Whether it is new construction or replacing equipment during an outage, today’s power plant construction projects place great emphasis on safety, on-time delivery, and budget. No matter the size or scope, these projects require a great deal of pre-planning and coordination in order to execute well and deliver these results. One type of construction practice, modular construction, can enable greater success in meeting these objectives.

Modular construction consists of fabricating and pre-assembling equipment in a shop environment, then shipping these sub-assemblies to the construction site via rail, barge, or truck. Once delivered to the jobsite, these sub-assemblies are bolted or welded together, to form the final piece of equipment. This is in contrast to traditional construction practices that involved shipping pieces of steel, fiberglass, or other materials to site, where they were fabricated and assembled one piece at a time.

Modular construction is not a new process. Other industries have been applying it for decades. For example, homebuilders have been pre-assembling walls and trusses in the factory, instead of shipping bundles of un-fabricated lumber to the home site. This type of process is being applied to power plant equipment like heat recovery steam generators (HRSGs), cooling towers, turbines, boilers, air cooled condensers (ACCs), transformers, and other equipment. It could also include components like stairways, conveyors, piping, electrical and control systems. Several EPCs are leading the modularization effort, and have built power plants with this type of approach. Modular construction is a common practice found in other parts of the world, and has been slowly adopted in the US. There are many benefits to this type of construction practice, but it also introduces some challenges.

Modular construction requires less manpower, because there are fewer construction activities that need to be performed on site. Photo courtesy: SPX Cooling Technologies

Benefits

It has been well-publicized that fewer people are entering into the skilled trades. That is resulting in challenges with staffing a large project, especially those that are located in remote rural areas where power plants are often located. The labor challenges are further strained, if there are multiple contractors on site that require the same skilled trades, and are competing for the same resources. A lack of experienced craft workers creates further challenges. Modular construction requires less manpower, because there are fewer construction activities that need to be performed on site. Also, the nature of the work that is performed on site is different. It greatly reduces the amount of craftsmanship involved with installing a piece of equipment, and replaces it with assembly type work.

Having less labor and fewer activities on site translates into an additional benefit of decreasing the risk of a safety incident. Any work that can be performed at the ground level will be safer and more efficient than doing aerial work where fall protection is required. Modular components are larger and heavier, so safety risks do still exist while handling the equipment. However, there is less cutting, welding, and grinding on site, which are all leading causes of work related injuries.

Modular construction compresses the overall project schedule, since there are fewer activities that need to be performed on site. This can be very advantageous at a busy construction site. It enables other construction activities to start sooner, or be scheduled in parallel, thereby reducing the critical path for completion. Modular construction also reduces schedule variability, since there are fewer construction activities on site. All of this leads to a greater likelihood of meeting the contractual schedule completion dates.

Anyone that has ever been to a power plant construction site knows that space is limited, and having adequate lay down space for material is a challenge. Traditionally, material is delivered to the job site in advance, and stored near the work area. Having materials close to the work area is critical to maintaining productivity. In the staging area, the material is spread out and sorted to find the right items needed for a specific task. This requires lay down space for the duration of the activity, which could be an extended period of time. In contrast, modular components are delivered on a just-in-time basis. This eliminates time spent sorting through materials in storage. In many cases, modular components are picked directly from the truck and placed in their final position, thereby minimizing the need for lay down space. This results in a more organized and productive jobsite because it alleviates site congestion and enables other construction activities to proceed.

Modular construction is of consistently high quality, since the work is performed in a controlled factory setting by experienced employees using automation for fabrication. Any errors or issues that arise during production can be quickly identified and corrected. These sub-assemblies can be stored at the factory and inspected by the customer beforehand. Conducting factory acceptance tests can expedite the inspection and approval process, and further compress the schedule.

The weather can be both a benefit and a challenge for modular construction, especially if the equipment is located outdoors. Since there are fewer construction activities that need to be performed on site, it means that the overall schedule is less susceptible to weather. This is particularly favorable in periods of cold or wet weather. Windy or severe weather, however, can still pose a challenge. When wind speeds exceed 25 mph, it is not advisable to hoist loads with a crane since the wind gusts could shift the load and create safety hazards. Similarly, severe weather or lightning could force all construction activity on site to stop.

The freight cost to transport modular components, which are heavier and potentially oversized, is a significant factor to consider. Photo courtesy: SPX Cooling Technologies

Challenges

Before any component is modularized, it must first be designed for this type of construction practice. In addition to designing for the specific project requirements such as wind load, snow load, and seismic conditions, these sub-assemblies must be pre-engineered for this type of installation. The equipment must be designed into segments, so that it can packaged for shipment. These segments may require additional reinforcement at specified pick points, so that they can be rigged and hoisted at the factory and on site. The size and weight of the sub-assemblies are important factors to consider. The equipment needs to be sized so that it can be handled in the factory and onsite. The weight and overall dimensions are also critical for transport and for handling by the crane. The modular sub-assemblies may require additional braces to stabilize the segments during handling and transport. They may also require additional structural elements to meet stability requirements and achieve robustness. A rigging and crane lift plan should be developed with Engineering, so that the work can be performed safely.

Modular construction is highly dependent on delivering components on a just-in-time basis. When multiple shipments are needed, this requires extensive pre-planning and adherence to a schedule. It also requires coordination between the factory and site. The sub-assemblies need to be delivered in the right sequence and at the right time. That means that any construction activities that must be performed in advance, must be completed on time or the entire schedule will be impacted. It also requires coordination with the EPC or Plant Operator on site, since there could be multiple deliveries by other contractors which could lead to site congestion and delays.

Some of the biggest challenges to modular construction pertain to site conditions. It is critical for the site conditions to be prepared to accept deliveries of modular components. This means that the access roads leading into the plant are unobstructed, clear of other construction activities, and prepared for truck traffic. The roadways must be compacted and graveled to enable passage of a heavy truck. This could be a challenge if rain turns the roads into muddy sinkholes. The heavy truck will find the roads impassable, which could lead to site congestion and delays. The plant access roads also need to be wide enough to accommodate oversized loads if necessary, and accommodate trucks that need to turn and maneuver into position.

Having access for the crane is also critical. The crane needs to be placed adjacent to the work site, so that components can be offloaded and installed in their final position. Here too, the area needs to be compacted and graveled so that the crane is on solid footing. If crane access is not possible, then larger cranes with a longer reach are needed to pick and place the equipment. While this is possible, larger cranes do add cost to the project.

Costs

The costs for modular construction are highly dependent on several factors, and these can determine if the overall cost is greater than or less than traditional build. The breakdown of these costs will vary by type of equipment, manufacturer, and location, but here is a general overview.

The material costs for modular construction could be marginally higher, since additional material may be needed to engineer the sub-assemblies as mentioned above. The labor costs to fabricate these modular sub-assemblies in the shop will vary by equipment manufacturer, and is dependent on shop labor rates. The savings depends on the difference between the shop labor rates and field labor rates. The greater the difference, the more savings for modular construction.

The freight cost to transport modular components is a significant factor to consider, especially if there are multiple shipments. The freight cost is highly dependent on the distance to the job site, mode of transport, and number of shipments. The cost per truck to ship pre-assembled components is often greater than shipping just raw material because the loads are heavier and potentially oversized. Transporting oversized loads introduces many challenges and costs. The regulations vary by state, so it is important to check with each state’s Department of Transportation (DOT) to ensure that the shipment is in compliance.

Additional permits may be required for oversized loads depending on the dimensions. An escort for the trailer may be required for loads exceeding 12ft or more (varies by state). Oversized loads can only be hauled on routes that have been pre-established with the DOT, and must abide by blackout times and days. Also, oversized loads cannot be shipped via rail or intermodal transport.

Loads that are extremely heavy or tall cannot be hauled by conventional trailers, and require specialized Heavy Haul trailers, or low boy trailers. There are fewer trucking companies with specialized trailers, so costs for that type of equipment will be greater than standard 48ft flatbeds. While barge transport can be used to haul large heavy loads, it is limited to where it can be applied. Many plants are located inland, and are not accessible by barge.

At the job site, a compressed schedule should result in a reduction of overhead costs for site supervision, administration, construction trailers, and equipment rental. Since there are fewer construction activities that need to be performed on site, it should also result in a reduction of direct labor costs. It is important to consider the size of equipment like forklifts and cranes. Although there may be fewer components to handle with modular construction, the components will be larger and heavier. Therefore, larger forklifts and cranes may be needed, which could be a significant expense.

The costs for material, shop labor, and freight are all predictable and manageable. The cost for field installation introduces the greatest risk, regardless of whether it is constructed in traditional or modular fashion. Modular construction can minimize that risk, but variability is still possible.

Conclusion

Modular construction practices can dramatically improve efficiency in new construction or outage projects. It addresses today’s construction needs and results in many benefits for the original equipment manufacturer (OEM), EPC, and power plant operators, but it also introduces some challenges. Understanding the benefits and challenges enables the entire team to plan for them upfront. This pre-planning effort is critical for the project to succeed.

