To give some idea of the potential scale of such events, it is worth looking at the largest geomagnetic storm on record, which affected much of the northern hemisphere and lasted from August 28 to September 2, 1859. It disrupted power across most of Quebec and was caused by a coronal mass ejection (CME) from the Sun. Such was its ferocity that it took only 18 hours to reach earth instead of the several days normally required by similar phenomena. The impact was largely limited by the fact that the world’s love affair with electricity had only just begun. Now that the developed world is utterly reliant on stable power supplies for the delivery of all essential services, a similar event could result in a radically different outcome.

More recent examples include the events of March 13, 1989, in which Hydro-Quebec’s power output was completely shut down within 92 seconds, courtesy of two solar CMEs. Power was restored in nine hours and a large transformer in New Jersey was destroyed. There was also the supply disruption that took place on Halloween 2003, including the destruction of 14 transformers in South Africa, which contributed significantly to that country’s long-running struggle to adequately provide its people and industries with electricity.

Unfortunately, current projections by NASA suggest that we may soon be due for a CME on the scale of the 1859 event. According to Dr Richard Fisher, director of the agency’s heliophysics division, solar flare activity varies in accordance with an 11-year cycle and is currently emerging from a quiet period, while the sun’s magnetic energy peaks every 22 years. As a result, solar activity is set to reach its maximum during the 2012-2015 period.

The point of greatest vulnerability in our electricity networks is the transformer. A simulation conducted by Metatech indicated that a geomagnetic storm roughly 10 times the strength of that seen in 1989 could melt the copper windings of around 350 of the highest voltage transformers in the US,  effectively knocking out a third of the entire US power grid and impacting an area 10 times that of the 1989 storm. Furthermore, the large size of the damaged transformers would effectively prevent field repairs and in most cases, new units would have to shipped in from abroad, ensuring that their replacement would take weeks or even months. Given that other countries could also be adversely affected and that the majority of transformers are manufactured in Brazil, China, Europe and India, there is no guarantee that the US would be the first priority for resupply in such an event. Although the industry has weathered geomagnetic storms of the highest (K9) classification since 1989 with little impact on performance, thanks to specialised operating procedures, all these storms were much less intense than the 1989 storm.

Vulnerability has been increased by the fact that in the US, there has been a marked increase in the voltages used in today’s networks. Now, networks operate at around 345-765kV, compared to the 100-200kV design thresholds seen in the 1950s. The higher the voltage, the lower the resistive impedance per unit distance and the higher the geomagnetically-induced currents (GICs) generated in the event of an EMP. Protective switching and control equipment also have to respond faster at higher voltages. At >230kV, a system has less than three cycles from detection to trip. Other related issues is that severe events can create harmonic currents, which can trip capacitor banks, while distorted sinusoidal waveforms created by the pulse can trigger HVDC converter commutation failures, impacting on system frequency and potentially tripping generators, or worse, inflicting damage caused by torsional stress or rotor heating.

Combustion flue gas analysis has been used by power plant operators for decades as a method of optimizing the fuel/air ratio. By measuring the amount of excess oxygen and/or CO in the flue gases resulting from combustion, plant operators can ensure that their facility works at the best heat rate efficiency and avoids unnecessary NO_x and greenhouse gas emissions. The theoretical ideal, or the stoichiometric point, is that in which all fuel is reacted with available oxygen in the combustion air, with none of any of the two reactants left over.

Figure 1: Key flue gas measurements relating to ideal combustion stoichiometry

Operating furnaces never attain this ideal, however, and the best operating point usually will result in 1-3 per cent excess air, and 0-200PPM of CO. This optimum operating point is different for every furnace, and also varies for differing loads, or firing rates. A higher firing rate induces greater turbulence through the burner(s), providing better mixing of fuel and air, and enabling operation with a lower excess O₂ before unburned fuel (represented by CO) appears, or “breaks through”.

Figure 2 (left): CFD depiction of the turbulent mixing of fuel and air through a burner. Figure 3 (right): DCS trend depicting the relationship of O2 and CO indications at CO breakthrough point.

Again, this ideal O₂ operating point will vary with firing rate, so a function generator is usually developed from test data to assign the ideal O₂ control point based upon an index of firing rate, such as fuel flow or steam flow.

Figure 4: a typical function generator depicting the optimum flue gas O2 level at different steam flows (firing rates).

This curve should be reestablished from time to time as burners wear, and other furnace conditions change over time. The curve for burners using natural gas and light oil fuels will tend to remain valid for long periods of time (years). Burners firing solid fuels such as coal, petroleum coke, or pellitized biofuels will experience more frequent pluggage and other degradation in the burners and fuel delivery systems, and will benefit from more frequent reestablishment of this curve.

Large furnace operators will typically dynamically control oxygen to the optimal level via the distributed control system. Control of CO is more difficult, since target levels are usually in the PPM range, and making fan or damper adjustments small enough to control at these low levels is difficult. Many operators will make manual adjustments based upon the CO signal, or use the measurement as a feed forward signal to adjust the O₂ control setpoint upwards or downwards.

New Goals

The traditional goal of achieving best combustion efficiency is sometimes being modified to accommodate two other goals:

1) Minimizing the thermal NO_x produced through the burner. O₂ levels and flame temperatures are key indicators to the production of NO_x.

Figure 5: NOx as a function of flue gas excess O2 Relationship of NOx production

One operating strategy to produce less NO_x uses staged combustion, whereby a cooler fuel-rich combustion is established at the burner. Overfire air is then added higher in the furnace  to complete the combustion. This results in less heat and oxygen passing through the burner, and less NO_x produced. Advanced control strategies utilizing neural nets are often implemented to find the optimum air settings to minimize thermal NO_x production. Another NO_x reduction strategy is flue gas recirculation, where a certain amount of flue gas is mixed with the normal air used for combustion.  An O₂ probe mounted after this mixing valve can be used to control final O₂ going to the burner, resulting in a cooler flame that produces less NO_x.

2) Slag prevention – Flux sensors provide good information about soot and slag buildup, but close attention to combustion analyzers can provide another indication of slag formation. Fly ash fusion temperatures are usually affected by the amount of excess O₂ in the flue gases, and some operators run with an O₂ setpoint that has been established to prevent slag.

Figure 6: slag formation on boiler tubes

Technologies for Measuring Combustion Flue Gases

Oxygen
The most ubiquitous technology for measuring combustion flue gases has been the zirconium oxide fuel cell oxygen analyzer.   This analyzer technology was first used in the power generation industry in the early 1970s, but the technology has transferred to use for any combustion process.  All automobiles now use one or more of these sensors for controlling fuel-air ratios, and small engines for lawn mowers, chain saws, etc. will soon be using them. Much has been written about the details of how the Nernstian phenomenon operates¹, and this paper will not review this information.

Figure 7: ZrO2 sensing cell mounted to the end of a probe (0.5-6m long).

The ZrO₂ sensing technology is ideally suited for measuring combustion flue gases for the following reasons:
- The sensing cell generates its own millivolt signal, similar to the way a thermocouple works.
- This raw millivolt signal is inverse and logarithmic, i.e. increasing greatly with the low O₂ readings typically found in combustion processes. Accuracy actually improves as O₂ levels decrease.
- The sensor is typically heated to 700-750°C, so operation in hot combustion flue gases does not present a problem
- The sensor is robust, and can withstand the sulfur components found in many fuels.
- No sampling system is required. The sensor can be placed directly into the flue gas stream on the end of probe that can be from 0.5m to 6m long. Since the flue gases enter the sensor via passive diffusion, even applications with heavy particulate content are possible with a low rate of filter pluggage.
- Sensors can be calibrated on-line and in-place. Automated calibration is also available.

The in situ ZrO₂ probe results in a point measurement within the flue gas duct, however, and several probes of different lengths may be required in order to get a representative average across large flue gas ducts.

Carbon Monoxide
CO is usually the first combustible gas component to appear when combustion fuel/air ratios start becoming too rich. Desired CO levels in combustion flue gases are typically less than 200 PPM, and infra-red spectroscopy is well suited to measuring at these low levels². Repeatabilities of better than +/- 5PPM are possible, with low interference from H₂O and CO₂. Instrument configurations include:
- extractive systems where the flue gases are removed from the duct and cleaned before being placed into a rack-mounted analyzer.
- Across duct line-of-sight configurations whereby an infra-red source is mounted on one side of the duct, and a receiver or detector is mounted to the opposite side.

Figure 8: Typical across-duct infra-red measuring arrangement.

This line-of –sight method results in an inherent average across the entire duct, so multiple instruments are less likely required to cover a large duct. Conversely, one does not get the granularity of information that an array of point measurement O₂ probes provides.
- Dual-pass probe- A modification to the across stack line-of sight method, this arrangement is a dual pass probe where the infra red energy is sent out to a mirror at the end of a hollow pipe, and then reflected back to the source end for analysis. The flue gases are permitted to fill the probe tube through holes or filters.

Any optical technology presents application challenges that need to be considered:
- An extractive system involves transporting and filtering the sample flue gases, removing the moisture, and returning the sample to the process or to a safe vent. This adds considerable cost to the system, and will require significant maintenance attention if there is particulate in the flue gases.
- An across duct line-of –sight system cannot be placed where temperatures are much above 600°C, nor endure high levels of particulate. Thermal growth of the ductwork and vibration can negatively impact the alignment of the source and receiver sides. Also, this type of arrangement cannot undergo a true calibration, since this would involve filling the entire duct with calibration gases.
- A dual-pass probe system has to contend with soiling of the reflecting mirror at the end of the probe. It is possible to conduct an on-line calibration by filling the optical path inside the pipe with calibration gases.

Tunable diode lasers (TDL) have recently come onto the scene, again using spectroscopy, but with a laser source and a diode sensing array. These systems typically use the line-of-sight arrangement across the duct, or a dual pass probe method. This technology is also capable of measuring O₂ in the overtone range, and NO_x. Again, much has been written about the underlying technology ³, so we will not cover this in this paper.
As with the traditional IR systems, a TDL in an across stack line-of-sight arrangement will inherently average across the entire furnace volume, requiring fewer instruments to cover a large duct, but also providing less granularity of the flue gases within the duct. Analyzers cannot be challenged with known calibration gases.

