of the transmission system. This could result in instability problems when the 

intermittent generators supply a significant proportion of system demand, especially at light loads. 

• Voltage control and power quality problems can arise when generators embedded within 

the distribution networks start or stop generating power. If not properly regulated, this 

could cause other network users to suffer voltage fluctuations outside the acceptable 

statutory limits and inject unwanted harmonics into the voltage waveform. 

Such changes, and increasing power loads, are putting new demands on DNOs and on the 

software packages they use to perform the critical analyses of their networks’ performance. 

One of our clients, a DNO facing these issues, wanted to upgrade its network analysis system 

accordingly, and hired PB to identify: 

• Power system analytical software that will be suitable for distribution networks of the future 

• Strengths and weaknesses of such software packages as seen by users, including ease of use. 

We approached this task by conducting an extensive survey of DNOs around the world. 

Some did not want to share this information, but those who did were equally interested 

in learning of our findings. While PB uses or has used many of the commercially available 

packages mentioned in this article, it was not our task to provide our judgment of them, 

but to report on the experiences that DNOs had with them. It should be noted that 

several of the packages are used for transmission network analysis also, but investigating 

that application was not within the scope of this project. 

The Survey 

Arthur Ekwue and Nicola Roscoe 

are principal power system 

engineers and professional 

associates. Arthur is based in 

Godalming and Nicola is in 

Manchester. 

Charles Lynch is the principal 

engineer/director of Power Analysis 

Limited, which is based in 

Northwich, UK. 

1 L A Jorge et al, “DPlan: Through 

R&D into a World Class Product”, 

Proceedings of EPRI Latin American 

Conference and Exhibition, Rio de 

Janeiro, Brazil, 2001. 

The main questions of the survey centred on the availability of power system analysis tools 

to assist in the connection of embedded generation on the 33 kV, 11 kV and LV (low voltage) 

networks. This included software packages used for: 

• Load flow, fault level, transient stability, reliability (customer interruptions and customer 

minutes lost calculations), contingency studies and protection coordination 

• Power quality studies, including voltage unbalance, flicker, motor starting and harmonics. 

The survey included some open ended questions aimed at learning: 

• Whether the DNOs had geographic information systems (GISs) and, if so, whether there 

were links between the GIS and the planning software 

• How DNOs rated the software packages they used in terms of usability, manufacturer 

support (e.g. technical support, user groups etc) and cost 

• Whether the DNOs had any plans to change or upgrade the software they used currently 

and, if so, what alternatives were being considered. 

 




Commercially Available Software 

We were interested in learning about the usage of 

commercially available power system analysis packages 

we were aware of for distribution network planning. 

These and the related Web sites are as follows: 

• DINIS (Distribution Network Information System) by ICL: 

http://www.dinis.com/ 

• Interactive Power Systems Analysis (IPSA) by TNEI: 

http://www.ipsa-power.com/ 

• CYMDIST (CYME International Inc., USA-Canada: 

http://www.cyme.com/ 

• ERACS (ERA Technology Ltd, UK): 

http://www.era.co.uk/Services/eracs.asp 

• Power Factory (DIgSILENT GmbH, Germany): 

http://www.digsilent.de/ 

• SynerGEE Electric: http://www.advantica.biz/default.aspx?page=323 

• SINCAL (Siemens, USA): 

http://www.siemens.com/power-technologies/software 

• DPLAN Distribution Planning 

• ETAP Power Station (Operation Technologies 

Inc, USA): http://www.etap.com/ 

• NEPLAN (BCP, Switzerland): 

http://www.neplan.ch/ 

An assessment of the technical features of 

each software is not presented in this article; 

however, readers seeking more information 

may contact the authors. 

Conclusions 

Fifteen DNOs in Europe, Africa, Middle East, 

New Zealand and Australia responded to 

the survey. We had no response from USA. 

We noted details of the various distribution 

network structures, including voltage levels 

and network design, and took them into 

consideration when reviewing the results. 

The main conclusions reached are as follows: 

1. In the UK, for example, the majority of 

DNOs use one or more of PSS/E, IPSA 

and DINIS, although more products are 

starting to be used as the international 

market in system analysis software develops. 

IPSA was developed in the UK by 

UMIST (now part of the University of 

Manchester) with contributions from 

several of the UK DNOs. 

2. Many of the DNOs outside of the UK 

use SINCAL. 

3. The majority of the respondents use the same software 

for 11 kV and 33 kV distribution networks. 

4. Many of the DNOs do not use any software package for 

their low voltage planning studies. Those who do use 

either DINIS, CYMDIST or WinDebut. 

5. For power quality studies, the DNOs either use the same 

software packages for load flow and fault level calculations, 

are not doing these studies, or currently outsource 

these studies. 

6. Many of the DNOs have a GIS system, but only one 

imports network data from it. 

The summary of responses to a question regarding what 

software packages are used for several 33 kV planning 

studies is shown in Table 1. 

It is expected that those software packages that incorporate 

the modeling of embedded generation with comprehensive 

analytical features, reasonable cost, adequate customer 

support and ease of use will become prime analytical tools 

that can be considered suitable for the distribution networks 

of the future. 

 

Table 1: Consolidation of Responses to Question 1(a): What software package 

(including version) do you use for the following 33 kV planning studies? 




Improving 11 kV Network Performance in Al Ain 

By Aleksandar Nikolic, Al Ain, Abu Dhabi, 971-506614170, nikolicA@pbworld.com 

This 11 kV OHL network 

performance improvement 

project is a pioneering one, 

and it is proving to be very 

demanding. It introduces 

the most advanced OHL 

equipment for the first time 

in the Abu Dhabi Emirate. 


AADC: Al Ain Distribution 

Company 

OHL: Overhead line 

Al Ain’s 11 kV distribution network is spread over 11,275 km 2 (4,350 square miles) and divided 

in four regions: City, Northern, Western and Southern. The 11kV overhead line (OHL) 

feeders are present in all regions and distributed mainly in desert areas, providing power to 

remote farms and water wells. Some of the OHL have mixed loads, however, particularly 

within housing or industrial areas. 

The 11 kV OHL network was subject to frequent power supply interruptions, low power 

factors and unacceptable voltage drops. Al Ain Distribution Company (AADC) decided to 

improve network performance and network reliability in order to provide consistent customer 

power supply and to maintain acceptable limits of voltage drops and power factors. The 

project initiator and coordinator, AADC Operation and Maintenance (O&M) department, 

decided to introduce the most advanced 11 kV OHL equipment. PB was awarded the 

consultancy, which covers study, design, tendering, project management and warranty services. 

The network performance improvement was divided into the three following projects related 

to the different network parameters and OHL equipment: 

• Performance. 11 kV pole mounted autoreclosers were introduced for the network 

performance indices improvement, such as system average interruption frequency index 

(SAIFI) and system average interruption duration index (SAIDI). PB’s scope of work for 

this project includes tendering, autorecloser location pinpointing including all necessary 

data collection and calculations, project management and site supervision. 

• Power factor. 11 kV pole mounted capacitor banks were introduced for the power factor 

improvement and loss reduction. PB’s scope of work for this project includes site survey 

and data collection, study, design and tender preparation. 

• Voltage profile. 11 kV pole mounted voltage regulators were introduced for the voltage 

profile improvement. PB’s scope of work for this project includes tendering, project 

management and site supervision. 

Using Some Latest Technology Developments 

The OHL equipment, being exposed to different and often severe weather conditions, is 

always subject to improvement. The weather conditions are particularly severe in desert 

areas, where more weather-resistant equipment requiring as little maintenance as possible is 

needed. We evaluated a range of solutions, but taking these severe conditions and our client’s 

objectives into account, we recommended that some of the latest technology developments 

be introduced. 

• Autoreclosers. Bidders offered more than seven different manufacturers. After the 

detailed technical evaluation, the autoreclosers with the higher fault current interruption 

rating were approved. These had provided more that ten thousand maintenance free 

operations, and they included the latest vacuum switch technology with dual magnetic 

actuator mechanisms, housed in solid insulation. At the same time, more advanced control 

units with flexible communication protocols were introduced to provide future autorecloser 

integration in AADC’s remote control system. 

• Voltage regulators. The main technology development is related to the voltage regulator 

tap changer and control unit. The approved voltage regulators are equipped with tap 

changer capable to perform 32-step operations within 15 seconds, providing fast response 

to voltage fluctuation. Control units are provided with tap changer contact duty cycle 

monitoring facility as well as flexible communication protocols for remote control 

and supervision. 

 




• Capacitor banks. Switched, kVAr controlled, pole mounted 

capacitor banks with the single pole vacuum switches have 

been proposed for this project. The latest technology 

development is related to the vacuum switch and the 

control unit. The zero voltage closing facility is introduced 

to reduce transient effects due to capacitor bank closing 

operation (Figure 1 and Figure 2). 

Figure 1: Voltage profile without 

zero voltage closing facility. 

The Challenges We Faced 

We faced challenges 

during different project 

activities such as data 

collection, autorecloser 

location pinpointing, 

capacitor bank calculation 

and design. 

• Data collection. 

The feeder topology 

data were required 

for the autorecloser 

pinpointing and 

capacitor bank placement 

study. The site 

survey was not the 

most effective 

method of gathering 

data because more 

than 270 11 kV OHL 

feeders are distributed 

over 11,275 km 2 

(4,350 square miles). 

As a solution, we 

used the AADC geographical 

information 

Figure 2: Voltage profile with zero 

voltage closing facility. 

Figure 3: The sample MVAr demand 

profile. 

system (GIS) as a source for conductor data, cable data, 

distribution transformer and other feeder topology 

data collection. 

• Autorecloser location pinpointing. The challenge was 

to propose autorecloser locations taking into consideration 

the similar average number of customers per autorecloser 

and the different regional demographies. The constraints 

were to propose autorecloser locations on existing free 

H poles close to the existing access roads. 

We used the combination of the GIS data collection 

and the site survey to verify proposed locations. 

• Capacitor bank study. The AADC 11 kV OHL 

network is facing huge MVAr demand fluctuation, 

not only between the summer and the winter 

period, but also within the same month (Figure 3). 

Some feeders are short ones, and some of them are 

extremely large. Some feeders are lightly loaded 

with only a few distribution transformers connected, 

and some of them are overloaded with more than 

150 distribution transformers connected. 

It was quite a challenge to propose capacitor unit and 

capacitor bank rating to satisfy the uniformity request 

and to cover all feeders load diversity. 

Conclusions 

The majority of the transient faults, as the most frequent 

power supply interruption factor, will be cleared with the 

autorecloser closest to the primary substation. Depending 

of the total number of customers connected to the feeder, 

additional autoreclosers are provided to reduce permanent 

faults impact on the network performance indices. 

After the capacitor banks installation, AADC benefits will be 

the power factor improvement, loss reduction and released 

feeder capacity. The loss reduction savings only will provide 

return on investment in less than two years period. 

PB has made a significant contribution to this pioneering 

project in Abu Dhabi Emirate, a project that will serve as 

an example for future distribution network development 

projects. It is the first of its kind for AADC, and one 

that will be referenced for other distribution network 

performance improvements in the region. 

 


• http://www.aadc.ae/ 

Aleksandar Nikolic is PMP certified project manager and is a principal resident engineer with PB Power Networks Abu Dhabi. His specialization is project management, 

power transmission and distribution. He has more than 22 years of experience including almost 2 years with PB. 




Energy Demand Management Programs in 

Western Sydney By Hanzheng Duo, Sydney, New South Wales, +61-2-92725168, hduo@pb.com.au 

The importance of demand 

management is increasing 

as the needs grow for more 

electricity but fewer carbon 

emissions and for sustainable 

network development. 

The topic of this article is 

a network-driven demand 

management approach for 

Western Sydney’s Wetherill 

Park industrial area, where 

reductions were made at 

the localized sub-zone level. 

Figure 1: Map of Integral 

Energy’s network supply area. 