Author:

Andjelko Piskuric is a Sr. Global Product Manager with SPX Cooling Technologies.

by Bonnie Marini, Phd

Power plant technology has come a long way in the last decade. New demands in the market, combined with the increased capabilities of today’s fossil fired power plants make comparing and choosing the right technology much more complicated than in the past. There is a lot of discussion on how new technology differs from conventional technology – but the real challenge is determining how today’s technologies compare with each other.

As we look to a future with more weather dependent renewable generation, many of the new fossil fired power plants will be built primarily as firming power – dispatching when renewables are not available and turning down or off when more renewable generation is available. One significant change in market options is the speed and responsiveness of combined cycle power plants. There are several fast-start combined cycle options now available, offering different operational styles and benefits. One key differentiator is how these various plants start.

The first fast-start combined cycles in the U.S. were commissioned in California. These plants introduced the concept of enabling a gas turbine to ramp to base load without a low load hold point. The first advantage to be seen was the tremendous reduction in start-up emissions. NOx and CO production dropped about of 90 percent. Features and capabilities have since been added to this product line so the rest of the cycle can start fast as well. One of the additions is the Co-Start option. With Co-Start the steam turbine starts very soon after the gas turbines, ramping to base load quickly, and depending on plant configuration, enables full plant power in about 30 minutes .

Other providers have also started to offer flexible, fast-start combined cycles, but with different start up scenarios. In these plants the gas turbine is ramped to minimum emissions compliance load(MECL) before reaching the first hold point. The subsequent start procedure is much like a conventional combined cycle, combining a series of holds and ramps to gently warm up the steam cycle. This start offers the same advantage in NOx and CO emissions reduction as the Flex-Plant, but it does not produce as much power as a Flex-Plant in early operation.

The high dispatch efficiency of the Irsching Combined Cycle Power Plant in Germany leads to lower CO2 emissions and the flexibility required to firm renewables. Photo courtesy: Siemens Energy

If the goal is purely reduction in start-up NOx and CO, these options are comparable. However, start-up emissions is only a very small part of the overall advantage fast-start combined cycles can offer.

When plants start and stop often, the cost of the start-up transient can become a significant lever in a plant’s profitability. Automakers are ahead of the power industry when it comes to providing simple, understandable information which clearly explains the benefit of automobiles designed to start and stop efficiently versus those that aren’t. Suppliers publish city gas mileage and highway gas mileage. It doesn’t take a technology expert to understand that if you use your car for short trips, city mileage is more important.

When power industry owners evaluate base load efficiency or heat rate, it is like evaluating you car’s mileage expectation from the highway gas mileage number alone. In today’s markets, where stopping and starting regularly is expected, the power generation industry should also be looking at a version of automobile city mileage, and this can be analyzed by looking at a plant’s dispatch heat rate instead of the conventional base load heat rate.

Heat rate is the result of a calculation of the amount of fuel needed to create a kilowatt-hour of electricity, typically at baseload. Heat rate is a practical expression of plant efficiency, using the units common to fuel purchase for the numerator, and the units common for electricity purchase for the denominator. (Efficiency is the dimensionless inverse of heat rate.)

Dispatch heat rate looks at these same parameters over the full dispatch time. To calculate the dispatch efficiency, the total amount of fuel needed for a given dispatch window is divided by the amount of electricity generated. The key difference between dispatch heat rate and a conventional heat rate is the fuel consumed to start and stop, and the reduction in efficiency during the entire transient are included in the dispatch heat rate calculation. The longer the plant is at part load, and the further it is from the design load, the lower the cycle efficiency and the more fuel the plant will use over the dispatch window. For example, if the plant is going to dispatch for 8000 hours continuously, one annual start, ramp and stop sequence has a negligible impact. However, if the plant is going to dispatch for 8 hours at a time, the dispatch heat rate can substantially impact the profitability of the facility.

To demonstrate the difference between conventional heat rate and dispatch heat rate, the chart on this page compares the dispatch heat rate for an H-class combined cycle to a Flex-Plant with Co-Start. The fast-start combined cycle which ramps to MECL reaches emissions compliance fast, but does include load hold points to warm the cycle up slowly. The Flex-Plant with Co-Start ramps the gas turbine to base load at its full ramp rate and the steam turbine follows shortly after.

As shown in Figure 1 on page 26, the difference in dispatch heat rate and conventional heat rate is dramatic. For a 12-hour operation window the dispatch heat rate for the Co-Start plant is about 100 BTU/kWh better than the alternative. For an 8 hour dispatch the benefit goes up to 150 BTU/kWh. This results in a very significant impact on the actual cost of generation for plants that respond to variable demand.

Dispatch Heat Rate vs. Conventional Heat Rate

A financial analysis was done for an H class 2×1 combined cycle plant to quantify the benefit of Co-Start capability. This analysis showed a 51-percent reduction is hot start cost, a 49-percent reduction in warm start cost, and a 35-percent reduction in cold start cost. For a plant with a duty cycle of a daily starter with 200 hot starts, 50 warm starts, and 10 cold starts per year, the estimated impact on NPV is a savings of more than $28,500,000.

The reason some plants are not designed for Co-Start is that this requires changes in the design of the balance of plant equipment and thoughtful integration of the entire cycle. The elimination of the series of holds enabling early dispatch of the steam turbine requires downstream equipment to have a more flexible design – and that starts with the boiler.

One way to eliminate the cyclic limitations in a combined cycle is to use a Benson once through boiler. In a conventional boiler, there is a high pressure drum which is a thick walled structure that expands and contracts with changing temperature. This drum is attached to thin walled tubes which are expanding and contracting at a different rate than the drum. The result is limited cyclic life. If those subcomponents change temperature too quickly or too frequently, low cycle fatigue induced cracking will occur.

In a Benson boiler the high pressure drum is eliminated. The critical life-limiting design element does not exist and the cycle can be ramped quickly without exceeding the design life of the boiler.

Benson boilers offer significant benefits in flexibility and have been proven for more than 18 years. There are more than 50 Benson boilers successfully operating in combined cycles around the world, but the flexibility of the Benson is only part of its advantage. The second benefit is the capability to enable high part-load combined cycle performance.

When operating a combined cycle at part load, the exhaust temperature out of the gas turbine typically rises. In a conventional boiler this higher temperature can result in overheating of superheater tubes in the boiler. The ability to control flow in the superheater is limited in these boilers, so to avoid overtemperature conditions, the steam is attemperated by injecting cool water into the steam. This reduces the temperature of the steam, mitigating the risk of tube overtemperature. However an undesirable consequence of this attemperation that some higher grade energy is transferred into lower temperature parts of the bottoming cycle. This results in lower part load efficiency.

Lodi Energy Center in California is another example of fast start Benson technology. Photo courtesy: Siemens Energy

In a Benson boiler, the need for attemperation is eliminated. There is no high pressure drum, so temperature in the superheaters can be managed by adjusting the flow into the evaporator. If gas turbine exhaust temperature rises, superheater flow increases and an overtemperature condition is avoided.

With a Benson boiler, eliminating the need for attemperation results in higher part load efficiencies, further enhancing the dispatch heat rate for these configurations.

Co-Start capability reduces start up NOx and CO, and improves dispatch efficiency. Co-Start also provides the added benefit of reducing greenhouse gas production. Lower fuel usage means less CO₂ production, so these plants are cleaner when they start, cleaner when they run, and more economical to operate.

Plants like the Ullrich Hartmann combined cycle in Germany demonstrate this. This power plant broke the world record for combined cycle base load performance and was the first combined cycle in the world to exceed 60 percent net combined cycle efficiency. This same power plant can put 500 MWs on the grid in under 30 minutes. The high efficiency and high dispatch efficiency result in a low CO₂ technology with the flexibility to firm renewables. This enabling benefit for renewable generation is also a contributor to a greener grid with high reliability.

Start Up Costs

The combined cycle solution offers the benefit of being a good fit for fluctuating demand and a good fit for base load.

Lodi Energy Center in California is another successful example of fast start Benson technology. Operating since 2012 this plant can ramp the gas turbine to base load with no hold points, enabling a dispatch heat rate much lower than either simple cycles or combined cycles without this capability. This highly efficient, flexible plant is also used to firm California’s expanding renewables portfolio.

The exciting fact about the latest generation of combined cycles is that you don’t have to choose between high base load efficiency and high dispatch efficiency. Today’s plants can start fast, load change quickly, hold emissions compliance at low load, and operate at high efficiency through a broad power range.

While the examples discussed look at a large combined cycle, this fast-start technology is available in a broad range of combined cycle plants, with power ranges from under 150 MW to plants well over 1000 MWs. The capability is primarily enabled by equipment outside the gas turbine, with technology like the Benson boiler which is in use in large and small plants around the globe.

Boiler Comparison

While there is a high level of interest in flexible technologies, determining the economic value of flexibility has been a challenge in the past. Introducing the simple concept of dispatch efficiency, like city gas mileage, to the power industry may be a simple way to help financial analyst make better choices for the bottom line and the environment of the future.