New Applications in Large Power Boilers

Each of the 20 or more burners in a large boiler can be considered as separate processes, each producing its own flue gases . The flue gases in furnaces utilizing burners in a single or opposed-wall firing configuration tend to form up into “columns” that often tend to stay stratified throughout the furnace.

Figure 9: CFD depiction of the flue gases passing through a wall-fired furnace

Combustion analyzers are typically mounted in the “back pass” of the furnace, after the economizer, and it is common for operators to see this stratification when using multiple O₂ probes in these large ducts. It’s not uncommon to see differences of one per cent or more across a large furnace. To accommodate this, an arithmetic average of multiple probes is often calculated in the DCS, and used as input to the O₂ control loop.

Flue gas stratification tells a story
Forward-thinking operators will use these varying O₂ indications as a diagnostic tool to look for problems in the furnace, such as:
- fouled burners
- sticking sleeve dampers
- ID fan imbalances
- roping in coal pipes
- classifier pluggage / coal finess problems
- coal mill imbalances

Figure 10: An array of oxygen probes mounted vertically downstream of an economizer.

The flue gases passing through a tangential-fired furnace do not experience as much stratification of the flue gases, and burner to burner variations are harder to differentiate. Some operators claim to be able to detect corner to corner variations with the O₂ probes in tangential furnaces, however.

Abrasion-resistance
Furnaces firing solid fuels (particularly coal) can have high levels of fly ash carried with the combustion flue gases. Separate schedule 40 pipes are often used as “abrasive shields” to protect in situ oxygen probes from fly ash erosion. Some operations have discovered, however, that fly ash is often much less abrasive in the hotter zones of the furnace (500-700°C), above the economizer. As the combustion flue gases are cooled through the economizer and air heater, the ash often agglomerates into larger particles that are far more abrasive. A location higher in the furnace can not only minimize abrasion, but also detect stratification better. Rosemount Analytical has developed a heavy-wall probe body that is more cost-effective than traditional abrasion shields, yet endures fly ash erosion well in high areas of coal-fired boilers.

Ideal Probe Placement
Oxygen probes are provided in a wide range of lengths, from 0.5m to 6m, but plant engineers often wonder if a given placement is the optimum. A variable insertion capability has been developed that permits the Instrument Engineer to find the best possible mounting location for a given probe.

Figure 11: variable insertion O2 probes in horizontal and vertical orientations

Air Heater and other duct seal leaks

Some air heater styles rotate like a revolving door in order to exchange remaining heat from the flue gases to the fresh air being fed to the burners. As the seals in these large rotating structures wear, air will typically migrate over to the flue gas side, elevating the O₂ levels on the flue gas side of the air heater. Any air leak into a furnace negatively affects heat rate efficiency, and also reduces fan capacity used for combustion, limiting boiler capacity.

Figure 12: Rotating air heater

New Applications in Gas Turbines
Gas turbines tend to run with around 15 per cent excess O₂ in order to keep the turbine sections from experiencing heat stress. If a heat recovery steam generator (HRSG) is used, duct burners are often added after the turbine in order to increase the amount of steam generated inside the HRSG, but this secondary combustion also results in a more efficient total combustion, with final O₂ values in the 2-4 per cent range. An O₂ probe placed after the duct burner can control the amount of fuel being added.

Figure 13: Duct burner for gas turbine (courtesy of Coen Co.)

New Sensor Developments
Continued research into the ZrO₂ fuel cell technology is yielding new capabilities. It was previously mentioned that the millivolt output of these sensing cells is inverse and logarithmic, so lower levels of oxygen results in higher levels of signal. A sensing cell has been developed that will continue outputting increasing voltage as flue gas O₂ levels pass through zero and into reducing conditions.

Figure 14: Millivolt signal output from a new ZrO2 sensing cell in oxidizing and reducing conditions.

This has become a tool for processes that periodically pass into reducing conditions, providing an indication of the level of oxygen deficiency during these events, and informing the operator if recovery measures being taken are being effective.

Continued research into the ZrO₂ fuel cell technology is yielding new capabilities including a ZrO₂ cell that measures CO. Eight test sites have been established at N. American power plants with promising results.

Figure 15: DCS trace depicting PPM reading from Alpha CO probe.

Summary

Combustion flue gas analysis has long been a key tool for optimizing the combustion of large power generation boilers. Innovative customers have exploited reliable analyzers to achieve new goals, such as NO_x reduction, and slag prevention. The measurement of Oxygen has been dominated by the in situ ZrO₂ probe, which provides a point measurement requiring an array of probes across a flue gas duct in order to arrive at a good average reading. Good granularity is afforded by this array, opening a furnace diagnostic capability to detect burner and coal mill problems.
The Measurement of CO is most commonly made with infra red technology in either an extractive configuration, across duct line-of–sight configuration, or dual pass probe configuration. CO is typically found in low PPM levels, so automatic control on CO is more difficult.
New tunable diode laser technology has the capability of measuring O₂, CO and NO_x. As with the traditional Infra-red technology, across duct line-of-sight configurations inherently average across a flue gas duct, minimizing the need for multiple instruments, but affording poor granularity within a given optical path.

New installation locations are being attempted, with hotter zones ahead of the economizer producing less abrasive fly ash. Variable insertion probe mounts afford the ability to find the ideal location within a flue gas duct.

Innovative customers use flue gas analyzer to detect leaks in air heaters or duct transitions, and also modify heat rate calculations of in-leakage. Gas turbines do not use flue gas analysis internally, but are increasingly using them to measure the final oxygen from a duct burner ahead of a heat recovery steam generator.

Continued research into fuel cell sensing technology has yielded a new sensor for the measurement of CO in PPM levels.

Maximum benefit from the use of flue gas analyzers results from close collaboration between instrument suppliers, plant instrument engineers who implement them, and operations personnel that use them on a daily basis.

References:
1) ZrO₂ measuring technology:
P. Shuk: Process Zirconia Oxygen Analyzer: State of Art, Technisches Messen, N 1, 19-23 (2010).

2) Infra-red spectroscopy:
Michael B. Esler, David W. T. Griffith, Stephen R. Wilson, and L. Paul Steele: Precision Trace Gas Analysis by FT-IR Spectroscopy. Simultaneous Analysis of CO₂, CH₄, N₂O, and CO in Air, Anal. Chem., 72 (1), pp 206–215 (2000).

3) Tunable diode laser:
Maximilian Lackner, (Ed): Gas sensing in industry by tunable diode laser spectroscopy (TDLS). Review on state-of-the-art metrology for demanding species concentration, temperature and pressure measurement tasks, Verlag ProcessEng Engineering, 115pp (2009)

Computer security breaches in energy companies pose a double threat. They endanger corporate data privacy, and they also threaten the stability of the oil and gas supply along with the national energy grid infrastructure. This is especially true in today’s environment, where high crude oil prices, dwindling fossil fuel reserves, the ongoing threat of global terrorism and increasing geopolitical instability in the Middle East remind the world of its dependence on a stable oil supply on a daily basis.

The challenge of maintaining information security in an energy company is exacerbated by the size of the distribution network.  With hundreds of locations that can be thousands of miles apart in dozens of countries, energy companies can run between 5000 and 26,000 applications to support their work. Each application typically requires a password for user access, creating daunting vulnerabilities and administrative burdens.

With decentralised operations extending to remote oilfields and distant offshore drilling platforms, for example, field personnel at a rig are often casual about sharing passwords. This creates the potential for unauthorised access to applications and sensitive data files. So does the fact that users often create passwords that are easy-to-figure-out derivatives of names and birthdays. A determined hacker may be able to crack the code with relatively little effort, leaving company systems and applications at risk.

Another problem is that remote oil field employees who forget their passwords frequently can’t get their jobs done. If a geologist in the field is locked out of test well data files he needs because he forgot his primary password, for instance, that may delay the drilling of a new production well or – worse – cause a drilling error that diminishes the output of the new well. Help desks can and do provide password reset services, but analyst firms estimate that each password reset call to the help desk costs between US$25 and US$40. This adds up to millions of dollars annually for some enterprises. Concerns about ineffective password systems and lax password security have led to industry regulations. In the U.S., for example, Sarbanes-Oxley includes a call for improved password security.

Password protection

Almost half of the major energy companies worldwide have turned to enterprise single sign-on (ESSO) technology to combat these and other problems. ESSO enables users to sign onto the corporate network at the start of their workday with a single password. Once users are signed in, their application passwords are entered automatically and securely by the ESSO system, enabling users to gain immediate access to drilling data, production reports and other critical information without having to create, remember, update and otherwise manage multiple passwords themselves.

IFandP: How does the acquisition of Skoda Power fit into your corporate strategy and what sort of synergies are you looking to see from it in the future?

Jean-Michel Aubertin (JMA): There were two main objectives involved in the acquisition of Skoda Power. The first is that it complements Doosan Power Systems, the western arm of Doosan Heavy Industries, in terms of equipment and technology. The acquisition has given us both turbine and turbogenerator competence, which goes hand in hand with the existing boiler expertise we have from Babcock. Doosan Power Systems now has the ability to provide more than just boilers and turbogenerators, but also integrated solutions to deliver full EPC power plants, as well as a complete range of services and retrofit projects. A key market for the latter is Eastern Europe, where many utilities are interested in integrated retrofits for existing power plants.

The second objective of the acquisition was to enable access to Skoda’s proprietary turbine technology for the entire Doosan group. We are now using Skoda technology in our latest projects, including 660MW turbines in India, and a similar project in the Middle East.

IFandP: You still see the coal-fired power sector as a growing market, then?

Jean-Michel Aubertin joined Doosan Power Systems as Chief Operating Officer in January 2010. Prior to this, Mr Aubertin held several managing director positions in the energy and aerospace sectors, managing and developing large international and global operations.

JMA: Due to environmental issues and a lack of regulation, the picture is mixed at the moment. Recently there has been a drop in the number of coal projects in Europe and the US, but we are still seeing a growing number of coal projects in India and China.

There is no doubt that coal will remain a fuel that will be used well into the future, and our projections show that it will remain a major fuel until 2050. Determining exactly how coal will be used, however, is a very different matter, and depends whether we are looking at developing economies such as China and India or more developed regions like Western Europe and the US.

