Power Engineering

Producing Reliable Power in the Hospital Setting

By Bhavesh Patel, Director of Marketing, ASCO Power Technologies

Ensuring power reliability for Northwestern Memorial Hospital's new Prentice Women's Hospital in downtown Chicago was a challenging project for contractor Environmental Systems Design (ESD).

Northwestern University's Prentice Women's Hospital has high power reliability as a result of emergency power redundancy throughout the building. All photos courtesy of ASCO Power Technologies.

At 937,237 sq. ft., the hospital contains 32 labor and delivery rooms, 134 labor obstetric beds, 144 normal newborn bassinets and 86 special care nursery beds. The hospital is also home to a surgical unit with 10 operating rooms. Supporting the healthcare units are retail stores, a chapel, dining services and an education center. Construction costs totaled $450 million.

As the engineering firm that designed the hospital's mechanical, electrical, plumbing, fire protection and emergency power systems, ESD faced a daunting range of obstacles. One challenge was connecting three, 2,000 kW engine-generators and engine paralleling switchgear to power transfer switches in the hospital. The job required miles of wire because the gensets and switchgear could not be housed in the hospital due to space limitations. The equipment was originally to be installed in a garage adjacent to the hospital, but that space was dedicated for another use. Instead, the gensets and paralleling switchgear found a home in an existing parking garage across the street from the hospital. Dealing with rights of way concerning the street added layers of complexity.

Connecting the gensets and paralleling switchgear with the transfer switches required spanning a 500 to 700-foot stretch beneath the street through a pedestrian tunnel that connects the new hospital, the garage and Northwestern Memorial Hospital, and then up to the new hospital's 7th and 17th floors. The emergency power system includes 62 transfer switches, including bypass-isolation transfer.

That adds up to a lot of wiring, since two wires for engine intelligence and two wires for load shedding were required for each transfer switch. Redundant wiring for higher reliability added to the total. Close to 3,000 wires, some as long as 700 feet, would need to be threaded. That totals over nine miles of wiring.

ASCO Power Technologies, which supplied the low voltage transfer switches, medium voltage engine paralleling control switchgear and design expertise, laid out a fiber optic communications control circuitry for the project. This self-sustaining, isolated network includes an ethernet "self-healing" dual fiber optic ring. The design helped reduce the quantity of wires that otherwise would have been needed.

Two pairs of traditional hard wires carry the start signals from the transfer switches to the gensets. This provides recognized reliability and helped obtain the variance required from the city to remotely locate the gensets in another building.

For communication between the transfer switches and switchgear, two cables (one redundant) run from the switchgear to three, remote terminal units (RTUs). The terminals serve as interconnection points to the power transfer switches.

Substations house connections for a dual fiber optic local area network for load shedding, ethernet switches for power transfer communications and hard-wired engine-start parallel circuitry. The emergency power system design incorporates layers of communications and control redundancy by providing redundant system controls and multiple communications and control paths for the system's most critical circuits, engine start and load shed. In the event of a PLC, communications LAN or hard-wired engine start circuitry failure, the system will continue to operate as designed. The substations also contain Liebert UPSes and 24 volt DC power supply for backup communications power to power transfer control panels and substations.

Fiber optics produced a number of benefits, such as eliminating signal loss that otherwise would have occurred with hard wire due to the long distances. Randy Ehret, senior vice president of ESD, said information also travels faster on the fiber optics than it would on copper wiring. The use of fiber optics also created a monetary benefit.

"Running two cables gave us a robust system and we didn't have to buy all that copper twice," Ehret said. "That saved a lot of dollars."

Connectivity wasn't the only issue created by the long distance between the generators and loads across the street. Running 4,160 volt feeders from the generators to the transfer switches also proved problematic as room height for the generators was tight.

Three cable entries for these power transfer switches made conduit installation a "coordination nightmare."

The original concept was to cut the garage's floor slab and take two 5 kV feeders, one redundant, underground and up adjacent to the pedestrian tunnel, Ehret said. The structural engineer determined, however, that the slab contributed to the building's structural support, so it could not be cut. The design allowed the feeder conduit to run outside and along the garage, under the sidewalk and beside the tunnel to get across the street and into the new hospital.

The overall power configuration for the hospital includes three utility feeds. A fourth emergency utility line on an automatic throw over switch is also part of the system. The four feeders connect to double-ended service gear with an automatic tie in between.

Monitoring and control capabilities of the emergency power system at Prentice Women's Hospital encompass this tile schematic.

Redundancy was also built into the emergency power distribution system. The configuration is N+1 with load shed capabilities that ensure power to life-safety and critical loads if not enough generators are available. The two 5 kV feeds run to five unit substations within the building. Transformers rated at 2,600 kVA step down power to 480 volts from 4,160. Each substation serves a different area of the hospital.

A 3,000 amp emergency power distribution board and a 480 volt distribution board from each of the substations also are part of the overall design.

On the 480 volt side, there are two levels of transfer switches for life safety and critical loads configured such that the first level is between two separate and independent normal sources of power. This feeds into the second level transfer switches along with the emergency feeder and out to the switches' loads.

Another step the team took to enhance redundancy and reliability was to keep the ampere ratings of the transfer switches small: 800 amps or less. The four electrical closets on each floor are fed from various transfer switches to further enhance redundancy and reliability.

Besides reliable power, hospital officials wanted reliable information. Therefore, the team paid close attention to the emergency power's monitoring and control system. Northwestern Memorial Hospital personnel liked the local monitoring and control capabilities they had at another facility.

"They wanted the LED 'Christmas tree lights' on the equipment itself that show system status at a glance," Ehret said. "They don't want to flip through screens or touch anything during an emergency situation."

But personnel also wanted to communicate and share information more efficiently. A 40-inch LCD screen that's part of the engine paralleling switchgear is in the engineering office on the 18th floor. It displays a one-line diagram of the onsite power system and shows a wide range of operational and other parameters. A second 40-inch screen was installed at another facility so personnel there can track system status as well. The remote capability is strictly for monitoring, not control.