Author:

Bonnie Marini is director of Product Line Management at Siemens Energy

During the period of large power plant construction in the last century, fresh water was plentiful and was typically the choice for plant makeup. Once-through condensers were common, with a river or fresh-water lake/reservoir as the source. Now, however, environmental regulations have essentially eliminated once-through cooling at new plants, with the replacement being cooling tower-based systems, or in some cases air-cooled heat exchange. Cooling tower operation and chemistry have been well established for decades, but the industry is seeing a significant shift towards alternate makeup water supplies.

One increasingly common replacement is effluent from publicly owned treatment [sanitary wastewater] works (POTW), while occasionally it might be deep-aquifer groundwater. The complex chemistry of these alternative supplies, combined with the fact that impurities “cycle up” in concentration in cooling towers, makes for extremely challenging water treatment and chemistry control issues. But, project developers at times seem to be unaware of these challenges and either implicitly or sometimes even explicitly conclude that “water is water,” and do not install necessary pretreatment equipment. Severe difficulties may arise from this mindset.

What Are the Problems?

Many decades of power and industrial plant operation have shown that impurities, even in seemingly moderate levels, can cause serious problems in cooling water and other systems if not reduced in concentration or if the system is not chemically treated in a proper manner. Several well-known issues are highlighted below.

• Microbiological Fouling: Cooling systems provide an ideal environment for microbiological growth. Without a well-designed and carefully-operated biocide system, microbes can foul heat exchangers, cooling tower fill, and other equipment. This leads to serious loss of heat transfer, potential under-deposit corrosion of metals, and sometimes even structural failure in cooling towers. Microbiological fouling has historically been the most prevalent problem in cooling systems.
• Condenser Tube Corrosion: Deposits on condenser tubes can serve as sites for localized crevice or pitting corrosion. 304 and 316 stainless steel have served as common tube materials, but it is now known that crevice corrosion can occur with as little as 200 ppm and 400 ppm of chlorides, respectively, in the circulating water. These chloride concentrations may easily be exceeded in cooling tower-based systems, especially if even semi-brackish water serves as the makeup.
• Scale Formation: A number of constituents in raw water can form scale when concentrated in cooling towers (and sometimes even in once-through) systems. Most notable is calcium carbonate (CaCO₃), but others include the phosphate, sulfate, and silicate salts of calcium and magnesium. Other potential deposition products include iron and manganese oxides. Manganese may be particularly problematic, as upon deposition it can induce galvanic corrosion at the deposition site.
• Wastewater Discharge: Plant discharge regulations are becoming increasingly stringent because individual states have the authority to establish discharge guidelines beyond those of the EPA. Previously, the four primary impurities in discharge guidelines were pH, total suspended solids, oil and grease, and residual oxidant (biocide such as chlorine or bromine). Additional impurities now appearing in NPDES (National Pollutant Discharge Elimination System) permits include; total dissolved solids, sulfate, chromium, zinc, copper, iron, phosphorus (phosphate), and ammonia.

Issues with POTW Effluent

Consider Table 1, a snapshot analysis of municipal wastewater effluent from a location in the U.S.

TOC = Total organic carbon
TSS = Total suspended solids

Let us examine briefly how several of the elevated constituents in this water would influence cooling water chemistry and wastewater discharge, primarily cooling tower blowdown.

First, as is clearly evident the chloride concentration is already at a value that could potentially influence crevice and pitting corrosion in 304 SS condenser tubes. Consider if the cooling tower operated at a modest four cycles of concentration (COC). The maximum chloride level would then exceed 1,400 mg/l. With few exceptions chloride salts are extremely soluble, and standard precipitation processes (clarification) will not remove the chlorides. Reverse osmosis will, but this is often a prohibitively expensive method for high-volume cooling system makeup treatment. The most practical option is selection of more corrosion resistant materials than 304 or 316 SS. Two popular alternatives are Seacure and titanium.

Second, note the elevated ammonia, phosphate, and TOC concentrations. Ammonia (in some POTW streams a significant portion of the ammonia nitrogen has been oxidized to nitrites and nitrates) and phosphorus serve as nutrients, and TOC as food, for microorganisms. As the author can directly attest, microbiological control even in once-through systems supplied with fresh water is, at times, a challenging task. Nutrients and food cycled up in a cooling tower greatly increase the potential for microbial development. Several critical design and operating issues arise from use of such waters, including:

• The combination of nutrients, food, and in this case also elevated suspended solids, could prohibit the use of film fill in the cooling tower. Rather, much less efficient splash fill might be required, but this selection significantly increases the size of the tower, and can literally add millions of dollars to the cost of a large tower.
• Control of microbes becomes quite complicated and requires sophisticated chemical feed. The common biocide for fresh water applications is bleach (liquid chlorine) or bleach-activated bromine. Both are oxidizing biocides. Ammonia irreversibly consumes chlorine, while organics react with chlorine and bromine to form halogenated organic compounds, which are troublesome due to potential carcinogenic properties. An alternative to bleach or bleach-activated bromine is chlorine dioxide, but this chemical must be generated on-site and is more expensive than bleach. Also expensive are the non-oxidizing biocides that serve as supplements to the oxidizers. Another troubling factor is that biocide feed at most plants is limited to two hours per day, which gives microbes a large window to colonize on surfaces and secrete a protective film before the next dose of biocide. Once biofilms become established, they are difficult to remove. The film (slime) establishes sites for crevice and under-deposit corrosion and reduces heat transfer in condensers. Loss of heat transfer is further exacerbated by the slime’s tendency to collect silt.
• Ammonia and phosphorus limits continue to appear with increasing frequency in discharge permits at power plants and many other industries. Ammonia in even relatively small concentrations (1 mg/l or so) is toxic to aquatic organisms, while phosphorus is to blame for numerous toxic algae blooms in receiving bodies of water around the country. Design of a plant without provisions to remove these constituents could be saddled with uncertainty if regulatory officials decided to include the impurities in the discharge permit.

What Can Be Done with These Raw Water Impurities?

Consider first a makeup water supply with substantial concentrations of common dissolved solids such as hardness (calcium and magnesium), bicarbonate alkalinity, and perhaps silica. While these impurities are the precursors for scale formation in cooling systems, the levels can be greatly reduced by traditional treatment methods such as lime or lime/soda ash clarification. Many readers are no doubt familiar with the large, circular clarifiers that are still common at municipal water and wastewater plants.

Condenser tube sheet and tubes coated with slime and entrained silt.

These clarifiers can be effective for pretreatment of industrial plant makeup, but footprint issues are often of concern. A common measuring stick of clarifier capacity is the rise rate. Rise rate is the flow of the water at the surface (gallons per minute, gpm) divided by the surface area of the water at the clarified water overflow. A typical rise rate for standard, circular clarifiers is around 1 gpm/ft². Much more modern systems are now on the market that have rise rates of perhaps 25 gpm/ft², or even greater. Often these are of rectangular rather than circular design with a rapid mix zone, reaction zone, and clarifier in series. Space does not permit a discussion of the various designs in this article, but some include continual feed of a ballasted material to the reaction zone to improve solids settling, and to dampen the effects of flow and chemistry changes. Others use sludge recirculation from the clarifier to provide bulk material in the reaction zone. A word of caution, however. Controlling chemistry in these systems is not a case of turning on the unit and walking away. Lime and lime/soda ash softening in a clarifier produces a sludge containing large quantities of precipitated solids, mostly calcium carbonate but often with magnesium and silica salts included. The author and colleagues have seen this precipitation occur too rapidly in the reaction zone and clog this vessel before the solids reached the clarifier. Also, either under-feed or over-feed of coagulating and flocculating chemicals can lead to carryover of solids from the clarifier to downstream equipment.

We will now move to a key question of this article, “What pretreatment can be installed to remove POTW impurities that would pass through a clarifier?” As we have seen, ammonia and nitrite/nitrate are problematic impurities. Many organics that do not get caught up in the clarifier precipitation process will also pass through. These contaminants are then free to cause fouling in the plant cooling water system and other equipment. This is where several biologically-based technologies can come to the rescue. We will briefly review two of these technologies, membrane bioreactors (MBR) and moving bed biofilm reactors (MBBR).

In its most simple form, an MBR can be thought of as an activated sludge process on steroids.

In this very basic design, the influent stream is mixed with return sludge and then flows to the activated sludge zone. The suspended solids are free-floating, and are loaded with microorganisms that consume the food and nutrients in the influent. The term activated refers to the oxygen that is introduced via air blowing into the vessel. The activated sludge vessel is obviously an aerobic zone and thus supports microorganisms that use oxygen for metabolic processes to consume nitrogen and organics. As we shall see, this design may not provide all of the treatment needed.

Diagram of a Sludge Blanket Clarifier.

