A power purchase agreement for an in-development solar project has netted what the Rocky Mountain Institute has called the lowest reported contract for distributed photovoltaic solar energy in the United States.

The 3-MW Carrizozo project, developed and owned in New Mexico by SoCore Energy, signed a contract with the Otero County Electric Cooperative for less than 4.5 cents per kWh. RMI provided project analysis and supported the competitive procurement process.

Carrizozo is expected to come online in March 2018. The project does not receive tax credits or subsidies.

“The Carrizozo solar project allows us to deliver renewable energy to our members while also saving them money,” Mario Romero, chief executive of Otero County Electric Cooperative, said. “Since OCEC purchases the energy produced by this project at such a great price, this project will allow all of our 14,000 members to benefit by reducing our overall cost of purchased power.”

Gas Turbines (GTs) operate at a constant volume of (hopefully) very clean air. It’s the density of this air however (weight per unit volume) that holds the key if we want to keep our Gas Turbine Power Output levels high.

On a hot summer day, air expands and is less dense (occupies more volume for the same weight) than on a cooler day. For Gas Turbines operating at a constant volume of ingested air, this then results in less mass flow of air to the compressor which will significantly reduce performance and power output.

Gas Turbines are rated for performance at 15°C (59°F), 60% Relative Humidity (RH) and at sea level air pressure. If your GT is located at and primarily operates during such conditions, then the efficiency and power output you see advertised is what you should expect to generate. If the above conditions are not met however, then you will see a significant drop off from the rated values.

All GTs have reduced performance levels at higher temperatures (and also at higher altitudes). A few common rules of thumb can be employed to understand the impact.

Expect about a 0.4% reduction in power output plus 0.1% increase in heat rate for each 1°F (0.85°C) rise in ambient temperature above 59°F (15°C).

Expect about a 0.4% reduction in power output plus 0.1% increase in heat rate for each inch Water Gauge (250Pa) of pressure drop.

Altitude has a minimal effect on heat rate but for each 1000ft increase in site elevation above sea level, there is about a 3.5% loss in power output.

By way of an example, if the ambient air temperature rises to 27°C (80°F), power output can drop by up to 3% for older ‘frame’ engines with a compression ratio of ~10 and approximately 8% for aeroderivative engines with compression ratios of ~30. This rises to 7% and 17% respectively as temperatures reach 38°C (100°F). When you crunch the numbers, the financial impact of this can be enormous.

On hot days, the losses in turbine output are further compounded because the market demand for power increases and (typically) the price goes up. Consumers turn on air conditioning units during hot days, driving up energy prices to a premium. Indeed, at peak times, energy prices can double to ~ $100 per MWhr or higher, making this a time when power companies really want to maximize output and generate increased profits. In many applications, however, the opposite is happening and GT performance is being reduced because of the ambient air conditions and the power output from the machine is actually dropping.

The most common way of compensating for this drop in performance is to employ supplementary devices which function to cool the inlet air, counteracting the drop in density and recovering a proportion of the losses in power output.

A payback analysis should be performed with the assistance of the technology supplier in order to understand the financial benefits to be had by introducing air cooling technologies. The technology supplier can also help define the best cooling methods for any given GT application or/and operational timeframe based on historical local area ambient temperature and humidity data. For retrofits they can also provide details about extending foundations and adding support to any new cooler support structure.

Different technologies are available to achieve GT air intake cooling, most commonly based on either water evaporation within the airstream or by using tube and fin style heat exchangers.

Evaporation of water is one of the simplest and oldest methods of cooling air. Even with all the sophisticated technology available today, including mechanical chillers, absorption chillers, and thermal energy storage systems, the simple principles of evaporative cooling remain a cost efficient method for GT air intake temperature control.

The performance of an evaporative cooler is based on the ratio of the number of degrees it can cool the air compared to the wet bulb temperature depression. This terminology can appear confusing but really all it means is the difference between the dry bulb (which is just another term for the ambient air temperature) and the wet bulb temperature (which is the temperature this air would be if it were 100% saturated i.e. at 100% Relative Humidity (RH)).

As air passes through an evaporative cooler system, heat energy is transferred from the air to the water. This energy transfer causes the water to evaporate and the water vapour then mixes with the air, manifested as increased humidity. The total amount of energy in the air, however, remains constant so the process can be considered as adiabatic.

Water evaporation based designs use what is termed as latent heat transfer. This is when heat is transferred from one substance (the hot air) without a corresponding temperature increase in the other substance (the introduced water). In this application the other substance (water) instead changes physical state from liquid to gas as it evaporates, thus the terminology ‘evaporative cooling’.

The most commonly used evaporative cooling systems employ a ‘wetted’ media. In this type of system, the GT inlet air passes through a bank of water-soaked evaporative cooling media. Evaporation of a portion of the water contained in the media lowers the dry bulb temperature of the air. A moisture separator stage is located immediately downstream of the media bank, the function of which is to remove any liquid water droplets that may become re-entrained in the airstream. The cooling media through which the inlet air passes is typically located between the inlet filter compartment and the inlet plenum, upstream of the silencer. An additional skid is used to house the cooler feed water tank, pumps, controls, and water quality (blowdown) sampling system. For larger systems the feed water tank (sometimes called the sump) can be located directly underneath the sets of media banks.

Wetted media evaporation systems offer the greatest benefit in hot, dry climates and/or at high altitudes where the air is thin. They are the most widely used and proven solution to reduce gas turbine losses in high temperatures and can offer low initial investment cost and small auxiliary power load.

Evaporation efficiency is directly controlled by contact time between airflow and the moist media. Contact time is a function of airflow velocity and effective media area. The longer the air remains in contact with the media, the greater the cooling that can be achieved through evaporation. Maximum saturation efficiency can be obtained by maximizing the contact area while maintaining relatively low speeds for the airflow. Low speeds are typically a function of filterhouse size, so a balanced compromise is needed to decide on the most cost effective overall solution.

Large quantities of water are required for the system to operate and so this needs to be readily available as a local utility or through on-site storage tanks. Water also needs to be of a relatively clean quality to protect the gas turbine from corrosion and scale formation and to help reduce maintenance frequency of the evaporative cooler system and media.

Water always contains a certain amount of dissolved minerals, unless it is treated and termed demineralized (more on this later). The process of evaporative cooling removes liquid water from the re-circulating flow and leaves behind the solids that had been dissolved in the water when it was added as makeup. Accordingly, for recirculating systems, enough water must be blown down (removed) from the re-circulating flow to control the level of these solids and to avoid build-up of insoluble minerals on the media pad surface (also known as scaling), which results in an increase in pressure drop, and a loss of evaporation efficiency. Blow down is a function of evaporation rate and the cycles of concentration. The chemistry of the sump is established by determining the maximum cycles of concentration that the makeup water can go through before needing to be changed.

The other main water evaporation based cooling methodology used for GT cooling is when atomized water is sprayed directly into the air intake. This is termed ‘fogging’. Fogging is a method of cooling where demineralized water is converted into a ‘fog’ by means of arrays of atomizing nozzles operating at high pressures. The fog, which consists of billions of small droplets, mixes with the hot ambient air and evaporates. This evaporation is again a latent heat transfer process whereby the ambient air temperature decreases. Care needs to be taken with fogging because atomizing nozzles are prone to wear which increases droplet sizes and can increase the risk of droplet erosion on the GT compressor blades as well as decreasing the effectiveness of heat transfer. It is also important to ensure that no ‘overspray’ occurs. This is the term used when the fog generated does not have sufficient time to interact with the air and fully evaporate or when more water is injected than is actually required to raise the relative humidity to 100%.

Fouling of the gas turbine inlet air system and the compressor will occur with inadequate water quality for both methods of water evaporation based cooling. For fogging systems, demineralized water is necessary to limit spraying nozzle blockage and there is no recirculation of the water employed, however for wetted media designs, ‘blowdown’ or continuous sampling of the (normally) recirculated water is necessary to ensure the water quality remains sufficiently clean and is topped up as necessary.

If either of these technologies is used, air temperatures cannot be lowered below the wet-bulb temperature (which if you recall from earlier is the temperature when the air is completely saturated i.e. at 100% Relative Humidity). It is important to then also realize that the effectiveness of these systems are limited if local levels of ambient humidity are already high, as the air already contains increased moisture levels to start with. Improvement gains to be had are directly linked to the delta between the ambient humidity and this 100% humidity (wet bulb) condition. Using wetted media also increases differential pressure across the system noting that the way the technology is employed and maintained means it can (and should) be removed in cooler times of the year when not required. The differential pressure associated with fogging systems is minimal.