A supervisory control and data acquisition (SCADA) system monitors and controls the automatic transfer switches, medium voltage paralleling switchgear, engine-generator sets and graphically displays the status of more than 250 breakers.

The approach to ensuring redundancy and reliability carried over to powering air handling units that ventilate each floor. Two supply and return fans in each unit have a separate emergency feeder and transfer switch.

Other loads, such as kitchen equipment and primary imaging, are not fed by the emergency power system since those capabilities are largely provided by the general hospital across the street. One of two medical machines that support outpatient services in the new hospital are included in emergency power, however.

Two information technology closets per floor are classified critical loads. The closets manage primarily patient treatment data and are cross-connected for enhanced reliability. If power is interrupted to one closet, the other could manage data handling and storage for both. A 400 kW uninterruptible power sully (UPS) maintains power to the closets until genets can provide power when utility power fails.

A 10,000 sq. ft. data center located in another building on campus supports the primary IT requirements of the hospital. A tier three onsite power system and UPS help provide business-critical continuity during loss of utility power.

The team devised a two-night "blackout" test that included not only the electrical systems, but also the integration and interactions of all the building systems on normal and emergency power. The test included the Illinois Department of Public Health, state officials who had to sign off on the project, local city inspectors, contractors, owners and design teams.

"We tested every potential failure condition that we could think of over the course of two nights," Ehret said. Questions the test needed to answer included: What would happen if feeds were lost? Would all the transfer switches transfer? Would all the mechanical systems that were supposed to come back on, come back on? Was the building automation system properly integrated with the emergency power system? Were the elevators properly integrated with the emergency power systems? How would the life-safety and critical loads function? What would happen with the UPS system and the IDF closets?

In the end very few problems were identified.

"The owner had a high degree of confidence that this system was going to perform in the event of a true, actual emergency," Ehret said.

Anhydrous Ammonia Considerations for SCR Reagents

By Shannon McAvoy, Colorado School of Mines

Environmental legislation has caused many utilities and heavy industries to implement new NOx reduction technology. One option to comply with these regulations is a SCR (selective catalytic reduction) which can reduce NOx by 90 percent. The SCR operates by injecting ammonia into the flue gas upstream of the catalyst. The ammonia and NOx react in temperatures between 550 to 750 F with the catalyst to form nitrogen and water vapor.

There are several options of ammonia reagents that can be used in an SCR: anhydrous ammonia, aqueous ammonia or urea. For capital and operations and maintenance (O&M) costs typically, anhydrous ammonia is the most cost effective option, followed by 29 percent aqueous ammonia, 19 percent aqueous ammonia and urea.

Aqueous ammonia solutions are not as cost effective or efficient as anhydrous ammonia but they are safer for transportation and use. The solution must be hydrolyzed before it can be used in an SCR application. This requires additional equipment, steam and electricity attributing to the additional costs. A greater volume of the reagent is necessary to achieve the same NOx reduction because of the additional water. By removing the water, aqueous solutions are converted back to anhydrous ammonia.

Twnty-nine percent aqueous ammonia is regulated and will require a Program 2 risk management program (RMP) if more than 20,000 lbs. are stored onsite. Currently, 19 percent aqueous ammonia is not regulated.

Urea is the safest ammonia reagent however it requires conversion to ammonia through thermal decomposition in order to be used in an SCR. Urea is generally the most costly reagent because the thermal decomposition requires sustained high temperatures and additional equipment within an enclosed area. At times when anhydrous ammonia is not feasible, urea may be the lowest cost alternative compared to an aqueous solution (this would be typical of large scale facilities).

Anhydrous ammonia is the most cost effective and efficient reagent because no additional equipment is needed to convert it for use in an SCR application and less volume of reagent is needed because it is pure ammonia.

However, anhydrous ammonia is a toxic chemical that has the potential to be lethal. It is therefore regulated by 29 CFR 1910, 40 CFR 68 and 6 CFR 27. Each of these regulations has a governing agency: Occupational Safety and Health Administration (OSHA), Environmental Protection Agency (EPA) and Department of Homeland Security (DHS), respectively.

OSHA requires a process safety management plan (PSM), EPA requires a risk management plan (RMP) and DHS requires compliance with chemical facility anti-terrorism standards (CFATS). This is only necessary if anhydrous ammonia is stored onsite in quantities greater than 10,000 lbs.

The PSM/RMP is a combined plan for anhydrous ammonia because several aspects of each plan overlap with each other. This document includes information pertaining to employee participation, process safety information, process hazard analysis, operating procedures, training, contractors, pre-startup safety review, mechanical integrity, hot work permit, management of change, incident investigation, emergency planning and response, compliance audits, off-site consequence analysis, five-year accident history and registration for the facility (for EPA data submitting through RMP*eSubmit). This plan is reviewed and updated every five years and refresher training on the process and associated chemicals be performed every three years.

For Homeland Security and CFATS a Top-Screen procedure is completed. Anhydrous ammonia is listed in 6 CFR 27 Appendix A: Chemicals of Interest List. To determine if a facility meets the requirements of the CFATS a Chemical Security Assessment Tool was created, Top-Screen.

To complete the Top-Screen, it is necessary to register with DHS to gain access. Preferably three people, a "preparer," "submitter" and "authorizer," complete the Top-Screen process. The preparer enters the data into the CSAT system and sends the Top-Screen to the submitter. The submitter can revise and submit the information to DHS. The authorizer provides assurance to DHS that the submitter and preparer were authorized to complete the information.

The questionnaire should be completed within 60 days of gaining access to Top-Screen. DHS will designate the facility with a preliminary tier level (levels are labeled 1 to 4 with 1 being the highest security risk) after reviewing the Top-Screen. After the preliminary tier level is distinguished several additional plans must be submitted.

The security vulnerability assessment (SVA) collects facility identification information, information about the chemicals onsite and information on assets pertaining to the chemical of interest. The tool provides information on possible terrorist attack scenarios which is then used to identify necessary security measures.

After reviewing the SVA, DHS will designate a final tier level. After the SVA is submitted, a site security pan (SSP) or alternative security plan (ASP) must be submitted. The SSP details information for the facility, information on security measures for the entire facility, and security measures for particular assets.