The overall trend is towards a balanced portfolio of fuels and there is no doubt that renewables will be a growing market.What is certain is that coal will have to become cleaner and carbon capture and storage is one of the technologies that will be needed in Europe in the coming years. It will take quite a few years to develop new “clean coal” technologies such as Carbon Capture and Storage (CCS), and the current lack of regulation in this area does not help.

We are investing significantly in carbon capture technologies to be ready for when there is sufficient market demand.

IFandP: Which areas of CCS in particular are you looking at?

JMA: We are developing two key technologies. Firstly, in post-combustion technology, we are developing a demonstration plant with an amine-based solution in partnership with the University of Regina, in Canada. They have been involved in carbon capture from flue gas for many years. We are also working with the university’s collaborative partner, HTC Purenergy.

Secondly, we are investing in and developing solutions for oxy-fuel combustion, which involves burning coal in an oxygen-rich environment. The resulting exhaust stream consists mainly of CO₂ and can therefore be more easily captured. This is a natural extension of our Babcock boiler business which houses our own test facility in Renfrew, Scotland, and is now the world’s largest carbon capture research facility.

IFandP: One other thing that I noticed is that you are benefiting from KEPCO’s large nuclear order in the UAE. I hear that you’re tied in with it? How does it benefit you?

JMA: It benefits Doosan because it is a significant order. Doosan is delivering the steam generators under the contract and it is a major success for Doosan because the contract was won against major international competitors. It is a real success for Korean industry in general.

IFandP: One of the things that enabled KEPCO and Doosan to win the contract was the fact that you were able to offer significant cost savings compared to the other bids. To what extent was your technology and Doosan’s offering in particular responsible for that?

JMA: Steam generators are a major element of the overall proposal and Doosan’s part of the offer was very competitive.

IFandP: In the west, what would you say is the largest growth market for you, given that its taken a bit of a battering, due to the financial crisis and the sovereign debt problems in the Eurozone?

JMA: My view resonates with many of the opinions expressed at the conference. The market is the market. There is large growth in renewables at the moment and utilities are investing in them. In the short term there will probably be some significant markets in gas applications, because the gas price is low at the moment and it can be a short-term answer to stable demand. There are also a significant number of technologies under development. I mentioned carbon capture, but in addition there is offshore wind and solar power which are also enjoying significant growth.

IFandP: Are you looking to move into the gas market?

JMA: We are there already. We provide components and equipment, and are essentially offering two main products to gas EPC players: the first is the HRSG, the steam recover generator, and the second is the steam turbine which is used for combined cycle power plants. Our offer is quite significant. We aren’t currently represented directly in the European gas turbine market, but the group does have some licenses to offer gas turbines in the Middle East. We are aiming to secure licences in other regions

IFandP: In terms of boiler design, how much room do you see there being for improvements in efficiency? Is there much more than can be done or will we eventually hit a brick wall?

JMA: We are continuously working to improve the efficiency of the boilers. In the same way, we are always working to optimise and reduce the emissions. In general, we are looking at optimizing coal plants in their entirety, and in Europe there’s definitely a trend towards advancing efficiency.

IFandP: Are you looking to make more acquisitions in future?

JMA: We have significant growth ambitions. We will certainly look at potential acquisitions if they make sense in terms of complementing our market positions, our technology portfolio and if they are at a reasonable cost.

IFandP: Is there any other area that you’re planning to move into in the near future or are you planning on spending some years consolidating your existing position?

JMA: We are definitely going to diversify our portfolio of products. You may have seen, for example, that the group has recently developed a 3MW offshore wind turbine*. It has undergone extensive testing over the past year and this is one area that we are looking at carefully.

IFandP: That sounds very promising. One of the things that I’ve often wondered about offshore wind, is that you’re essentially putting a large quantity of steel into what is possibly the worst environment you can imagine for it and therefore how sure can companies be that they’re going to last for 25 years or so, when obviously there hasn’t been an offshore wind turbine that has actually spent that time in the sea.

JMA: In my view, this problem is not very different from the one faced every time you introduce a new product. Obviously, the selection of wind turbines, particularly in the offshore environment, has been carefully thought through by utilities who will want to have information regarding their reliability in the marine environment and will want the comfort that can only be given by an operational demonstration. The testing can’t be done for 25 years, but it can still give them a feel for the reliability and the ability of the product with servicing. We are not speaking about turbines, but the combined technology and the servicing that are going to be essential to ensure normal operations.

IFandP: Are there any projects that you’ve recently completed that you’ve been particularly pleased with?

JMA: We pride ourselves on delivering quality products on time while ensuring the highest safety standards. In recognition of our performance the company was recently awarded the Sir George Earle trophy, the highest accolade in UK industry) by the Royal Society for the Prevention of Accidents. This is something the whole company is really proud of.

IFandP: Thank you very much for your time. It’s much appreciated.

JMA: My pleasure.

* Doosan completed the installation of the WinDS3000TM, a 3 MW-class onshore wind power generation system, in Gimnyeong, Jeju Island, Korea, and started operation in mid-October 2009. The height of WinDS 3000TM is 80m, equivalent to 30 storeys of a building, and comes with three giant blades, each measuring 44m long. The system generated and recorded a power output of 3005kW at a wind speed of 15.6m/s on the first day of operation, exceeding the rated output of 3000kW. The blade for the WinDS3000TM has been designed to allow for angular adjustments, like the blades of a helicopter, in order to obtain the maximum rotational energy according to the direction and strength of the winds. The WinDS3000TM has overcome the prevailing concept that a gearbox must weigh at least 10t/MW of output by a 30 per cent reduction in weight to 7t/MW of output.

About Doosan Power Systems Ltd

Doosan Power Systems Ltd (DPS) consists of four businesses (Doosan Babcock, Škoda Power, Doosan Power Systems Americas, Doosan Power Systems Europe) which between them provide complete plant solutions to power utilities across the globe.

www.doosanpowersystems.com

About Doosan

Founded in 1896, Doosan is the oldest enterprise in Korea, and has evolved into a leading international business with sales of US$18.2bn in 2009. It has a global sales network of 4100 staff, and 36,000 people working across 35 countries. Since 2000, Doosan has pursued infrastructure support business (ISB) as its main growth engine, and transformed its business from a base of consumer goods, import/export, and construction to incorporate power plants (Doosan Power Systems), desalination (Doosan Heavy Industries & Construction), a comprehensive line of construction and mechanical equipment (Doosan Infracore), marine diesel engines (Doosan Engine), and railway and residential apartments (Doosan Construction & Engineering).

The Department of Energy and Climate Change (DECC) recently issued the announcement that many had long been anticipating: as part of the government’s drive to reduce the country’s carbon emissions, smart meters must be installed in every UK household by 2020.

Smart meters – which display, store and transmit detailed data on energy usage between the supplier and the customer – are the central component of a dynamic, flexible smart grid, which will dramatically change the way energy is produced, bought, sold and consumed. In simple terms, the smart grid is a network that uses IT to manage the supply of electricity efficiently. Unlike the current, rigid grid, it enables greater consumer participation, giving customers the opportunity to interact with suppliers and other participants on the grid. Not only that, but immediate information about energy use and pricing incentives provides a more tangible, monetary incentive to us all to change the way we use energy.

Smart metering aims to encourage the customer to cut their carbon footprint by making them aware of exactly how they are consuming their energy, and, perhaps more persuasively, what that energy costs them. Of course, many of us already take part in car-sharing schemes, buy energy-efficient appliances and offset the carbon impact of our long-haul flights. So from a purely altruistic point of view, having a simple piece of technology in our homes that can help us cut carbon dioxide emissions sounds like a no-brainer.

Yet reaction to the DECC announcement has not been universally positive: some are opposed to the concept of smart metering because of fears over costs, the security of their data and lack of choice as a consumer. Many people have voiced concerns that the initial costs of smart metering will be passed on to the customer at a time when the state of the economy is punishing those customers who ill afford their energy bills as it is. But in fact, smart meters are all about giving customers the tools they need to understand their energy consumption and therefore cut their bills. At their most basic, they act as an electronic version of customers’ usual utility bills, providing very immediate and transparent way to see exactly how much energy they are using and what it is costing them.

Because the meter is directly connected to their supplier, consumers can also benefit from receiving information on the tariffs that best fit their usage patterns and needs. The detailed data that will come from smart metering provides a more accurate breakdown of our energy consumption, and this more timely and accurate data puts an end to some of the longstanding issues with current meters, such as estimated billing.

But the accuracy and level of detail in the information is a further reason for resistance for some, given concerns about the security implications of having a smart meter installed in their home. Some fear that this open access to private information could make it easy for utilities companies to invade their privacy or to misuse or even lose their data. These concerns, which have hampered the smart meter rollout in The Netherlands, have not been lost on the UK’s Department of Energy and Climate Change (DECC), which cites data protection and system security as crucial issues for the success of the rollout and operation of smart metering in this country.

This is one of the foremost challenges facing the government in the battle for the smart metering hearts and minds of the public: securing buy-in and engagement from domestic customers is very dependent on the reliability and robustness of the infrastructure and technology that supports the new system. Without that buy-in, the smart metering programme will miss an important goal: if customers do not engage with meters, they are unlikely to reduce their consumption. With the country-wide roll-out approaching fast, the government and utilities will need to make a concerted effort to convey the message that smart metering is a safe and secure way to make cost savings as well as reduce the carbon footprint of the UK’s homes.

The final sticking point for some is that the compulsory nature of the smart meter roll-out could take away freedom of choice for consumers. After all, we’ll get a smart meter whether we want it or not, so why assume that we’re likely to have any choice in what happens to our data?

Smart meters have the potential to significantly reduce costs for consumers and utilities alike

In fact, choice is likely to be a key feature of the smart metering market as smart meters become a compulsory fixture in every home across the UK. The smart metering roll-out is opening up a new frontier for utilities companies – and for their customers. This unobtrusive piece of technology will start to change the relationship between the customer and the supplier: with increasingly detailed data on our energy usage – and better visibility on exactly where our money is going – customers will be better positioned to challenge suppliers to improve the products they provide and help them save money.