Chemicals mix with the inlet water in a rapid mix zone, flow upwards and outwards to the inner cone where flocs form, and then settle as a sludge blanket in the main body of the clarifier. Mature particles help to capture newly formed floc coming from the inner cone. Illustration courtesy: ChemTreat, Inc.

A key feature of these systems is treatment of the MBR effluent with micro- or sometimes ultrafiltration membranes (MF and UF, respectively), placed within the vessel. MF or UF essentially removes all suspended solids, resulting in a very clear effluent that can then be distributed to downstream equipment for further processing. Of course, a key aspect of employing MF or UF membranes in this application is keeping them clean. The solids in the MBR, commonly termed as the mixed liquor suspended solids (MLSS), can reach levels of several thousand ppm. This is much greater than in fresh water filtration applications. One method to keep membranes clean is periodic air scouring, which not only blasts accumulated material off the membranes but adds oxygen to the process.

MBR can reduce ammonia, organics, and phosphorus content to low values. A difficulty with the design shown above is that in this simple aerated system, ammonia (NH3) is converted to nitrite (NO₂) and nitrate (NO₃) in a process known as nitrification. But even though the ammonia concentration is greatly lowered, the nitrogen remains, albeit in an oxidized form. Thus, the nitrogen is still available as a nutrient to feed potentially troublesome microbes in cooling water systems and elsewhere. MBRs can be designed with anoxic and anaerobic treatment sections. The decreased oxygen concentration in these zones allows other beneficial microorganisms to proliferate, including denitrifying bacteria, which convert the nitrites and nitrates to elemental nitrogen that then gasses off to the atmosphere. Phosphorus removal is also enhanced in these more sophisticated systems.

Fundamental MBR Process

An alternative to the MBR process is MBBR, in which the activated sludge zone contains thousands of small plastic media to give microorganisms sites to attach and then do their work.

Some readers may be familiar with trickling bed wastewater treatment, where the microbes grow and establish colonies on fixed substrates. This gives them a stable platform to do their job. The media in an MBBR provide a similar function, but the constant agitation better exposes the media and attached organisms to the suspended solids.

Like MBR, several reaction vessels may be placed in series, with sludge recirculation included, to achieve the desired nutrient and organics removal. However, placement of MF or UF membranes within the vessels is not possible, but rather an external filtration system is required.

MBBR Suspended Medial Illustration

Illustration courtesy of Veolia Water Technologies.

Operating These Systems at a Leanly Staffed Plant

A trademark of the combined cycle power industry is to operate lean and mean. But, too much “leanness” can have enormous drawbacks due to staff that is not properly trained when it comes to monitoring steam generation chemistry and operating water treatment systems.

The systems outlined above may be quite daunting to plant management and operators. A possibility to consider is that the major reputable suppliers often offer equipment setup and operation on a build, own, operate, and maintain (BOOM) status. Yes, the plant must pay an annual fee for the contract, but it relieves plant personnel of all duties regarding operation of the system and allows them to focus on making power. Personnel can also rest easier knowing that the plant’s water treatment systems are protected from impurities that could cause major problems. If nothing else, minimization of microbiological fouling can be paid back in huge dividends. Alternatively, plant personnel can consider purchase and installation of a permanent system, but at the POTW rather than the power plant. This would place the system in the hands of personnel who are much more familiar with these processes.

Author

Brad Buecker is a senior process specialist in the Water Technologies group of Kiewit Engineering Group Inc.

Carbon dioxide (CO₂) constitutes the largest fraction of greenhouse gases, which are widely believed to be a major contributor to climate change. Even though some coal projects in India and China have been halted and the projected renewables share of the global energy mix by 2030 is expected to grow, fossil fuels will be a significant source of electric generation-about 44 percent. These trends show there is still more to be done if we are to achieve significant reductions in global carbon emissions.

There is a method (patent application pending) for efficient and cost-effective removal of CO₂ from a gas turbine combined-cycle power plant. The proposed solution applies two techniques in an innovative manner: high supplementary firing in a heat recovery steam generator (HRSG) and recirculation of a portion of its stack gas. The advantage of the invention is to reduce the CO₂ capture penalty-power diverted away from generation-by almost 65 percent and the overall capital cost ($/kW) by about 35 percent. For a power plant with CO₂ capture rated at 800 megawatts electrical (MWe), this translates into significant reduction in capital cost while producing 75 MWe extra power output. The end result is significant reduction in carbon footprint in the most cost-effective manner. Before discussing the new technology in more detail, let us evaluate how carbon capture takes place presently.

Current Post-Combustion Capture Methods

To date, post-combustion CO₂ removal from the stack gases via deployment of aqueous amine-based absorber-stripper technology is the only commercially available option, which is applicable to new units as well as to retrofitting the existing plants and has been demonstrated in several pilot projects. The stack gas of a modern gas turbine combined cycle (GTCC) power plant with advanced F, H or J class units contains about 4 percent CO₂ by volume at near-atmospheric pressure (about 4.5% on a dry basis). Low flue gas pressure and density result in large volume flows requiring large piping, ducts and equipment, which are reflected in plant footprint and total installed cost. The only commercially available absorbents active enough for recovery of dilute CO₂ at very low partial pressures are aqueous solutions of alkanolamines such as monoethanolamine (MEA), diethanolamine (DEA), methyl-diethanolamine (MDEA) and the newly developed sterically hindered amines (e.g., piperazine).

In a fossil fuel-fired power plant with post-combustion capture, a continuous scrubbing system is used to separate the CO₂ from the flue gas stream by chemical absorption. As shown in Figure 1, the system consists of two main components:

• an absorber in which the CO₂ is removed, and
• a regenerator (stripper) in which the CO₂ is released in a concentrated form and the solvent is recovered.

Carbon dioxide capture from flue gas via aqueous amine-based absorption

Prior to the CO₂ removal, the flue gas (at around 90°C at the heat recovery steam generator stack for the most efficient GTCC power plants) is typically cooled to about 50°C (e.g., in a direct contact cooler or “quench tower”) and then treated to reduce particulates and other impurities, which would otherwise cause operational problems and costly loss of the solvent. The solvent absorbs the CO₂ (together with traces of NOx) by chemical reaction to form a loosely-bound compound. A booster fan is requisite to overcome the pressure loss in the capture plant and is a significant power consumer.

The largest power reduction caused by the CO₂ capture system is due to the large amount of heat required to regenerate the solvent. The temperature level for regeneration is normally around 120°C. This heat is typically supplied by steam extracted from the bottoming cycle and reduces steam turbine power output and, consequently, net efficiency of the GTCC significantly. In addition, as for all other carbon capture technologies, electrical power is consumed to compress the captured CO₂ for transportation to the storage site and injection into the storage cavern.

Technologies for gas sweetening and syngas purification using alkanolamines and other absorbents have been extensively utilized in chemical process industry (CPI) over the past century. Nevertheless, large-scale recovery of CO₂ from flue gas poses several serious challenges. Most important of these challenges (in a GTCC context) have already been mentioned: low CO₂ partial pressure and high regeneration energy. In addition, oxygen in the flue gas (about 12percent by volume at the HRSG stack) can cause corrosion and solvent degradation. Due to the absence of many impurities, which are amply present in coal-fired power plant flue gases, e.g., SOx (negligible), soot, fly ash, and mercury, the only significant degrading agent to worry about in GTCC flue gas is oxygen. While inhibitors have been reasonably effective in mitigating these effects, the need for continuous removal of unavoidable solution contaminants adds to the operating costs.

Table 1 shows performance and cost impact of a post-combustion absorption system with MEA. Performance (efficiency and output), and cost data was calculated and estimated based on its wide use in CPI applications, albeit at much smaller scales. The original (base) case is a state-of-the-art GTCC power plant (note the vintage, ca. 2000). Construction of a new plant based on existing technology is assumed. The difference in plant size chosen in the studies made by IEA GHG and SINTEF and inflation (at least to some extent) should be responsible for the differences in the specific investments. (The former obviously uses a 2x2x1 GTCC as a basis whereas the latter uses a 1x1x1 configuration.) Nevertheless, the economies of scale between the two, 410/625 = 0.656, is too optimistic. Based on the published budgetary prices, 0.9 seems to be a more appropriate factor. In other words, the “original” GTCC specific investment for the IEAGHG (year 2000) plant in Table 1 would, in all likelihood, be around 550 €/kWe. This would imply a with-capture cost of (790/410) x550 = 1,060 €/kWe.