The other main method of cooling air for GT air intake applications is by using heat exchanger ‘coils’.

Chiller coil cooling systems work like a radiator in a car. Cool fluid flows through tubes and is radiated into the inlet using fins which cool the surrounding inlet air, removing water vapour from it. This technology is not dependant on local ambient humidity and can lower the air temperature below the wet-bulb temperature. However, this solution adds a very high parasitic load, which can typically be around a third of the output gain achieved (several thousands of kW for a 100MW turbine), and increases differential pressure across the installation all year round (which negatively impacts GT performance), without the ability to easily remove when not needed.

A comparison of technologies is provided below with the relative pros and cons of the existing technologies commonly employed for GT air intake cooling, today.

A cool payback (case study)

To demonstrate the sort of payback period inlet for air cooling, let’s look at an example of a gas turbine installation in inland North Africa. The site has two GE 9E turbines and wishes to use the proven wetted media evaporation technology. Temperature and humidity levels assume the evaporating system operates between the hours of 10 a.m. and 8 p.m. from June to September. At peak temperatures (maximum evaporation) the two units combined will require approximately 42 m3/hour (184 US GPM) of water.

The average decrease in inlet air temperature as a result of the cooling system is 12°C (21°F). This equates to approximately 8.5% of reduced loss in turbine output. The 9E turbines are ISO rated at 126 MW (15°C). If an average of output of 110 MW is assumed, the cooling system saves 9.4 MW. As this saving is during peak periods, taking a price of $90/MWhr means in one year (excluding water treatment) the cooling system will save:

9.4 MW x 10hrs x 122 days x $90 = $1,032,120

For these installation conditions, a typical payback period of just one year makes the wetted media evaporation system an appealing option. This assumes a scope of supply including evaporative cooling system and the required supporting structure.

Not a component in isolation

A complete inlet system needs to consider multiple aspects to ensure the turbine is best protected – both in terms of its performance and against costly damage. Components may include weatherhoods and moisture separators, pulse systems if dust levels are high, filters to handle wet and dry contaminants as well as inlet acoustic and cooling systems. The cooling system itself requires water pumping, distribution and quality monitoring systems to help ensure desired results are being obtained. All need to be designed to offer robust and reliable performance based on local, often harsh, environmental conditions.

Companies such as Parker (formerly CLARCOR Industrial Air) can offer fully designed and engineered solutions to cover all aspects of a gas turbine inlet system. Experience, knowledge and expertise across all areas means customers can have peace of mind that they are getting optimum, reliable and consistent performance from their gas turbine all year round.

Summary

The design and effect of a gas turbine inlet system is highly dependent on local environmental conditions. Seasonal variances, site location, different contaminants, operational procedures, criticality of turbine availability and value of turbine output all come into play. Whatever the turbine technology used, lower air density will reduce power output. Companies such as Parker can help customers ensure their system is optimized for their specific installation requirements, minimizing losses and optimizing profit levels.

Author

Pete McGuigan is senior product manager of the Gas Turbine Filtration Division at Parker Hannifin.

During the heyday of coal-fired power plant construction and operation in the last century, many lessons were learned regarding correct water/steam chemistry control in high-pressure, fossil-fuel steam generators. Even seemingly minor issues had the potential to cause serious problems, and some corrosion-induced failures led to injuries and death of plant personnel.

Progress in transferring these lessons to the combined cycle power industry has often been slow, and a number of outdated chemistry concepts continue to appear in the specifications for new combined cycle plants. Some problems are magnified by the unique geometrical features of heat recovery steam generators (HRSGs) as compared to their coal unit counterparts.

This article will examine three of the most important issues in this regard, as outlined below:

• Unless the condensate/feedwater system of the HRSG contains copper alloys (very rare), an oxygen scavenger should not be part of the chemical treatment program. Use of oxygen scavengers, a more accurate term is reducing agent, induces flow-accelerated corrosion (FAC) of plain carbon steel. FAC has caused catastrophic piping and tube failures at a number of facilities over the last three decades, and it continues to occur at many plants.
  
• Tri-sodium phosphate has served as the primary chemical for boiler water treatment in many base-loaded coal units, and the chemistry is often employed in HRSGs. Even at steady load, phosphate treatment is problematic due to the phenomenon known as phosphate hideout. In cycling units, hideout may make phosphate chemistry extremely difficult to control.
• While a strong focus should always be placed on operating chemistry, off-line chemistry control is frequently neglected. Air in-leakage into water-filled steam generator networks during down times can significantly damage tubes, piping, turbine blades and rotors, and other equipment. Given the regular cycling nature of most power plants in today’s environment, the potential for air ingress and subsequent corrosion may be extensive.

Forget the Oxygen Scavenge

When this author began his power career in 1981, common wisdom said that any dissolved oxygen which entered the condensate/feedwater system of utility boilers was harmful. At that time, large base-loaded steam generators were the norm. Such units were typically designed with extensive condensate/feedwater networks with perhaps a half-dozen feedwater heaters. A common material for feedwater heater tubes was some type of copper alloy. The prevalent thinking was that any dissolved oxygen (D.O) would cause feedwater system and boiler corrosion, and indeed dissolved oxygen can be very troublesome if copper alloys are present or if oxygen accumulates in stagnant areas. Therefore, virtually all feedwater systems for conventional high-pressure steam generators included a deaerator for oxygen removal. A properly-functioning deaerator can lower D.O. levels to 7 parts-per-billion (ppb).

Even this residual D.O. concentration was still considered harmful, so supplemental chemical deaeration was a nearly universal process at most plants. Hydrazine (N2H4), typically supplied as a liquid in 35 percent concentration, was once the common reducing agent/oxygen scavenger. Feedwater hydrazine residuals of perhaps 20 to 100 parts-per-billion (ppb) were sufficient. Hydrazine treatment was coupled with feed of ammonia or an amine to maintain feedwater pH within a mildly alkaline range, 8.8 to 9.1 for mixed-metallurgy feedwater systems and 9.1 to 9.3 for all-ferrous systems.

NH3 + H2O ⇔ NH4+ + OH-

This program is known as all-volatile treatment reducing [AVT(R)], and was designed to maintain the protective magnetite (Fe3O4) coating that forms on steel when a unit is placed in operation.

Hydrazine has long been a suspected carcinogen, so alternative chemicals such as carbohydrazide, methyl ethyl ketoxime, and others emerged as alternatives. All still had the same purpose, to establish a reducing environment in the feedwater circuit, thus inhibiting oxidation of metal. AVT(R) became a standard in the industry.

“This changed in 1986. On December 9 of that year, an elbow in the condensate system ruptured at the Surry Nuclear Power Station [near Rushmere, Virginia.] The failure caused four fatalities and tens of millions of dollars in repair costs and lost revenues.” [1]. Researchers learned from this accident and others that the reducing environment produced by oxygen scavenger feed results in single-phase flow-accelerated corrosion (FAC).

The general effect of single-phase FAC is outlined in the next illustration..

The attack occurs at flow disturbances, e.g., elbows, valves, etc., in feedwater piping, HRSG low-pressure (and to some extent intermediate-pressure) evaporators and economizers, attemperator piping, and similar locations. As the following figure illustrates, pH and temperature also have a large influence on FAC; the latter of which explains why LP economizers and evaporators, and attemperator lines, are particularly susceptible.

Corrosion reaches a maximum at 300o F and is highly influenced by pH. This author has attended several presentations by the well-known steam generation chemistry expert, Dr. Barry Dooley (formerly of the Electric Power Research Institute [EPRI] and now with Structural Integrity Associates), who has commented on the numerous FAC-damaged HRSGs he has seen around the world, many with only a few years of operation. The reason; lack of understanding of this chemistry.

So, what are solutions to this issue? Nearly a half century ago, researchers in Europe developed a program known as oxygenated treatment (OT) to minimize carbon steel corrosion in supercritical steam generators. The key component of the program was, and still is, deliberate injection of oxygen into the condensate/feedwater network to establish oxygen residuals of up to 150 ppb. What chemists discovered is that in very pure feedwater (cation conductivity ≤ 0.15 μS/cm), the oxygen will intersperse and overlay magnetite to generate a tenacious and very insoluble film of ferric oxide hydrate (FeOOH). OT greatly minimizes single-phase FAC and can lower feedwater iron concentrations to 1 ppb or less. OT is now the preferred feedwater treatment for most once-through utility steam generators around the world.