Smart meters give suppliers another way to differentiate themselves in what is set to become an increasingly crowded and competitive market, with enormous scope for them to tailor their range of products and services to increase value to customers and encourage them to get the best out of energy saving. It will allow them to provide easier ways for customers to save money by helping them reduce wasted energy (for example, as a result of unused equipment), cut peak-time usage with a minimum of effort and optimise their use of dual-fuel energy.

Utility companies will need to take on board the idea that different groups of consumers will use their smart meters in very different ways and will want different products and services based around the smart meter. This means that in order to attract and retain customer loyalty, they will need to segment their customer base, perhaps by demographic, location or usage level. This move towards increasing segmentation is likely to be one of the principal forces underpinning the evolution of the market. It will also drive the creation of more specialised smart meters catering for diverse sectors of the population, with different levels of technological functionality based on need, and on the degree of involvement that the customer chooses to have with their smart meter.

People who are fully engaged with cutting their costs and optimising energy-saving measures within their home will demand much greater functionality than someone who is happy to let the smart meter quietly do its work to improve billing accuracy, but has no real desire to interact with it. Similarly, a visually impaired user will have specific requirements in terms of the display. All these factors will encourage energy companies to work on developing customised products that deliver exactly what their users require of them.

Effective customer segmentation by the utilities – supported by the right technology for the job – will be crucial to the success of the smart metering roll-out. The meters must be robust enough to support the higher levels of functionality that many consumers will demand and to carry the security standards that allay some of the fears over privacy and data security.

As a country, the UK needs to cut greenhouse gas emissions by 34 per cent on 1990 levels by 2020, and by at least 80 per cent by 2050. This commitment has tangible implications for every one of us, and the presence of a smart meter in our homes is perhaps one of the most obvious. But having this technology is not the end of the story: it’s just the start. If we want to make smart meters work for us – and, ultimately, for the environment – we need to engage with them as a tool to help us change the way we look at our energy consumption. It’s all about changing the way we think and the way we behave when it comes to energy. These changes will require a small effort on our part, but the impact they will have on our carbon footprint and on our pocket is empowering, and cannot be ignored.

It is 2014. The roll out of smart meters has begun and the market for associated home energy products, in areas such as microgeneration (using solar PV, wind or combined heat and power boilers), demand control and energy storage, has begun to expand.  But how will different consumers buy and use these products?  What advantages will they offer consumers?

Bill is a trainee pharmacist who shares his house with 2 friends.  Although they are conscious of their carbon footprint in theory, in practice the thing that really concerns them is the size of their electricity bill – they only check their energy display and online record when the bill arrives.  They have signed up to a cheap tariff that allows their energy supplier to pause their washing machine or dishwasher at moments of peak demand. The energy company had to check their appliances were compatible and sent them a special node to strengthen the wireless signal, but the installation was very quick and easy.

Now, for most of the time, they forget about their tariff. Sometimes Liz, Bill’s girlfriend, thinks she notices a difference in the length of time a wash cycle takes when she wants her favourite jeans clean for the weekend, but it’s never stopped her getting out of the door on a Friday night. When the bill does arrive online, Bill sometimes checks how often their energy supplier is using their ‘load control’ facility and is a bit startled to find it can be up to eight times a week.

Without knowing it, though, Bill and his housemates are also contributing to the stability of the National Grid in another way. Last year, their landlord purchased a new fridge which incorporates dynamic demand, allowing it to make automatic adjustments to the power it draws in response to the level of stress on the Grid. Bill’s fridge is one of tens of thousands across the country, which between them provide a valuable dampening effect on fluctuations in supply and demand.

Bill and his household are saving around 15 per cent on their electricity bill by giving their supplier some limited control of their appliances.

Mike and Rachel have three children, two dogs, two jobs, an allotment and a family enthusiasm for model aeroplane racing.  So they’re very busy, but also very concerned about living a lifestyle with a low carbon impact. They invested in solar thermal and PV panels three years ago, encouraged by the feed in tariffs available, and they have been selling some of their surplus power back to the grid on a regular basis throughout the summer months.  Their solar system installer worked with their energy supplier to provide them with a controller and smart meter that tracks consumption in the house, the cost of importing electricity from the grid and the value of exporting their solar electricity. This lets them decide the basic rules of how they will use the energy they have generated: two options being consume it all on site or make as much money as possible from the sale of the energy. Once they have decided the basic ground rules the system takes care of the rest, automatically choosing to use locally or export.

They are now considering the purchase of an electric car for Rachel’s business. Since she works from home, the car can charge on a sunny day and if it’s not used, store electricity for their use or for sale back to the grid in the evening when energy is more valuable. But balancing the use of the car against its value as a storage facility is another complicated set of decisions that Mike and Rachel do not want to consider every time they decide to take the car. So they’re happy to change tariff with their energy supplier to give them an upgraded smart meter and energy controller, which lets them set their overall strategy to balance running a normal life with reducing their carbon footprint and making the most money possible from the energy they produce and store.

The new tariff and smart meter shares their preferences with their energy supplier, allowing the energy supplier to make estimates of the electricity that might available from Mike and Rachel’s house. Mike and Rachel estimate that their household expenditure on hot water and electricity is 10 per cent of the average for a household of their size. More importantly for them, they could reduce their carbon output by 60 per cent if they use their electric car efficiently.

George and Eileen are retired and live in a small house in a big garden. Their income is fixed so they are careful about their utility bills – they’ve invested some money in proper insulation for their home and like to keep an eye on the best energy deals available.

At the moment they are on a tariff which rewards them for low consumption at key times of the day with a capped charge per month. Going over their consumption limits in the key times would be charged at a very high additional rate. Rather than automating their energy consumption, they prefer careful monitoring of their habits: their smart meter can disaggregate some of their energy use so their energy monitor can show them which large appliances are consuming energy and when. George has fitted some intelligent plugs to other appliances and they have now have a good understanding of where their energy gets used.

They use this understanding to control their consumption in the peak rate hours, turning off unnecessary appliances and delaying activities like dishwashing or water heating. Some of their appliances have timer switches, but mostly they prefer to do this manually: they like to feel in control and be certain that things have been turned off.

Using these methods, George and Eileen have been able to fix their energy bill for two years, well below the market rate. Even though they have bought a number of new electronic gadgets in that period, their energy budgeting has been so effective that they have come nowhere near their consumption limits.

Examples such as the above highlight the potential benefits of smart grids for consumers and also may help power utilities to sway consumer opinion in their favour. This will be crucial, given that both utilities and consumers will only benefit from the introduction of smart meters, if consumers seize on the opportunities they present, by adjusting their behaviour and electricity usage patterns to reduce consumption during periods of peak demand.

One of the issues that the power utilities of the future will have to deal with is an ever increasing contribution of intermittent renewable energy sources to the grid. While substantially more than the current level of solar and wind power can be accommodated with few repercussions, once the percentage of generating capacity they represent increases above 30 per cent there will be a clear need for advances in super grids and energy storage. The former is to allow electricity to be brought in from regions that are producing a surplus of power during times when local generation fails to match demand. At the same time, energy storage effectively smoothes out the peak and troughs experienced locally. Both technologies are of prime interest, as their progress has the potential to reduce, or perhaps one day entirely eliminate the need for expensive fossil-fuel (typically natural gas)-fired back-up capacity. In this article, I will summarise the latest developments in the Energy Storage field.

Much of the recent excitement in the field has been generated by an increase in the funding of energy storage research by the US Department of Energy. In November 2009, it announced US$185m in grants for 16 utility energy storage projects, of which compressed air energy storage (CAES) accounted for nearly US$60m. The Department’s Energy Storage Systems Research Program is also collaborating with over 20 projects, including nearly US$10m of grants with the California Energy Commission and almost US$6m for six projects with the New York State Energy Research and Development Authority. The DoE is also providing US$2-5m a year to six Frontier Research Centres for the purposes of developing energy storage technologies.

The growth of this sector is expected to be significant. According to a report by GTM Research, the current amount of energy storage for the purposes of mitigating short-term supply disruptions is just 49MW, of which the vast majority is in the form of pumped hydropower. However, GTM expects this to rise to 479MW by 2015 and could peak at 7,317MW in the US and 37,828MW worldwide. More significantly, energy storage for the purpose of balancing daily demand and supply could rise to 1321MW by 2015, representing a cumulative investment of nearly US$2bn. GTM estimates that a mature market for this suite of technologies could be 450GW worldwide and 85GW in the US.

A key driver is the rapid expansion of the wind industry. According to current DoE data, every new 1GW of wind capacity requires an additional 17MW of spinning reserves to compensate for the increased variability in supply. While the most efficient method of tackling this problem is probably the construction of supergrids, to allow local fluctuations in output to be countered by sourcing electricity from other regions experiencing a power surplus, energy storage devices have the advantage of being a much smaller undertaking and as a result can be more rapidly deployed.

There are currently three main avenues that are being pursued by companies in the Energy storage field: compressed air, which stores energy in the form of air kept at high pressure and releases it through a turbine to produce electricity, batteries which store electricity in the form of chemical energy and flywheels which can quickly convert electricity to kinetic energy and back again at high efficiency.

Compressed air

Californian power utility PG&E is working on a compressed air project in Kern County, which once complete will be capable of storing 300MW for 10 hours. It is looking to store energy at off-peak times before releasing it back onto the grid during periods of peak demand. It considers the technology as a vital tool in its goal of attaining compliance with California’s renewable portfolio standard, which requires that 20 per cent of a utility’s electricity needs to be sourced from renewables in 2010.

CAES hit the headlines late last year with the announcement that FirstEnergy Generation Corp had acquired from the Haddington-owned CAES Development Company, LLC, the rights to the Norton Energy Storage project in Ohio. All the permits needed to develop the 2000MW+ storage facility, which is being converted from a 2200ft deep disused mine have already been acquired and the engineering and equipment design, together with project cost estimates, have been completed for the first 268MW of generation and 200MW of storage capacity.