• http://www.integral.com.au/ 

1 To read about PB’s work on the 

Demand Management and Planning 

Project (DMPP) for New South Wales 

Department of Planning, see “Demand 

management for Sydney CBD and 

Inner West Area” by Hanzheng Duo 

and Damir Jaksic, PB Network, Issue 

No. 65, pp. 90-91. 

Integral Energy’s electricity distribution network in western Sydney serves more than 2.1 million 

people across 24,500 square kilometres (9,500 square miles) (Figure 1). The network is made 

up of approximately 28,000 transmission, zone and distribution substations and 315,000 power 

poles bound together by 33,000 kilometres (20,000 miles) of underground and overhead cable. 

Western Sydney has experienced rapid development in recent years due to new release 

areas and a booming economy. As a result, an ongoing trend within Integral Energy’s supply 

area is the transformation of the network from one that serves a rural or semi-rural to one 

that serves a more densely populated urban area. Summer peak demand has been growing 

quickly also, driven primarily by air conditioning loads in residential areas. This growth is 

reflected in the summer demand forecasts shown in Figure 2. The rapid growth in demand 

has been a great challenge to maintaining the network reliability and to sustainable development. 

The various areas In Western Sydney are experiencing demand growth at different rates. 

While Integral Energy is planning network augmentation to ensure system reliability, it is also 

pursuing demand side management (DSM) and other energy efficiency measures as alternatives 

to supply-side solutions. PB was hired in 2005 to serve as technical advisor and provide 

program management services for a number of DSM programs for western Sydney. 

DSM Approach 

The concept behind DSM is to reduce peak demands to below the network 

capacity limits in the parts of the network (localised programs) where required 

and, by so doing, defer or avoid capital expenditure. Peak demands tend to occur 

relatively infrequently. They pose a substantial risk that the network might not be 

able to supply the needed power, however, making it important that supply networks 

have sufficient capacity for handling these peak demands. 

Government supports the DSM approach. Electricity distributors in New South 

Wales (NSW) operate under the NSW Electricity Supply Act 1995, which includes 

a licence requirement to investigate demand management alternatives to network 

augmentation for specific capital expenditure projects. 

The approach to DSM in western Sydney is different from the approach we have taken 

in large, densely populated areas. For example, a goal of the demand management 

planning project for Sydney's central business district was to collect information 

from a wide range of areas. 1 On our current project, Integral Energy’s DSM 

programs concentrate on demand reduction for smaller networks, or zone 

substations. As with any demand management program, however, the challenge is to 

manage the changing consumer behaviour by developing and implementing a suite 

of initiatives aimed at encouraging them to reduce energy consumption at particular times. 

Wetherill Park Industrial 

Area DSM 

The Wetherill Park industrial 

area has been experiencing 

steady growth of about 1.7 

percent per year and the substation 

supplying the industrial 

and surrounding residential 

 

Figure 2: Summer 

demand forecasts. 



area was approaching its transformer capacity limit. The 

demand reduction required to defer the construction of 

a new zone substation for three years was 5,400 kVA. 

Our team was responsible for developing the demand 

reduction strategy. Some of our steps were to: 

• Identify and approach the high demand customers 

• Conduct energy audits at customers’ sites to identify 

demand reduction/energy efficiency opportunities 

• Recommend demand reduction/energy saving measures 

• Coordinate the implementation of these measures, including 

incentives and other support that Integral Energy offered. 

One of the challenges is to obtain electricity customers’ 

commitment to participate in the program. We worked 

closely with Integral Energy to develop approaches by using 

various measures, such as financial incentives, media exposure 

and case studies to get customers involved in the program. 

Typically power factor correction (PFC) and lighting control 

measures are cost-effective for industrial sites, and there 

are also some load-shifting opportunities. (In recent DSM 

programs, we involved PB’s community consultant team 

in Sydney to approach the customers. This step has been 

proved to be effective.) 

During the program, we also developed close relationships 

with technology suppliers, and we were able to provide 

expert advice and implementation coordination. This step 

also helped us to minimize our financial risks. 

The program ran for two years and was successful in achieving 

the demand reduction target (Figure 3). Key results are: 

• Thirty customers participated in the program. 

• Forty-seven initiatives were identified representing a 

6,647 kVA of demand reduction potential. 

• Twenty-seven of these initiatives were implemented, 

resulting in a 5,546 kVA demand reduction. 

• An energy reduction of 202 MWh per year was achieved. 

• A reduction of 260 tonnes of CO2 gases per annum 

was achieved. 

Figure 3: Wetherill Park zone substation summer peak demand. 

Note that the 2003/04 summer was hotter than normal and 

achieved a higher than normal peak demand. 


Outcomes and Lessons Learned 

Network-driven DSM programs are effective mainly in 

industrial and commercial areas where there are more 

opportunities to work with several large customers. Also, the 

current regulatory regime in NSW requires evidence of a 

network capital expenditure item being deferred as a result 

of the DSM program. This requirement forces DSM programs 

to be localised, and to concentrate on only the customers 

supplied from the constrained part of the network. 

As indicated above, one of the main challenges in any DSM 

program is to encourage customers to respond positively to 

requests for demand management. This challenge is due, in 

part, to the following: 

• Electricity is an “invisible” input into a customer’s process 

or business. 

• The savings from demand management programs may not 

be identified easily. 

• Energy efficiency is typically not a core business function. 

• Many demand and energy reduction initiatives require up 

front investment to deliver future benefits. 

• Electricity is a relatively low-cost input for many businesses 

(and households). 

We have, however, observed positive changes in customers’ 

attitudes in working on a subsequent project in the Minto 

Industrial Area due to recent increases in electricity prices; 

government regulations, such as the federal government Energy 

Efficiency Opportunities (EEO); and the growing awareness 

of climate-change issues. We hope to see this trend continue 

on a new DSM project that we won recently and expect will 

get underway in July 2008, the Chipping-Norton Industrial 

Area. These two projects are also in Western Sydney. 

More to Do 

Great potential exists in demand management. Successful 

DSM programs will reduce network investment for network 

suppliers, save operating costs for end-users, improve network 

reliability and reduce greenhouse gas emissions. Unfortunately, 

this potential is not yet well understood by many network 

suppliers and end-users. 

A concerted effort by the industry, regulators and government 

is needed to encourage consumer acceptance of DSM 

programs and to change consumer’s attitudes about 

electricity consumption. It is important that PB act as a 

catalyst to provide knowledge and information that will 

help achieve such changes and the resulting sustainable 

development. 

 

Hanzheng Duo is a senior energy management consultant with PB’s National System and Electrical Team in Australia. His areas of expertise are energy efficiency, 

renewable energy, power system and greenhouse gas management. He has been project manager and technical leader for several demand management programs. 

Hanzheng has a Ph.D. in power system planning and is a visiting fellow at the School of Photovoltaics and Renewable Energy, University of New South Wales. 


Planning and the Role of Regulators 


Planning and Regulating Power Infrastructure in 

a World of Change 

PB is actively involved in the planning of power systems and the provision of strategic advice 

on energy supply issues throughout the world. 

Recognising the magnitude of the investment and asset lives of power infrastructure, the 

decisions we make today in the planning and regulation of power infrastructure will result 

in technologies and systems being implemented that will benefit people for decades and 

directly affect the price paid for electricity, the environment and the security of supply 

enjoyed. With a number of utilities around the world having asset bases that are aging and 

operating beyond their book lives, this is an increasing area of focus. John Douglas outlines 

how PB has supported regulators in ensuring efficient asset replacement strategies are 

adopted by utilities while, in the Transmission section, Conor Reynolds presents a paper 

on 3D data capture and reporting for transmission network condition assessment. 

The increasing concerns over cost and security of resources combined with a challenge for 

all countries to migrate to lower carbon energy systems are particularly important in today’s 

world of global energy markets. In his paper, Nick Barneveld describes the ramifications of 

New Zealand migrating to provide more sustainable energy solutions from a supply/demand 

perspective, while Alex Neumann’s papers in the Distribution section present how developments 

in distribution technology combined with changes in approach to the way distribution systems 

are designed can address these challenges. 

PB has been and is at the heart of not only these issues, but many others. For example, we 

also provide advice on the restructuring and regulation of electricity supply industries. Since 

advising in the UK on the world’s first electricity industry privatisation, our firm has led the 

way in developing and implementing solutions for deregulation and restructuring worldwide, 

including Africa, Asia, Australasia, Europe, the Middle East and South America. 

Our strength is a strong engineering understanding and capability of power and energy systems 

combined with utility operations experience. We constantly adapt and improve our techniques 

to ensure we can deliver solutions appropriate not only for today but also for the future. 

Please see page 89 for a list of many articles related to power system planning and innovations 

from past PB publications. 

Bruce Stedall 

Operations Director, Power Systems and Energy Strategic Consulting 

Newcastle, UK 




Asset Replacement: The Regulator’s View 

By John Douglas, Newcastle upon Tyne, UK, +44 191 226 2252, douglasJak@pbworld.com 

The expenditure required to 

replace ageing assets for 

a mature electricity 

transmission or distribution 

network can represent half 

of the network operator’s 

capital budget, and these 

costs continue to rise. In a 

regulated power supply 

industry such as exists in 

the UK, the regulator often 

has limited resources to 

perform a budgetary review 

in comparison with those 

available to the network 

operators who prepare the 

budget, but must ensure 

that an appropriate level of 

network performance is 

achieved at an efficient 

level of cost. PB has developed 

an asset replacement 

model that is helping 

provide regulators with the 

information they need to 

make their decision. The 

author describes the model 

and recent changes in views 

on asset lives and changes 

to the regulatory review 

process. 

Setting the level of revenue a network operator can charge to fund operations and/or 

replacement of assets is generally the responsibility of the utility regulator, who acts in the 

interests of the customers. The regulator has to balance the expenditures required, particularly 

for long-term reliable performance of the network, against the corresponding allowed revenue, 

the level of which is based on a regulatory price control review generally conducted every 

four to five years. As part that process, regulators can apply three tests: 

• Is there a justifiable need for the expenditure? 

• Have efficient design and life-cycle costs been taken into consideration? 

• Is the timing of the expenditure appropriate? 

At the same time, some recent developments among network operators are that they: 

• Are increasing the attention they give to managing their aging transmission and distribution 

assets, including monitoring the condition of their assets more extensively 

• Are adopting risk-based planning methods 

• Have introduced annual expenditure and activity reporting to regulators 

• Have a limitation of resources available for asset replacement programmes. 

The level of asset replacement activity depends considerably on judging when an asset is “life 

expired.” There is generally a tendency for network operators to forecast high. If an unreasonably 

high expenditure was allowed under incentive-based price control regulation as in the UK, the 

network operator might readily achieve efficiency savings to the detriment of the customer. 

A key distinction between a network operator and the regulator in the regulatory review 

process is that more information and time are available to the former. A regulator views 

the network at a high level, so requires a means of modelling proposed asset replacement. 

Accordingly, PB has developed an asset replacement model that has been used to review 

corresponding expenditure for a number of regulators in different countries. 

Review of Replacement of Assets 

Network assets are generally judged to have average lives of about 40 to 60 years, or even 

longer for some cable types. The asset age situation in the UK is illustrated in Figure 1, which 

shows the percentage of value of existing transmission and primary (33 kV+) distribution 

assets that was installed each year over an 80-year span. Installation activity reached a peak 

in the mid 1960s, some 40 

years ago, and the network 

operators are presently forecasting 

rapidly rising replacement 

quantities and 

expenditures. On its own, 

Figure 1 may be regarded as 

evidence of age, but not as 

need for replacement. 

The principal drivers for 

replacement of assets include: 

• Poor condition, e.g., reliability, 

failure, obsolescence 

• High environmental 

impact, e.g., oil-filled 

apparatus, overhead lines 

Figure 1: Comparison of transmission and 

distribution asset values by age in the UK. 



• Safety concerns, e.g., poorly performing switchgear, line 

fittings 

• Improved performance, e.g., increased functionality of a 

new asset 

• High operating costs, e.g., frequent repair and maintenance, 

energy losses and outages. 