Although OT has been successfully applied to some drum boilers, another program has emerged (thanks to research at EPRI) that is very popular for condensate/feedwater treatment in drum units. It is known as all-volatile treatment oxidizing [AVT(O)]. AVT(O) relies on oxygen that enters the condensate from condenser air in-leakage to establish the protective FeOOH layer. But to re-emphasize, OT and AVT(O) are not permissible for feedwater systems containing copper alloys, as the oxygen would simply be too corrosive to the metal. Copper alloys in HRSGs are virtually non-existent, making the issue moot in almost all cases for these units.

Now consider Figure 4, which is the basic schematic of the most common type of HRSG; the design EPRI designates as a feed forward low-pressure (FFLP) HRSG. In this configuration, the low-pressure circuit essentially serves as a feedwater heater for the intermediate-pressure (IP) and high-pressure (HP) evaporators.

When EPRI researchers developed AVT(O), they took into account the pH effect on carbon steel dissolution, as was previously illustrated in Figure 3. AVT(O) guidelines [3] for the HRSG shown above are as follows:

• Condensate pump discharge D.O. concentration: ≤20 ppb
• Economizer inlet D.O. range: 5-10 ppb
• Recommended LP economizer inlet pH25C range: 9.6-10.0
• Condensate/feedwater cation conductivity: ≤0.2 μS/cm

As with OT, the condensate must be quite pure to allow oxygen to generate the FeOOH protective layer rather than cause pitting. However, the normal cation conductivity limit with AVT(O) is a bit more relaxed at ≤ 0.2 μS/cm.

The amount of air in-leakage required to establish the recommended limit of ≤20 ppb D.O. in the condensate is not a hard and fast value, and depends upon several factors including the effectiveness of the condenser air removal system. The key point is to maintain the 5 to 10 ppb D.O. concentration at the economizer inlet. If sufficient D.O. is not available from condenser air in-leakage, a supplemental feed of pure oxygen may be required. When proper AVT(O) chemistry has been established, the internal surfaces will develop a uniform “rugged red” color, as shown in the following photo.

The requirement for a constant small concentration of dissolved oxygen in the feedwater is why mechanical deaeration has been eliminated in some new plant designs. And at existing plants with deaerators, in some cases the plant chemists have had the operators close the deaerator vents to maintain the required feedwater D.O. residual for a successful AVT(O) program.

Even with the accumulation of experience regarding AVT(O) and its benefits, the author regularly sees a call for an “oxygen scavenger” chemical feed system in new combined cycle plant specifications. Altering this mindset has been a difficult task, but hopefully continued articles and papers will alert new owners and developers to FAC and the correct chemistry to control it.

Also of note is that a metallurgical approach is available to control FAC, particularly the single-phase version. The addition of even a slight amount of chromium to carbon steel greatly inhibits the corrosion mechanism. Fabricating susceptible locations such as economizer and evaporator elbows from 1¼ or 2¼ chrome steel will virtually eliminate single-phase FAC. However, doing so does add a bit of cost to the project, which may cause some owners and designers to turn away from what can be a practical solution to the problem.

Brief mention must be made of the seemingly high pH range recommended in the AVT(O) guidelines above. In accordance with FFLP HRSG design, phosphate or caustic cannot be employed for alkalinity control in the LP circuit due to the potential for direct transport of these compounds to steam via the attemperator sprays. But, as feedwater enters the drum a substantial portion of the ammonia will flash off with the steam, which lowers the pH of remaining water droplets in what is a two-phase fluid mixture in the upper portions of the drum. Impingement of the droplets on drum surfaces can lead to the appropriately-named corrosion mechanism of two-phase FAC. Establishing a feedwater pH within the range of 9.6 to 10.0 helps to maintain reasonable alkalinity in the water droplets even with some ammonia flash-off.

In some HRSG designs, the LP evaporator is an independent circuit. The terminology for this configuration is stand-alone low-pressure (SALP) HRSG. Tri-sodium phosphate or caustic is permissible for chemical treatment in the LP evaporator of these steam generators. A lower feedwater pH range of 9.2-9.8 is allowed due to the presence of the solid alkali in the LP evaporator. This in turn allows for reduced ammonia feed to the condensate.

The Complexity of Phosphate Treatment

The alkalinity induced by ammonia feed to the condensate will carry through to the HRSG, and can maintain a basic pH although some of the ammonia will flash off in the LP evaporator. But regardless of the residual ammonia concentration that remains in the HRSG evaporators (and this goes for conventional units as well), ammonia-generated alkalinity offers virtually no protection in the event of impurity ingress, say from a condenser tube leak. Common for years has been feed of tri-sodium phosphate (TSP) to boiler drums to establish more permanent alkalinity. The primary chemical reaction is:

Na3PO4 + H2O ⇔ NaH2PO4 + NaOH

The caustic alkalinity (NaOH) generated by this treatment helps to counteract the influence of the (usually) minor concentrations of chloride and sulfate that may enter the condensate.

However, it has long been known that a considerable difficulty arises with tri-sodium phosphate chemistry due to the variable solubility of this chemical with temperature.

The graph clearly shows that solubility increases as temperatures rise to 300o F, but then declines rapidly and is virtually negligible at the temperatures of high-pressure boilers. As a unit comes up in load, TSP precipitates leaving very little residual in the boiler water. The common name given to this deposition is “hideout.” Then, if boiler load is reduced or especially if the unit comes off line, the TSP re-dissolves. In the middle of the last century, coordinated phosphate treatment, later modified to congruent phosphate treatment, came along as a method to stabilize chemistry due to hideout. In both programs, TSP was blended with di-sodium phosphate (Na2HPO4) and occasionally a small amount of mono-sodium phosphate (NaH2PO4) in an attempt to balance the chemistry of the deposits with that of the bulk boiler water. Subsequent operating experience and research showed that coordinated and congruent chemistry were flawed and led to formation of acidic phosphate deposits that attacked the base metal. Thus, TSP has become the only recommended phosphate species for high-pressure steam generators. Regardless, hideout causes swings in boiler water chemistry, including pH, and can make chemistry control problematic. Even at base-loaded plants, hideout presents difficulties and though the plant may have plenty of on-line instrumentation to monitor boiler water conditions, much extra effort may be required to control chemistry. [4]

So, what recourse do HRSG technical personnel and/or operators have to avoid these problems? Chemists at some plants, most notably existing coal plants, have switched to caustic as the chemical for boiler water pH control. However, caustic treatment requires very careful monitoring as iron is an amphoteric material, meaning that carbon steel will corrode at high pH as well as low. The recommended maximum free caustic concentration in high-pressure steam generators is 1 part-per-million (ppm). [3] For plants without trained chemistry personnel, caustic control may be very difficult.

A method to avoid phosphate or caustic chemistry issues is to employ full-flow condensate polishing, which provides a barrier of protection for the steam generators and allows simplified boiler water chemistry. We have already noted that the alkalinity generated by ammonia feed to the condensate system transports to the steam generator, but that impurity ingress will almost immediately destroy ammonia-based chemistry. Minimize the chances of boiler water contamination with condensate polishing, and now the AVT(O) feedwater chemistry program also becomes acceptable for the boiler. (For more discussion regarding condensate polishing, please refer to the author’s article in the current issue of Power Engineering, [5] which was distributed to all Power-Gen attendees.) An item that the author and colleagues regularly encounter with new project development is elimination of a condensate polisher from initial plant design or during the purchasing process as an easy method to reduce capital costs. This is short-sighted thinking.

Off-Line Protection

Much focus, and rightly so, is given to on-line chemistry issues, as upsets while a unit is at pressure and temperature can be quite problematic. However, plant designers, owners, operators, and technical personnel often tend to overlook corrosion issues that can arise when units are off-line. Given the transition of the power industry from base-loaded operation to high cycling duty, these issues have been magnified. Much of the following discussion is extracted from reference 6, which the author and a colleague from the combined cycle industry prepared for Power Engineering magazine in 2012, and whose ideas are still completely valid.

Both conventional units and HRSGs are a complex maze of waterwall piping, superheater and reheater tubing, boiler drums, and other equipment. When a unit is taken off-line, the water inside the circuits contracts slightly in volume. The volume change draws in outside air. Now, stagnant conditions with oxygen saturation, at least at water-air interfaces, have been established.

Oxygen attack is extremely serious for several reasons. The corrosion mechanism itself can induce severe metal loss in those areas of high oxygen concentration.