Comparisons

Comparison of efficiencies and costs for post-combustion CO2 capture from natural gas fired power plants

To summarize, in a natural gas-fired GTCC framework, post-combustion CO₂ capture plant design challenges are as follows:

– to minimize regeneration energy by selecting a solvent with a relatively low reaction energy
– to use the lowest possible exergy steam extraction to provide the requisite energy
– to cool the gas turbine exhaust gas to the lowest possible temperature in the HRSG
– to maximize the CO₂ content of the HRSG stack gas

Proposed Solution

The solution that addresses these challenges proposed herein meets three key design challenges of post-combustion CO₂ capture from the stack gas of a GTCC power plant using aqueous amine-based scrubbing method by offering the following:

– Low HRSG stack gas temperature
– Increased HRSG stack gas CO₂ content
– Decreased HRSG stack gas O2 content

This is achieved by combining two bottoming cycle modifications in an inventive manner:

– High supplementary (duct) firing in the HRSG
– Recirculation of the HRSG stack gas

A detailed system diagram is shown in Figure 2. This diagram is used to explain the key features of the GTCC with carbon capture (henceforth GTC4) per the earlier discussion and how they are implemented to result in a final coherent system. Furthermore, a detailed sample calculation with all the pertinent numbers will be presented in the following section to demonstrate the significance of GTC4 vis-à -vis current state-of-the-art.

System diagram of the GTCC optimize for carbon capture

The gas turbine combined cycle system of GTC4 comprises the following major components:

(i) Main gas turbine generator (Main GTG)
(ii) Single-pressure HRSG with reheat and supplementary firing.
(iii) Steam turbine generator (STG)
(iv) Recirculation gas turbine generator (Recirculation GTG)

Main GTG, HRSG, and STG comprise the current state-of-the-art in terms of gas turbine combined cycle plant arrangement. HRSG stack gas is forwarded to a post-combustion carbon dioxide capture plant (CCP).

The proposed system, GTC4, is based on the diversion of a portion of HRSG stack gas from the CCP. Diverted gas is mixed with ambient air cooled in a heat exchanger (i.e., evaporative cooler, electric chiller, etc.). The remaining gas is forwarded to the CCP. The combined air-gas flow is the motive air of the recirculation GTG, which generates further electric power. The exhaust gas from the recirculation GTG is mixed with the exhaust gas from the main GTG. The combined exhaust gas enters the HRSG and its energy is increased by the duct burner. The rest of the steam cycle is similar to the current state-of-the-art.

The carbon capture plant can be based on any post-combustion capture technology and has the following features:

• It is inclusive of CO₂ compression and conditioning for pipeline transportation to the final storage or usage location (e.g., sequestration cavern, oil field for enhanced oil recovery, etc.).
• It includes electric motor-driven equipment such as compressors, pumps, etc., whose power consumption is debited to the gross power generation of the GTCC power plant.
• It utilizes steam at specified pressures and temperatures to provide energy requisite for capture processes (e.g., the reboiler of the stripper/regenerator column of the aqueous amine-based capture plant in Figure 1).

Steam requirements of the CCP are met by steam extracted from suitable locations in the bottoming cycle of the GTCC, e.g., the HRSG and/or the STG. One example is low pressure steam extraction from the STG, which is shown in Figure 2. Another option is to supply the low pressure reboiler steam from an auxiliary boiler. Final selection is subject to a cost-performance trade-off and operability impact study, which can be done on a case-by-case basis.

The recirculation GTG supplementary air flow requires cooling for optimal gas turbine performance. This is especially important for plant operation on hot days. The inlet cooler in Figure 2 can be an evaporative cooler, which is projected to be the most cost-effective option in most cases. However, it can also be one of myriad possibilities including electric chiller, absorption chiller (utilizing steam or hot water extracted from the HRSG or the STG) among others. The final selection should be determined on a case-by-case basis via diligent cost-performance trade-off.

Recirculation GTG can be identical to the main GTG (most likely to be the ideal configuration) or it can be of a different type and size. The final selection should be determined on a case-by-case basis via diligent cost-performance trade-off. Gas turbine fuels can be of the same type (e.g., both natural gas) or different (i.e., one natural gas and the other distillate).

Similarly, the HRSG duct burner can use the same fuel as the GTGs or a different one.Other important design parameters and decisions subject to optimization are the duct burner exit gas temperature, the location of the duct burner and the HRSG stack gas recirculation rate (commonly referred to as exhaust gas recirculation, EGR).

Higher EGR, although beneficial from a stack gas CO₂ and O2 content perspective, results in warmer motive air for the recirculation GTG (plus with reduced O2 for the combustor). The discussion herein is based on calculations with 30 percent EGR. This is believed to be roughly the optimal rate. Nevertheless, a diligent optimization study is requisite to pin down the best EGR rate on a case-by-case basis.

EGR is being considered by one OEM for their next-generation gas turbines with 1,700°C turbine inlet temperature (TIT) to reduce NOx emissions. In the system adopted by that OEM, recirculated HRSG stack gas, after being cooled and mixed with ambient air, is admitted into the compressor inlet.

Tests have been conducted in full-scale combustors at medium and high pressures to demonstrate operability and NOx reduction capability with up to nearly 30 percent EGR. Another OEM has also demonstrated the effect of EGR on operability, efficiency, and emission performance under conditions of up to 40 percent EGR. Recirculation GT compressor and turbine operability considerations due to changing gas composition and molecular weight should be evaluated by the OEM at the detailed design phase.

Performance and Cost

The significance of the GTC4 is its immense capital cost benefit of about $200 million (nominal 750 MWe net), which makes it quite attractive even at expensive fuel gas (at the same net MWe output).

The advantage of the system is demonstrated by detailed heat and mass balance simulation of the power block (using Thermoflow Inc.’s Thermoflex and GT PRO software) and the amine-based post-combustion capture system (using ProMax v3.2 with a hypothetical amine of 50 percent(wt) MDEA and 5 percent (wt) Piperazine). Comparison of GTC4 cost and performance with those of a base GTCC is summarized in Table 2.

Performance and Cost

Post-combustion capture performance and cost data for the proposed system. Base GTCC is two 1×1 plants with the same main GTG (served by one large CCP).

In particular, GTC4 has the following advantages

– $182 million lower installed cost
– 25+% lower specific cost ($/kW)
– 15+% lower capture penalty (relative basis)

Note that there is a variant of GTC4 (not discussed herein but included in the patent application), which can reduce the capture penalty by 65 percent (relative basis) with the same specific cost advantage. The benefits of GTC4, vis-à -vis state-of-the-art GTCC with conventional post-combustion capture, can be enumerated as follows:

• Higher CO₂ concentration
  • Faster reaction kinetics
  • Lower regeneration energy per mole of CO₂ captured
• Lower O2 concentration
  • Reduced solvent degradation
  • Reduced reclaiming need
  • Reduced solvent consumption
• Lower HRSG stack gas temperature
  • Reduced booster fan power
  • Reduced direct-contact cooler (DCC) duty
• Lower volume flow (per unit energy)
  • Smaller duct, DCC and absorber diameter

In order to provide an assessment in alignment with previously published information, a cost of electricity analysis in a recent U.S. DOE NETL report is selected as a baseline. In particular, GTCC cases without and with capture, B31A and B31B, respectively are selected.

Using the cost and performance deltas in Table 2, a new capture case is calculated on an apples-to-apples basis. (Ten percent reduction in fixed and variable O&M costs is assumed.) The results are summarized in Table 3, which indicate that, even with some sacrifice in overall net efficiency, it is possible to reduce the cost of CO₂ captured to about $40/ton.

Cost of CO2 Avoided and Captured

Cost of CO2 avoided and captured (as defined in section 2.7.4 of the NETL Report “Cost and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity Revision 3,” July 6, 2015, DOE/NETL-2015/1723). TASC: Total As-Spent Cost.

As the world works together to reduce or eliminate emissions of CO₂ into the atmosphere, technological solutions like the optimized post-combustion CO₂ capture and repowering can go a long way to deliver results.

Bechtel is working on a number of combined-cycle plants in the U.S., including Carroll County Generating Facility in Ohio, Hummel Generating Facility in Pennsylvania, and has recently completed the Stonewall Generating Facility in Virginia.

Authors:

Both authors work at Bechtel. John Gà¼len is Senior Principal Engineer and Chris Hall is Project Engineer.

In today’s dynamic energy industry, the need for flexible, efficient electricity generation is increasingly important. The days of predictable peak demand patterns are behind us. As wind and solar energy sources achieve greater market penetration, their intermittent energy supplies present challenges for Independent System Operators (ISOs) to balance loads and maintain frequencies. These challenges are often intensified at sub-transmission voltages.

As demonstrated by recent market trends, reciprocating engine generators are well suited for flexible peaking and intermediate generation needs in the 20-300 MW output range. Reciprocating engines offer competitive heat rates and multi-shaft reliability to compete in energy markets, plus industry leading ramp rates and startup times to compete in ancillary services markets. The information presented herein highlights market factors driving the growth of the reciprocating engine market and compares reciprocating engines to other generating options.

The Fairmont Energy Station is a 25-MW project equipped with four Cat G16CM34 generator sets. The plant was commissioned in 2014. Photo courtesy: Caterpillar Inc.