DHS has been prohibited from denying an SSP due to the presence or absence of a particular security measure. Security measures that are implemented must demonstrate a standard of reliability according to the specific tier level. These standards are outlined in the risk-based performance Standards set by the DHS.

The ASP must address each security/vulnerability issued identified in the SVA and how the security measures in place address the risk-based performance standards and potential terrorist threats. DHS can approve an ASP in whole or in part, or subject to revisions or supplements. After the necessary reports are submitted and approved, a letter of authorization will be sent to the facility.

How DHS specifically determines the tier level for each facility is classified. DHS does consider the consequence, vulnerability and threat that pertain to each facility. Anhydrous ammonia is flagged in Appendix A because if released it is toxic.

Several aspects should be considered when anhydrous ammonia is evaluated for a particular site. How many people will be impacted by a release? What environmental receptors will be affected? How can the facility be attacked? What is the worst-case release scenario if anhydrous ammonia is released? How will the facility respond to a toxic release? What redundancies can be used to render the chemical non-hazardous? What security measures are necessary to deter a threat? Why would this particular facility be attacked? What liability will be assumed if anhydrous ammonia is used?

If the answers to these questions create a scenario of minimal consequence for the surrounding area, limited vulnerabilities for the facility, and a reasonably minor threat level is expected, then it may be necessary to evaluate to cost differences between anhydrous ammonia, aqueous ammonia and urea for the facility in question, including the cost of additional safety and security; not just capital and O&M expenditures.

Typically, some have avoided anhydrous ammonia because of the PSM/RMP and DHS requirements, but for an 85 percent NOx reduction in a 500 MW coal-fired unit costs savings from the reagent alone are greater than $1 million annually when compared with 19 percent aqueous ammonia. The cost savings increase dramatically as unit size increases.

In many cases, anhydrous ammonia may be the most efficient and cost-effective option even after additional costs are added as a result of regulations for additional safety and security precautions. Anhydrous ammonia may need to be evaluated by many utilities as a result of emission regulations.

Gasification Offers a Cleaner Coal Solution

By Jeffrey Goldmeer, Ph.D, Fuel Flexibility Manager, GE Energy

The use of coal for power generation presents a dilemma: how to create energy from this abundant, fairly inexpensive resource without releasing high levels of carbon dioxide (CO2) into the atmosphere. A way to resolve that dilemma is with a technological one-two punch: an integrated gasification combined-cycle (IGCC) process to convert synthesis gas (syngas) into essentially carbon-free, high-hydrogen (H2) fuel and advanced syngas turbines to efficiently convert the hydrogen to power.

There are several reasons why coal is becoming more attractive. Other conventional fuels are costlier, subject to volatile price shifts and vulnerable to supply disruptions caused by political instability; recoverable oil reserves are dwindling; and competition for resources is growing. Moreover, coal is plentiful, with many countries relying on it for their own power—including China and the U.S. (which generates half of its electricity from coal)—while others, such as Australia, have surplus coal they export.

But compared to natural gas—the other primary alternative to oil—coal has two disadvantages: its uncontrolled carbon emissions are more than twice as high as those from natural gas and coal-to-energy technologies are less efficient. Climate change is ramping up the pressure to cut greenhouse gas (GHG) discharges, so governments are implementing regulatory and tax policies to control carbon. To generate the cleaner, more affordable and more secure energy the times demand, systems that depend upon coal must reduce their inherent carbon content and become more efficient, too.

There are four major options for dealing with carbon in fossil fuels: implementing energy efficiency and power conservation measures to depress power demand; switching to low- or no-carbon fuel alternatives (for example, replacing a coal plant with a natural gas plant); altering power generation strategies by shifting to technologies that reduce carbon output, such as carbon capture and storage (CCS); and replacing older plants with more efficient new units or retrofitting existing plants with improvements.

The last two are where IGCC makes coal appealing. According to a report published in 2010 by the U.S. Department of Energy and the National Energy Technology Laboratory, an IGCC application with 90 percent carbon capture has lower total CO2 emissions over its lifecycle than an existing pulverized coal or super-critical pulverized coal plant. These advanced combined-cycle gas-turbine plants are also capable of operating efficiently with a variety of fuels.

The Carbon-Capture Advantage

In an oxygen-blown IGCC plant configured for carbon reduction, coal gasification begins when coal and oxygen are fed into a gasifier that changes the coal into syngas, which is primarily hydrogen and carbon moNOxide (CO). After that happens, the syngas is cooled and the other pollutants including sulfur dioxide (SO2), mercury, ash and particulate matter are removed. A water-gas-shift reactor turns the carbon moNOxide from the syngas into CO2 and more hydrogen, while an acid gas removal unit separates out the CO2 for compression and storage.

What results is a hydrogen-rich fuel (about 90 percent H2 by volume) which is sent to a combined-cycle power plant that produces electricity from a combustion turbine that burns the gas and a steam turbine powered by gas turbine exhaust heat.

That hydrogen volume is at the high end of what is possible today, given that available options for carbon capture can produce fuels whose H2 volumes are between 45 and 95 percent. Plus, the CO2 separated from the syngas either is diverted to useful purposes such as enhanced oil recovery or sequestered in underground aquifers. The IGCC technology consumes 30 percent less water and emits 75 percent less SOX, one-third less nitrogen oxide (NOx) and more than 90 percent less mercury—reducing that element to its least detectable levels —than any other coal-to-power technology.

While there are no gasification or turbine-technology barriers to implementing carbon capture in new or existing plants with contemporary IGCC plant designs, governments must adopt definitive carbon policies—with carbon-liability rules—that make carbon capture economically feasible.

Gas Turbine Fuel Flexibility

Modern gas turbines have the capability to operate on a variety of fuels—including non-traditional fuels—such as low-calorific-value fuels. Heavy-duty gas turbines can run on alternate gas and liquid fuels that include syngas and other industrial by-product gases. For example, GE has gas turbines that can burn fuels with H2 levels of 50 to 95 percent by volume. Since gas turbines have the flexibility to handle low-Btu fuels such as syngas and H2, coal gasification technology solves the conundrum of how to create low-to-no-carbon power from coal.