Meanwhile, General Compression (see our “Reliable wind power” article) has secured US$17m in commitments for its Series A funding round, with which the company is hoping to install its first full scale 2MW CAES unit later this year. It is also looking to have a commercial project up and running in 2011, in partnership with its new investorss, USRG and Duke Energy. General Compression has opted for a modular approach, allowing facilities to easily be scaled according to a client’s requirements.

A company called SustainX Energy Storage Solutions is currently working on a CAES system with a radically different approach from many of its peers. It is aiming to store compressed air in off-the-shelf tanks and has set itself the goal of fitting 4MWh of stored energy in a 40ft long container, capable of delivering 1MW. As a means to achieving this goal, SustainX is building a 100kWh pilot project, which will be used to test the technology. Instead of letting the compressed air escape through a turbine, the company’s system will use a hydraulic piston to convert the high pressure back into electricity.

Dax Kepshire, president of SustainX, expects the initial efficiency of the system to be around 50 per cent, before rising to roughly 70 per cent in the fully developed system. The use of near isothermal gas cycling as opposed to adiabatic compression, in which the temperature increase associated with increased pressure is retained within the gas, is a key feature of the system and allows it to make use of cogeneration and waste heat from nearby industrial processes.

Batteries

Battery technology is perhaps one of the most established energy storage technologies used today. One of the issues with traditional lead-acid batteries is their environmental footprint, primarily in terms of their disposal. In comparison, lithium-ion batteries are rapidly gaining favour among utilities. Their chemistry allows for very high energy densities and results in a very low rate of self-discharge. The worldwide market for lithium-ion batteries was thought to be worth an impressive US$8bn in 2008 and expected to regularly record double digit figures for growth, given the pace set by related renewable energy and electric vehicle markets. Pike Research believes that it will become the energy storage technology of choice for electric vehicles and it expects that “improved storage capacity and economics will lead the utility sector to adopt Li-ion [lithium-ion] as well…” The analyst group also predicts that Lithium-ion batteries will represent 26 per cent of what will be a US$4.1bn stationary energy storage industry by 2018. Recently, Southern Californian Edison Co has applied for a US$25m stimulus grant for what could be the world’s largest lithium-ion battery, which would be built and developed by A123 Systems Inc.

Sodium Sulphur batteries have been extensively developed by NGK Insulators Ltd and Tokyo Electric Power Co (Tepco), to the point where Tepco believes they may one day replace central pumped hydro as the principal means of energy storage in Japan. The main reason for their initial decision to develop the technology was that all of the raw materials could be sourced within Japan. American Electric Power Co is working on a “bus-sized” 7MW sodium sulphur battery string to help address the issue of congestion on transmission lines and initially trialled NGK and Tepco’s technology back in 2001 at the Dolan Technology Centre. More recently, NGK Insulators has formed a consortium along with EDF Energy, MEIDEN and JWD, to develop the “large scale sodium sulphur NAS battery assets to provide ancillary services in the UK.”

GE Energy is focusing its research efforts on improving its sodium metal halide batteries. In addition to the more obvious applications, GE is also looking to use them as a key-enabler of electric trains and in various stationary roles.

In Chile, AES Energy Storage and A123 systems teamed up to develop and successfully commission a 12MW frequency regulation and spinning reserve project at AES Gener’s Los Andes substation in the Atacama Desert, Chile. The system uses A123 System’s Hybrid Ancillary Power Units, a lithium-ion battery system.

Boston-Power Inc, a leading provider of lithium-ion batteries has chosen to team up with AV Concept Holdings Limited with the goal of breaking into the lucrative Korean and Chinese markets. Its technology is based “on flat, oval-shaped prismatic cell design with external dimensions equivalent to two conventional 18650 lithium-ion cells. The design includes an aluminium can, supporting high energy density, dependable cycle-life, and multiple independent safety features.” For utilities, it offers the Swing 4400, which features a 20-50 per cent space saving compare to “existing solutions”.

Despite all these efforts, the story is by no means over for lead batteries. Axion Power International is currently developing its Axion PowerCube ™, an advanced 500kW lead-carbon battery and received nearly a quarter of a million dollars from the Pennsylvania Energy Development Agency to help commercialise the system. Axion has won the Frost & Sullivan Technology award for North America in the field of lead-acid batteries as its approach has “the potential to revitalise the lead-acid battery industry by breathing new life into an established technology that is not well suited to the requirements of important new applications like hybrid electric vehicles and renewable power.”

Other companies active in the lead-carbon battery field include Furukawa Battery Company and Exide technologies, which has recently teamed up with Axion to develop a range of products based on Axion’s technology. Products such as the Ultrabattery suggest that Lead-carbon batteries may be able to out-compete lithium-ion batteries on economic grounds, as far as electric vehicle applications are concerned. This suggests that the same could be true for stationary applications, particularly as weight is less of an issue (lead-carbon batteries typically weigh more than their lithium-ion counterparts).

Xtreme Power is taking a different approach. It is working to commercialise a fibre-glass dry-cell battery which, thanks to being composed of solid materials, is able to deliver high efficiency power coupled with high levels of reliability, to the point where the company claims its device can still function after being riddled with bullets. It is seeking to raise up to US$475m to help fund the retooling of a closed Ford Motor factory in Michigan, as part of a joint venture with Clairvoyant Energy with the aim of producing 2000MW of batteries a year. Xtreme Power has stated that the batteries would cost about one-tenth of comparable lithium-ion systems and their modular set-up allows individual installations to scale up to 100MW.

Flywheels

Beacon Power Corp’s Smart Energy 25 Flywheel can be used both for frequency modulation and to boost the effectiveness of wind farms

One of the major advantages that flywheel have over other forms of energy storage, is the rate at which they can respond to sudden changes in demand, making them particularly suited for frequency modulation. According to a study by Pacific Northwest National Laboratory carried out in 2008, 1MW of fast responding flywheels provides the same response as double the capacity of conventional slow-responding regulation, such as hydropower.

Beacon Power Corp has started construction of a 20MW US$69m energy storage facility in southeastern New York. The project is expected to be completed in 2011 and has obtained a conditional US$43m federal loan guarantee from the DoE. Beacon has also received a US$24m stimulus grant for use in the construction of its second 20MW energy storage plant to serve the Chicago, Illinois area, which will help the PJM interconnection manage its grid. It also announced that it has recently shipped, installed and connected a flywheel system to a wind farm in Tehachapi, California, as part of a wind power/flywheel demonstration project being carried out for the California Energy Commission. According to a report from the California ISO, up to 4200MW of wind power could be installed in the area over the coming years. It will feature “intelligence agent” controls designed to unlock the full potential of flywheels as a means of boosting the amount of electricity that can be delivered from the wind farm without overloading the locally constrained transmission system.

Pentadyne Power Corp (which we featured in our “Flywheels: reducing energy risk” article) has also been busy with the recent launch of the GTX, which offers 25 per cent more energy storage, than its previous flywheels. According to the company’s CTO, Claude Kalev, it operates without bearings and without the need for a vacuum pump, making it highly reliable “and virtually maintenance free.”

Supercapacitors

Another approach that may make its presence felt a number of years down the line is the use supercapacitors as a means of energy storage. This is currently being developed by Battelle, South Korea’s Nesscap, EESTOR Batteries, Graphene Energy, EnerG2 and Ioxus, which have been attracted by the fact that such devices may be able to offer over 10 times the energy density of present-day capacitors and a cycling lifetime 10 times that of present lithium-ion batteries, once the full potential of nanotechnology is realised. At present, super- or ultra-capacitors can discharge their power 10 times faster than batteries, but are far less energy dense, needing 16 times as much area to store the same amount of energy. Researchers such as Joel Schindall, a professor of electrical engineering and computer science at MIT, believe that nanotechonlogy may be able to drop this figure down to four, but this is still far from ideal and suggests that it will be a long time before such devices become viable for utility-scale applications.

Heat Engines

One of the more innovative approaches to hit the headlines in recent months was the public unveiling of UK company Isentropic’s reversible heat engine, which can pump heat from one container of thermal storage material (such as gravel) to another, and then subsequently use the temperature gradient to generate electricity. Approximately 75 per cent of the energy stored by the device can be recovered, putting it in the same ballpark as pumped hydro power, but with the added advantage of being independent of geography and with a footprint 300 times smaller. It also boasts an isentropic efficiency of 99 per cent and can be used to produce electricity from solar thermal systems.

Fuel Cells

ZBB’s Zinc Energy Storage System (ZEES) utilises fuel cell technology to deliver 2-3 times the energy density of lead-acid batteries

More commonly thought of as lying in the realm of distributed generation (as recently publicised with the launch of “the Bloom Box”) or as an alternative to the internal combustion engine, ZBB Energy Corporation has been pioneering fuel cells as a means of energy storage. Its current Zinc Energy Storage System (ZEES) uses zinc and bromide electrodes separated by a microporous separator, which are suspended in an aqueous zinc/bromide solution. A key difference in this approach from conventional batteries is that the electrodes act only as substrates for the reactions, meaning that electrode degradation via repeated cycling does not occur. ZBB claims that the ZEES offers 2-3 times the energy density of conventional lead/acid batteries. Its ZESS 50 system, which weighs in at a dainty 30,000lb, can store 50kWh and can deliver 250kW for two hours, together with 200 per cent peaking capacity.

Pumped storage

Whilst not at the cutting edge of R&D, pumped hydro storage systems in terms of capacity account for around 99 per cent of all large-scale electricity storage systems. In fact there is over 127GW of pumped storage worldwide. Given that it is still the most cost-effective utility-scale form of energy storage, it will be with us for a long time to come. It is also seeing healthy levels of investment. For example., Ukraine has been building what will be Europe’s largest pumped storage plant since 1983. The first generating unit was launched in December 2009 and another six will soon follow. Japan’s Itochu Corporation has expressed an interest in assisting in the completion of the project. The design capacity of the plant is an impressive 2268MW for turbine operation and 3010MW for pumping.