Utility-scale engine models include the 9-10 MW and 18-20 MW unit classes. These are heavy duty, medium speed (514 – 900 rpm) engines that can easily adapt to grid-load variations. Table 1 shows the expected net output and heat rate values from three similarly sized peaking plant options: a 220 MW reciprocating engine plant based on the 18-20 MW unit class, a 2x 100 MW aeroderivative gas turbine (GT) plant, and a 1x F-class frame GT plant. A 1×1 F-class combined cycle is also included to demonstrate how these options may compare to an indicative option for intermediate load dispatch.

The reciprocating engine plant has the lowest full-load heat rate among the peaking options, and this difference is even more pronounced at part load operation. There are two ways for the engine plant to achieve 50-percent plant load. First, half the plant can be operated at full load, which will essentially maintain the full load heat rate, depending on the auxiliary loads still running. Second, if all reciprocating engines are ramped down to 50-percent load simultaneously, the resultant net heat rate is still better than the frame GT full-load heat rate. This trend is illustrated in Figure 1, which shows the net heat rate curves at summer conditions.

Summer Heat Rate Curves

Based on summer conditions of 95°F and 50 percent relative humidity.

Reciprocating engines can start up and ramp load more quickly than most gas turbines, but it should be noted that the engine jacket temperature must be kept warm to accommodate start times under 10 minutes. In addition, reciprocating engines are generally more tolerant of altitude and ambient temperature than gas turbines. With site conditions below 3,000 feet and 95°F, altitude and ambient temperature have minimal impact on the electrical output of reciprocating engines, though the efficiency may be slightly affected.

When operated and maintained according to manufacturer recommendations, modern reciprocating engines commonly exhibit availability factors of 95 percent or better. Since there are often multiple engines at a given site, maintenance outages can be staggered to avoid taking the entire plant offline. Similarly, an unplanned outage event for a single engine will not force the entire plant offline.

The case for flexible generation begins with the changing makeup of the electricity market. In 1999, over half of U.S. energy was produced by coal fired generators, according to data from the Energy Information Administration (EIA). In that same year, wind and solar energy were essentially negligible at approximately 0.1 percent (combined) of total generation. Since then, environmental and economic drivers have continuously changed the composition of U.S. energy supply. In 2015, coal energy fell to 33 percent of total generation while the combined impact of wind and solar rose to 5.3 percent. This may not seem significant when considered nationally, but renewable integration is unevenly distributed in the country, so there are substantial impacts in areas where renewable penetration is high. For example, wind accounted for over 9 percent of the installed capacity and 7 percent of generation in MISO in 2015. In ERCOT, wind accounted for nearly 12 percent of generation in 2015 and set a record for instantaneous penetration of 45 percent of demand in February 2016. However, in PJM, wind accounted for less than 4 percent of generation in 2015.

Meanwhile, the makeup and behavior of energy consumers must also be considered. During the latter half of the 20th century, the electricity consumption trends for industrial, commercial, and residential customers steadily increased in parallel paths, as shown in Figure 2.

Retail Electricity Sales by Sector

EIA 2014 Annual Energy Outlook

However, it is important to notice that electricity sales to industrial consumers flattened out in the 1990s while commercial and residential trends maintained their upward slopes. Industrial demand is generally understood to be a primary component of baseload electricity demand, while commercial and residential users typically set the peak demand levels. Therefore, a simple review of Figure 2 suggests that baseload demand has remained steady in recent years while peak demand continues to rise. Further, because energy costs often represent a significant annual expense for industrial consumers, they are more likely to have financial incentives to reduce energy consumption. Annual energy expenses for commercial and residential consumers are typically less significant in proportion. Except in areas where energy costs are significantly higher than the national average, there is less financial motivation for those consumers to change their consumption behaviors. This suggests that the trend in Figure 2 is likely to continue, which means the delta between the daily peak demand and the baseload demand may grow.

In the past, increased peak demand was a relatively simple problem to solve, but it gets more complicated when considering the impact of renewable energy integration. Wind and solar sources are rapidly increasing their shares of annual energy production, but the timing of this production can be a challenge for load serving entities (LSE) and ISOs. Because they are intermittent resources, it is often difficult to match the load profile in areas with high renewable penetration. When the wind stops blowing, there is a need for a reliable generator with fast starting and ramping capabilities to quickly fill that energy void.

Wind energy is generally more consistent at night than during the day, and also tends to be stronger during the spring and fall than during the summer. Wind energy sources are less likely to provide maximum benefit during summer days when peak demands are highest.

Solar generation is obviously at its best during summer days, so these sources can help reduce peaks when the sun is shining. However, increased solar penetration creates an even greater need for flexibility among the generating fleet. Figure 3 demonstrates how significant implementation of solar resources can reshape a daily demand curve by displacing typical peaking, intermediate, and baseload resources.

“Duck Curve” – Impact of Significant Solar Integration

Source: NERC and California ISO: 2013 Special Reliability Assessment: Maintaining Reliability While Integrating Variable Energy Resources – CAISO Approach

The blue line shows a traditional demand curve with a consistent base load, intermediate plateau, and late afternoon peak. The yellow and green lines show the impacts of solar and wind, respectively. Finally, the red line shows the net resultant load that must be met by dispatching the generating fleet. Note that the red line has two daily peaks, which have led many to label this a “duck curve” because the daytime shape resembles the back of a duck. This curve demonstrates the importance of a fleet’s ability to ramp up and ramp down quickly to react to the impact of solar generation.

Localized grid factors are also driving the need for distributed energy resources, and reciprocating engines are competitive in that arena. Electric loads are typically connected at voltages under 230 kV, and extra-high voltage transmission systems often do not provide voltage support to lower levels. Renewable energy sources are also commonly connected under 230 kV, and often at distribution voltages. In areas where renewable sources are clustered and transmission constraints exist, flexible generating assets can help mitigate the impacts of intermittent electricity resources. For example, wind farms are common in the middle of the country, in areas that also tend to be sparsely populated, so the wind farms may be a significant portion of the local generation profile. LSEs need to balance those systems, but they likely have a much higher area control error (ACE) than an ISO, so flexible generation assets may be critical at lower voltages. In those areas, the fast start times and ramp rates of reciprocating engines, along with the ability to scale the installation linearly by reducing the number of engines at a given site, are well suited to “follow the wind,” maintaining desired output and frequency.

The technological benefits of reciprocating engines are evident for flexible peaking applications, but supply and demand drive the success of the plant, as demonstrated in an indicative economic analysis. For the example plant options introduced above, generation revenues were evaluated based on a production cost model (PROMOD IV) simulation using historical data from 2011 – 2014 in MISO, ERCOT, and PJM. Essentially, the evaluation shows generation revenues according to the dispatch results during the study period.

Figure 4 shows the expected annual operating and maintenance (O&M) costs plus major maintenance costs. Fuel is excluded from variable O&M. On a $/kW basis, there is little differentiation among fixed O&M costs for the peaking options.

O&M Comparison

Variable O&M rates are highest for the aeroderivative option, largely due to costs related to demineralized water consumption. Note that the aeroderivative model can be selected with dry combustors and fin fan cooling to minimize water consumption. That model would be expected to have variable O&M costs of approximately $1.50/MWh, but the output at summer conditions would be more than 10 percent lower. The reciprocating engine plant requires very little water, measured in gallons per week, for cooling loop makeup. However, there is routine, minor maintenance on the engines plus SCR reagent and catalyst replacement considerations.

Figure 5 shows the comparative energy revenues based on the model results. The results from three example ISOs are broken out by color shading. The superior heat rate of the reciprocating engines allows for a higher capacity factor than the other peaking options, and therefore better energy sales. The combined cycle was shown for indicative comparison between peaking and intermediate dispatch applications. There are applications for intermediate dispatch of reciprocating engine plants where a combined cycle may not be financially prudent. In direct competition at higher capacity applications, the combined cycle will generate more revenue due to its superior heat rate.

Energy Market Snapshot

Depending on the ISO, capacity markets and ancillary services markets (ASM) offer additional opportunities to generate revenue. Ancillary services commonly include frequency response, spinning reserves, and non-spinning reserves. Frequency response is typically the most lucrative opportunity, and it also requires the most rapid response times. Reciprocating engines are well suited to compete among fossil fuel options for frequency response. Annual revenues from ASM represent a smaller piece of the total revenue pie, but they are a potential tiebreaker when choosing the most favorable generating option for an application.

Capital costs obviously play a major role in an economic analysis because they are the hurdle to profitability. Of the peaking options shown, the F class GT has the lowest expected cost per kW output ($/kW), based on an engineer, procure, construct (EPC) contract methodology. The EPC cost for a generic simple cycle F class plant is approximately $550/kW, while a generic 220 MW reciprocating engine plant is approximately $950/kW. The capital cost difference is analogous to the energy density of the plants themselves. The frame GT generates over 225 MW from a single machine, while the reciprocating engine plant requires 12 units to achieve a similar capacity. In simple terms, the engine plant requires more material to generate the same output, but the multi-shaft design allows for scalability and right-sized plant design in addition to the operational flexibility and superior heat rates outlined above. In any evaluation, it is important to evaluate the costs and benefits for the specific application.