Network Operator’s Asset Replacement 

Assessment 

Asset management systems incorporate a comprehensive 

database of network assets, including their characteristics 

and functions, details of their condition (reported and 

updated at appropriate intervals) and performance, and 

their repair and maintenance histories. From such a database 

an assessment of the expected remaining lives of the 

assets can be made, including identification of replacement 

candidates. This assessment is key to the planning and 

prioritizing process when preparing a programme and 

budget for asset replacement. 

Regulator’s Review: Asset Replacement Model 

PB acted as engineering consultant to OfGEM, the British 

energy regulator, for recent transmission and distribution price 

control reviews. In carrying out this task, we developed and 

applied the replacement profile model illustrated in Figure 2. 

The inputs are: 

• Asset age profiles 

• Asset retirement profiles 

• Unit replacement costs. 

Figure 2: Replacement Profile Model. (Example is for the asset 

type: 11 kV pole mounted transformers.) 

The asset age profile data for existing assets in the example 

were averaged over five-year periods due to the way the 

historic data was recorded, hence giving the stepped profile. 

In practice, most operators are able to provide age profiles 


by year. It can be seen that most of these types of asset 

were installed between 20 and 35 years ago. The retirement 

percentage profile in the example is assumed to be a normal 

distribution with a mean of about 40 years and a standard 

deviation of 4 years. The model can, however, accept any shape 

of retirement profile provided the sum of the percentages 

to be retired in any one year does not exceed 100 percent. 

The quantity of assets for retirement in any year is the 

summation of the cross-multiplication of the retirement 

profile and the asset age profile (sumproduct function). For 

the next year the retirement profile is advanced by one year 

with respect to the age profile. 

The retirement profile in the example is relatively narrow, so 

there is a high quantity of assets to be replaced in the initial 

years, reflecting assets that are older than the retirement 

profile. Furthermore, the replacement assets tend to reflect 

the original age profile. A broader retirement profile would 

have the effect of smoothing out the year on year replacement. 

Due to the influence of assets introduced in later years, 

the smooth solid line representing the projected retirement 

profile of the existing asset base diverges from the dotted 

line, which represents quantities of replacement assets to be 

introduced in each year in future. This divergence begins at 

the point in the distant future at which replacement assets 

introduced in the near future begin to be replaced themselves 

in accordance with the same retirement profile being applied 

to the existing asset base. 

In practice the retirement profiles should reflect the actual 

ages at which assets are being replaced. 

The outputs of the model are the replacement quantities and 

expenditures by asset category and by year. The model also: 

• Allows users to undertake scenario analyses by examining 

the sensitivity of the modelled output to variations in 

asset lives 

• Provides a network-wide strategic view of the risk to be 

assessed in terms of percentage weighted average remaining 

life of an asset category. 

Although the model considers like-for-like replacement, the 

level of “betterment” due to, say, replacement with increased 

capacity or putting cables underground can be reviewed 

through consideration of cost differentials. Separately, 

account is also taken of assets replaced because of system 

development. 

Trends in Estimated Asset Lives 

The average lives of most of the principal British distribution 

assets show an increasing trend, as presented in Figure 3 on 

the following page. These new numbers also illustrate that 

the modelling of asset replacement is dependent on 

 



assessments of asset lives that are extending as condition 

assessment techniques improve. Where the retirement profiles 

are considered as normal distributions, the standard 

deviations have also shown an increasing trend, typically from 

about 8 to 11 years. 


• TPCR (2000/1 to 2004/5) allowed and actual non-load 

related (largely asset replacement) expenditures. 

• TPCR2006 (2005/6 to 2011/12) forecast and allowed 

non-load related expenditures. 

Figure 4: Comparison of operators’ forecasts and regulatory 

allowances. 

The allowed distribution expenditure represents an increase 

of some 34 percent over the annual average expenditure of 

the historic period. The increase in allowed transmission 

expenditure represents a virtual doubling of that expenditure 

on an annual basis, however, due largely to increases in refurbishment 

of overhead lines and replacement of switchgear 

and cables. The allowed expenditures were determined 

largely by the model described earlier. 

Figure 3: Trends in average lives of distribution substation assets 

(top) and in average lives of distribution lines and cables (bottom). 

Similar developments in the assessment of the asset lives of 

transmission plant and equipment have been reported by 

National Grid in the UK, recognizing that as knowledge has 

increased, lives have been extended for the majority of assets. 

Comparing Operators’ Forecasts and 

Regulatory Allowances 

Figure 4 presents comparisons of the respective projected, 

forecast and allowed annual capital replacement expenditures 

for the recent British distribution and transmission price 

control reviews (DPCR and TPCR): 

• DPCR3 (2000/1 to 2004/5) and DPCR4 (2005/6 to 

2009/10) asset replacement expenditures where the 

DPCR3 projected expenditure was the actual expenditure, 

adjusted by OfGEM for comparison purposes to exclude 

certain items. The DPCR4 forecast expenditure is that 

forecast by the network operators and the DPCR4 

allowed expenditure is that subsequently allowed 

by OfGEM. 

Two of the most experienced regulators, the Essential 

Services Commission of Victoria, Australia, and the UK’s 

OfGEM have accordingly introduced annual regulatory 

reporting requirements for network operators to 

supplement the price control reviews at four to five-year 

intervals. These reporting requirements allow the 

variances between actual and forecast expenditures to 

be monitored steadily and so improve the review process. 

Using Risk Assessment in Estimating 

Remaining Asset Life 

Risk assessment methods are now used by network 

operators, as mentioned above, including criticality analysis. 

Such assessments are an important part of the detailed 

and complex process of prioritizing asset replacement. 

A regulator would also need an overall output metric of 

asset risk to complement the input-related modelling of asset 

replacement and output-related annual reporting of network 

reliability performance. The concept of weighted average 

remaining life of assets has been used elsewhere to obtain 

a general view of the appropriateness of asset replacement 

expenditure levels and may be considered as an indirect 



indication of asset risk (Table 1). Caution should be 

exercised, however, when comparing the weighted remaining 

lives from different jurisdictions because asset lives may differ. 

Table 1: Asset Risk: Weighted Average Remaining Life (WARL). 

Figure 5 presents the WARL trends for the assets of a 

particular network, including the results of sensitivity analysis. 

Conclusions 


A regulator requires a means to assess a reasonable level of 

expenditure on asset replacement by network operators. 

This can be provided by retirement profile-based modeling, 

which is also a useful aid to network operators for reviewing 

programmes built up from detailed considerations, principally 

of asset condition. There is a general trend to date for asset 

lives to increase. The integrity of the modelling process 

remains dependent on quality of data and, to this end, the 

retrospective modelling of historic replacement enables 

verification of asset lives. Weighted average remaining life 

provides an overall output metric of asset risk. 

PB has applied the model in reviewing the asset replacement 

expenditure on a number of distribution and transmission 

price control reviews in recent years for OfGEM in Great 

Britain, in 2001 for the Commission for Energy Regulation in 

the Republic of Ireland and in 2006 for the Energy Regulatory 

Commission in the Philippines. The model has enabled the 

regulators to make final decisions on the allowed levels of 

asset replacement expenditure with little challenge. 

 

Figure 5: Weighted Average Remaining Life Trends — Existing 

Assets. 


• OfGEM www.ofgem.gov.uk 

John Douglas has more than 35 years of experience in electrical power engineering with PB, specialising in transmission and distribution planning as well as electricity utility 

regulation. In recent years he has undertaken reviews of investment expenditure on electricity networks in Great Britain, Ireland, Philippines and South Africa. John is 

coordinator of PAN 53, High Voltage Transmission & Distribution. 




New Zealand Energy Strategy – A Plan for a 

Sustainable Nation By Nick Barneveld, Wellington, New Zealand. 64 4 916 6558, barneveldN@pbworld.com 

New Zealand promises to be 

one of the world’s leaders in 

taking proactive measures 

toward sustainability in the 

electricity sector. The 

author tells of its goals and 

strategies, and in so doing, 

illustrates the promise of 

the Kyoto Protocol. 


CER: 

ETS: 

GHG: 

NZETS: 

NZU: 

Certified Emission 

Reduction 

Emission Trading 

Scheme 

Greenhouse gas 

New Zealand 

Emission Trading 

Scheme 

New Zealand Unit 

Figure 1: Fuel supply – 

Hydro storage trajectories. 

The New Zealand government is determined that the country become a truly sustainable 

nation, and even a carbon neutral nation. Its recently introduced New Zealand Energy Strategy 

to 2050 (referred to in this article as The Strategy) maps out an ambitious pathway for the 

reduction of energy-related greenhouse gas emissions. Operating within a framework of 

competitive energy markets,The Strategy was designed to: 

• Set conditions for capital investment 

• Provide leadership on energy security and climate change issues 

• Respond to the challenges of meeting demand in a growing economy, maintaining security 

of supply and reducing greenhouse gas emissions. 

The Strategy and the associated New Zealand Energy Efficiency and Conservation Strategy 

introduce initiatives that champion: 

• Renewable energy across the electricity generation market 

• Energy efficiency among transport, domestic and commercial users 

• Development and deployment of sustainable energy technologies. 

The current electricity sector of New Zealand is characterised by: 

• A long stringy transmission system spanning two islands, which are linked by a high voltage 

direct current (HVDC) transmission line with both over-land and sub-sea components 

• Significant indigenous fossil fuel 

• Tightening supply and demand 

• Rising investment costs and wholesale and retail prices 

• Vertically integrated generator retailers 

• Renewable generation resources that are notable for significant seasonal and year-on-year 

variability (Figure 1). 

New Targets for Low Emissions 

A secure energy system with low emissions will require 

changes in the way electricity, heat and motive power are 

produced and delivered. For example, the electricity 

sector, currently sourcing 65-70 percent of its “fuel” from 

renewable sources (Table 1), has a target of achieving 

90 percent renewables generation by 2025. This very 

challenging target requires servicing all new demand with 

renewable generation and reducing existing fossil fuelled 

thermal generation by more than 50 percent, replacing it 

with energy generated using renewable technologies. 

This renewable generation policy position is a major change 

from the prior neutral policy position. The new policy has been given impetus by a legislated 

ban 1 for the next ten years on new base-load thermal electricity generation, plus New 

Zealand is a signatory to the Kyoto Protocol. 

1 At the time of writing the legislation is 

in the process of being enacted. 

Tidal power is one technology that the government is supporting, as New Zealand has 

significant potential available along its extensive coastline. In fact, Crest Energy Limited has 

applied for environmental consent to construct a marine turbine power generation project in 

the Kaipara Harbour in Northland, northern New Zealand. The project comprises up to 200 



Table 1: Electricity generation by fuel type (2006 calendar year). 

completely submerged marine tidal turbines with a maximum 

generating capacity of about 200 MW. They would be 

located near the entrance of Kaipara Harbour, one of New 

Zealand’s natural harbours that is not used as a major port. 2 

Emission Trading Scheme 

The introduction of the New Zealand Emission Trading 

Scheme (NZETS) was announced in September 2007. 

NZETS is the first mandatory greenhouse gas emissions 

control measure in the world that proposes to cover all 

six Kyoto Protocol greenhouse gases: 

•CO2 Carbon dioxide 

•CH4 Methane 

•N2O Nitrous oxide 

• PFCs Perfluorocarbons 

• HFCs Hydrofluorocarbons 

•SF6 Sulphur hexafluoride. 

Figure 2: Electricity generation weekly CO2 emissions 

March 2007-May 2008. Source: Energy Link Limited 


Figure 2 shows the CO2 emissions from March 2007 through 

May 2008 from the various generation facilities currently 

within New Zealand’s thermal electricity generation portfolio. 

These levels are based on the current operating regime 

of the asset portfolio shown in Table 1. They illustrate 

two factors: 

• The magnitude of the target CO2 emissions from electricity 

generation. (On a global scale, the emission quantities are 

very small.) 