The attack often takes the form of pitting, where the concentrated corrosion may result in through-wall penetration and equipment failure in a short period of time. Also of concern is that off-line oxygen attack generates corrosion products that then carry over to the steam generator during startups. Deposition of iron oxides within evaporator waterwall tubes leads to loss of thermal efficiency and, much more importantly, establishes sites for under-deposit corrosion. These corrosion mechanisms may include acid-induced hydrogen damage, [3] direct phosphate corrosion, and caustic gouging. In fact, cases have been known of both under-deposit acid and caustic corrosion in the same unit. [7]

Another method by which oxygen can infiltrate steam generators is at startup when condensate or fresh demineralized water is needed for filling or boiler top-off. Usually this water is stored in atmospherically-vented tanks and absorbs oxygen and carbon dioxide. Subsequent injection of oxygen-saturated makeup into a cold steam generator induces additional corrosion.

Perhaps the most critical item of all, at least with respect to the greatest potential for catastrophic damage, is exposure of the low-pressure turbine to atmospheric conditions during short-term shutdowns. If a unit comes off-line, and condenser vacuum is broken, outside air, humidified by standing water in the condenser hotwell, will permeate the low-pressure (LP) turbine. “So what?” is a reply this author has heard more than once. The answer lies in the fact that even with proper boiler water chemistry and operation, trace quantities of salts, and most notably chloride salts, still carry over with steam. Superheated steam remains dry during its passage through most of the turbine, but some condensation begins in the last few rows of the LP turbine. This location is known as the phase transition zone (PTZ). The salts in the steam precipitate in the PTZ, and these compounds, especially if subjected to humid air during shutdowns, will initiate pitting of the turbine blades, blade attachments, and rotors. Pitting in itself is a very troublesome corrosion mechanism, but with turbine blades, and especially the long blades in a LP turbine, pitting can evolve into stress corrosion cracking and corrosion fatigue. These corrosion mechanisms may in turn lead to blade failure, and if this happens with a turbine spinning at 3,600 rpm, catastrophic results are guaranteed.

Per reference 6, at the Lincoln Electric System (LES) Terry Bundy combined-cycle plant utility personnel have implemented several very effective techniques to prevent oxygen ingress and corrosion. Primary power is produced by two GE LM 6000 combustion turbines and two Nooter-Eriksen dual pressure HRSGs (no reheat) feeding a 26 MW steam turbine. Feedwater chemistry is AVT(O), with ammonium hydroxide injection to maintain feedwater pH within a range of 9.6 to 10. High-pressure evaporator chemistry is based on EPRI’s phosphate guidelines, with tri-sodium phosphate as the only phosphate species. The phosphate control range is 1 to 3 parts-per-million (ppm). The HP evaporator pH control range is 9.5 to 10. Free caustic concentrations are maintained at or below 1 ppm to minimize the risk of caustic gouging.

“An individual who enters a confined space where nitrogen has not been purged may pass out nearly intantaneously due to lack of oxygen.”

For off-line protection of the HRSGs, first and foremost is nitrogen blanketing during the last stages of shutdown and subsequent short-term wet layups. Introduction of nitrogen to key spots in steam generators before the pressure has totally decayed will minimize ingress of air. Then, as the system continues to cool, only nitrogen enters void spaces. At Terry Bundy, the nitrogen injection points are at the steam drum vents. For more complicated systems, including conventional coal-fired units, additional locations for nitrogen protection include feedwater heaters, the deaerator, and superheaters. It is also possible to protect the LP turbine and condenser with nitrogen, but another method for longer-term layups is outlined shortly.

One question that often arises is how best to store or generate nitrogen. Certainly it can be provided from nitrogen bottles delivered by local gas-supply or welding firms. Liquid nitrogen is another possibility. LES personnel selected a different method, nitrogen generation via pressure-swing adsorption (PSA).

The process utilizes a carbon molecular sieve, which, when compressed air (130 psig at Terry Bundy) is introduced, adsorbs oxygen, carbon dioxide, and water vapor, but allows nitrogen to pass through. The nitrogen is collected in receivers for use as needed. At regular intervals pressure is released allowing O2, CO2, and H2O to desorb from the material, at which time these gases vent to atmosphere. The table below outlines nitrogen purity from this system as a function of production rate.

During wet layups nitrogen is applied at a pressure of 5 psig to the LP and HP drums when unit pressure has decayed to this level. Also, nitrogen is utilized to “push” water from an HRSG during dry layup draining. A nitrogen pressure of 5 psig is maintained during the dry layup, provided no major tube work is required. An obvious major concern with nitrogen blanketing is safety. Of course, elemental nitrogen is not poisonous, as it constitutes 78 percent by volume of our atmosphere. However, an individual who enters a confined space where nitrogen has not been purged may pass out nearly instantaneously due to lack of oxygen. Death can occur within minutes.

Another important point with regard to wet layup chemistry is periodic water circulation to minimize stagnant conditions that can concentrate oxygen in localized areas. Both Terry Bundy HRSGs have circulating systems installed on the high-pressure and low-pressure circuits for use during wet layups. Each circuit utilizes one of two redundant pre-heater recirculation pumps (100 gpm capacity), which normally are in service during HRSG operation to mitigate acid dew point corrosion of external tube surfaces. Valves and piping have been modified to allow for seamless transition from layup circulation to normal operation. Sampling/injection systems are available to allow operators to test the layup chemistry for pH and dissolved oxygen concentration (using colorimetric ampules), and to inject ammonium hydroxide if the pH needs to be raised. Also, modifications made in each boiler drum allow the layup water to bypass the drum baffle, promoting circulation and minimizing short-circuiting via the downcomers. The pumps are typically started once drum pressure drops below 50 psig, and remain in service for the duration of the layup.

Dissolved Oxygen Removal from Condensate and Makeup Water

As was previously noted, demineralized water is commonly stored in atmospherically-vented tanks. If untreated, oxygen-saturated water enters the steam generator during boiler fills or per demand for makeup during normal operation. Several methods are possible to limit oxygen ingress to storage tanks and steam generators, and Terry Bundy personnel selected a gas transfer membrane technology to remove oxygen from makeup water.

As the makeup flows along the hollow fiber membranes in the vessel, gases pass through the membrane walls but the water is rejected. The technology is capable of reducing the D.O. concentration to less than 10 parts-per-billion (ppb).

Protecting the Steam Turbine

Previously noted is the corrosion that can occur in the LP steam turbine if it is exposed to moist, atmospheric conditions. Nitrogen blanketing is one method to prevent attack, but another practical method to combat this corrosion, and one that has been adopted at Terry Bundy, is dehumidified air (DHA) injection to the condenser during all but short-term (<72 hours) layups.

This particular DHA system is capable of providing 700 standard cubic feet per minute (SCFM) of 100oF air at 10 percent relative humidity to the condenser and low-pressure turbine. The process can lower the relative humidity of the surroundings from 100 percent to less than 30 percent in just a few hours. The common flow path is injection at the LP steam injection point with extraction at the condenser hotwell. DHA is initially applied in a once-through mode until an acceptable humidity is attained, at which time bypass valves are opened allowing for recirculation of the exhaust air to the dehumidifier. This procedure is in stark contrast to the author’s observations at a number of plants, in which, when the unit came off for an extended outage, the hotwell was not completely drained and still contained standing water. Such conditions are ideal (in the worst sense of the word) for subjecting the LP turbine, and the precipitated salts in the PTZ, to a humid, oxygen-laden environment.

Summary

This article outlined several of the most important modern chemistry aspects to maximize HRSG operation and reliability, including control techniques for flow-accelerated corrosion, complexities regarding boiler water treatment, and the importance of off-line corrosion control. One key point to re-emphasize is that during normal operation a small amount of dissolved oxygen is vital for proper feedwater chemistry, but when the unit is off-line or being filled for a return to service, oxygen ingress can be quite destructive. (Seems rather paradoxical, doesn’t it?) Any power plant is an expensive facility that provides vital electricity to the grid. These valuable assets need to be protected with the most modern technologies and chemistry programs available.

Author

Brad Buecker is Senior Technical Publicist at ChemTreat.

References

1. Cycle Chemistry Guidelines for Shutdown, Layup and Startup of Combined Cycle Units with Heat Recovery Steam Generators, EPRI, Palo Alto, CA: 2006, 1010437.

2. Buecker, B. and S. Shulder, “Power Plant Cycle Chemistry Fundamentals”; pre-conference seminar for the 35th Annual Electric Utility Chemistry Workshop, June 2-4, 2015, Champaign, Illinois.

3. EPRI Comprehensive Cycle Chemistry Guidelines for Combined Cycle/Heat Recovery Steam Generators (HRSGs). 3002001381. December 2013.

4. C. Taylor, “Phosphate Hideout at Labadie Energy Center Following Boiler Chemical Cleaning”; 34th Annual Electric Utility Chemistry Workshop, June 3-5, 2014, Champaign, Illinois.