These units perform in a variety of applications, including coal-based IGCC, refinery IGCC and steel mills. They offer more than 90 percent availability in power, industrial and petrochemical plant installations. Gas turbines operating on syngas and high-H2 fuels in a wide range of outputs have gone into facilities using gasification and fuels such as high- and low-sulfur coals, heavy oil and petroleum coke.

Combustion System for H2 Fuels

Gas turbines that operate on low, or ultra-low heating value fuels like H2 require a specialized combustion system that is compatible with the physical and chemical properties of those fuels (particularly the large volumes required and their higher flame speed) and, therefore, can reliably generate low-carbon power in systems like IGCC with carbon capture. Pre-mixed combustion systems, such as a dry low NOx (DLN) combustor, are inadequate for operation on syngas and high H2 fuels for two reasons. First, the hydrogen flame speed is greater than that for natural gas. This means a higher risk exists of flame holding in a DLN fuel nozzle that premixes the fuel and air upstream. Second, since the systems are designed to handle richer fuels like natural gas, the fuel system is not sized correctly to handle the volume flow of low-Btu fuels. Specifically, the lower heating value (LHV) of a high H2 fuel is approximately 30 percent smaller (on a volumetric basis) than the LHV for natural gas. Therefore, the fuel system design must take the increased flow into account in order to maintain the same heat input into the gas turbine.

What will effectively address these design challenges is a diffusion-based combustion system that can sustain high-efficiency operation on low-Btu fuels, including many varieties of syngas, and has the fuel flexibility to allow the operator to function in base load applications. GE's multi-nozzle quiet combustion (MNQC) system provides these capabilities. Gas turbines equipped with a multi-nozzle quiet combustion system can operate over a wide range of loads, with or without carbon capture and on syngas, natural gas, or both gases. The ability to operate at baseload can be important if syngas is not available. In addition, if syngas production falls to a reduced level, the turbine could be fired on a combination of syngas and natural gas, a process called co-firing. The ability to turn down the gas turbine (to operate at a lower megawatt output) could allow the owner or operator to tailor the plant operation to meet needs of the local power grid.

The multi-nozzle quiet combustor is a diffusion-based system where the fuel and air are injected into the combustor through a series of fuel nozzles. The fuel passages in the combustor have larger diameters to accommodate the increased mass flow of the syngas fuel. These combustors also have provisions to allow for head end injection of diluents directly into the air stream for NOx emissions control.

In operation with a high H2 fuel, the MNQC combustion system creates a more compact flame in response to the heightened reactivity of the hydrogen. This can result in reduced heat transfer to the combustion liner. There also is more flexibility with the diluent, since it can be blended with the fuel before being injected into the combustor, or injected directly into the combustion system (for a possible auxiliary load saving, since pressure requirements are reduced).

GE's MNQC system installed on gas turbines has amassed more than 1.2 million fired hours and more than 25,000 fired starts on a variety of fuels in multiple applications. Turbines in IGCC plants that have been outfitted with MNQC systems have compiled more than 520,000 fired hours and more than 4,000 fired starts. These installations include Duke Edwardsport, which will be the largest IGCC plant in the world when it's completed next year.

A series of tests performed at GE's Combustion Lab on a range of fuels simulating syngas with and without carbon capture have validated that the MNQC combustion system can operate on high-H2 fuels whose hydrogen content is as much as 95 percent by volume. These tests were performed at full temperature, pressure and flow to evaluate combustion performance. This includes a full suite of instrumentation to measure key parameters, including combustion dynamics, emissions and exit profile. Typical sensors used in these tests include thermocouples, thermal paint and strain gauges. In conjunction with advanced computational fluid dynamics modeling and finite element analysis, this allows for evaluation of system durability.

This capability to operate a combustion (gas) turbine on a high H2 fuel lets the gas turbine technology use decarbonized fuel directly from IGCC or other process operations. Since that also makes it unnecessary to pre-blend fuel and diluent, the net plant output and efficiency increase because there are none of the pressure losses that happen with fuel/diluent blending systems.

A few factors, then, have coincided: the global need and push to cut GHG emissions, the emergence of low-carbon and carbon-free power generation technologies to help achieve that, and commercial applications of those technologies, like IGCC with carbon capture. The logical, and most effective, result of that convergence is the development of syngas-capable heavy duty gas turbines that have extensive low-Btu fuels experience and are equipped with high-hydrogen-compatible multi-nozzle combustion systems.

SO2 Mitigation in a Bituminous-fired Boiler

By Mark Pastore, Vice President, Environmental Energy Services Corp.

U.S. government health standards have steadily grown stricter on emissions of sulfur dioxide (SO2), an emission linked to smog and acid rain. Coal plants and other industrial facility power boiler operators are now willing to consider novel solutions that bring their facilities into federal compliance.

Environmental Energy Services Corp. (EES) was recently commissioned to assist the operator of a number of industrial facility power boilers in Pennsylvania to reduce SO2 emissions. At one site, there was no room to install a wet flue gas desulfurization (WFGD) system, prompting the plant operator to look at other chemical sorbent options.

EES and EnerChem (ECI) presented plant owners with a proposal to demonstrate ECI's furnace sorbent injection technology as a means to reduce 50 percent or more of SO2 generated by injecting chemicals into the furnace. The technology uses injectors to deliver largely discreet submicron mineral particles into the furnace combustion zone, thereby achieving a massive number of particles per pound of reagent. This boosts both the reactive surface and the probability of reagent particle contact with the SO2 molecules.

The net result is higher emissions capture efficiency than was achieved with -325 mesh reagent in earlier Department of Energy and Tennessee Valley Authority investigations. The test program examined both precipitated and ground forms of calcium carbonate, the active ingredient in EES's CCS-64x platform. Both forms are available in commercial volumes within reasonable shipping distance of most power plants.

EES is licensed by ECI to market the technology, which is also useful in capturing Hg, As, and SO3.