• The extreme sensitivity of the existing generation mix with 

its high proportion of renewable plant to uncontrollable 

weather influences. The 30 percent year-on-year increase 

in CO2 emissions for the month of May is a result of a 

lack rainfall in the hydro generation catchments. The 

contribution attributed to Whirinaki during April/May 

2008 (see Figure 2) is from a 150 MW diesel fuelled open 

cycle gas turbine power station built by the government to 

provide back-up to the hydro generators in the event of 

water shortages. 

Under NZETS: 

• There will be no free allocation of greenhouse gas 

emissions for electricity generators and fossil fuels. 

• Larger industrial firms will get a partial free allocation 

of emission units to cover their direct emissions and 

the indirect emissions of their electricity use. They will 

have to buy NZ Units (NZU) to cover their remaining 

greenhouse gas emissions 

• The international reductions purchased will be primarily 

Clean Development Mechanism Certified Emission 

Reductions (CERs) from developing countries. 

The price of NZU will be set by international CER prices. 

Higher Energy Prices on the Horizon 

Meeting New Zealand’s new targets means 

that everyone in the country will be affected 

by higher prices for nearly all forms of 

energy. Businesses and individuals will be 

able to manage their exposure to these 

higher energy prices by: 

• Improving their energy efficiency 

• Developing their own renewable 

energy sources 

• Investing in their own Clean Development 

Mechanism projects in developing 

countries. 

With NZU prices expected to converge 

eventually with European Union Emission 

Trading Scheme (ETS) prices, petrol and 

2 For more information about tidal power, see “Project Brief: Tidal Power” 

by Peter Kydd on page 53. 



diesel prices will increase by around NZ $0.10/litre. Wholesale 

electricity prices will rise by nearly 20 percent (Figure 3). 

This increase can be expected to flow through to nearly 10 

percent retail electricity price increases. 

Figure 3: Forward price estimate based on $20/tonne CO 2 

in 2007 escalated @ 7.5%/yr – incurred from 2010. 

NZ $ / MWh 

180 

160 

140 

120 

100 

80 

60 

40 

20 

0 

2008/ 

2009 

2009/ 

2010 

2010/ 

2011 

2011/ 

2012 

2012/ 

2013 

Year 

2013/ 

2014 

2014/ 

2015 

2015/ 

2016 

2016/ 

2017 

95th Percentile 75th Percentile Average 25th Percentile 5th Percentile 

2017/ 

2018 

An ETS scheme will not have much direct impact on the 

wider energy demand in New Zealand because transport fuel 

use and electricity demand are not particularly price sensitive. 

The recent dramatic oil price rises have demonstrated the 

weakness of marginal price signals to reduce CO2 emissions 

from transport. In addition, major industrial users can expect 

to get generous free NZU allocations initially. 

Extensive renewable generation development will require 

major investments in the transmission grid investment over 

and above that already contemplated to deal with organic 

load and generation portfolio growth. This need results from 

the thermal generation close to demand being replaced by 

distributed renewable generation located more distant from 

demand. This major additional investment will result in 

increased transmission charges to consumers, who will receive 

no additional commercial benefit. This additional transmission 

investment will result in an increase to the cost of delivered 

electricity to all consumers on top of the 10 percent increase 

expected from the CO2 charge effects on generation costs. 


PB is Supporting New Zealand’s Becoming a 

World Leader 

PB is involved extensively in the New Zealand energy sector, 

having played a role in: 

• The development of wind farms; geothermal power 

stations and steam fields, and hydropower stations 

• The planning, design and implementation of transmission 

system 

• Areas of sustainable development, energy efficiency and 

Clean Development Mechanism projects. 

Current activities in the sector include assisting Contact Energy 

Limited develop a large geothermal power station, and serving 

as project manager for the development and implementation 

of a biodiesel manufacturing facility based on canola seed 

feedstock for Biodiesel New Zealand Limited. We have also 

been invited by Crest Energy Limited to propose what skills 

we can bring to bear on the development of its 200 MW 

tidal power scheme after they secure the environmental 

approvals. 


•New Zealand Energy Strategy: http://www.med.govt.nz/templates/ 

ContentTopicSummary_19431. aspx 

•http://www.climatechange.govt.nz/ 

•http://www.biodiesel-nz.co.nz/index.cfm/1,118,0,44,html 

•http://www.contactenergy.co.nz/web/view?page=/contentiw/pages/ 

ourprojects/temihi&vert=pr 

•http://www.crest-energy.com/ 

•http://www.meridianenergy.co.nz/OurProjects/ 

Nick Barneveld has worked in business development, corporate strategic energy planning, power station commercial assessment, technical and commercial due diligence, 

financial modelling including development of technical and commercial assumptions, power station engineering and operations and maintenance and functions. His’ recent 

activities include assignments relating to technical due diligence for a successful A$7.4 billion competitive bid for Australian infrastructure assets, the development of a 

US$4 billion coal to liquids plant in New Zealand, due diligence of a new high moisture content low rank coal gasification technology, exploitation of coal bed methane, an 

underground coal gasification development programme, and the development of New Zealand’s first commercial-scale biodiesel manufacturing plant. 



Power Articles in Network, NOTES, and Powerlines 

Compiled by John Chow, New York, 1-212-465-5249, chow@pbworld.com 

Eight years have passed 

since the last PB Network 

devoted to power, and six 

years since the last NOTES 

on power. This is a partial 

list of the steady stream of 

power articles that have 

appeared in three PB publications 

since then. 

PB Powerlines 

The 7-page June 2008 issue is typical of the past 17, with 12 provocative titles: Turning the 

tide into power; Sunshine in Spain; Celebrating in style; Meeting the need; Green light for 

Az-zour North; Hot design; New power plant for Portugal; Waste not, want not; Asian 

expansion; Mining a rich new seam; Laying a strong foundation; and Changes at the top. 

NOTES 

“A World of Power” was the last issue devoted to power (Feb 2002). Another 2009 NOTES 

features power. Power-related articles since 2005 include: 

• Powering the Middle East, Dec 2007, pp. 13-15 

• The Essentials: Water and Power, Sep 2007, pp. 19-23 

• Green Power Around the Globe, Dec 2006, pp. 9-11 

• Building Green Structures in Support of Environmental Quality (section on ethanol plants), 

Dec 2006, p. 16 

• First Things First: Clean Air for Students, May 2005, pp. 6-7 

PB Network 

“Innovation in Global Power” contains 42 power-related articles (PB Network 68). “Power 

Engineering” was the last issue on power and energy, containing 35 power articles (#48, Nov 

2000, http://www.pbworld.com/news_events/publications/network/issue_48/48_Index.asp.) 

Over 20 power/energy articles have appeared since 2003. 

In Issue 67 on Project and Public Communication, June 2008 

Addressing a Community’s Concerns about a New Wind Farm. Mark Denny and Richard Wearmouth, 

Newcastle. Both engineering and environmental knowledge are crucial to the public consultation 

process in having a new wind farm approved. (#67, pp. 67-68) 

Powerlines 

News and industry comment from the 

power group of PB. Published 2-3 

times a year. Editor Maria Laffey, 

Newcastle, UK. Under “Publications” 

in PB Ltd’s web site at 

http://www.pbworld.co.uk/index.php?doc 

=530. 

NOTES 

Each issue highlights a PB market or 

service. Published 3 times a year. 

Editors Tom Malcolm and Muriel 

Adams, New York. Under “News & 

Events” in PB’s web site at 

http://www.pbworld.com/news_events/ 

publications/notes/default.asp. 

Network 

A technical journal by PB employees 

and colleagues. Published 3 times a 

year. Editors John Chow and Lorraine 

Anderson, New York. Under “Research 

Library” in PB’s web site at http:// 

www.pbworld.com/news_events/ 

publications/network/. 

In Issue 66 on Visions,Trends, Innovations, December 2007 

http://www.pbworld.com/news_events/publications/network/issue_66/66_index.asp 

Which Will Run Out First, People or Gas? Alan Lawless, Manchester. Is there sufficient talent to handle 

the future needs of the mature UK gas industry? (#66, p. 29) 

New Designs of Electricity Networks to Include Renewables and Improve Reliability. Nicola Roscoe 

and Katherine Jackson, Manchester. We may soon be designing electricity network architectures that 

are very different from today’s.The catalyst for change is the increased levels of renewable generation. 

(#66, pp. 81-83) 

Cutting Carbon Emissions by Distributed Energy Generation. Ian Burdon (Newcastle),Tom McKay 

(London) and Alastair Robinson (London). PB undertook a study for a UK agency about legislative 

barriers to carbon reductions, and PB recommended a strategy for success. (#66, pp. 84-87) 

Experiences and Trends in Automating Transmission Substations in Abu Dhabi. Oleg Matic. PB has 

contributed to the introduction of and improvements to transmission substation control systems in 

Abu Dhabi since the late 1990s. (#66, pp. 88-89) 

In Issue 65 on the Middle East, June 2007 

http://www.pbworld.com/news_events/publications/network/Issue_65/65_index.asp 

400 KV Interconnection of Abu Dhabi Island. Walter Bullock. Undertaken to augment the supply of 

electricity to Abu Dhabi Island and prevent blackouts, this project incorporated some of the latest 

 



developments in circuit breaker and cable technologies. 

(#65, pp. 79-80) 

Design and Construction Considerations for Offshore Wind Turbine 

Foundations. Sanjeev Malhotra, New York. Larger wind turbines 

are being developed for off-shore wind farms, and their loads are 

creating new design and construction challenges for foundations. 

(#66, pp. 92-95) 

In Issue 59 on Sustainable Development, Nov 2004 

http://www.pbworld.com/news_events/publications/network/issue_ 

59/59_index1.asp 

The First Trigeneration System in a Beijing Commercial Building, 

Vincent Tse and Colin Chung, Hong Kong. A trigeneration system 

produces energy for electricity, heating and cooling very efficiently, 

becoming an attractive option for sustainable development projects 

encouraged by the Chinese Government. (#59, pp. 78-80) 

Independent Water and Power Projects: PB Invention to Improve 

Desalination. Paul Willson, Manchester. PB served on a technical 

team that demonstrated an independent water and power project 

plant that was much more efficient and sustainable and offered the 

lowest life cost. (#59, pp. 54-56) 

Using Minewater as a Heat Source. James Dickson and Dominic 

Bowers, London. For a new community to be built at a former 

coal-mining site, our analyses proved that the most sustainable 

option included the use of minewater as a heat source. 

(#59, pp. 61, 62) 

Sustainable Energy in the English Dales, Ian Burdon and Daniel 

Dufton, Newcastle. PB’s strategy for the regeneration of a dale 

taps into geothermal heat; brings power, heat, and economic 

strength to the region; and maximises benefits to the client, 

developers, and the community. (#59, pp. 63-65) 

In Issue 57 on Segmental Bridges, Feb 2004 

http://www.pbworld.com/news_events/publications/network/issue_ 

57/57_index.asp 

Advantages and Disadvantages of Long-Term Service Agreements 

for Independent Power Projects. Richard Whyte. Several considerations 

need to be evaluated if a long term service agreement 

for an IPP will meet the owner’s objectives. (#57, pp. 78-80) 

In Issue 56 on Australia/New Zealand, July 2003 


issue_56/56_Index.asp 

Criteria for Identifying Viable Wind Power Market Sites. Achim 

Hoehne. Selection of appropriate sites for wind farms is a key factor 

to the growth of wind power use. PB uses four criteria in helping 

clients identify sites that will be feasible, productive, practical and 

acceptable to the public. (#56, pp. 24-26) 

The Permitting of Toora Wind Farm. David Spink, Melbourne.The 

climatic conditions of certain Australian coastlines are ideal for 

wind farm development. PB had a role in the permitting of one of 

Victoria’s first wind farms. (#56, pp. 27-28) 

Steamfield Manager: Software for Resource Consent Reporting and 

Long-Term Steamfield Management. Errol Anderson and Aaron 

Hochwimmer, Auckland. PB Power designed Steamfield Manager 

software to manage the unique data environment of a geo-thermal 

power plant. (#56, pp. 29-31) 

Electrical Requirements of Geothermal Power Projects. Ivan Hunt. 