5. B. Buecker, “Merits of Combined Cycle HRSG Condensate Polishing”; Power Engineering, November 2017.

6. Buecker, B. and D. Dixon, “Combined-Cycle HRSG Shutdown, Layup, and Startup Chemistry Control, Power Engineering, August 2012.

7. S. Shulder, “Treatment Selection and Optimization of Cycle Chemistry at Fossil Plants”; 37th Annual Electric Utility Chemistry Workshop, June 6-8, 2017, Champaign, Illinois.

Old boiler systems with outdated, inefficient equipment are the norm for our industry. This is because boiler technology is largely stable, and boilers are reliable pieces of equipment that can last decades. They are also expensive. This means that boilers are only infrequently replaced, and boiler replacement is often the only time that upgrading the rest of the system (burners, pumps, control systems) comes up for discussion.

However, the world is rapidly changing. Electrical costs continue to climb, petroleum and natural gas prices increase, and regulations on emissions continue to tighten. Many outdated boiler systems are, or soon will be, prohibitively expensive to run and out of compliance with state and federal regulations.

We will examine components of the boiler system that can be replaced without having to replace the boiler itself. In particular, we will present boiler retrofits that can increase efficiency and prepare the system for the future.

Upgrade to Parallel Positioning or Fully Metered System

When we evaluate burner systems for upgrade potential, one of the first things we look at is whether the system is using some sort of jackshaft linkage or single point positioning. This antiquated technology is surprisingly common, and presents a relatively straightforward and inexpensive retrofit opportunity. But there are some things to look for and keep in mind.

Fuel and air must enter the burner at specific ratios and rates, and the ratios vary with desired firing rates. This is because more excess air is required at low firing rates than at high firing rates. So fuel and airflow (and potentially other aspects of the system, such as recirculated flue gas) must be coupled in a way that is sensitive to the firing rate.

Jackshaft linkages solve this problem in a straightforward mechanical way. A single actuator controls the output of the system and is changed depending on the firing. This actuator is attached to a jackshaft, which is in turn attached to the fuel and air fan valves via linkage arms. Fuel and air flow ratios can then be configured at different firing rates by adjusting the length and angle of the linkage arms. As more and more components are tied into the jackshaft, the setup can become very complex and expensive.

There are two problems with these systems: configuration and maintenance. Correlating linkage arm length/angle to desired outputs is an extremely complex and manual task. A service manual may list specs for some common output parameters, but fine tuning things requires a highly skilled operator. And because adjusting one part of the system can potentially affect all others, the process is error prone and can take a long time. Because of these constraints, it is very common to set these systems for one scenario and then not update them — even when it’s known that under current conditions, a different configuration may be more efficient.

Additionally, because the components are made of metal and connected by bolts, the system drifts from the desired configuration over time. Bolts loosen, introducing slippage (or hysteresis) into the system. Hysteresis means inefficiency as incorrect amounts of fuel or air flow into the burner. It also can mean that the system is not operating within the desired specifications — this can be problematic for facilities operating under stringent emissions regulations.

Because of these two problems, burners using jackshaft linkages are generally not operating anywhere close to maximal efficiency. These systems are using far more fuel or electricity — and producing more emissions — than the burner requires for the given firing rate. Jackshaft linkages are one of the first things that should be replaced in facilities looking to retrofit for the future. What’s the alternative? Either a parallel positioning system or a fully metered system.

In a parallel positioning system, each burner component has its own actuator valve that is wired into a central control computer. The obvious benefit here is that configuration is straightforward — punch in the desired parameters into a computer interface — and there is no slippage to speak of. Burners can reliably operate at specified conditions, representing large efficiency gains.

O2 Trim & VFDs

One of the biggest sources of error in a combustion control system is variation in ambient temperature and humidity. The oxygen content of air changes with temperature and humidity. Recall that in a jackshaft linkage system, each firing rate is configured to deliver a particular volume or mass of air to the furnace. The upshot is that this may or may not be the optimal amount of oxygen, depending on temperature/humidity. To account for this, traditional systems must add large quantities of extra air to cover the full range of temperatures/humidities in which the burner operates. Because extra air means higher operating costs — by sending wasted heat out the stack — this is a big downside.

Parallel positioning helps by making it easy to add an O2 trim system. This means that O2 sensors can be added to monitor oxygen content in the furnace in real time. This feedback can then be used to change the fan actuator to correct the air flow. Good O2 trim on a parallel positioning system can significantly reduce the amount of excess air required. When paired with a good variable frequency fan drive (VFD), electrical costs can be drastically reduced — in some cases by as much as 85 percent.

Tradeoffs

The combination of easier configuration, reduced hysteresis, and O2 trim with VFDs adds up to greatly reduced operating costs and greatly improved operating precision. The cost of switching to a parallel positioning system can vary from $5,000 to $20,000+. Part of the decision for this retrofit will be balancing operating cost savings against this upfront investment. In the context of retrofitting for the future, consider tightening regulations and ever-increasing electrical expenses. From this perspective, anything that improves efficiency and reduces electrical consumption is a win.

When replacing outdated jackshaft linkage systems, the option of fully metered control systems offers an additional level of precision over parallel positioning systems. However, they are also much more costly and complicated to install. While a deep dive into fully metered systems is beyond the scope of this article, a good rule of thumb is that parallel positioning systems are the best choice for boilers up to 600 BHP. Beyond that, the advantages of a fully metered system start to outweigh the additional cost. A good design and engineering firm will be able to discuss the tradeoffs of a particular application.

NOx Emissions Control: Striking the Balance

Nitrogen oxides (NOx), and in particular nitrogen dioxide (NO2), are a harmful byproduct of combustion. They are one of the primary constituents of “smog” and are known to cause serious damage to human health once above a certain concentration. For this reason, they have been a big focus for federal and state regulatory agencies, especially since the 1990s. Stricter NOx standards began at the federal level through the EPA under the clean air act. Since then, there has been a steady trend of state and municipal agencies enacting stricter regulations on NOx emissions than formally required by the EPA.

“The elephant in the room is that moving to ultra-low NOx emissions inherently means lower combustion efficiency…”

There are many sources of NOx emissions. The most significant is heavy-duty trucks, and much of the NOx regulations focus on these emissions. But industrial boilers are another significant source, and most states regulate NOx emissions from these too, especially where heavy-duty trucks already meet stringent requirements but further air quality improvements are required. California has led the charge here, with many areas of the state now requiring that burner emissions have NOx concentrations of only 9 parts per million (ppm). Meanwhile, some areas, like New York City, don’t place any NOx emissions requirements on boilers. Many states fall in between, with more moderate NOx requirements between 20-30 ppm. Tracking these regulations starting in the 1990, the tightening trend is clear.

There are three primary ways a boiler can form NOx: prompt formation, thermal formation, and fuel formation. Prompt NOx contributes only negligibly to combustion emissions, so thermal and fuel NOx are the primary target. Thermal NOx is formed during combustion, and is a reaction between the oxygen required for combustion and the nitrogen that is present in the air. Fuel NOx is the result of nitrogen present in the fuel source that is freed during combustion. This is negligible in the case of natural gas, but can represent up to 50%-80% of the total NOx produced when burning coal or oil (which, by the way, is a great reason to upgrade older coal or fuel oil systems to natural gas).

We can expect NOx standards to become stricter over time, so retrofitting a boiler for the future should take this into account. The most straightforward strategy is to opt for an ultra-low NOx burner, capable of achieving ~9ppm NOx emissions (generally agreed to be the lowest practical level). These have been on the market for a number of years now, primarily to serve facilities in California and other areas with very stringent NOx regulations.

Since thermal NOx is highly dependent on combustion temperature and oxygen presence, reducing temperature and the presence of excess oxygen are the best ways to control it. Ultra-low NOx burners generally achieve this by either flue gas recirculation or a lean premix of fuel and air. Flue gas recirculators (FGR) use fans to recirculate exhaust back into the combustion chamber. Because flue gas is both cooler and has significantly reduced oxygen concentrations, this can dramatically reduce the concentration of NOx in emissions. Lean premix burners, on the other hand, premix the fuel and air at a very low (“lean”) ratio of fuel to air. This produces a very uniform, low flame temperature.

There are tradeoffs to both systems. FGR systems are typically more efficient than lean premix systems. A typical FGR burner operates at 2-3% O2, while a typical lean premix burner operates at 8-10% O2. This can translate to a boiler efficiency difference of 3-4% O2. Additionally, FGR burners can achieve excellent turndown rates. The flipside, though, is that these burners incur substantial electrical costs, because they have to power large flue gas fans. This can be a problem where electrical costs are high, or where a facility also has strict carbon commitments (using electricity creates a carbon debt).