The precipitated crystal structure (PCC) used has a more open structure that ensures access of pollutants in the flue gas stream to the core of each particle. It is best produced on-site or nearby because the structure limits the slurry solids to about 50 percent. The finely ground dispersion of calcium carbonate (GCC) is ground to less than 1 micron for maximum reactivity. It is available in 75 to 80 percent solid slurries. Both slurries are stable, fluid and easy to handle.

A brief furnace sorbent injection (FSI) test program was conducted over a five-day period and then repeated to confirm results. ECI and EES are continuing research in pilot combustors to optimize injector nozzle performance. Normal boiler operating conditions were maintained for local steam production on coal for the demonstrations.

The liquid calcium-based reagent products PCC and GCC were injected in a proof-of-concept exercise to confirm feasibility as a control technology for the customer. Results are based on flue gas analysis for SO2 and address only the customer's main objective. Other analytical efforts aimed at maximizing performance through gaining a better understanding of the role of reagent properties are ongoing by ECI and EES.

The objective of this demonstration was to:

  • Achieve SO2 reductions of 40 to 50 percent as indicated by EES' gas analyzer.
  • Confirm what effects, if any, the additional particulate loading will have on ESP performance, boiler deposits, ash handling and combustion.
  • Validate the combustion model used to design the injector configuration.

This demonstration proved successful with 50 to 70 percent removal of SO2 achieved with:

  • GCC with a stoichiometric treat ratio of 2.3
  • PCC with a stoichiometric treat ratio of 1.3
  • No adverse impact on fly ash capture or handling
  • No adverse impact on furnace deposits
  • Step Combustion, a combustion engineering firm, developed a computational fluid dynamics model which was validated by field test data.

Nozzle performance is key to achieving high capture efficiency. During the demonstration, variable steam pressures were used to test the effects on additive droplet size and capture efficiency. Using steam below 150 psi, 1,000 lbs/hr resulted in less than optimal spray patterns in over-fire air ports, resulting in deflection of some of the chemical and reduced atomization of the reagent into the flue gas.

When the steam flow and pressure problems were corrected in the second test series, removal efficiencies of up to 70 percent were achieved. The 70 percent reductions were achieved at 1.9 stoich with the PCC grade. A 50 percent reduction was easily achieved and repeated at 1 stoich. ECI expects that this capture performance can also be significantly enhanced by incorporating trace amounts of a non-toxic submicron catalyst with carbonate reagent.

In recent pilot combustor testing, removal efficiencies of 80 percent have been demonstrated with new nozzle designs.

Preparation for the demonstration included a boiler model to determine the optimum configuration for the injectors for both GCC and PCC conditions. Since the PCC was supplied at 20 percent solids versus 72 percent solids for the GCC, two separate pumping systems and nozzle sizes were built to achieve the various stoichiometric levels for the two products. In commercial applications, EES will inject both grades at a 50 percent solids dilution level to maximize atomization while keeping water inputs to a minimum in the furnace. Even when the PCC was injected at 20 percent solids, there was no impact on combustion performance. In fact, in some tests the combustion improved by a significant drop in CO levels.

ECI had four injector systems fabricated for installation in existing ports in the subject boiler. The ports were chosen based on the boiler model and were expected to be adequate to demonstrate the technology, but less effective than new ports specific to the purpose that could be installed during an outage. Two injectors were temporarily installed in the over fire air ducts and two were placed in side inspection doors near the rear wall above the burner elevation.

The Step boiler model was used to determine which existing ports could best be used to achieve reasonable coverage of the flue gas flow. The model was also used to determine nozzle flow requirements, design specifications and location of the in-furnace injectors for optimum distribution of the chemicals into the combustion zone for this short-term proof-of-concept exercise.

Results Summary

GCC Results: GCC supply pump flow was maintained at a flow rate of 230 gph (Stoich 2.3 feeding 59.3 percent solids), which resulted in an SO2 reading of 728 ppm for a reduction of 43 percent. EES and ECI are working toward the optimum product formulation for commercial application of the CCS-64X product platform (See Figure 1).

The decrease in efficiency at Stoich 1.4 resulted from exceeding design capacity of the nozzles by more than 200 percent to achieve the highest Stoich with the existing pump system. Despite the undetermined chemical waste caused by high flows, an SO2 reduction of 45 percent was still achieved. The dosage was then reduced to 10 gpm, 7 gpm and 0, resulting in an upward trend of SO2 readings back to the baseline. This data reiterates the importance of droplet size for performance efficiency. Product utilization was determined to be greater than 60 percent throughout the demonstration.

PCC Results: With all the feed going through the two over fire air ports at 1.3 stoich, a reduction of 56 percent was achieved. The economics of removing SO2 from the furnace are improved since the removal efficiency is so high. For example, to remove 70 percent SO2 using a DSI system in the back end with trona only and an electrostatic precipitator collection device, the stoich levels will be five to six time times NSR. To remove this from the furnace would be 1.9 to 2 times NSR with CCS-64X.

EES and ECI are working on improved nozzle design and a hybrid sorbent injection scheme that incorporates both furnace sorbent injection and direct sorbent injection to meet the U.S. Environmental Protection Agency's Cross State Air Pollution Rule requirements. EES is targeting SO2 reduction costs to be in the range of $400 to $600/ton SO2 removed.

Small Bearings at Concentrated Solar Plants

By Janaki Weiden, Global Market Manager, Solglide

Solar energy is a huge and important trend. And it is infinite and free, with the total amount of energy irradiated from the sun to the earth's surface each year providing enough for annual global consumption 10,000 times over. The benefits of solar power are both compelling and obvious, from reducing carbon emissions to providing a sustainable energy source.

So what makes the huge solar power trend work? Small parts, of course. To meet the ongoing demand for energy, it is crucial to continually enhance the longevity of the concentrated solar power (CSP) plant. The small parts that make up these large plants help to keep the applications maintenance free, long lasting and moving efficiently, extending overall facility life and productivity.

The key for any CSP plant is bearings, devices designed to reduce friction between two parts in motion, which saves energy by facilitating movement. There are many bearing options and the choice of bearings can have a major impact on plant productivity. The wrong technology could cause CSP plants to need continuous maintenance over the years, adding additional costs and uncertainty. The right technology can enable rapid scale-up to keep up with the booming solar industry, ensure minimum maintenance and keep the amount of energy to power the technology low, keeping plants running efficiently over the coming years.