Each opportunity and each ISO is unique. The market for reciprocating engines is rapidly expanding because of flexibility and performance benefits. Full load and part load heat rates, startup times, ramp rates, and multi-shaft reliability all favor the reciprocating engines over gas turbine alternatives. In addition, reciprocating engine designs allow for scalability and right sized solutions, especially for applications in the 20-300 MW range. As the industry accelerates toward an even more dynamic and uncertain future, the market for proven, flexible generation will continue to grow.

Authors

Brian Elwell is EPC Project Manager at Burns & McDonnell. Kieran McInerney is a Development Engineer in Burns & McDonnell’s Energy Division

Tampa Electric’s generating fleet provides 4,700 MW of power to some 700,000 residential, commercial and industrial customers in west central Florida. About 35% of this capacity, or 1,700 MW, is generated at the Big Bend Power Station in southeastern Hillsborough County. Big Bend operates three Riley Power turbo-fired 4000 MMBtu/h pulverized coal boilers (Units 1, 2, and 3) and one tangentially-fired Combustion Engineering 4300 MMBtu/h pulverized coal boiler (Unit 4). Each boiler uses pulverized coal for main fuel and No. 2 fuel oil for Class 1 oil igniters.

In 2014, Tampa Electric initiated a project to replace the oil igniters with high heat input natural gas igniters, which would reduce fuel costs by eliminating No. 2 fuel oil, and firing igniter gas to achieve full load when one pulverized coal mill is out of service. Also, high heat input natural gas igniters allow each of Tampa Electric’s four PC units to potentially operate at 33% of full load when coal mills are out-of-service. With these objectives in mind, Tampa Electric’s project team developed specifications for complete natural gas igniter systems, including igniters, warm-up guns, flame detectors, high-energy spark rods, and all required accessories.

Pressure Reducing Station (front view showing pressure control valves).

The Switch Is On – Oil to Gas Igniters

Units 1, 2, and 3 originally paired twenty-four 15-MMBtu/h oil igniters with twenty-four coal burners. These boilers are Wet Bottom Riley Stoker TURBO Furnaces characterized by upper and lower furnace zones separated by a venture-shaped construction. Burners are mounted in the lower furnace on opposite downward facing arches. The igniters provided 360 MMBtu/h of heat input per unit. In converting to natural gas, Tampa Electric specified a total boiler heat input of 1680 MMBtu/h for the new igniters, nearly five times greater than the heat input with the oil igniters.

To achieve this heat input, the project team specified 24 Forney MAXFire® 40 gas igniters and 24 Forney gas guns for each boiler. The igniter/gas gun combination can provide between 20 and 70 MMBtu/h heat input at a natural gas supply of 35 psig. Each igniter uses Forney’s flame rod detection system to ensure flame presence and discrimination between coal and gas flame.

Pressure Reducing Station (rear view showing Wye strainer, Coriolis Mass Flow Meter, Pressure Regulators sized for Pin 400 psig/Pout 3-35 psig – Max flow 1,680,000 scfh).

Unit 4 boiler is a Combustion Engineering, tangentially fired, balanced draft dry bottom boiler. It originally used 16 side-fired oil horn igniters, with four igniters at each corner of the tangentially-fired boiler. The boiler had five burner levels in each corner, with one 10 MMBtu/h oil igniter at each of the top three burner levels. The bottom two burner levels shared a 2-MMBtu/h oil igniter in each corner and four 130-MMBtu/h oil-fired warm-up guns, one in each corner. The 16 oil-fired horn igniters plus the four warm-up guns provided a total heat input of 648 MMBtu/h.

For the natural gas igniter conversion project, Tampa Electric specified a total boiler heat input of 1920 MMBtu/h, about three times greater than the heat input with the oil igniters and warm-up guns. To achieve the required heat input for Unit 4, Forney provided 16 gas-fired horn igniters, each designed for 70 MMBtu/h (Figure 3) and four 200-MMBtu/h warm-up gas guns. The 70-MMBtu/h horn igniters are a first-of-a-kind design as horn igniters of this capacity have never been provided. The new horn igniters went through extensive 3d flow modeling to ensure boiler wall impingement, flame pattern and combustion emissions were optimized.

For the horn igniters, ionization rods were installed with flame amplifiers factory wired to the ignitor junction boxes. For each of the four warm-up guns, Forney provided its new, high temperature, IDD Ultra flame detectors using UV quartz fiber optic cable bundles connecting the detector head to the scanner amplifier cabinet. The IDD Ultra system eliminates maintenance issues associated with shutters and solenoids found in UV tube type detectors.

Gas Igniter

Management and Control

The project team specified and installed over half-a-mile of 12″ natural gas supply piping from the gas yard at the edge of the property up to each of the boilers. Natural gas is supplied to the igniters and warm-up guns from the main natural gas inlet header at Big Bend. To reduce the pressure from 400 psig at the main header to the 35 psig needed at the igniters and warm-up guns, Forney designed, engineered, delivered four pressure reducing stations (one for each of the four units) that included pressure regulating, control, block and vent valves; interconnecting piping; and instrumentation. These stations were factory assembled and mounted on rigid steel frames. During operation at full load, two pressure reducing/pressure control valves are full open (with a third set in standby off-line), providing total flow of 1,680,000 scfh for 12 igniter pairs (24 igniters total) at full load for each units 1, 2 and 3. Under maximum turndown (low load) conditions, these stations are controlled to provide 40,000 scfm for one igniter pair. For unit 4, the total gas flow is 1,920,000 scfh. Photos 1 and 2 show the front and back views of one pressure reducing station.

Gas shutoff is managed using SKOTCH Trifecta igniter gas shutoff valve assemblies with 3-inch fail-closed pneumatic actuators. These assemblies are complete valve systems that provide shutoff, blocking and venting functions in a single housing. This valve selection reduced the total DCS I/O count by approximately 2/3 from that which would be required using individual valve components.

Cooling Air Blower Skid

MAXFire Gas Igniter Drawing Showing High Energy Spark Igniter (HESI), Gas and Air Inlets, and Guide Tube.

Each natural gas igniter for Units 1-3 requires cooling/combustion air to support primary combustion during operation. Air flow also is required when the igniters are out of service to cool the igniters and prevent debris from migrating into the end of the guide tube. Forney designed, engineered, and provided four cooling air blower skids, containing air blowers sized for 2300 SCFM at 31″ W.C. (four Units 1,2 and 3) and 360 SCFM at 31″ W.C. (for Unit 4). The blowers, with 480 VAC, 60 Hz, 3-phase TECF motors, were mounted on common skids containing pressure transmitters, fan inlet air silencers, valves and piping

For the unit 4 igniters, cooling/combustion air is supplied by the FD fan via the individual igniter windboxes.

Instrumentation and transmitters for the new igniters and all ancillary equipment were wired to local junction boxes. The control and instrumentation devices enable complete remote control and monitoring by the plant distributed control system (DCS). Hardware from the plant’s existing Emerson Ovation DCS was reused to the greatest extent possible.

Maxfire 40

Maxfire 40 over A-Gas gun (igniter/gas gun combination) – Stable natural gas fire on Big Bend Unit 3.

Maintaining Fuel Flexibility

For Units 1-3, the gas igniters were provided with a total guaranteed heat input of 1680 MMBtu/h (70 MMBtu/h x 24 igniters),and for Unit 4 the guaranteed heat input is 1920 MMBtu/h (70 MMBtu/h x 16 igniters + 200 MMBtu/h x 4 warm-up guns). The total combined capacity for the system with all four units firing is 6960 MMBtu/hr. This allows the operators for each Unit to potentially achieve 33% of full load when firing igniter gas only. This provided added fuel flexibility and allowed running at full load when one pulverized coal mill on any Unit is out-of-service.

Tampa Electric’s analysis justifying the project, estimates that the switch from No. 2 oil to natural gas for ignition will save its customers $76 million in fuel costs over the life of the units. This will be achieved by eliminating the use of 30,000 barrels year of light oil at the plant while reducing both dependence on foreign oil and emissions.

Horn Igniter

Horn Igniter Showing Gas Gun, High Energy Spark Igniter, and Diffuser Horn.

Summary

Changes in the power sector are compelling significant changes in the management of generating assets. While many coal-fired units are shutting down for economic and emissions-related reasons, others are investing in plant modifications to adapt to new market dynamics and save money for their customers. Tampa Electric’s Big Bend Station successfully replaced its oil igniters with high heat input natural gas igniters to acquire the additional fuel flexibility necessary to remain an essential component of the dispatch order in the Southeast.

One of the perks of writing the Nuclear Reactions column for Power Engineering is that I get to write about a wide variety of nuclear-related topics. I also get the opportunity on occasion to point out linkages (or differences) between seemingly unconnected topics. This column squarely fits into this latter category.

Two recent items caught my attention related to the “next generation” of nuclear professionals that prompted me to opine here on the perils and the promise of youth.