Lean premix systems avoid these electrical costs, at the cost of some O2 efficiency. An additional benefit is that the underlying physics here is very well-understood, making predictable configuration fairly easy. One of the major downsides of lean premix systems is that their combustion heads are typically made of a fragile, metal mesh that is prone to clogging. Additionally, they generally use air filters that require frequent changing. This not only increases maintenance costs, but means that efficiency gradually decreases over time. Yet another negative is that these systems generally have poor turndown of around only 3:1.

The good news for facilities that can’t use FGR is that new lean premix systems are coming onto the market that address some of these problems. Look for lean premix burners that use solid metal heads and don’t require air filters. The best and most recent entrants to the market can achieve high turndown rates of 6- 9:1.

Switching to an ultra-low NOx burner will require other modifications to the system — many of these considerations are well-covered in a previous issue of Power Engineering. The elephant in the room is that moving to ultra-low NOx emissions inherently means lower combustion efficiency, and so higher operating costs (in addition to the electrical overhead of an FGR system). Remember, if we’re burning at a low temperature, we’re not using our fuel as efficiently as possible, and so more fuel is required to produce the same amount of heat.

When we talk about future proofing, we’re talking about being prepared for future NOx requirements that could be around 9ppm. But we also know that these requirements are typically enacted gradually. Switching to operating at 9 ppm NOx now for regulations that might not come into effect for 5 or 10 years means incurring a lot of unnecessary operating costs in the meantime. At the same time, many old burners need to be replaced — and if you’re going to replace one, shouldn’t you replace it with an ultra-low NOx model so that you’re not facing another replacement in a few years when regulations change?

The way out of this conundrum is the latest breed of low-NOx burners that offer configurable NOx emissions concentrations. These now exist in both FGR and lean premix forms. In the case of the FGR configurable burners, the amount of flue gas that gets recirculated is programmable over a wide range, and down to the lowest theoretically possible levels. In the case of the lean premix configurable burners, that fuel-to-air ratio is configurable, from super lean to very rich. These configurable systems are the best option for areas that don’t yet face the strictest NOx standards. By switching to one of these burners, NOx emissions can be set to exactly meet current NOx regulations, while maximizing efficiency. When and if these standards change in the future, the burner can be simply reconfigured to meet the new requirements.

Retrofitting for Biofuel: The New Frontier of Liquid Wood

Along with a trend towards lower NOx emissions, there is a trend toward lower carbon footprints and the use of renewable biofuels. Until recently, the only viable option for boilers was solid-mass biofuels — in particular, wood pellets or chips.

The wood for these fuels can be sustainably sourced from tree farms, and replanting the trees used to produce the fuel can mostly offset the carbon emitted from burning them. What has limited their widespread adoption, however, are the significant costs of switching to such a system. An entirely new boiler is generally required to enable burning solid chunks of fuel as opposed to burning liquid or gas. The solid biomass fuel will need to be burned over a grate or in a fluidized bed boiler, which is significantly different from a standard firetube or watertube boiler. Additionally, burning solid biomass produces much more ash, and the burner has to be equipped so that this can be regularly removed from the boiler. All of this means that switching to solid biomass fuels can easily exceed $20M in upfront investment. That type of investment is generally only made sense for institutions with very strict carbon or renewable commitments (for example, universities which adopted strict carbon commitments under the American College & University Presidents’ Climate Commitment).

However, it is now possible to retrofit for biofuel because liquid wood, (renewable fuel oil or bio-oil) has become viable for use in existing gas or oil boilers for the first time. Liquid wood is produced by heating wood in the absence of oxygen, in excess of 500º Celsius. Because there is no oxygen, the wood does not combust: it first becomes charcoal, and then further decomposes into gas and liquid. When heated above 700º C, pyrolysis occurs very quickly and the yield will be around 60% bio-oil, 20% char, and 20% “syngas.”

From the perspective of the boiler, this bio-oil is essentially the same as traditional fuel oils or natural gas. Burning the liquid wood efficiently and reliably however, is rather subtle: the liquid is highly corrosive, thermally unstable, and will easily polymerize if exposed to air. Accordingly, it requires tight temperature and pressure tolerances from the burner, along with pumps, piping, and storage tanks that are very corrosion resistant. The difficulty of engineering the burner and pump system, along with the lack of a reliable, cost-competitive source of liquid wood has–until recently–prevented the use of this bio-oil in boiler applications.

Though liquid wood has long been available on the market, commercially viable burners that can handle burning it have just arrived. These burners are compatible with a wide range of existing boilers, and represent a highly future-proof choice for retrofitting an existing boiler. The cost of such a retrofit is generally around 90 percent less than the wholesale replacement of a boiler for a solid biomass solution. It’s effective too: a college in Maine that recently made the switch reduced their carbon footprint by 83 percent in just one year.

This is new technology, and its applicability will depend on a facility’s prioritization of carbon footprint and sustainability and their ability to obtain liquid wood, which is now becoming increasingly available.

A Cleaner Future with Your Existing Boiler

When looking to retrofit for the future without having to replace your entire boiler system, one of the most inexpensive, and widely applicable retrofits is replacing jackshaft linkage with a modern parallel positioning system. Switching to a low-NOx burner with configurable NOx emissions prepares your system for tightening NOx regulations without incurring an unnecessary efficiency hit in the meantime. For the truly forward-looking, switching to bio-oil with a compatible burner and pump system can dramatically reduce your facility’s carbon footprint.

A good boiler can last many decades and because boiler technology is fairly mature, replacing one typically only makes sense when the boiler is at the end of its life. The technology surrounding the boiler, however, has changed radically over the last 10 years. In addition, emissions and efficiency requirements will continue to tighten for the foreseeable future. There has never been a better time to retrofit your existing boiler with these modern, forward-looking components. By future-proofing your boiler in this way, you can ensure that it remains in operation for its full lifespan — and significantly reduce operational costs in the process.

Author:

Dan Wallace is Vice President of Research & Development at Preferred Utilities Manufacturing Corp.

Unmanned aerial vehicle (UAV) technology is garnering growing interest in the utility space for its use in asset inspections. Adding imaging or sensing devices to these small aircraft enables improved data collection safety, quality, speed, and cost. With UAV prices dropping, using UAV as part of an integrated enterprise asset management program is becoming easier than ever. Or, is it?

Developing a UAV-capable enterprise is more than simply purchasing the UAV hardware and flying it around assets. Building a culture of adoption for UAV technology requires considerable thought and planning for the people, processes, and technology within an organization. Many utilities have started to explore the benefits of using UAV to support asset inspections but struggle to move beyond pilot projects to develop standardized processes that are a part of their overall enterprise asset management program.

A utility, recently having purchased a rotary UAV, wants to look at several hundred miles of transmission lines damaged after a large storm devastated the area. Although the technology is at hand, no one on the team knows quite where to start: What are the critical assets that need to be assessed, and how do we deploy our teams to start inspecting the damage?

Then, after eventually collecting the asset data using the UAV, an analyst is now sat at her desk, dreading the thousands of images and data points that she has to work through. What asset is that cracked transformer associated to, and where is it? What maintenance and repair follow-up actions are needed now that I have photos and data points on our assets?

“Utilities deploying a UAS have seen considerable improvements in inspection time. Field tests… found that using a UAS allowed them to inspect 20 or more 500 kV transmission towers per day.”

These are the types of scenarios that utilities will begin to face as they embrace these new technologies, and while these may seem like daunting questions to face, embracing the changes to make a utility UAV-capable will bring great benefits.

Meeting Asset Inspection Challenges Head-On

Performing complex asset inspections is a difficult, time-consuming process for utilities. Physical inspections may also present safety challenges and sometimes deliver inconsistent results, dependent on factors such as the inspector experience and weather conditions. Using an unmanned aircraft system (UAS) -especially when inspecting hard-to-access assets such as transmission towers -not only accelerates the inspection process; it eliminates safety hazards for utility employees and standardizes how data is collected and recorded.

Utilities deploying a UAS have seen considerable improvements in inspection time. Field tests with a leading electric transmission and distribution provider in Ontario, Canada, found that using a UAS allowed them to inspect 20 or more 500 kV transmission towers per day; reducing inspection times by over 50 percent, while simultaneously moving personnel away from the high energy system.

Improved asset inspection efficiency enables utilities to realize reduced costs and/or more frequent data collection. More frequent inspections drive better intelligence on asset performance trends over time. Furthermore, the use of UAV governed by automated flight scripting heightens data collection consistency and quality needed for bulk and over-time analyses.