PB helped develop electrical design and engineering solutions to 

meet the unique requirements of new geothermal power stations. 

(#56, pp. 32-34) 

Tokelau Power Project. Christopher Lynch, Christchurch. Unique 

challenges, including non-technical ones, arise when designing a new 

power supply system in a remote area. (#56, pp. 35-36) 

Re-using Effluent to Supply the Millmerran Power Station. David 

Kent, Brisbane. We included unusual devices and protocols when 

designing a main to transport effluent from a sewage treatment 

plant to a new power station in order to prevent effluent from discharging 

accidentally. (#56, pp. 37-40) 

The Upgrading of an Existing Coal-fired Power Station. Mal Cotter 

(Brisbane), David Lesneski, Peter Reimann. In 2003, Australia derived 

85 percent of its energy from coal. With increasing limitations on 

development of new coal facilities, however, refurbishing existing 

plants is becoming more important. (#56, pp. 41-43) 

Victoria’s Ageing Low-Pressure Gas Mains: Urgent Replacement or 

Not? Lane Crockett. Cast iron and unprotected steel gas mains are 

considered to be the main contributors to maintenance costs, leak 

rates and public safety risks. (#56, pp. 44-45) 

PB Takes Lead Role in Electricity Competition Reform. Anthony 

Seipolt. PB has taken an unusual role for a consultancy and is 

working with Australian regulatory bodies to enable the smooth 

implementation of competition amongst utility providers, which is 

a growing trend. (#56, p 46) 

Expenditure and Reliability Modelling. Brian Nuttall and Jacqui 

Bridge, Melbourne. In contrast to Seipolt’s article about the policy 

level, this article describes how we help utility companies adhere to 

regulations. Our models forecast network expenditure and reliability 

for the electricity, gas and water markets, and are applicable to 

pipeline, road, rail, and other networks. (#56, pp. 47-49) 

Lenders Engineer on Power Projects...Tales from the Vault. David 

Maslin. Based on experience working for financial institutions, 

Maslin discusses features of being a lenders’ engineer on power 

projects. (#56, pp. 50-51) 

John Chow has been the Executive Editor of PB Network since 1986. He has 

managed the Practice Area Networks since 1994. As part of the knowledge 

management team, John is the global content manager for Hub (PB’s SharePoint 

intranet), and has always fostered the sharing of knowledge at PB. 


DEPARTMENTS 

PB’s power specialists 

provided R&D for the 

redesign of the main 

components of a dynamic 

composting system. This 

was a new area of work that 

resulted in lower energy 

consumption for our client 

and an expected longer life 

for its composting equipment. 

Figure 1: Corridors in an opentrench 

composting facility. 

Figure 2: Composting machine. 

PB Redesigns a Composting 

Machine for Improved Operations* 

By Oriol Altés, Barcelona, Spain, 34 93 5088520, altesO@pbworld.com 

Manufacturing organic compost is an effective way to recycle urban solid waste (USW) and 

other raw materials, such as sewage sludge and vegetable and forest residues. This can be 

done by using a dynamic composting system in either open trenches or closed tunnels. 

Open trench dynamic composting requires the construction of specific machinery. We are 

seeing many new developments and continuous improvements in such machinery. In fact, 

PB has worked closely with a client in Spain on the redesign of its operational units. Our 

research and development of new solutions and improvements have led to a revised design 

of the main systems of the composting machinery, including the mechanical, electromotor, 

hydraulic, control, and safety systems, and the redesign of civil works for the implementation 

of the machinery. 

Dynamic Composting Machinery 

Dynamic composting is based primarily on mixing USW or sewage sludge with other 

vegetable substances to obtain the correct initial properties for density, viscosity and humidity. 

The fermentation and maturing processes of this primary material take place in a group of 

trenches (Figure 1), which are corridors limited by concrete 

walls and a lower soleplate/ventilation system. The soleplate is 

a false floor made of perforated tiles that provide adequate 

ventilation to the material in the composting process. The 

trenches can be in a closed industrial warehouse or in an 

open one with a roof only, depending on the surrounding 

environmental needs, such as odor control and other 

considerations. 

The composting machine moves along the concrete walls on 

a rail system turning over the material with a cylindrical rotating drum 

with blades as it moves (Figure 2). It is propelled with electric motors 

for the translation movement and hydraulic power for the rotating 

drum. Composting operations are fully automated. The machines can 

be programmed to turn over material in all the trenches at the plant. An 

auxiliary transfer rack guides the machine into position over each trench. 

The turn over accelerates fermentation and the maturing process by 

contributing to the dissipation of excessive heat/temperature and restoring 

oxygen to the material. In addition, the ventilation system helps to 

maintain adequate levels of temperature and oxygen. The machine could 

also incorporate an on-board irrigation system. Gases emitted in the 

fermentation process are captured and sent to a treatment system (washing and filtration). 1 

Leaching generated is reused to wet the organic material at the beginning of the process. 

*La edición en lengua española del 

presente artículo está disponible 

en la dirección Web de PB Network. 

1 The topic of treating gases is covered in more detail in a preceding article, “Converting Landfill Gas to High-Btu Fuel” by Roger 

Lemos. This is also on the web at http://www.pbworld.com/ news_events/publications/network/ 


Networking 

Approach to the Development of New 

Machinery 

PB’s power specialists in the Barcelona office were contracted 

to develop a new generation of dynamic composting 

machines together with our client, ROS ROCA IMA, a 

well known firm in the Spanish environmental sector, and 

significantly improve the existing operational units. Our 

reengineering works were directed to the accomplishment 

of two main objectives: 

• Update the technology of the existing machinery to solve 

the problems associated with operations reliability and 

difficulty of maintenance, and to bring it up to state-ofthe-art 

standards using the best technical quality affordable 

• Design new machines that would be of reasonable cost 

for the manufacturer, buyer, and plant operator. 

A complete study of the reengineering works was developed 

from the technical information provided by the client, the 

client’s previous experiences, information learned during field 

trips to different composting plants, and a full analysis of the 

existing units. At this stage of the project, the scope of the 

reengineering works included the following systems: 

• Mechanical 

• Electrical and traction/propulsion 

• Hydraulics 

• Control and security 

• Civil works and the trenches. 

Figure 3: 

Stresses on 

various areas of 

a composting 

machine component. 


Mechanical System. Our goals were to reduce energy 

consumption and to extend the life of the critical parts of 

the system by three to four times. For this effort, we 

worked together with Centre de Disseny d’Equips Industrials 

(CDEI) at Universitat Politècnica de Catalunya (UPC), an 

external design center that we hired. CDEI has extensive 

experience in machines and industrial mechanical equipment 

and had first order references from important firms in the 

Spanish market. Under our supervision, the following problems 

were studied in depth: 

• Wear and abrasion 

• Alternative designs of mechanical parts and the use of 

different materials with more mechanical strength 

• Fatigue of some parts that had a short life expectancy. For 

this task, specific software and the finite element method 

were used for our analysis. (Figure 3). 

• General redesign to provide for less wear and lower 

weight for the main parts involved in the rolling and 

coming in direct contact with the compost materials 

Electrical Propulsion System. We studied the static (i.e., 

forces and moments diagrams, centers of gravity) and the 

dynamics of the machine (i.e., torque/traction motor, speeds, 

phases of movement) to find solutions to the main problems 

with the machines, which were primarily slipping and sliding. 

Our work included: 

• Studying available alternatives in terms of electric traction 

motors and drives: conventional electric motors with 

frequency converters compared to vector or servo motors 

driven by servo-frequency converters. 

• Calculating real power demand to move the machine and 

the distribution of torque for optimal traction of the driving 

wheels, depending on the work phases and different loads 

caused by the turning of organic compost. 

The solutions we proposed to the client also involved using 

a different nominal power for the front and rear axles and 

changing the gearboxes. 

Hydraulic System. The hydraulic system provides the power 

to the main burrowing drum that turns over the compost 

material, and also to the various hydraulic cylinders that 

move major parts of it. The most important problems in this 

hydraulic system were caused by the harsh environmental 

conditions of the work, such as high temperature, dirty 

environment and oxidation. These conditions affect all other 

systems of the machine as well, but were particularly harsh 

on the hydraulic system. 

The proper redesign made by the supplier and the client’s 

experience in operating and maintaining the machines will solve 

the dysfunctions observed in the system, such as excessive 

temperature of the hydraulic oil caused by the blocking of 

the cooling system or pollution to the environment. 

Control and Security System. As mentioned, the 

composting operations in the field were fully automated 

and controlled by computers in the central control room. 

We conducted an extensive review of the existing system 

to determine: 

• What sensors and transmitters were needed for the 

correct operation of the machines and the trenches 

system in the field 



• What CPUs and PLCs were needed in the control panels 

at the central control room in the plant and local control 

panels in the machines 

• How to reconfigure the programs loops and basic software 

control of the machines to solve the problems of 

traction/sliding, strikes and setbacks of the machinery in 

operation, incorrect travel and operation speeds, etc. 

• What signals were needed for operation, control, warning 

and personal safety, and machine and installation security 

• How to provide a centralized control system for maximum 

automation modes at a reasonable cost. 

We also investigated the use of state-of-the-art industry 

standards for bus communications under Industrial Ethernet 

(called PROFINET) with both wired and wireless connections 

between devices in the field at field and in the control. It 

was important that the new system be more reliable and 

faster than the current system, which communicates via 

radio. Other future enhancements we considered included: 

• Decentralized equipment for local control in manual or 

maintenance mode operations 

• Expanded control system to allow more than one machine 

to operate in the trenches at the same time. 

With regards to security, our client was interested in 

improving the personal safety of those working in the field. 

After conducting a thorough review of the issues concerning 

the safety and protection of personnel, including mechanical 

safeguards, light and acoustic signals, emergency stops at 

field, and danger warning posters, we made the following 

recommendations: 

• Integrate the security functions of the machines in the 

control system using Profisafe standard developed under 

Profinet standard. 


• Add an “ADJUSTMENT” mode to the control system for 

safe local maintenance operations. 

• Prepare documentation to guarantee and maintain the 

machine and installation safety, including instruction 

manuals, periodic safety inspections, training, etc. 

All the investigations and developed works that resulted 

represented several new ideas/concepts/solutions for the 

new equipment, or new ways of operating the composting 

machines. 

Civil Works and Trenches. For this system, we worked on 

two major tasks. We drafted protocols about dimensional 

control for trenches and the rail system to ensure that they 

were constructed properly. This was important because the 

composting machines require well-executed civil works with 

the planned and precise tolerances for proper operation. 

We also recalculated the reinforced concrete walls and their 

foundations to have a standard for manufacturing. The external 

dimensions were not modified because they are in accordance 

with our client’s standards. The changes that were needed 

were in the composition of the concrete walls and foundations 

and in their reinforcement. 

Conclusions 

This R&D project introduced our power specialists in Spain 

to a new area—consulting on detailed project engineering. 

The working method has been the result of a very close 

collaboration of our team with all parties involved: our 

client, supply companies and external collaborators. This 

collaboration was essential for the project’s success. Our 

client plans to introduce PB’s redesign solutions progressively, 

and we fully expect that the composting operations will run 

much more smoothly. 

 

Oriol Altés is project engineer with PB’s power group in Spain. He holds a Bachelor of Industrial Engineering degree, Energetic Techniques Intensification. Oriol specializes 

in the fields of energy, process engineering and cogeneration. He has a good knowledge of the industry and some major components due to his professional experience in the 

field of industrial steam boilers. 



Water Factory Will Help to Address Water 

Shortage Concerns 

By Andrew Hodgkinson, Melbourne, Victoria, 61(3) 9861 1171, hodgkinsonA@pbworld.com 


Gippsland Water Factory is 

a leading example of 

integrated urban water 

cycle management. The 

author provides an overview 

of the facility and the key 

three steps in its wastewater 

treatment process, 

and tells of the alliance 

delivery model that has had 

outstanding results in 

Australia. 