The first relates to Transatomic Power, a nuclear startup spun out of MIT in 2011 to pursue commercialization of a molten-salt reactor that purportedly could run on spent nuclear fuel at efficiency levels many times higher than conventional reactors. A white paper published in 2014 claimed that the reactor concept would be able to “generate up to 75 times more electricity per ton of mined uranium than a light water reactor.”

Transatomic became something of a sensation in the nuclear and new energy fields, leading to an influx of venture capital that has sustained the company’s growth and evolution over the past several years. The promise of recycling nuclear waste added green cachet to the company, burnishing a favorable public image.

That cachet has taken a hit in recent months. As reported in MIT Technology Review in February, the company is backtracking from certain claims based on an analysis by Kord Smith, an MIT professor and nuclear physics expert. “In early 2016, we realized there was a problem with our initial analysis and started working to correct the error,” said Transatomic CEO Leslie Dewan in an email response to MIT Technology Review.

The efficiency claim has been dramatically reduced; instead of the 75X advantage, Transatomic now lays claim to only “more than twice” with its reactor concept. Just as striking is the company’s retraction regarding recycling; Transatomic now states that their design will not reduce stockpiles of spent nuclear fuel or even use them as a fuel source.

To its credit, Transatomic has owned up to the errors and re-done its analysis acknowledging the “reduced” advantages. And if Transatomic can develop a reactor that increases efficiency by even 2X, that would remain a remarkable technical achievement.

The second item relates to a new mobile phone app that attempts to apply millennial technology to nuclear advocacy. Most of us have probably had conversations with strangers or casual acquaintances where nuclear power has come up and we’ve struggled to find just the right way to convey its attributes while simultaneously highlighting its stellar safety record and acknowledging the potential risks. It’s a tricky balance and has to be tailored to the person you’re talking to.

Generation Atomic, a non-profit nuclear group that uses “gamifying” techniques to enhance advocacy, released its Atomic Action app in early April. The app transforms potentially difficult advocacy conversations into interactive, digitally enhanced conversations. Users accumulate points through various actions: for example, 5 points for checking into the app daily, 50 points for watching a video on nuclear power, 500 points for knocking on doors, and 2,500 points for posting a selfie with a legislator. True to its gaming origins, the app includes a leaderboard tracking user progress.

“In a 2014 global poll on peoples’ views of different energy sources, only 28% of respondents had a favorable opinion of nuclear,” said Generation Atomic co-founder and organizing director Tay Stevenson. “In our early modeling, we were hoping we could get positive responses during 35-40% of our conversations. After three months of piloting with student volunteers knocking on hundreds of doors in State College and Pittsburgh, Pennsylvania, we are seeing 50-55% of people sign up as supporters.”

According to Google Analytics, the app had more than 335 users in the first two weeks after its release, but Generation Atomic expects that to grow quickly. “Currently, our only campus chapters are at University of Pittsburgh and Penn State,” said company founder and executive director Eric Meyer. “However, earlier this month we were holding advocacy trainings at the American Nuclear Society Student Conference and there was a lot of interest in starting chapters in Indiana, Florida, and other states in the fall. This summer we’ll remain focused on building the pro-nuclear constituency in Pennsylvania and Ohio, two states where nuclear is at great risk of early abandonment right now.”

For both of these items, what stands out to me is the enthusiasm for nuclear demonstrated by these young professionals…and soon-to-be professionals. So keep knocking on those doors, Pitt Panthers and Penn State Nittany Lions! And on behalf of the nuclear community, Ms. Dewan, we forgive you. Don’t lose your fervor and love for nuclear – just remember to check in with the graybeards along the way.

Wind turbines totaling nearly 15,000 MW in capacity were ordered for wind projects worldwide in the second half of 2016, according to a new report from Navigant Research.

The orders came from projects in 24 countries and 11 vendors.

Vestas extended its lead from other wind manufacturers with more than 6,445 MW of capacity delivered, which was almost 3,000 MW more than the first half of the year.

Gamesa came in second with just over 2,000 of orders. Asia Pacific lead among the regions with 1,800 MW of new capacity thanks to strong showings in India and Australia. North America and Europe were second and third, respectively.

Construction Begins on Largest Solar Power Project in the Americas

Construction has begun on a 754-MW solar power park in Mexico that will be the largest in all of North and South America when it becomes operational next year, CleanTechnica reported.

A subsidiary of Enel Green Power is developing the Villanueva Solar Park in North Mexico. Firmer will supply over 600 of its R 11015 TL 1500V inverters for the project, while NEXTracker will supply single-axis trackers.

NEXTracker noted the key drive and electrical components of its trackers are sealed to prevent penetration by sand and dust, which is critical for the project’s desert climate.

The plant will deliver power to 1.3 million households and offset 780,000 tons of CO₂.

ERCOT Predicts Sufficient Summer Generation Resources Through 2022

ERCOT released a report indicating it will have sufficient power for each summer through 2022 through most weather scenarios.

The system, which represents 90 percent of Texas’ electricity load, indicated it will have a reserve margin of 18.9 percent in 2018, though that margin will fall to 16.8 percent in 2022.

Total ERCOTer summer generation is estimated at 82,000 MW this year, which includes 2,500 MW of planned gas-fired generation and 800 MW of new wind and solar additions.

ERCOT estimates its planned resources will increase to nearly 16,000 MW by summer 2019, including plans to mothball one unidentified plant indefinitely, with a capacity reduction of 840 MW starting in 2019.

Canada Now Generates Two-Thirds of its Electricity from Renewables

The Canadian government announced a full 66 percent of the entire country’s electricity was generated from renewable sources in 2015, up from 60 percent in 2005.

Only Norway, New Zealand, Brazil, Austria and Denmark have similar or larger shares of renewable energy.

Hydro generation accounted for 60 percent of Canada’s generation, though wind power grew twenty-fold over the last decade, according to a report from Canada’s National Energy Board. The report noted the intermittent nature of wind generation is an obstacle to more widespread use, though it suggested trading electricity with neighboring jurisdictions as a solution.

Biomass accounted for two percent of Canada’s electrical generation, and solar was largely restricted to Ontario, home to 98 percent of the country’s solar capacity due to the provinces’ feed-in tariff programs.

Siemens Introduces 38-MW Aeroderivative Gas Turbine

Siemens has launched the SGT-A35 RB, its newest gas turbine designed for the oil and gas industry.

The lightweight, aeroderivative gas turbine can generate up to 38 MW and is integrated into a compact, lightweight Dresser-Rand package, which is up to 30 percent smaller and lighter than its Industrial RB211 predecessors.

Siemens indicated the new turbine is suited for offshore applications, including floating production, storage and offloading vessels that have become increasingly popular for oil and gas production in harsher deep-sea environments.

The SGT-A35 RB gas turbine is based on the Industrial RB211 and Industrial Trent 60 gas turbines, built with Rolls-Royce Aero Engine technology. This turbine family has more than 800 installations worldwide exceeding 37 million operating hours.

The SGT-A35 RB gas turbine is available in 34 and 38 MW variants to match a range of application requirements.

United States Records Fastest First Quarter Wind Growth Since 2009

In the first quarter of 2017, more wind turbines were installed in the U.S. than in any other first quarter since 2009.

Wind companies installed 908 utility-scale turbines with a combined 2,000 MW of capacity, the American Wind Energy Association reported.

The association said that while turbine installations spanned the United States, Texas had the most installations at 724 MW, bringing its total capacity to 21,000 MW.

Kansas had the second-most first-quarter installations at 481 MW.

North Carolina became the 41st state to host an operational wind farm with the activation of Amazon Wind Farm US East.

That facility is also the first wind farm to come online in the southeast in 12 years.

Companies now have 4,466 MW of wind facilities either under construction or in advanced development, with a near-term pipeline of 20,977 MW.

Block Island Now Generating Electricity From Offshore Wind

The Block Island Power Company announced it is now providing its 2,000 customers on the island with electricity generated from offshore wind.

Though the 30-MW Block Island Wind Farm began generating electricity in December, Block Island itself had to be connected to the facility with a new cable, the Boston Globe reported.

Block Island Power has now deactivated its diesel generators. The company had begun looking for an alternative to diesel generation more than a decade ago when the cost of fuel drove electrical costs above 60 cents per KW/h.

Block Island, developed by Deepwater Wind, also provides power for the mainland grid.

Power Generation’s Share of Total Carbon Emissions Plunges

Though the power generation industry’s share of carbon emissions was traditionally the second highest in the U.S., a plunge in emissions has dropped it to the second-lowest in 2016.

The study by the Energy Information Administration showed power generation emissions has dropped from a near-steady 60 kg CO₂/MMBtu since the 1990s to 48 kg CO₂/MMBtu last year.

Electrical generation emissions began dropping in 2008.

Only the industrial sector had less emissions with 44 kg CO₂/MMBtu due to the use of biogenic fuels and the capture of some carbon in the form of plastics and other non-energy products.

The EIA said carbon intensity of the electric power sector has fallen due to the shift away from coal and to natural gas and renewable sources.