Part of the Puzzle

Small parts play a huge difference in a technology's success, evidenced by the role bearings play in CSP plants. Solar power is produced by collecting sunlight and converting it into heat and finally electricity. This is done through the use of tracking structures equipped with flat or curved mirrors to concentrate the sunlight in a focused point or line.

In order to achieve the high temperatures required, solar radiation must be concentrated. Parabolic trough collectors represent the most advanced technology for use in doing this (see Figure 1). These troughs are attached together to form a "collector" that can be from 100 meters to 150 meters long. For solar power plants, the total length will be several kilometers. The troughs track the sun over the course of the day and focus the resulting radiation along the lines of the mirrors onto absorber tube receivers. Comprising 80 to 90 percent of the technology used in CSP plants, parabolic troughs are by far the most commonly employed solar power technology. Many parallel rows of solar collectors span the plant's solar field, tracking the sun as it moves. To collect sunlight, CSP plants may also use larger power towers in the middle of the solar field, surrounded by an array of flat, movable mirrors, known as heliostats (see Figure 2), which reflect sunlight to it.


Applied at the pivot points on the major tracking systems used to collect sunlight, specifically parabolic troughs and power towers, bearings enable the troughs to move easily and with little or no friction (see Figure 3).

Figure 3 Heliostat

While bearings are small components, they can make a big difference to the bottom line. Since not all bearings are created equal, CSP plant owners can look for certain features to optimize efficiency.

It is important to source bearings that are chemical and water resistant as well as weatherproof. This will lead to less corrosion from external elements and longer-lasting application, reducing replacement and maintenance costs. To be truly effective, the bearings also need to withstand extreme temperatures ranging from 0 C to 70 C.

Bearings that contain proprietary polytetrafluoroethylene (PTFE) compounds feature the lowest coefficient of friction of all solid materials, meaning smoother movements and extremely high wear resistance for CSP technologies. Low coefficient of friction of solid materials will result in less steel-on-steel action, less friction and, therefore, less wear and a longer life. This reduced friction and avoidance of stick-slip effects in the tracking systems allows mirrors to move more easily towards the sun with less energy usage. PTFE, with its extreme weather resistance and high corrosion resistance, can increase the long-term operational efficiency of solar equipment, reduce energy usage and decrease long-term costs.

Manufacturers must also consider different backing layers on the bearings they choose. Ideal options include normal steel protected with a proprietary corrosion protection system, and aluminum or stainless steel backings, all of which do not rust and therefore, never need replacing.

To comply with environmental regulations, bearings that feature lightweight materials are ideal, as well as those that are also free of heavy metals and banned chemicals such as chrome VI and perfluorooctanoic acid (PfOA). Additionally, it is worthy to note that bearings that can operate without grease can help plant operators avoid cleaning costs needed to remove drippings from the structures, which impedes effectiveness.

Choosing the Right Supplier

The importance of small parts cannot be undervalued. CSP directors, owners and engineers must choose their suppliers with care to ensure long-term support and scalability as demand rises. The key is to partner with experienced global companies with high-performance solutions and innovation teams that keep up with this rapidly advancing field.

Other factors to evaluate include testing and research and development (R&D) capabilities. Selecting bearings with a proven track record is ideal to guarantee performance, so partner with companies that can provide thorough testing data supporting resistance to temperature, water and friction as well as the influence of various shaft surfaces and coatings.

Bearings can offer clear-cut solutions for CSP plants, by being able to offer different PTFE blends to fit the needs of the plant. Bearings help to reduce maintenance costs while increasing overall efficiency of the technologies on CSP plants, not such a small part after all.

A Long-term Review of Fogging

By Joe Zwers, Freelance Writer

Some technologies quickly fade away; others become a part of standard operating procedure. Back in the 1990s, turbine inlet fogging took off as utilities found it was an inexpensive way to boost power output when it was needed most. In 2002, Leonard Angello, manager of combustion turbine technology for the Electric Power Research Institute stated, "Fogging is a cheap way to add capacity when you need it most, especially during the hot days of summer. It tends to give the biggest bang for the dollar compared to other inlet air cooling technologies."

So, a decade later, how well has that statement held up? Are companies still using the fogging equipment they bought back then? Do the systems hold up for long term operation?

In the high desert town of Boron, Calif., two 48 MW Siemens Westinghouse 251B10 gas turbines—one owned by Mojave Cogen and the other by U.S. Borax—have been using fogging systems supplied by Mee Industries since the early '90s. This makes them one of the earliest pioneers of fog.

"The fogging system still works well," said Michael LaFollette, a utility engineer for U.S. Borax. "We occasionally check the nozzles, replace any that need it and do regular preventive maintenance on the pumps. Nothing very difficult."

In this article, we take a look at three other companies' long-term experience, good and bad, with using fogging on different types of turbines, under varying operations and at locations ranging from the desert to India's humid west coast. Most importantly, we find out how they get the most out of their equipment.

Chemical Plant Cogen

Reliance Industries Ltd. is India's largest business enterprise with annual revenues from its energy and materials businesses running in excess of $44 billion. Reliance's Hazira Manufacturing Division, located on India's western coast near Surat, Gujarat, consists of a Naphtha cracker together with 16 other plants producing fiber intermediates, plastics and polyester. The first construction phase included a cogeneration plant which converts natural gas, cracker gas, C9, naphtha and high sulfur diesel into the steam and electricity used by the complex.

Fogging is a cheap way to add capacity when you need it most, especially during the hot days of summer.

Commissioned in September 1991, the cogen facility has seven 30 MW GE Frame 6 PG 3541gas turbines, two 36 MW GE Frame 6 PG 6581B gas turbines, two 40 MW steam turbines and auxiliary boiler and nine 125 tons per hour (TPH) heat recovery steam generators (HRSG). Together, the plant produces up to 350 MW and 1,220 tons per hour of steam. Due to the steam heat recovery, the plant operates with an effective fuel utilization of approximately 70 percent. Under normal operating conditions, the cogen plant allows the complex to operate independently of the grid (the Gujarat Electricity Board), but it can connect to the grid when needed.