Figure 1: Membrane bioreactor 

construction as of September, 

2007. 

1 Two other articles in this issue are 

about related topics. See “Converting 

Landfill Gas to High BTU Fuel” by 

Roger Lemos, pp.54-55; and ”Planning 

for Mini Hydro in Distributed Generation” 

by Tony Mulholland, pp.25-26 and 

37. 

2 To learn more about commercial composting, 

see the preceding article, “PB 

Redesigns a Composting Machine for 

Improved Operations” by Oriol Altés, 

pp.91-93. 

The Latrobe Valley region in the State of Victoria, Australia, is pioneering a solution that will 

help to address water shortage concerns, provide lasting community benefits and set the 

standard in Victoria for industrial water reuse. The Gippsland Water Factory, an A$174 million 

facility, will be an innovative wastewater treatment and water recycling facility. An alliance of 

PB, Gippsland Water,Transfield Services Limited and CH2M HILL will deliver the facility. 

When PB first began working with Gippsland Water on the project in 2001, the focus was to 

develop a management strategy to solve some immediate environmental issues (especially 

odour) associated with Gippsland Water’s Regional Outfall Sewer. Over several successive 

stages, the project’s focus widened to the long-term sustainability of the entire region’s water 

supply, and the variety of benefits the facility could deliver. The current Gippsland Water 

Factory (Stage 1) works are establishing an initial recycled water supply of 8 ML (2 million 

gallons)/day to service a local paper mill. 

Major civil works began in early 2007. Major concrete works for the membrane bioreactor, 

the key structure of the facility, are now complete (Figures 1, 2, 3 and 4). The membrane 

bioreactor is a membrane filtration system that will use ground-breaking technology to 

provide an important step in the treatment of the region’s domestic and industrial 

wastewater. Successful hydro testing of this structure was 

completed in March 2008, a major milestone for the project. 

How the Technology Works 

The facility was designed to minimise greenhouse gas emissions, 

with carbon efficiency being a key design objective throughout the 

project. Electricity to help power the facility’s operation will be 

generated onsite from biogas produced in the initial biological 

treatment and from a nearby micro-hydro facility. 1 Such generation 

methods will help to minimise environmental impacts on the 

site and help keep the carbon footprint of the project as small 

as possible. 

Also planned as part of the water factory is the Vortex Centre, 

which would showcase the wastewater treatment technology and 

serve as an education resource for the community. 

The water factory includes three key treatment processes: biological treatment, membrane 

filtration and reverse osmosis. 

Biological Treatment. During biological treatment, bacteria feed on organic substances in 

the water. At this stage, the organic matter present in the water is converted to carbon 

dioxide, water and sludge. This sludge concentrates in the bioreactor and over time is removed 

from the reactor tank as biosolids, which will be further processed offsite into compost. 2 

The remaining water moves on to the next stage of the process, membrane filtration. 

Membrane Filtration. During membrane filtration, the biologically treated water is 

separated from the sludge through a series of ultrafiltration membranes. Each membrane 

is like a straw dotted with thousands of tiny holes (pores) that are less than one-tenthousandth 

of a millimetre in diameter. 



Figure 2: Post-tensioned walls under construction in October 

2007. 

Figure 3: Walkway around membrane bioreactor, February 2008. 

Each membrane is periodically cleaned to remove the sludge 

from its surface so the filtration process can continue. The 

filtered and biologically treated domestic wastewater is then 

suitable to progress to the third stage of the water treatment 

process, reverse osmosis. 

Reverse Osmosis. Reverse osmosis is most commonly 

used to remove salt from water. It can remove more than 

90 percent of the salts contained in wastewater. This process 

uses a semi-permeable membrane that has pores around 

one-ten-millionth of a millimetre in diameter. The salty water 

is placed on one side of the membrane filter and pressure is 

applied to drive the water through the semi-permeable 

membrane. The result is a high-quality, low-salt water product. 

Alliance Delivery Model 

Alliance contracting is a form of relationship contracting that 

has delivered outstanding results on many Australian projects 

supported by PB and is continuing to be developed, increasing 

its ability to inspire innovation, drive high performance, and 

reward all participants. 

Figure 4: Aerial view of Gippsland Water Factory as of April, 2008. 

The Gippsland Water Factory Alliance has a contractual 

framework that aligns the commercial goals of all participants 

to the pursuit of one common goal or vision.This means that 

each alliance partner: 

• Assumes collective responsibility for delivering the project 

• Takes collective ownership of all risks associated with 

delivery of the project 

• Shares in the “pain or gain,” depending on how actual 

project outcomes compare to pre-agreed targets. 

 

Andrew Hodgkinson, an environmental scientist, is serving as technical director on the Gippsland Water Project. He joined PB in 1996. 

Note: See “Gippsland Water Factory: A Milestone in Water Cycle Management,” by Andrew Hodgkinson, PB Network 64, December 2006, p 64, 

http://www.pbworld.com/news_events/publications/network/Issue_64/64_21_Hodgkinson_Gippsland.asp. 




Swim Lanes Part 2: Laying Out a Swim Lane 

Diagram Using Microsoft PowerPoint ® or Visio ® 

By Kurt Sloan, Denver, Colorado, 1-303-390-5920, sloan@pbworld.com 

Swim lane diagrams are 

great tools for identifying 

the flow of a business 

process, responsibilities of 

its associated players, 

and areas for possible 

improvement. Read on to 

learn how to use standard 

software that most of us 

already have to make your 

swim lane diagrams. 

In our previous article, “Streamline Your Business Processes by Using a Swim Lane Diagram” 

(PB Network Issue 67 1 ), we discussed what a swim lane diagram is, how it could be used to 

map out a business process, and how it can help to identify candidate areas for improvement 

and process efficiency. In this article we build on these topics and show how either 

PowerPoint ® or Visio ® can be used to create basic swim lane diagrams. Beyond that, all you 

need is: 

• A process that needs mapping 

• A person with a good understanding of the process, its players, and their associated activities. 

PowerPoint ® 

Once you have started PowerPoint ® and have a process in mind that you want to map out, 

you are ready to make your swim lane diagram. First you build your diagram template (or use 

the pre-made template discussed below), and then map out your business process. 

Activate the “Drawing” Toolbar. Make sure that you have the “Drawing” toolbar activated 

(Figure 1). If not, then: 

1. Click on “View” at the top of the screen 

2. Click on “Toolbars” to see a list of all currently active toolbars within your PowerPoint ® session. 

3. If there is not a checkmark to the left of “Drawing,” click on the word to activate the toolbar. 

The “Drawing” tool bar should now be active, and most likely appear at the bottom of the screen. 

1 2 3 4 5 6 7 8 9 

Figure 1: The PowerPoint® 

“Drawing” Toolbar. Numbers 

coordinate with descriptions 

below. 

1 This article is also on the Web at 

http:www.pbworld.com/news_events/ 

publications/network/Issue_67/67_ind 

ex.asp 

Create Your Diagram Using the “Drawing” Toolbar. All the tools that you need to create 

a basic swim lane diagram are located on the “Drawing” toolbar. Those you will use in the 

order they appear on the toolbar are the following: 

1. AutoShapes. These are the symbols you can use to populate your diagram. Find the ones you 

like and drag them to your template. You can then add text and copy them as needed for reuse. 

2. Line. You can use the line tool to section off areas within the diagram, such as phases or 

departments. 

3. Arrow. Use the Arrow tool for showing the physical flow of information as it moves 

through the diagram. 

4. Rectangle. This feature allows you to create rectangles of varying shapes and sizes. 

It is a great tool for creating the layout (template) of the diagram prior to populating it with 

symbols, lines and text. 

5. Text Box. This feature allows you to add text to any of the shapes you place in the diagram. 

6. Fill Color. The “Fill Color” feature allows you to fill in the background of a selected shape 

to make it stand out from the rest of the objects on the page. 

7. Line Style. PowerPoint ® allows you to create lines of varying thicknesses, but experience 

shows that using the same width for your process arrows will make your charts easier to read. 



8. Dash Style. You can use the “Dash Style” button to 

change the type of line that you are using in the diagram. 

This is useful when you are differentiating between 

process steps and electronic data transfers. 

9. Arrow Style. The “Arrow Style” feature allows you to 

set the arrow head location on your lines to help your 

readers understand the direction the process is flowing. 


Creating Your Diagram. With your specific process in mind 

that you want to map and Visio ® started, your next steps are: 

1. When you are asked to “Choose a Drawing Type,” select 

“Business Process” to see the set of templates available to you. 

2. Select the “Cross Functional Flowchart” template by clicking 

on the appropriate icon for your geographic region (Figure 3): 

Now that you have a good grasp on the tools available to you, 

you can begin using them to create your swim lane diagram. 

Template Available for PB Staff. For the benefit of 

readers, I have created a pre-made PowerPoint ® swim 

lane diagram template (Figure 2) that can be downloaded 

from PB WorldNet at the following address: 

http://www.pbworldnet.com/launcher.asp?action=5&v=3&w= 

3765526&x=-1&y=563&z=3765526 

Figure 2: 

Sample 

Swim Lane 

Diagram 

Template. 

Figure 3: The “Cross Functional Flowchart” Icons. 

3. This will bring up the “Cross-functional flowchart” wizard 

screen (Figure 4): 

This template can be modified easily using PowerPoint ® to 

meet the needs of your actual process. 

Pros and Cons of Using PowerPoint ® . Using 

PowerPoint ® to create a swim lane diagram provides 

the following benefits over Visio ® : 

• It comes with most versions of Microsoft Office ® , so other 

team members can readily modify and enhance the diagram. 

• It provides a greater freedom for customizing the layout 

and design. 

PowerPoint ® does have a few drawbacks though: 

• There is no automated method for diagram creation. 

• It takes a greater effort to configure the diagram as needed. 

Visio ® 

If you have Visio ® available, you may prefer to create your 

swim lane diagram using its “Cross Functional Flowchart” 

template, which is another name for the swim lane type 

of diagram. You will still need to add your actual process 

steps, however, and to modify the drawing to identify your 

process needs. 

Figure 4: The “Crossfunctional 

flowchart” 

Wizard Screen. 

4. From here, you can tell Visio ® whether you want to create 

a “Horizontal” or “Vertical” flow. I prefer vertical for most 

situations, but choose the one that best fits your need. 

5. You can select the number of “bands” (“swim lanes”) that 

you want to create. I usually use one swim lane for each 

person (“actor”) involved in the process. 

Note: The Visio ® template allows no more than five 

“Function bands” in a single diagram. I believe that this is 

a drawback to using Visio ® because even though it is rare 

to need more than five, it is not unheard of. 

6. If you wish to add an area for a title bar at the top of the 

chart, be sure to select the “Include title bar” option: 

7. Once you are happy with your selections, click the “OK” 

button and Visio ® will provide you with a pre-made layout 

for your Swim Lane Diagram (Figure 5 on the following 

page) 

 




And, like PowerPoint ® ,Visio ® has its limitations: 

• You are limited to between one to five swim 

lanes. 

• Connection lines that cross each other will 

change shapes to reflect the process “fly 

over.” This feature is one of my least 

favorites, particularly because Visio ® does not 

give you a choice about using it. 

• There is an extra-cost involved for most 

users because Visio ® is not part of the standard 

PowerPoint ® suite of products. 

Which Application Is Right for You? 

This is a question that only you can answer. If 

you have access to both applications, then your 

answer will probably depend on how much 

freedom you want and how much help you 

think you will need when creating your swim 

lane diagram. I suggest you make a few sample 

diagrams in each program to see which one is 

more comfortable to you. 

Conclusion 

Figure 5: Visio’s ® pre-made diagram layout. 

8. From the left side of this screen, select the “Basic Flowchart 

Shapes” menu bar to see a list of premade shapes you 

can use to create your diagram. You simply drag and drop 

these symbols onto the working area and then use the 

tools included with Visio ® to insert or modify lines, line 

types, line ends, shading, etc., as needed until your diagram 

looks the way you want. 