Meanwhile, Alstom Hydro, which has a 47 per cent market share in the pumped hydro equipment market, was awarded a EUR178m contract in October 2009 to supply four 250MW variable speed pump turbine and motor generator units for a 1000MW pumped storage facility in Switzerland. It also received a EUR125m contract back in May 2009, to equip the Swiss 628MW Nant de France facility with reversible turbines and other related equipment. In Hungary, power utility Matrai Eromu, which is majority owned by German’s RWE is planning to build a 600MW pumped hydro facility at a cost of HUF140-150bn (US$735-788m) and expects to launch the permitting process in the second half of 2010. It would be Hungary’s first such plant and is sorely needed, given that the country’s wind turbine fleet is expected to expand significantly in the coming years. Israel is also looking to pumped storage and its public utilities authority has set up a supporting tariff scheme for 450MW of storage capacity. Two projects have already been approved for construction in the north of the country and the development is expected to result in substantial savings.

No clear winner?

The large differences between the various energy storage technologies described above, makes it clear that as with solar power, no one solution is likely to prevail. Instead, as is currently the case, it will be a case of selecting the right tool for the job in hand: compressed air or pumped hydro for large scale storage, advanced batteries for small-scale wind projects and flywheels for frequency modulation and applications where rapid response is paramount. However, it is entirely possible that future breakthroughs may generate a clear winner in the current tussle between advanced supercapacitors, lithium-ion and lead-carbon batteries.

There is another element to energy storage in that it is a key enabler in terms of the electric vehicle, which is expected to achieve significant market penetration in the medium-term. The wider implications of this shift in technology are immense. A recent report from Deutsche Bank makes the case that hybrid and electric vehicles will boost the global average efficiency of new light vehicles by over 50 per cent by 2030 and will cause a peak in global crude demand in 2016, while US gasoline consumption is forecasted to drop by 46 per cent by 2030. This will have dramatic consequences for the power sector, which will have to expand significantly in order to meet the additional demand for electricity, although clever demand management may substantially alleviate the need for additional capacity. A similar trend is expected to occur worldwide, with developing nations such as China and India largely skipping the internal combustion engine, in as much as they have land-based phone lines.

There are clear signs that many companies are already looking to capitalise on these opportunities. GE has already invested over US$150m in battery R&D and its transport division received a US$25.5m tax credit in January to help build a manufacturing facility in Schenectady, NY, to produce the next generation of energy storage systems. The facility is expected to be commissioned in mid-2011 and will employ 350 full-time workers. At full capacity, it could potentially build as much as 10m cells capable of generating 900MWh per year.

look out for our article in September, which will go into much further detail regarding the current state of the electrical vehicle and its impact on power utilities.

Energy providers share the common goal of efficiently providing electricity to their customers. Governments, businesses and households all depend upon the electricity that these companies provide. It is electricity that turns the world, and without it our modern way of living inconveniently stops. In today’s society, humanity runs twenty-four hours a day, seven days a week.

Because we live, work and play around the clock, the generators of a baseload power station must run nonstop for long durations at a time. But a fact of life for utilities is that generators, just like anything else, deteriorate over time and must be inspected to avoid serious problems. But improper testing and inspecting allows costly issues to develop, issues that, if overlooked or ignored by the maintenance crew or utility, greatly increase the chances of the machine breaking down or even worse, experiencing a catastrophic failure that could result in the utility purchasing a new generating unit—costing millions. If a unit goes offline because of a failure, then the utility has no choice but to fix the generator—known as a forced outage (opposed to a planned outage). Forced outages are costly and time consuming for utilities and usually occur when energy demand is at its greatest during the winter and summer months, exactly when the unit is needed most.

There is a constant battle between the downtime and uptime of a generating unit. The higher the forced outage rate, the worse it is for the utility because of the aforementioned time and expenses, which is why utilities want the percentages of forced outages to be as low as possible—something that Larry Johnson, Vice President of Generator Services International, a generator consultancy agency, is all too familiar with. Johnson has nearly thirty years of experience in the power generation industry and has led maintenance teams that have tested, inspected, and repaired large turbine generators. He’s been deployed to countless forced outages, and knows how imperative it is for a utility to have an effective generator maintenance strategy. Now as a consultant, he offers his expertise to power companies who are looking to cut down forced outage rates and get the most out of their money on a planned outage.

“Forced outage rates largely depend on the effectiveness of a planned outage,” Johnson states. And adds that there are a number of reasons why generator breakdowns occur. These factors consist of, among other things, problems with the wedge system, the stator bars, support systems, and high voltage bushings to transfer the energy to the grid. Inside the generator is a rotating component known as the field rotor, which subjects the generator to centrifugal forces that stress the rotor wedges and the internal electrical conductors or coils, and the insulation components. “If a crew, either an in-house team or a second party fail to identify an issue during a planned outage, it’ll come back to bite the utility.” (In the case of a second party being involved and if they make a mistake, there can be all sorts of legal matters that arise. But that’s a completely separate issue.)

In February 2009, a silo at a coal-fired power plant exploded, severely injuring six workers and resulting in US$300,000 in fines. This recent power plant explosion, located in the Midwest United States, serves as another dangerous reminder of the risks faced by power plants that handle combustible coal dust.

Coal handling, processing and storage systems can produce hazardous conditions with the potential to produce a dust explosion. Explosions occur as a result of ignition of a combustible material (dust, gas, or vapour) when mixed with oxygen, typically that which is present in the air. When this takes place inside a confined enclosure, such as a dust collector or a conveyor gallery at a power plant, a rapid pressure rise is developed in addition to the expected flame of combustion. This pressure could develop to over 100psig in a fraction of a second if the dust explosion is not mitigated in some way, exerting destructive forces within a few milliseconds that will place both personnel and equipment at risk. Examples of potential ignition sources within the coal systems of a power plant are:
• tramp metal producing sparks within milling, grinding and conveying systems
• pyrites producing impact sparks
• static electricity
• hot surfaces
• smouldering fire nests which can self-ignite at relatively low temperatures, as low as 160°C, compared to a dust cloud self ignition temperature as low as 440°C
• easily ignited pockets of “coal gas” that can generate a secondary dust explosion.

In this recent example of a combustible dust explosion within a power plant, the event occurred at a silo used to collect fugitive before the dust is then used as fuel. Contract workers were onsite setting up scaffolding on the outside of the silo when the explosion occurred. Flames, embers and dust rained down on the workers causing severe burns which required hospitalisation.

By mitigating the impact of an explosion, the pressure generated remains below a safe level for the process equipment (see blue line). The higher the Kst value, the faster the rate of pressure rise due to combustion. Coal dust has a fairly wide explosive band depending on the type and moisture content, which is why it is important to test for explosibility. There are more than 100 published Kst values for coal ranging from 37 to 176 recorded. A Kst value of 138 will generate a pressure in excess of 100psi within an enclosed volume in less than 100 milliseconds.

Measuring explosion hazards

Three parameters are used to assess the reactivity of coal dust and form the heart of the risk assessment process that leads to the design and specification of appropriate safety measures:

1. Pmax – Were a coal dust explosion allowed to fully develop within an enclosure of great strength, a peak pressure of up to 133psig for bituminous coal would be reached. Different types of coal and variation in particle size result in different values for Pmax. However, the figure is consistently above 100psig which is far above the design pressure of most coal handling and storage equipment as well as most processing equipment.

2. Kst – A factor determined by measurement of rate of pressure rise for a combustible dust sample, the Kst value for a given material indicates the power potential of the combustion event. Coal dust Kst values range between 80 and 130bar-m/sec for bituminous coal and can exceed 200bar-m/sec for Powder River basic coal.

3. MIE – The Minimum Ignition Energy required to ignite a cloud of coal dust is as low as 30mJ. This is sufficiently low for an inadvertent electrostatic discharge to start a coal dust explosion. While an elevated moisture content will increase the amount of energy required to trigger combustion by around 10-fold, this is still only 300mJ.

Other factors which are important include process information such as dust concentration, airflow velocity, operating pressure, temperature and humidity.

In the US, under National Fire Protection Association (NFPA) 68-2007 Standard, dust sample testing is required to correctly define the combustion risk. The concern is that assumed reference data may result in decisions that leave a facility under protected. Under-protection can lead to consequences as severe as no protection. Often actual dust sample testing indicates lower Kst and Pmax values than reference data. This supports a lower level of protection resulting in cost savings to the plant owner/operator. Particle size can profoundly affect explosibility of combustible dusts; the finer the dust, the higher the Kst value.

Conventional liquid fuel combustion

Traditionally, spray diffusion burners (Figure 1A) have been employed in gas turbines that operate on liquid fuels, including petroleum-based fuels such as naphtha, kerosene and diesel and for renewable fuels such as ethanol and biodiesel. However, this diffusion mode of operation produces high emission levels of NO_x, CO and particulate matter. The current technology for burning liquid fuels in gas turbines is to use water and/or steam injection with conventional spray diffusion burners. Emissions levels for a typical “state-of-the-art” gas turbine, such as a GE 7FA burning fuel oil #2 in diffusion mode with water/steam injection, are 42ppm NO_x and 20ppm CO. Water/steam injection has a dilution and cooling effect, lowering the combustion temperature and thus lowering NOx emissions. However, water/steam injection is likely to increase CO emissions as a result of local quenching effects. Thus, the “wet” diffusion type of combustion system for liquid fuels must trade off NO_x for CO emissions and still results in high levels of particulate matter.

Figure 1: A. Conventional liquid fuel spray diffusion flame (left) – B. Typical lean, premixed natural gas flame (middle) and C. Biodiesel LPP Gas™ flame (right).

In recent years, increasingly stringent emissions standards have made lean, premixed combustion more desirable in power generation and industrial applications than ever before, since this combustion mode provides low NO_x and CO emissions without water addition. Lean, premixed combustion of natural gas avoids the problems associated with diffusion combustion and water addition (Figure 1B). As a result, lean, premixed combustion has become the foundation for modern dry low emissions (DLE) gas turbine combustion systems. When operated on natural gas, these systems provide NO_x and CO emissions of ≤25ppm without the need for water addition.

However, DLE systems cannot currently operate in premixed mode on liquid fuels because of autoignition and flashback within the premixing section. Autoignition of the fuel/air mixture can occur before the main combustion zone, when the ignition delay time of the fuel/air mixture is shorter than the mean residence time of the fuel in the premixer. It is more likely to occur with the higher-order hydrocarbon fuels (eg fuel oils and biodiesel), which have shorter ignition delay times compared to natural gas. These short ignition delay times have proven difficult to overcome when burning in lean, premixed mode.