"The efficiency of the gas turbines is greater than the steam turbines," said Ninad Bhadkamkar, the plant's senior general manager. "Hence, if we load the gas turbines more than the steam turbines, it gives a cost benefit in unit generation."

To get more output from the GTs, in 2002 Reliance installed a fogging system on one of the Frame 6s, following it up with four more. Bhadkamkar says fogging was chosen due to the low capital cost, reliability and ease of maintenance. He doesn't do overspray, but sets the foggers to cool the air to about five degrees above the wet bulb temperature.

He said there have been problems with seal failures on the pumps. This is a common issue with foggers that have a lot of run time because the deionized water does a poor job of lubricating the seals. This issue has been addressed by switching to flushed seal pumps for such applications. He also recommends that the inlet ducts be made or stainless steel or have a water resistant coating to prevent erosion.

But any such issues are more than offset by the power boost. When the foggers are used, he says he gets about an extra 8 to 10 percent output.

"Our site is near the coast and the humidity level is very high for seven to eight months out of the year," said Bhadkamkar. "The rest of the months we are running the fogging skids."

California Peaking

Wellhead Electric Co. Inc. of Sacramento, Calif., operates several peaking and cogen plants around the state, mostly under contract to investor owned utilities, primarily using GE LM6000 and Pratt and Whitney FT4 turbines.

Tom Tinucci, Wellhead's manager of Engineering & Operations, said the units are mostly fast-start (10 minutes), simple-cycle gas turbines with the exhaust going through an SCR emissions reduction device. Most of the plants are remotely operable and can start at any time if called to provide local grid support. In 2001 Wellhead installed its first fogging unit and now has Meefog systems at six of its plants stretching from Yolo County through the San Joaquin Valley and as far south as coastal San Diego.

"When chilling is not available, fogging is considered," said Tinucci. "While fogging can only get down to wet bulb temperatures (or slightly lower by 1 to 3 F) and will not get the air temperature to as low as a chilling system, the cost per degree cooled for fogging is economical when compared to other forms of cooling such as chilling."

With a decade of experience with six plants, Tinucci has several tips to pass on to others using inlet fogging. He says to keep up the basic maintenance and to always look for design improvements that reduce the future maintenance such as getting brass out of the pumps and using stainless wetted parts. He also advises paying attention to the brazing of the nozzles to the piping. Finally he says that, due to the wet environment, galvanized structures are better than painted surfaces for the inlet house since this avoids the need to repaint the surfaces annually.

Tinucci added that keeps the fogging arrays far enough from the inlet to ensure there is complete atomization of the water.

"The key to successful fog is to pay a lot of attention to where it is mounted in the inlet house so that one gets the maximum evaporation effect (cooling) and minimizes droplet formation (which ultimately goes to drain)," he said.

Round-the-Clock Operation

Portland General Electric's (PGE) Coyote Springs plant, near the Columbia River in Oregon, has two GE Frame 7FAs. Unit 1 went commercial in 1995 and two years later. PGE bought a fogging system from a major fog OEM which was added to Unit 1. Unit 2, on the other hand, came equipped with a fogger from the turbine OEM. Dan Turley, a project manager at the plant, says that between 1997 and 2003, they ran on-line water wash (OLWW) on Unit 1 for half an hour daily, when the temperature was above 50 degrees and the fogger whenever the temperature was above 60 degrees. During the summer, the fogger might run around the clock. When GE began restricting the use of water few years back, he estimates that the unit had 1,000 of OLWW and 10,000 of fogging time.

Turley says that the Unit 2 fogging system did not perform as well as the Unit 1 fogger. The second fogger had fewer nozzles and produced droplets that were too large so they didn't fully evaporate, and the nozzles array was too close to the compressor bell mouth.

"On Unit 2, we had nothing but problems; we could see huge droplets coming off the nozzles," says Turley. "We took out the original nozzle array and put in a nozzle system similar to Unit 1 and have been fogging the machine ever since."

GE introduced new R0 blades and will allow 7FAs that have these blades to use unlimited fogging. Those blades have been installed on Unit 2 and will probably also be installed on Unit 1 so it can resume fogging.

"Fogging is an integral part of our economics; in a normal year, the fogger will generate $350,000 in net profit," says Turley. "Having the properly designed and functioning fogging system on both units has made us a tremendous amount of money compared to the cost of the system."

Techniques to Cut Construction Time, Cost and Corrosion

By Todd Padezanin, Project Manager Energy and Petrochemical Market, Hilti North America

Welding is unavoidable during construction projects at all types of power plants. It is an indispensable skill and is often the most economical solution for primary structural steel fabrication, pipe joints and countless other connection types. However, welding of protective-coated steel—whether painted or galvanized—presents challenges to both the welder and the facility owner. However, now there are innovative and cost effective solutions for a variety of supplementary steel fabrications and light-duty stud fastening applications that minimize or eliminate these concerns.

Supports for piping, cable and conduit racks, instrumentation panels, equipment stands, access platforms and other supplementary steel assemblies are traditionally welded using various hot-rolled steel shapes. If the supports will be exposed to the elements or corrosive industrial environments, the engineer will typically specify a suitable protective coating system. Shop fabricated supports can be galvanized or painted after assembly.

Sometimes, field conditions require welded modifications of prefabricated assemblies, which in turn necessitates field repair of the protective coating system. Additionally, new supplementary steel is commonly welded to existing structures which are already painted or galvanized. In each case, the project specification may require surface preparation of painted and galvanized steel prior to welding.

Surface preparation is required for reasons including health, safety and weld quality. Some welds can be made with specific electrodes through certain paint systems. Unfortunately, using the wrong material combinations or welding techniques can compromise the finished weld. Even if the weld is done effectively without paint removal, existing coatings near the weld can be damaged. Without proper ventilation or respiratory protection, vaporized paint fumes can be hazardous to the welder. Proper surface preparation to remove existing paint will help avoid these problems, but can also increase the welded connection's completion time and cost. Lastly, field welding can require an additional fire watch person, further increasing the labor cost.