Pros and Cons of Using Visio ® . Using Visio ® to create 

your swim lane diagram provides you with the following 

benefits over using PowerPoint ® : 

• It comes with a template for faster creation and less need 

to “eyeball” the layout. 

• It provides more pre-made shapes and templates to 

choose from. 

• The line tool adjusts automatically to make it easier for 

the reader to follow the flow. 

As we mentioned in the first article, using 

swim lane diagrams to analyze and improve 

your business process is not rocket science. 

Figure out which tool and symbols work best 

for your purposes and don’t feel tied down to one set way 

of creating these diagrams. What is important here is to 

make sure you properly capture the process and deliver 

the message within the diagram in a way that all readers 

can understand. If your team can look at it and understand 

what you’re trying to say, then you are on the right path and 

well on your way to making your process more efficient. 

Next Time 

In Part 3 of this series, we will demonstrate how to take an 

existing process and capture it into a swim lane diagram, 

using what we have learned to this point. 

 

Kurt Sloan is the client services manager for the PB Project Information Management Technical Excellence Center in Denver, Colorado. 2008 represents Kurt’s 20th year 

providing information technology support and guidance to companies such as PB, Accenture / Andersen Consulting and Bank of America. 



Working with Text in Adobe Acrobat Pro: 

COPY TEXT TO OTHER SOFTWARE APPLICATIONS, 

USE BUILT-IN OPTICAL CHARACTER RECOGNITION, 

MAKE CORRECTIONS WITH THE TOUCHUP TEXT TOOL 

By Jim Hinshaw, Austin, Texas, 1-512-347-3504, hinshaw@pbworld.com 

Figure 1: Text 

selection. 

Most PB computers have a copy of Adobe Acrobat Professional installed thanks to a corporate license. 

Many users are not aware, however, that editable text can be copied from unsecured Acrobat files and 

pasted into Microsoft Word or other files. Acrobat even has a built-in optical character recognition 

function that lets users create editable text from scanned documents. These techniques will not work 

with Acrobat Reader software. 

Selecting and Copying Text 

Copying and pasting an image, text, and tables from a .PDF 

document to an MS Word document is easy. Click the Text 

Selection Tool (Figure 1), and click and drag over the text you 

wish to copy. Copy the text to the clip board (click on Copy 

under the Edit menu), and then paste it into your text document. 

This technique should work with any software that handles 

text and has a paste command. If you want to select all 

the text on a page, click your right mouse button and choose 

Select All from the contextual pop-up menu. 

Let your mouse hover over the selected text for a moment 

and you will see an Acrobat button appear. Move your mouse 

over the button, and more buttons appear giving you several 

options for copying or marking up the text (Figure 2.). Or, 

right click your mouse and this list will appear. 

If you want to copy all the text in a .PDF file and retain the formatting, choose 

Save As under the File menu and select Rich Text Format from the Save as type 

pop-up menu. Then save the document as a Rich Text Format (*.rtf) file. Microsoft 

Word will open the Rich Text file as if it were a native Word document. Be aware 

that text spanning several pages may contain header and footer text that you may 

not want to keep. 

Optical Character Recognition (OCR) for Copying Text 

Figure 2: Options for 

copying or marking 

text. 

If you have a document that you want to copy text from but can’t select the text, it 

is likely that the document was scanned. You are seeing a picture of the text that is 

not editable. Acrobat comes to the rescue with its built-in OCR function. OCR is a process whereby the 

software recognizes letter forms and converts their images into editable text. Click on the Document 

menu at the top of your window and select the Recognize Text Using OCR command (Figure 3 

on the following page). For most scanned documents, you can use the Start sub-command to 

convert all letter forms to editable text. A dialog box will appear asking you to specify the pages 

that you want converted. 

After Acrobat has finished OCR, use the copy and paste steps outlined above. It is a really good idea 

to proof-read the text after copying it, however, because OCR can make mistakes with a poor quality 

original. 

 


Computer Tutor 


You must have the document font on your computer system 

in order to add or replace text. Other properties are editable 

as long as the font is embedded in the PDF. Certain PDF 

security measures prevent documents from being edited. 

PDF Security 

Figure 3: The Documents menu showing how to start optical 

character recognition (OCR) function. 

The TouchUp Text Tool 

You can do quick, minor corrections to text inside a PDF 

with the TouchUp Text tool. The TouchUp tool is located 

under the Tools menu and Advanced Editing submenu. 

You can edit text and a variety of properties including 

font, size, horizontal scale, character spacing, baseline 

offset, character fill and stroke, and font embedding and 

sub setting (Figure 4). Once you access the TouchUp tool, 

simply highlight the text you want to replace and type in 

the corrections. To change properties, have the cursor over 

the selected text, then right click, and select Properties. 

If the techniques described above do not work, it could be 

that the author of the document has saved the file with 

security measures that prevent the copying of text. In this 

case, it is best to contact the author and ask permission to 

copy the file. This might be accomplished with a password 

or an unsecured version of the file. Not many people 

bother to or know how to secure a .PDF file, however, 

so if a document has been secured, the author is likely to 

have strong feelings about protecting the content. 

If you would like to secure your .PDF documents, the command 

to do so is found just above the OCR command in the 

Document Menu. There are several options available in the 

Security dialog box, and to cover them all would be an article 

in itself. In fact, that article will be in the next installment of 

Computer Tutor. Until then, use the Acrobat help file to 

learn more about both OCR and document security. 

 

Figure 4: The dialog box that appears when you select text with 

the TouchUp tool and then right click and select “Properties.” 


• http://www.adobe.com/products/acrobat/ 

• http://www.acrobatusers.com/ 

• http://www.planetpdf.com/ 

Jim Hinshaw, a senior graphic designer and business development associate, is located in Austin, Texas. Jim (aka graphics monkey) is a former PAN 9 coordinator and 

currently coordinates the Computer Tutor section of PB Network. He has worked for PB on and off since 1983 and is currently part of the U.S. Central 

District marketing team. 


Going Green: Walking the Walk!! 

By Kim Sammut, Adelaide, South Australia, 61 8 9489 9782, sammutK@pbworld.com 

PB offices around the world 

have established Green 

Teams dedicated to implementing 

initiatives that are 

reducing our impact on the 

environment. Members and 

staff are banding together 

with management support 

and changing the way we do 

business. 

For several years, many PB offices around the world have planned, implemented and 

monitored environmental management systems (EMS) to a standard worthy of ISO 

14001 certification, and many more are well on their way to achieving such certification. 

ISO 14001, the international specification for environmental management systems, is 

considered a base-level requirement by many of our clients and joint venture partners, 

who are increasingly recognising the need for duly diligent environmental management. 

In many instances, however, there have been gaps between what is prescribed in our EMSs 

and the daily practises demonstrated by our staff. We may have been seen to talk the talk, 

but not to walk the walk. Enter the Green Teams ... 

Green Teams 

Green Teams within PB offices are comprised of volunteers who share a passion for sustainability 

and for encouraging sustainable practises amongst their colleagues. Their members 

help to raise the profile of environmental issues while encouraging positive interaction between 

colleagues. This home-grown approach develops a sense of ownership among office staff of 

the steps laid out to save energy and reduce waste, and responsibility to follow these steps. 

Within the New York office, a mission statement has been developed that captures the 

essence of the Green Team philosophy: 

“To promote the continuous adoption of sustainable practices by PB in its New York 

offices and to create a sustained and growing awareness of the benefits of 

environmental responsibility among PB employees.” 

Ideally, within each office there will be active participation from a range of disciplines and levels 

of seniority. To maintain momentum, local Green Teams should share ideas regularly and 

make the time to implement initiatives. Whilst all of the above may sound good to the 

converted, there are others who may want to know what this all amounts to. Well, read on... 

Green Initiatives in PB’s Offices around the World 

Many of our offices appear to be on the same page with respect to the green initiatives that 

have been implemented locally. In one respect, this is remarkable due to the relative lack of 

Green Team collaboration throughout the regions; but it makes perfect sense considering the 

similarity of our office environments. Some of the more popular initiatives implemented 

around the world include: 

• Using only 100 percent recycled paper and printing double-sided (if at all) 

• Having automatic power shut-down on electrical equipment, including motion-sensor 

light switches in meeting rooms 

• Recycling paper, plastic, glass, batteries and mobile phones 

• Participating in events such as Earth Day, Earth Hour, Ride to Work Day and local 

neighbourhood clean-up days 

• Auctioning unwanted office equipment to staff or donating to local schools or charities 

• Drinking ‘Fair Trade’ organically-grown coffee in mugs (not throw-away cups). 

Green Teams have also helped to implement other sustainable measures in several offices. 

For example: 

• The Melbourne Office has recently installed LED lights, which consume up to 90 percent 

less energy than standard incandescent globes. 

 


Planetwise 

• The Portland Office has created vendor guidelines to 

encourage the use of local produce and minimal packaging. 

• In the Perth Office, waterless urinals have been installed, 

saving upwards of 500,000 litres (132,000 gallons) of water 

each year. 

• A number of Australian offices have worm farms that 

convert unwanted food scraps into a take-home fertiliser 

for staff gardens. 1 

Green Team members train staff about the initiatives in 

place and provide ongoing encouragement and monitoring 

of participation. 

What Does the Future Hold? 

In an ideal world, PB Green Teams the world over would 

participate in greater knowledge sharing to enable us all to 

reduce, re-use and recycle as much as practicable. Maybe we 

could even have an annual award for the greenest PB office? 

In parallel with us getting our own house in order, the new 

challenge for PB is to become a leader in advising our clients 

on sustainable solutions that could be incorporated into their 

projects. The awareness that our Green Teams promote in 

house coupled with a more external application of our 

environmental management systems will assist PB in fulfilling 

its vision of improving our communities. Let’s all walk the walk!! 

For more information on Green Teams or for advice 

on getting one started in your office, contact me at 

ksammut@pb.com.au or put the word out on PAN 63. 

 


• ISO: http://www.iso.org/iso/management_standards.htm 

• Earth Day: http://www.earthday.net/ 

• Earth Hour: http://www.earthhour.org/ 

• Ride to Work: http://www.earthride.com.au/ 

Issue 69. Managed Lanes, Bus Rapid Transit, 

and Other Congestion Management Solutions. 

Managed lanes, high occupancy toll lanes, and bus rapid transit 

(BRT) technologies and strategies help manage growing 

metropolitan traffic congestion in cities around the world. 

Other related topics are congestion pricing, tools for mobility, 

bus rapid vehicles, and streetcars. Our intent is to showcase 

the advances in technology and management strategies that 

PB is spearheading with our clients. 

Contact guest editors Cliff Henke (Arcadia California, 

henkeC@pbworld.com) and/or Darren Henderson 

(Houston, hendersonD@pbworld.com). 

Issue 70. Simulation and Modeling. 

This PB Network will focus on PB's strength in application of 

high-tech computer analysis techniques for environmental, 

power, transportation, buildings, and economics simulations. 

Many of PB's engineering services use complex computer 

analysis tools to aid design and construction of infrastructure, 

making it more efficient and cost effective. Key examples 

are computational fluid dynamics (CFD), virtual design and 

construction (VDC), 3D visualization, and animation. 

Sometimes, physical modeling (such as scaled-down wind 

tunnel testing) is also conducted, often to demonstrate how 

engineers' designs will function in the real world, providing 

calibration/verification of the computational model. Interfacing 

between computational models, providing a multi-physics 

capability is another area for innovation at PB. 

Deadline October 2008. Send articles to guest editors 

Simon Drake (Croydon, UK, drakeS@pbworld.com) and/or 

Glen Loyd (Denver, loydG@pbworld.com). 

Issue 71. Let the Games Begin. 

We will cover sports and entertainment facilities, Olympic 

venues, arenas, theaters, gambling and gaming sites, and casinos. 

This will include PB's achievements and lessons learned from 

Olympics in Beijing, Salt Lake City, Sydney, Atlanta, and others 

major events. 