The LPP combustion process

A patented fuel vaporisation and conditioning process was developed and tested to achieve low emissions (NO_x, CO and PM) comparable to those of natural gas while operating on liquid fuels, without the need for water or steam addition. In this approach, liquid fuel is vaporised in an inert environment to create a fuel vapour/inert gas mixture, called LPP Gas™, which has combustion properties similar to those of natural gas. Premature ignition (autoignition) of the LPP Gas™ is controlled by the level of inert gas added during the vaporisation process. An extra advantage of the fuel vaporisation and conditioning process is the ability to achieve fuel-interchangeability of a natural gas-fired combustor with liquid fuels. The fuel switching change-over from natural gas to LPP Gas™ is done on the fly and does not require the turbine to be shut down or run at reduced load. Tests conducted in both atmospheric- and high-pressure test rigs utilising commercial DLE burners (designed for natural gas) found operation to be similar to that achieved when burning natural gas (Figure 1C).

Figure 2: The LPP Combustion process

Figure 2 shows a simplified process diagram for the LPP System. Liquid fuels were supplied to the LPP fuel conditioning skid using a fuel pump. An inert gas (nitrogen) and heat were provided to the LPP skid to vaporise and condition the liquid fuel. Although nitrogen was used for this application, other inert diluents such as exhaust gas or CO₂ could also be used. For testing purposes, the heat was applied to the skid using electrical heaters. For commercial systems, combinations of electrical, thermal and waste heat could also be used to provide energy for fuel heating and vaporisation. To maximise system efficiency for commercial application, waste heat utilisation is preferred to supply heat to the LPP skid. Once the liquid fuel is vaporised and conditioned in the LPP System, the resulting LPP Gas™ can be used as a substitute for natural gas and in potentially any combustion device originally designed for such a gas. The resulting emissions from burning LPP Gas™ are similar to those for natural gas including NO_x, CO and particulate matter. Since both biodiesel and ethanol contain little or no sulphur, natural gas SO_x emission levels are also achieved. The same clean blue flame typical of natural gas is achieved when burning LPP Gas™ derived from liquid fuels.

The LPP Combustion System changes the nature of the fuel by adding an inert gas during the vaporisation process thus preventing autoignition during the relevant timescales for fuel transport, mixing and burning with air. The vaporisation of liquid fuel takes place away from the combustion device in a separate skid-based fuel conditioning device under temperature conditions much less severe than in the combustor. This reduces burner maintenance compared to traditional spray diffusion methods.

The reliability and optimisation of pulverised coal-fired and oil-fired boilers often corresponds with the performance of the auxiliary equipment, controls and all of their processes. These include, but are not limited to, combustion control equipment such as the fuel preparation and measurement systems, coal pulverisers, burners, forced draft and induced draft fans, air pre-heaters, air dampers, and processes such as primary air, secondary air, and fuel delivery systems. These produce the “inputs” to a large utility furnace and it is essential that the systems be validated and proven through periodic instrumentation and system device calibrations.

By doing so, this ensures minimal variability from the design values for the system. By integrating a performance-driven maintenance programme that evaluates the performance of the mechanical components with actual measurements of their calibration and/or performance, you can indeed manage the system. As the old saying goes, “if you can measure it, you can manage it.” With that said, let’s take a look at a successful “performance improvement” and/or “preservation” programme that is based on industry best practices for boiler tuning and testing methodologies.

Storm Technologies Inc (USA) has been promoting the essentials for combustion for many years and offers a unique approach to optimisation which is a comprehensive, yet a fundamentals-driven effort for obtaining optimum steam generator performance, capacity and reliability.

Figure 1: Storm Technologies Inc. (USA) -
APPLES, cycle of events

This approach integrates a five part optimisation programme:
1. Training – helping others understand combustion and boiler performance
2. Testing – measuring performance to evaluate the baseline performance
3. Interpretation and planning – performance driven maintenance
4. Tuning – operational optimisation, fuels flexibility and efficiency
5. Performance preservation – maintaining best possible performance.

This cycle is STORM’s Annual Plant Performance Longevity and Evaluation Services (APPLES) approach and is shown in Figure 1.

Optimum combustion and best heat rate operation of a large utility boiler requires a coordinated approach of matching combustion and the performance of the steam cycle. Quite often, you’ll find a large number of folks intrigued and interested with the performance measurement, care and cleanliness of steam turbine/generator, while the boiler is often neglected and under-appreciated. The fact of the matter is that most forced outages and/or reliability issues with large steam plants are related to the performance and reliability of the boiler. Given that the cost of fuel to fire the boiler is typically in the magnitude of 80 per cent of the production cost of a typical power station, efficiency of the boiler should be ranked first on the list of important things to do. Just for review, let’s take an example of a 500MW unit designed for 1000F/1000F and 2400 psi throttle pressure.

Given a unit load capability of 500MW, a capacity factor of 90 per cent, together with a fuel cost of US$3.00/MMBtu and a normal heat rate of 10,000Btu/kWh, the approximate fuel cost per year can be calculated as follows:

Total heat input = (500,000kW)(8000 hours/year)(10,000Btu/kW)

Total heat input = 4 x 1013 Total Btus/year

Total annual fuel cost at US$$3/mBtu = Total Btu input/1,000,000 x US$3.00/mBtu = total annual fuel cost at US$3/mBtu = US$120m.
Throughout the industry can be seen in Table 1.

Figure 2: Typical stealth heat rate factors

Stealth heat rate factors

As previously illustrated, factors such as de-superheating spray water flows, non-optimum steam temperatures at low loads, air in-leakage, air heater leakage, high tempering airflows, unbalanced fuel lines, poor fuel balance, non-optimised secondary and over-fire air flows are all known to elevate heat rates. We refer to these as stealth heat rate factors.

Increased heat rate correlates with lower overall cycle efficiency and increased emissions. Therefore, these factors should be evaluated and optimised using a comprehensive approach to identify problematic areas in need of attention. A qualified test contractor should be hired to measure the “inputs” to a steam generator to evaluate variances in the design performance and/or decreased efficiency. Storm Technologies “claim to fame” is not only measuring the losses associated with non-optimum combustion and operations, but also correcting the root cause of the deviation through ‘”esults-driven” maintenance.

Developing a test protocol

On a typical pulverised coal-fired unit, implementation of a testing programme should encompass at least seven areas for measurement, calibration and optimisation – these are as follows:
1. Pulveriser and fuel line performance
1.1 Clean airflow balance
1.2 Dirty airflow balance
1.3 Fuel flow balance
1.4 Air-fuel ratios
1.5 Pulverised coal fineness
2. Primary air calibration and control
3. Secondary airflow distribution
4. Excess O₂ probe measurement accuracy
5. Furnace exit gas temperatures and flue gas measurement
6. Air heater performance; Boiler efficiency and system air-in leakage measurement (boiler stack – exit)
7. In-situ flyash sampling and analyses for sizing and unburned carbon.

It should be noted that on a oil-fired unit, items 3-7 are equally as important. Most of the provisions required prior to implementation of the testing programme, are installations of testing ports during an outages.

Figure 3: Typical combustion airflow paths
on a pulverised coal-fired unit.

Combustion optimisation

Whether a boiler is pulverised coal-fired, oil, or gas, optimisation of the inputs to the furnace is a must. For most of today’s large utility boilers, the furnace residence time from the instant fuel enters the furnace, until the point the products of combustion leave the furnace, is in the magnitude of only one second. In addition, for carbon char to completely combust, it must be above 1400°F (760°C) and in an oxidising atmosphere. Finally, all in-furnace solutions to reduce NO_x, deliberately stage combustion (which means separating the air and the fuel and using up furnace residence time by delaying combustion).

These points illustrate the importance of precisely measuring and controlling fuel flow and combustion airflow into the furnace. Modern low-NO_x burner retrofits to utility boilers have continued to reduce the flame intensity and delayed the combustion airflow mixing with the fuel. This in turn has progressively reduced furnace forgiveness and the original three-phase combustion solution of optimisation of time, temperature and turbulence.

Typically, low-NO_x burners operate at stoichiometries of 0.8 to 1.0 by design. Considering that the furnace residence time is fixed by the furnace size. Similar requirements of mixing and distribution apply to oil and gas, however the fuel portion is much easier to uniformly distribute. With solid fuels only a second or two is available to complete the combustion of all the devolatilised coal or “carbon char” to CO₂. Complete combustion with minimal boiler outlet CO or unburned carbon in ash is the ideal. The precise distribution of fuel and combustion air to the furnace has become more important than back in the 1960s and 1970s when high furnace flame intensities were common and therefore “furnace forgiveness” with most low NO_x conversions is history.

Modern systems are often equipped with intelligent software-based systems. However, it is still extremely important to ensure the essentials or validations of the “inputs” are periodically evaluated and proven. For example, once the properties of the “as fired” fuel are known, through basic chemistry you can determine how much additional oxygen is required to convert all of the hydrogen into water and the carbon into CO₂. As the fuel properties vary, airflow requirements also change slightly. As an example, increased levels of carbon and hydrogen bound in the fuel require more oxygen to convert those quantities. Considering this, it is of paramount importance that total airflow is sufficient and apportioned properly for staged and controlled combustion.

Non-optimum measurement of the combustion airflow will likely lead to fuel rich or lean environments within the furnace, impacting on emissions. Operations with excessively high primary airflow will reduce residence time within a coal mill and also the amount of residence in the furnace for carbon burn-out. Because of this, it is also extremely important to measure the velocity of the pulverised coal departing a coal nozzle such that tuning of the primary and secondary airflow ratios together with distribution can be optimised.

All too often the combustion airflow delivered to a furnace is not measured and validated and therefore the most important function of “staged” or controlled combustion is overlooked. Within the USA, the importance of stoichiometry control with high-sulphur coals has become a serious matter as non-optimum measurement of the stoichiometric firing ratios can indeed result in severe water wall wastage, increased slagging and the associated reliability factors.