Utilities employing standardized asset models outlining critical facilities and components, as well as their required attributes further improve field data collection by ensuring the right data is captured during each flight. When integrated with the utility’s asset and work management systems, the ability to generate immediate follow-up repair and maintenance work orders, as well as perform bulk and over-time asset performance analysis, is gained. Integrating a UAS solution into a utility’s enterprise asset management system enables the organization to gain a clear, full lifecycle view of asset conditions and performance; informing decisions for overall operations improvements, extending asset life and determining future capital investments.

Implementing a UAS Program

Planning the successful deployment of a UAV-based enterprise asset management program can be thought of in three main components: people, process, and technology.

Engaging the Right Professionals

Engaging the right personnel within an organization is an integral part of creating a holistic UAS program. Clearly defined roles and responsibilities help establish a comprehensive process that will touch many aspects of the utility’s business. Operations professionals within a utility organization, from the C-suite to the shop floor, should be involved when developing this new asset management program to ensure that aspects of business strategy (capital investment planning, and risk management) as well as day-to-day operations (maintenance, safety, analytics, and aviation) are taken into account and incorporated into the standardized inspection process.

Developing a holistic asset management culture, despite what technologies are being used, can be a daunting task. Gaining this level of collaboration often requires the assistance of a third-party expert that can help bring these diverse functions together to best determine how to optimally integrate business operations with an end-to-end UAS solution.

An asset management partner with deep technical and industry knowledge and world-class engineering expertise can help evaluate foundational program components such as:

• Identifying the body of use cases for which the UAS will support
• Adapting current enterprise business processes
• Determining the optimal insourcing and outsourcing of various UAS services
• Selecting staff members to be involved
• Identifying the staff training/certifications needed
  

Defining the UAV Inspection Solution Process

Many industry-leading utilities have invested heavily in improving asset records and automating creation of compliance inspections and maintenance work. Building on this progress, the systematic integration of a UAS solution into this process allows for thoughtful planning of resources and prioritization of work to inspect critical assets.

By using an enterprise asset management system to trigger frequent inspections, mid- and long-term flight planning can be conducted, improving cost and efficiency of inspections, and providing insight into where future capital would be best spent. Planned orders can then be scheduled for pilots and resources. Critical information and a standardized set of forms will outline the specific information to be gathered.

Once the data is collected, where will it go? UAS data integration and management continues to be a challenge for utilities.

Utilities must ensure secure and standardized collection, storage and transfer of structured asset data. Integration of this data into an existing enterprise asset management system can drive future operations, maintenance, repair and inspection work as well as capital business investment decisions.

“While there are many technology options available, in the end, what will benefit a utility most is the ability to integrate UAV-based inspection data into its enterprise asset management system.”

In the ideal asset data collection approach, inspection requests originate from an asset management system and are used to develop an inspection flight plan. The inspection flight gathers images and/or videos based on peripheral UAV attachments, which are securely transmitted in near real-time to a digital form to be completed by a qualified utility technician. Completed inspection forms are saved to a cloud-based data bank. The inspection data is then transmitted back to the utility’s asset management system for storage; enabling condition-based alerts, notifications for upcoming inspection dates, and ongoing asset performance analysis.

Survey results from the 2017 Strategic Directions: Electric Industry Report indicate that 73 percent of electric utilities are capturing asset performance data, but only 35 percent are using that data to inform strategic and tactical investment decisions.

Deploying the Technology

The technology component, of course, encompasses the choice of which UAV hardware and software solution best fits a utility’s needs. Depending on which infrastructure elements are to be inspected, considerations should include UAV range, image and data types needed, and piloting capabilities. Does your utility need high definition aerial photos, 3-D images, methane gas detection, and/or thermal analyses? Requirements will vary between utilities in the electric, oil and gas, telecommunications, and water industries.

For example, power transmission tower inspections operated by pilot technicians are best suited for rotary UAVs that can operate within visual line of sight and allow for repeatable flight plans. Similarly, telecommunications providers use rotary UAVs to perform cell tower inspections that identify tower-mounted equipment and configurations/orientations, structural and dimensional mapping of towers, and verification of transmitter/receiver antenna line systems. Power line infrastructure inspections that must be made over several miles can benefit from a beyond visual line of sight (BVLOS) UAS.

For oil and gas providers, a UAS can help meet economic and environmental requirements for keeping facilities operational and safe. A rotary UAS can monitor pipelines for potential leaks using methane detectors and provide real-time performance data on assets using thermal cameras.

A UAS can benefit water utilities through confined space inspections inside wastewater treatment plants and dams, where accessing tight spaces to perform corrosion analysis can be hazardous to inspectors because of contamination, lack of oxygen, and other environmental factors.

While there are many technology options available, in the end, what will benefit a utility most is the ability to integrate UAV-based inspection data into its enterprise asset management system. One of the keys to the introduction of a UAS capable organization will be a standardized approach and set of processes to manage UAV, regardless of the hardware requirements of the utility.

Scaling Up for Future Operations

It was only three years ago when the Federal Aviation Administration authorized the first utility UAV program for San Diego Gas & Electric. So it’s no surprise that perhaps one of the biggest hurdles for utilities considering UAV use as part of their infrastructure inspection program is understanding and preparing for regulatory and legal ramifications. Depending on geographic location and type of aircraft, policies and requirements will vary. Working with a third-party expert with utility inspection experience can help ensure that compliance requirements are met when planning and executing inspection flights.

Federal mandates concerning the use of UAS technology will likely evolve over time and keeping a close watch on regulations will be critical as utilities scale their UAV-based operations. However, with increased regulatory pressure on these industries, the use of a UAS can also add considerable value to enterprise asset management programs. Lower-cost inspections allow for more frequent and higher quality asset surveys than required for regulatory compliance; allowing a utility to better identify anomalies and review potential risks in targeted locations for more proactive asset management.

With aging assets a top issue for nearly every critical infrastructure sector in the United States, optimizing current asset performance and making intelligent capital investments is a major priority for utility leaders. By focusing on developing the optimal enterprise-wide UAS program, a UAS-enabled utility will be able to make better, risk-based decisions around future asset investments, operations, maintenance.

Authors

David Price is Chief Technology Officer and Associate Vice President, Business and Technology Architecture in Black & Veatch Management Consulting LLC. Nathan Ives is a Managing Director, Business and Technology Architecture in Black & Veatch Management Consulting LLC. Caitlin Frank is a Consultant of Business and Technology Architecture in Black & Veatch Management Consulting LLC.

I have provided environmental compliance support for the power generation industry for almost 25 years. The more I communicate, verbally or in written form, the more convinced I am of the difficulty in doing it well. My job depends on effective written communication with local, state, or federal agencies. Before I begin writing, I focus on four concepts:

1. Effective Communication is hard. Reminding myself of this fact, right off the bat, helps put me in the proper mind set. I didn’t major in English, and I am not a linguist. Like many of us who find ourselves in the unenviable position of writing to an environmental agency, I am an engineer and therefore somewhat challenged in all things non-technical. My dad (who was an English major) almost had a stroke when he discovered freshman English wasn’t even a requirement in my college curriculum. Literary difficulties aside, many common everyday issues make good communication difficult. Differences in beliefs, experiences, understanding, and vocabulary interfere to confuse our message.

2. “Greasing the skids” is an old ship building phrase that means “to facilitate,” or “to help matters run smoothly along the intended path.” Remember that writing a letter to the agency should not be the first step in our efforts to communicate with them. Never surprise them with a letter, and never send them written communication they are not already expecting. There should have been a conversation, a meeting, or a phone call preceding the letter. I use a letter to confirm the understanding, decisions, or actions that were previously agreed upon. Whenever I am communicating with the agency I have a desired result in mind. The bigger the desired result, the more “grease” is required.

3. What is the message? The meat of the message is the story but using a basic construction for the correspondence can significantly improve its effectiveness.

Identification – Clearly identify the facility, the date, and the event. The agency deals with many different events at many facilities. Don’t make them search through piles of old documents or email to try to understand what you are talking about.

Reason for writing – State the reason I am writing, clearly and simply, up front. There are usually only a few basic reasons to write to the agency. It can be to explain an event which occurred, respond to an agency request or notification, document a previous communication (meeting, discussion, etc.), or to update a previous event or communication.

Message – The Story (see below)

Conclusion – “Please contact me if you have any questions.” I like this kind of ending because it’s simple and I don’t want to send the agency something that requires them to respond. Also, if I have done a good job greasing the skids I already know there will be no questions.

“I am an engineer and therefore somewhat challenged in all things non-technical.” – Vincent Dodge. Dynegy

4. Tell a good story. The story is the most important part of the correspondence. It needs to effectively communicate our message to the agency. It needs a theme with a clear, concise, and logical progression that leads the reader to understand and follow to the conclusion we want them to walk away with.