1 

To read more about PB’s worm farms, see “Worms Are One Way to Go Green” 

by Andrea Averkiou, PB Network, Issue 60, p.98; or on line at http://www. 

pbworld.com/news_events/publications/network/issue_60/60_39_averkiou.asp 

Acknowledgement to Simon Liddiard (UK) for his assistance in compiling this article. 

Kim Sammut, who holds a BSc and a post graduate Diploma in Environmental 

Management, was appointed recently as the Australia-Pacific Environmental 

Management Steward. He is a geologist, environmental scientist, project manager 

and safety, environment and quality manager. Kim is a founding member of the 

Perth Green Team and is currently playing a direct role in implementing green 

systems and promoting a culture of sustainability in PB’s Adelaide and 

New Zealand offices. 

Other Future Topics 

Please contact John Chow or any editor to discuss new topics. Other 

proposed themes are: Security; CADD; geotechnical instrumentation; 

the new Cincinnati Reds Ballpark; program management; scheduling; 

bridge management, bridge inspection and rehabilitation, and automated 

inspection services. What are your ideas? 



Call 

for 

We invite all PB employees to participate in technology transfer and submit articles to PB Network on any 

technical subject, especially our featured topics. (See In Future Issues.) We look forward to hearing from you. 

Articles Our Goal 

The goal of PB Network is to promote 

technology transfer by featuring articles that: 

•Tell readers about innovative developments. 

•Appeal to a broad range of readers. 

• Include only essential information in a readable format. 

• Encourage readers to contact authors for more information. 

Guidelines for Articles 

• Articles should conform to PB Network format (defined below). 

• Keep your article as short as you can—include only relevant details 

and descriptions. 

• Papers written for other publications will not be accepted unless 

they are modified to conform to PB Network format. 

PB Network Format 

• Length: Articles should be 1,400 words or less. 

• Byline: Include the name, location, phone number and e-mail 

address of each author. 

• Introduction/Overview: Provide a brief paragraph stating your 

topic and how it is significant 

• Body of text: 

– Clearly describe the challenge PB faced and how you or the 

PB team solved it. 

– Provide exact name of client and state PB’s role and responsibilities. 

– Tell what innovative technologies or approaches PB developed 

or used. 

– Provide all units of measures in metrics followed by U.S. 

Customary in parentheses. For assistance in converting 

measures, see http://www.onlineconversion.com/ 

• Conclusion: 

– What lessons did you learn? 

– What was the impact of PB’s solution on your project? 

– What does your new technology or technique mean to PB and 

the state-of-the-art of the industry? 

– What is the current status of your project, technique, or technology? 

• Biographical Information: Tell us about your work experience, 

noteworthy professional achievements and contributions to 

particular projects in 2-3 sentences at the end of your article. 

• Related Web Sites: Provide any Web addresses that readers 

can go to for related information. 

File Formats 

Provide electronic files 

• Text: must be an MS Word file without graphics embedded. 

• Graphics: 

– Format must be either bitmap, tiff, eps, jpeg or psd 

– Resolution must be at least 300 dpi 

– Printed size must measure at least 165 mm (7 inches) wide 

– Screen captures are only 72 dpi and not acceptable. 

– Screening: If any artwork contains a screen (percentage of color) 

or some intricate grid, please also submit a copy of the art 

without these and we will add them. 

To Submit Your Article 

E-mail article and graphics files to the contact person named on the “In 

Future Issues” page, which appears in every issue of PB Network, or to: 

John Chow, New York, chow@pbworld.com, 1-212-465-5249. All 

graphics files and a clear hard copy at least 165 mm (7 inches) wide 

must also go to Laurie Ludwin, PB Graphics Services, One Penn Plaza, 

New York, NY 10019, 1-212-465-5725, ludwin@pbworld.com. 

 

This issue was produced on 

a Power Macintosh G4 

using QuarkXPress 6.5, 

Illustrator CS3, and 

Photoshop CS3 publishing 

software. It was output 

on a Linotronic L330. 

Copies were printed via 

offset lithography. 

August 2008 

Volume XXIII; Number 2 

Macintosh File: 

Graphics Database T894; 

14,000 copies printed by 

Howard Press, 

Roselle, NJ 07203 

File: PB Network 68 

® 

Printed on recycled paper. 

PB Network ©2008 

Parsons Brinckerhoff Inc., One Penn Plaza, New York, NY 10119, 1-212-465-5000. All rights reserved. Articles may be reprinted 

only with permission from the Executive Editor. This journal is intended to foster the free flow of ideas and information among 

PB staff. The opinions expressed by the writers are their own and are not necessarily those of Parsons Brinckerhoff. 

Past issues of PB Network starting from 1995 are available electronically on PB's Web site http://www.pbworld.com, under 

the button Research Library > PB Publications > PB Network," or go directly to http://www.pbworld.com/news_events/ 

publications/network/. All recent issues are available in .pdf format. All others are available in reader-friendly html format. 

Past issues are also available to PB employees via the PB Intranet, http://www.pbworldnet.com. Go to PB News > PB Publications > 

PB Network > View All Issues Here. 

PB employees can have additional printed copies to use for conferences, seminars and proposals. Send your request to 

pbnetwork@pbworld.com. 

Executive Editor: John Chow, Office of Professional Practice, New York, New York, chow@pbworld.com 

Editor: Lorraine Anderson, Office of Professional Practice, New York, New York 

Associate Editors: Gordon Clark, Seattle, Washington; Willa Garnick, Office of Professional Practice, New York, New York 

Column Editor: Tracey Nixon, Dublin, Ohio 

Graphic Designer: Laurie Ludwin, Graphic Services Group, New York, New York; Amy Geller, Graphic Services Group, 

New York, New York 

Production Manager: Michael Babin, New York, New York 

Web Team: Rick Goldsmith, New York, New York; Erik Dennis, New York, New York; Feng Lu, New York, New York 

Column Coordinators: Gordon Clark, Seattle, Washington,“The Net View;” Jim Hinshaw, Denver, Colorado, “Computer 

Tutor;” Tracy Abbott, New York, New York, R&I; Kathy Leotta, Seattle, Washington, “Globetrotters” and “Planetwise” 

Guest Technical Editors and Reviewers for this Issue: Guest Editors: Katherine Jackson, Manchester, UK; Arthur 

Ekwue, Godalming, UK. Guest Reviewers: John Douglas, Newcastle, UK; Ferrel Ensign, Sacramento, CA; Steve Loyd, Newcastle, 

UK; Chris Meadows, Bristol, UK; Brian Van Weele, San Francisco, CA; and John Wichall, Godalming, UK. 

Advisors: Judy Cooper, New York, New York; Paul Gilbert, Seattle, Washington; Amer Khan, Dubai, United Arab Emirates; 

Alan Knott, Manchester, U.K.; Steven Lai, China; Andrew Lawrence, Singapore; Faye Purbrick, Dubai, United Arab Emirates; and 

Catherine Singleton, Brisbane, Australia. 



Fishing Power 

By Gordon Clark, Seattle, Washington 1-206-382-5246, clark@pbworld.com 

It’s springtime in the Pacific Northwest of the USA. I’m looking out over Port Madison Bay on the Puget Sound, 

wondering what the forecast is for offshore weather. It’s probably for moderate swells out of the west and stiff 

northwesterly gusts, fresh and cold off the Bearing Sea. It’s always the same this time of year. By now I’m usually 

in the middle of planning and outfitting for several deep sea fishing trips off the Oregon coast. Waiting out there 

at depths between 100 and 200 meters are halibut fish weighing over 60 kilos. The big one that got away last year 

is still out there. The sea gods are daring me again to challenge the wind and waves in a bid to put one of those 

huge-ugly-delicious-wonderful fish on my barbeque. For ten consecutive years, since moving to the Seattle area, I 

have come off victorious. This year will be different. This year I cannot accept the challenge. There will be no 

moonlight crossings of the bar at 5:00 AM, no moments awestruck by the spectacular sunrises over Yaquina Head, 

and no pounding 50-kilometer journeys offshore to where the halibut wait. There will be no probing the darkness 

for stray crab pot floats as we clear the jetty, no navigation by GPS to the spot where the big fish are. There will 

be no chatter on the marine band radio with the Halibut PAN, no tug of war with a barn-door-size brute, and no 

bragging when I get back to the dock about the monster that got away again. This year I will be staying home. I 

still can’t believe I am saying this. I can’t believe this is happening. As I stare out past the fir and alder trees and 

focus on the boats and water I’m suddenly sad and depressed, and I can feel the ghost pains of a missing arm or 

leg, like a piece of me has been removed. In an effort to console myself, I let the logical, rational engineer in me 

review the facts that are prompting me to deny myself this ritual event. 

I keep telling myself that it is really quite simple. The cost of 

the trip has more than doubled in the last two years. While 

I love to extol the adventurous independence of fishing and 

the romantic lure of the sea, that is only half of it.The financial 

benefit of eliminating the middleman in getting fish on the 

barbeque has been a major plank in discussions with my wife 

to gain a weekend off fishing with the boys. A few years ago 

I could put fresher halibut on the grill than I could buy at the 

local fish market and end up paying half their asking price. 

That was back when oil was $50 a barrel and gas around $2 

for 4 liters. Today the cost of gas to drive 600 miles round 

trip to Depoe Bay plus the cost to put 300 liters of gas in 

my brother’s boat is no longer palatable. Even if I were able 

to catch a really, really big fish, the cost would work out to 

be about the same—except that if I buy it at the fish market 

I don’t have to bob like a bottle cap in a lake for ten hours 

risking life and limb. Not that the prospect of drowning has 

ever discouraged me from pushing out into the deep, but 

the thought always lingered faintly in the back of my mind. 

Dog-paddling in circles while waiting to slowly freeze to 

death or get eaten by a shark is a horrible way to leave this 

world. Now, just the thought of what the fish would actually 

cost has spoiled my appetite. If this keeps up, I may have to 

question my keen taste for salmon and ling cod—although 

these can still be found much closer to shore. 

I have thought about ways to cut costs so I could still make 

the trip. One idea was wind power. I could sail right out of 

Port Madison in my new sailboat, across Puget Sound and 

out through the Strait of Juan de Fuca into the Pacific Ocean. 

I have even gone so far as to plot the course from Bainbridge 

Island, where I live. The round trip would be roughly 

400 nautical miles. If I had great winds, I could make a 

speed of 6 knots and complete the trip in about 72 hours 

of continuous sailing. I love to sail, but three days of nonstop 

sailing changes a fishing trip into a sailing marathon. Besides, 

I would much rather get fish blood and guts all over my 

brother’s fishing boat than on my sailboat. 

What I really need is a cheap source of reliable energy. The 

boat is too small for a steam plant and it will be a few years 

before portable nuclear reactors or cold fusion are available 

at the local chandlery. The sailboat does harness the wind 

but, like many small-scale energy collection devices, it is 

hard to gather enough energy to power things at the 

desired level. It takes a lot of power to drive a boat at 

25 knots over swells and against ocean currents. Maybe a 

hydrogen powered boat using something to extract the fuel 

directly from seawater or the atmosphere? After much 

brainstorming, I am forced to surrender to the sad fate 

that I am not going fishing this year. At the same time, 

I’ve realized this problem is way bigger than just my annual 

fishing trips. The increasing demand for energy and its 

increasing price affects all aspects of our lives. It is all the 

more important to make the most of what we have while 

we search for new sources of energy. This is where the 

energy professionals at PB can help design state-of-the-art 

power generation plants and transmission systems. If any 

of you can figure out a way to power my boat for less, 

we could discuss it over a fish barbeque. 

 

Gordon Clark is a senior professional associate, senior project manager, and 

coordinator of the Tunnel and Underground Engineering Practice Area Network 

(PAN 37) He currently serves as chief engineer and technical lead for the 

Alaskan Way Viaduct and Seawall Replacement Project in Seattle, Washington.

Innovation in Global Power - Parsons Brinckerhoff

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