Throughout the USA and abroad, it is my experience that most often, actual airflow measurement and control is often neglected and the “assumed” excess air at the furnace exit is determined by the accuracy and/or representation of the boiler exit O₂ probes. However, too often the O₂ probes are found non-representative of the actual measurements when a representative grid of flue gas samples is collected.

Figure 4: Example of acceptable theoretically calculated and measured airflow, at 15 per cent excess air.

Theoretically, excess oxygen can be an indicator of combustion airflow. However, experience has shown that older units with high tramp air infiltration upstream of the O₂ probes corrupts the ability to accurately determine the true amount of excess air in the unit (as tramp air in-leakage falsely represents excess air). Because of the importance of stoichiometry control and balancing of the combustion airflow, it’s important to periodically measure combustion airflow as well as conduct periodic system air in-leakage tests. Figure 4 shows how an example of an acceptable measurement where the measured values follow the theoretical air calculations. This demonstrates the importance of accurate airflow measurement and control on a mass flow basis. Non-feedback, percentage-based control systems are often vague and leave room for errors based on predetermined ranges and values.

Figure 5: Burner stoichiometry compared to varying fuel and air imbalances on a pulverised coal-fired unit.

As noted and previously illustrated, the measurement of combustion airflow and distribution is critical. However, it is also pertinent that each air flow path distributed to the burners is uniform. Staged combustion and control of stoichiometric firing ratios is important, but average stoichiometry doesn’t really matter if the unit is air-rich on one side and fuel-rich on the other. Optimum combustion demands balanced air and fuel flows within acceptable tolerances. Figure 5 shows an example of how the minimum and maximum stoichiometry changes with increasing air and fuel imbalances that are in typical and/or above average ranges.

In the previous example, keep in mind that seven per cent air imbalance and 14 per cent fuel imbalance is a conservative number for typical air and fuel imbalances. When conditions like this arise on a pulverised coal-fired boiler and the sub-stoichiometric zones are introduced with high iron ash levels, slag propensity worsens and water-wall tube wastage is likely to occur. Again, these factors illustrate the need for optimising the air and fuel inputs.

Figure 6: Storm Technologies, Inc – HVT testing equipment.

The importance of diagnosing combustion efficiency

The high velocity thermocouple (HVT) probe traverse is the single most important test in diagnosing combustion related problems on a large utility furnace. On a utility boiler, as the load or output increases, radiant heat transfer decreases and convective heat transfer rises by design with a boost to boiler efficiency.

Figure 7: Example of a typical boiler, FEGT versus heat release rate.

Furthermore, most boiler designs, tube spacing, tube surface areas and regional placement of surface area portions is based off a design furnace exit gas temperature (FEGT) for a given load. Typically as the load increases, furnace exit gas temperature rises as well (see Figure 7). Periodic use of the HVT probe can therefore be used to validate furnace exit gas temperature in relationship to the boilers design.

If the combustion system is non-optimum, the residence time within a furnace for carbon burn-out is reduced and this correlates with higher boiler exit gas temperatures, likely leading to over-heating of some of the tube metal circuits. This will induce such issues as tube exfoliation and solid particle erosion of the turbine blades, overheating of the carbon steel ductwork and induced air in-leakage and tube alignment issues. To exacerbate these issues, the impacts of coal ash chemistry variation with high furnace exit gas temperatures and/or increased slag propensity will reduce heat transfer surface and/or create imbalances of the flue gas. This, in turn, thermodynamically challenges the boiler’s capability to feed steam to the turbine at its design limits.

The HVT probe is intended to accurately measure flue gas temperature, but its greatest importance is the measurement of actual or “true” furnace exit, excess oxygen, carbon monoxide and NO_X profiles.

Balance draft steam generators over 10 years of age can undergo high air in-leakage throughout the boiler setting and sometimes upstream of the excess O₂ probes. Furthermore, sometimes due to stratifications of the air and fuel inducing flue gas variations, O₂ measured just isn’t representative of the average. On older units, it is not uncommon to find total leakage between the furnace exit and the economiser exit in the range of 10-15 per cent. This will result in indicated oxygen of 3-4 per cent at the economiser exit and zero per cent at the furnace exit, which can lead to serious reliability issues (especially with the units firing high-sulphur fuels).

Some of the issues are noted as follows:
• Secondary or delayed combustion elevates the combustion zone, reduces water-wall heat absorption and results in high FEGT.
This combined with a reducing atmosphere can lead to:
• decreased combustion efficiency
• overheating of superheat/reheat tubes
• combined with the effect of a reducing atmosphere, tube wastage and the subsequent tube thinning can result in future tube failures
• aggravation of coal-ash corrosion
• increased de-superheating spray flow
The resulting high FEGT combined with a reducing atmosphere can lead to the following:
• carrying over of cinders from sintered ash deposits on the super-heater and re-heater tubes. These deposits contribute to air heater plugging.
• slagging and fouling of heating surfaces. Reducing ash fusion temperatures are sometimes 250°F lower than oxidising ash fusion temperatures. Therefore, high exit temperatures combined with lower ash fusion temperatures lead to heavy slagging and fouling.
• increased cycle losses due to higher soot blowing frequency as a result of increased fouling and slagging of heating surfaces.
• high boiler exit gas temperature which can lead to accelerated deterioration of air heater heating surface and possible degradation of precipitator performance.
• high leakage can reduce the available induced draft fan capacity and subsequent de-rating of unit generation and availability.
• high leakage rates down stream of the furnace, but upstream of the excess O₂ probes can contribute to low steam temperatures due to the reduced mass gas flow over the super-heater and re-heater.

Temperature and oxygen profiles obtained by the HVT traverse can also be an indication of imbalances in air and fuel originating in the burner belt zone. Therefore, the flue gas chemistry can be compared to the measurement of burner performance, fuel imbalances, combustion (secondary) air imbalance, closed air registers, plugged fuel lines, etc. Consequently, any adjustments to the pulverised coal-fired burners and/or oil fired atomisers can be easily reinforced by the temperature, O₂, CO and NO profiles determined by a HVT traverse.

Figure 8

Representative sampling and measurements are absolutely necessary and good decisions cannot be made with “bad” data. During a testing and burner tuning programme, it is also useful to compare side to side fly ash loss on ignition (LOI) and slagging tendencies with HVT oxygen profiles. In addition to the furnace exit traverse, the accuracy and representation of the excess O₂ probes, air in-leakage from the furnace exit to the economiser, air heater performance and O₂ rise to the stack should be checked periodically. Prospect units for evaluation should be equipped with representative sampling probes such that samples of the flue gas and ash are collected in a timely manner as required for combustion tuning and optimisation. A photo of a representative grid for measuring flue gas temperatures is seen in Figure 8.

Figure 9

Storm Technologies’ multi-point emissions sampling systems (as seen in figure 9) can minimise the effort required to conduct such a test. These are custom-designed and built with an integrated in-line gas sampling grid for measuring flue gas constituents such as temperature, oxygen, CO, NO_X as well as being used as an in-line fly ash sampling “grid” system from collecting representative samples of fly ash for unburned carbon analyses. The inter-relationships of total boiler performance must be considered when optimising combustion. Unit load response, reliability, and capacity are all related and therefore a successful approach must be comprehensive, taking into account boiler performance, mechanical adjustments, fuels, soot blowing, airflow measurement, actual in-furnace O₂ and other factors such as the fuel quality being fired. For boilers equipped with low NO_X burners, there are certain essentials that are a useful checklist. Some of these are as follows:
• The furnace exit must be oxidising (preferably three per cent).
• The fuel lines must be balanced.
• On oil fired boilers, such areas as the measurement of steam and oil differentials is essential
• On coal fired boilers: The fuel lines balanced to each burner by “clean air” test ± two per cent or better. Fuel lines should be balanced by “dirty air” test, using a dirty air velocity probe, to ± five per cent or better. Fuel lines balanced in fuel flow to ± 10 per cent or better. Another critical parameter to optimising fuel balance and carbon burnout is the need for fuel line coal fineness to be 75 per cent or more passing a 200 mesh screen. 50 mesh particles shall be less than 0.1 per cent.
• Combustion airflow must be measured and controlled.
• Secondary air distribution to burners should be within ±5-10 per cent.
• On pulverised coal fired boilers: primary and secondary airflow shall be accurately measured and controlled to ± three per cent accuracy (locally measured vs indicated); Primary air/fuel ratio shall be accurately controlled when above minimum. Fuel line minimum velocities shall be 3300 fpm.
• Over-fire air shall be accurately measured and controlled to ± three per cent accuracy.
• Mechanical tolerances of burners and dampers shall be ±1/4” or better.
• Fuel quality and preparation must be optimum.
• On oil fired boilers fuel oil temperature, quality and atomisation mediums should be considered.
• On coal fired boilers: fuel feed to the pulverisers should be smooth during load changes and measured and controlled as accurately as possible. Load cell equipped gravimetric feeders are preferred. Fuel feed quality and size should be consistent. Consistent raw coal sizing of feed to pulverisers is a good start. These essentials are practical, proven, and effective. I consider these as prerequisites for optimising combustion. Non-compliance with the essentials will compromise the boiler’s full potential. Too often, the evaluation of boiler performance, burner design, OFA systems and/or fuel changes are solely based upon computational fluid dynamics (CFD) models and/or some other ‘Engineering Tool’ model that evaluates conditional changes in design or the fuels fired. With such models, there are many assumed variables. Therefore, it should be taken into consideration that these programmes are slave to the inputs and neural networks and/or other computerised operational programs are only as good as the inputs!

One of the most commonly overlooked details with testing is obtaining reliable and representative measurements. Utility boilers are often extremely large in size and therefore to determine flue gas composition, fly ash unburned carbon and temperatures throughout the system, a methodical and proven approach must be taken to ensure elimination of the ‘garbage in = garbage out’ side of boiler optimisation. Conversely, integrating the APPLES method of conducting baseline performance and/or evaluating empirical data with advanced engineering technology is the best approach to excellence in boiler optimisation.

Stephen Storm is an executive vice president with Storm Technologies Inc. technical field service division. Having a broad background in evaluating combustion, performance and efficiency opportunities on utility and industrial systems, Stephen is also one of the primary trainers for Storm Technologies’ Performance and Combustion training course. He can be contacted at:
stephen.storm@stormeng.com