Identify the concepts – Begin by having a clear idea of the overall message we want to communicate, and the pieces or concepts that will get us get there. The list of concepts needs to be as short as possible so that our story doesn’t get too long or go in too many directions.

Know your audience -Know and understand who will be reading the correspondence; Write to their level of understanding, not ours. While it is sometimes important to educate our audience so they understand our story, accomplish this when “Greasing the skids.”

Be concise – Don’t use 200 words if 75 will clearly tell the same story. If it is a response to questions from the agency be careful to clearly respond to all of the questions, but stick to answering the questions only. Don’t include details and information that are not absolutely necessary. Providing unneeded details of an action plan may require follow up correspondence later if minor plan deviations occur.

Don’t create deadlines and requirements – Don’t set deadlines, make promises, or require a response from the agency unless it is required.

Effective written communication establishes rapport with the agency and facilitates compliance.

Tell me if you’ve heard this one before: “EPA is considering proposing emission guidelines to limit greenhouse gas (GHG) emissions from existing electric utility generating units (EGUs) and is soliciting information on the proper respective roles of the state and federal governments in that process, as well as information on systems of emission reduction that are applicable at or to an existing EGU, information on compliance measures, and information on state planning requirements under the Clean Air Act (CAA).”

Those are the words from an advanced notice of proposed rulemaking that EPA released on December 18, 2017. Let’s call it the Clean Power Plan – Trump since, at a very high level, the proposal is similar in intent to what President Obama’s EPA attempted to achieve with the original Clean Power Plan (CPP) in 2014. In 2016, the Supreme Court halted implementation of CPP-Obama before it could take effect, and the Trump Administration has promised to replace it.

In practice, CPP-Trump would likely be quite different from CPP-Obama. Whereas CPP-Obama had an ambitious goal of reducing power plant GHG emissions by more than 30% over 2005 levels by 2030, CPP-Trump appears to be targeting specific efficiency improvements at certain plants instead of large system-wide reductions.

The EPA will undoubtedly receive thousands of comments on CPP-Trump from both sides prior to any form of implementation. It’s pretty safe to say, though, that it won’t be as stringent as CPP-Obama. And while clean power regulations are generally a positive for nuclear, the narrower expected scope of CPP-Trump will not be a silver bullet for existing nuclear power plants.

“The growing patchwork of climate change activities are sustaining the momentum in the absence of national commitment.”

The resurrection (or reincarnation) of CPP got me to thinking about the evolution of climate change regulation. In case you missed it last year, 2017 was the 20th anniversary of the Kyoto Protocol, an agreement reached among industrial nations in late 1997 to slash their GHG emissions. Industrialized nations that signed the Protocol (plus the nations of the European Union) were required to reduce GHG emissions 5% below 1990 levels by 2012; developing nations, including India and China, were asked to voluntarily comply.

Although the Protocol officially went into effect in 2005 when countries representing at least 55% of the world’s GHG emissions ratified it, the Kyoto Protocol never truly reached its promise. The mechanisms developed for implementing the Protocol were challenging, and without participation from the world’s two leading emitters – China and the United States – many countries felt the Protocol was simply unworkable. These concerns limited the global effectiveness of the Kyoto Protocol and ultimately led to the Paris Agreement in 2015, which is decidedly less prescriptive.

Still, Kyoto was a watershed moment. It marked the beginning of substantive climate change dialogue and policy debate on a global basis. Moreover, Kyoto can lay claim to some climate successes, or at least lay claim to a role in these successes. GHG emissions from countries that supported the Kyoto Protocol were more than 20% lower than 1990 levels in 2012 according to the United Nations, far exceeding the 5% target. While other factors were certainly at play in that reduction – such as economic slowdowns, the rapid growth of renewable energy, and the existence of decarbonization policies in some countries – Kyoto initiated a new way of looking at greenhouse gas emissions. Mechanisms were devised for introducing an international carbon market, new techniques were developed for reporting and verifying emissions, and green investment funding schemes gained traction around the world.

Multi-national efforts like the Kyoto Protocol and the Paris Agreement are inherently difficult. Getting hundreds of nations to agree to targets – whether hard or soft – is a complicated political, economic, and emotional tug-of-war. Still, momentum can behave like a nagging parent, not letting an issue go until action is taken.

Perhaps multi-national efforts are simply too difficult. That doesn’t mean action is impossible. The growing patchwork of climate change activities – by cities, states, even corporations – are sustaining the momentum in the absence of national commitment.

Whether these action are ultimately to the benefit of nuclear power is unclear. We’ve seen state-level actions that hold promise for tagging nuclear as a clean energy source. It will be interesting to see in 2018 if those actions are viewed as one-off historical artifacts or if they become momentum builders.

The phrase “doing well by doing good” is often attributed to Benjamin Franklin as the secret to his success as both a scientist and as a diplomat. His autobiography expands on that phrase saying, “As we enjoy great advantages from the invention of others, we should be glad of an opportunity to serve others by any invention of ours, and this we should do freely and generously.” 

Despite being more than 300 years old, this concept of “doing well by doing good” is increasingly applicable in today’s business environment. Companies are realizing that business and social issues cannot-and should not-be mutually exclusive, and they are focused on creating innovative solutions to the social and environmental challenges that the world faces today. Thus, doing well by doing good.

In fact, in a survey by McKinsey & Co., CEOs were asked about the most critical environmental, social and political issues for the future success of their business. One hundred percent of respondents named a social issue that was directly affecting the success of their businesses-whether it be security of the energy supply, technology accessibility in developing regions or other issues.

It’s clear that ignoring social issues is no longer an option for today’s businesses. That’s especially the case for utilities that are increasingly faced with modern-day challenges to their operations and efficiencies. By aligning business issues like improving access to energy, with social issues such as increasing access to the internet, utilities will not only boost business growth, but foster the economic advancement of emerging communities as well-from education to business opportunities, and beyond.

Utilities are faced with a host of challenges that are negatively impacting both their businesses and local economies. For example, non-technical energy loss like energy theft is costing electric utilities billions per year in lost revenues – every year as much as $96 billion is lost worldwide, with $64.7 billion of that in emerging markets, and $6 billion in the U.S. alone. Another roadblock for utilities is outdated energy infrastructure, which is typically being monitored by old software and hardware with a limited ability to anticipate potential problems.

Without the right solution in place to address these challenges, resources are stretched thin and it becomes a challenge for utilities to handle customer needs and complaints, service adjustments, and general system failures.

Additionally, from a social standpoint more than 3.8 billion people worldwide don’t have internet access and internet penetration in developing countries is nearly 1/3 that of developed countries. Research shows that internet and electricity-poor regions have less access to healthcare, education, and overall opportunities.

The business answer is in having utilities look for solutions to build out infrastructure in the right way to optimize power delivery and improve access to the internet. In doing so, they will see efficiency gains, be able to enhance revenues and improve customer service, among other benefits. But, in parallel, they will be addressing important social issues by enabling broader access to a world of knowledge otherwise inaccessible to communities.

In seeking to achieve their business goals, utilities are also opening the doors for those in underserved populations to become empowered to better their future. That’s especially critical in places like sub-Saharan Africa, where more than two-thirds of the population are without access to electricity.

From an education standpoint, a community is empowered to learn, grow, and gain access to new information. In fact, research shows that by extending internet penetration in Africa, Latin America, India and South and East Asia to some of the levels seen in developed countries today would enable an additional 640 million children access to the internet and the information it makes available while they study.

In addition, studies show that there is a strong correlation between country wealth and internet access, with poorer nations such as those in south and southeast Asia and sub-Saharan Africa, having much lower internet rates compared to richer developing countries in Latin America and the Middle East. Without access to internet, early developing nations lose a key competitive ingredient when contrasted against their peers in developed nations. Expanding infrastructure and improving access will, in turn, improve local economies by providing a platform for communities to explore business ideas, conduct competitive research, and support enterprise and innovation.

India and Africa are expected to see sweeping growth over the next few years in the number of internet users.

The number of internet users in Africa has grown by 8,503 percent from 2000-2017-almost twice as much as the next closest region (the Middle East at 4374 percent). Yet, while internet access is improving in South Africa, it still remains behind the global standard.

Aligning business and social issues will help to boost business growth for utilities, while also helping associated communities to expand their economic opportunities-from business, to education, and even healthcare. By improving access to energy (a business concern) and increasing access to the internet (a social issue), not only will utilities improve their business position, but communities will be empowered to tap into the many internet-based resources currently unavailable to them.