For galvanized steel, the cost of surface preparation is unavoidable. The American Welding Society's (AWS) Specification D-19.0, Welding Zinc Coated Steel, and the American Galvanizers Association's (AGA) Guide Welding and Hot Dip Galvanizing both require zinc coating removal before welding. Similar to paint vaporization, zinc removal by "burn-off" also can create hazardous fumes that necessitate proper ventilation or respiratory protection.

Once field welds are completed, bare weld and base metal surfaces must be coated with a suitable paint system or organic zinc-rich coating system (a.k.a. cold zinc galvanizing). Damaged coatings must be repaired. The Society for Protective Coatings (SSPC) Standards and the American Institute of Steel Construction (AISC) Code of Standard Practice for Buildings and Bridges both specify surface preparation prior to repair painting or cold zinc galvanizing. Inadequate surface preparation, painting or zinc application can cause premature coating failures, adding to the owner's maintenance costs.

There is a growing trend to use pre-engineered modular support systems for many types of supports and supplementary steel structures. Because these modular systems virtually eliminate the welding and coating repair procedures discussed previously, the resulting assemblies are often constructed faster with a lower total cost. In fact, pre-engineered modular support systems have begun to replace welded supplementary steel for small and medium pipe supports, cable tray hangers, instrumentation panel stands and access platforms.

The most common pre-engineered modular support system member shapes are tubes and channels. Cold-formed steel 1-5/8" slotted channel systems, frequently nicknamed "strut," have been used for decades to build a wide variety of supports. Although the section properties are fairly consistent among manufacturers, proprietary connectors and accessories can offer specific benefits such as easier adjustability, faster assembly and three-dimensional framing versatility. Proprietary and third-party accessories are on the market to connect items like pipes, conduits, tubing, cable tray hold-down clips, floor plates, switches, junction boxes and process control panels.

More recently, hot dip galvanized cold-formed steel rectangular tube sections with larger cross sections and thicker walls have entered the market. These shapes have greater flexural and torsional resistance compared to 1-5/8" slotted channel. Their larger section properties allow tube systems to bridge the load bearing gap between strut and hot-rolled steel shapes. Depending on the galvanization, they can be installed in many outdoor applications and corrosive industrial environments.

A variety of framing connectors accommodate construction of supports and structures including bents, goalposts, crosses, trapezes, knee braces, racks, bridges, stands and platforms. Systems include an assortment of baseplates for concrete anchorage and multiple clamping assemblies for mechanical attachment to primary structural steel. Accessories are designed to attach support devices including U-bolts and pipe shoes.

One proprietary system's rectangular tube sections have continuous rows of holes on all four sides. These holes are designed to receive adjustable framing connectors, fasteners, and other attachment accessories. Most framing connectors are cast steel or iron brackets with slotted holes and serrated faying surfaces. The fastening hardware for these connectors include springs and serrated plate washers which mesh with the bracket serrations and allow for incremental adjustment of intersecting members over the entire member length.

Perhaps most significantly, strut can be attached to these tube sections in either longitudinal or transverse configurations. This means that modular tube assemblies can also support devices designed for strut mounting, thus providing many cost effective and versatile alternatives to welded hot-rolled steel.

Some pre-engineered modular support system manufacturers also provide design tools such as CAD, PDMS, and BIM objects, engineering software, as well as design and drafting services. These tools and services can help contractors to field-design supports and supplementary steel assemblies, and give relief to engineers and owners constrained by tight budgets.

Example: Cable Tray Supports

SM Electric was an electrical subcontractor on the scrubber addition project at the Public Service Enterprise Group (PSEG) Hudson Generating Station in Jersey City, N.J. As part of their work, SM Electric was responsible for designing and erecting some cable tray supports that were too heavily loaded for strut. Traditionally, the construction team might have procured supplementary steel from a steel fabricator, or deployed certified welders and ironworkers to build supports in place, or both. However, to keep the project on schedule SM Electric had already erected cable trays in some locations with temporary supports. Congestion in some of these locations made traditional methods relatively expensive.

Earlier in the project, SM Electric built a simple panel stand using a pre-engineered modular support system. Project Engineer Chris Gargiule believed that system would be ideal for a cable tray support tower, too. Taking advantage of the manufacturer's technical support and 3-D CAD objects, SM Electric designed a 40-foot-high supplementary steel tower. The entire structure was erected piece by piece and adjusted in place using the manufacturer's various bolted connectors.

According to Gargiule the design minimized costs in a few ways. PSEG saved about $100,000 in material costs by using the pre-engineered system instead of hot-rolled steel, but there were other savings, too. The pre-engineered system served dual purpose as structural frame and support device, minimizing additional strut and accessories. The structure's relative light weight reduced its foundation sizes. Pre-engineered mechanical connectors eliminated the need to modify the primary structure for lateral support attachments. And, perhaps most importantly, the project stayed on schedule.

Other Prime Candidates

Some types of light-duty steel attachments are also prime candidates for innovative, cost effective, corrosion-resistant alternatives. For example, static electrical grounding connections, cable tray clips, strut attachment to structural steel and floor grating hold-downs are frequently welded. As with steel fabrication, these welded connections can have similar surface preparation and protective coating requirements. Even when these attachments are not welded, traditional mechanical methods like drilling, through-bolting or tapping, powder-actuated nailing and screw fastening are not always ideal. Each of these methods can damage existing coatings and drilling methods can be time-consuming.

Powder-actuated fasteners are driven directly into base steel using portable, hand-held tools. Powder-actuated fastening to steel with ballistic point nails has been common practice for decades. In fact, today it is standard practice for a variety of structural and non-structural connections. Many of the attachments discussed previously can be made with powder-actuated fasteners, eliminating the surface preparation and coating repairs required for welding. As a result, these fastenings are finished more quickly and at a lower cost than other traditional methods.

A fastener's ballistic point will commonly penetrate through steel plates, flanges and tube walls. This nail penetration may be unacceptable in some corrosive environments because it may damage protective coatings on the backside of steel flanges and plates. For this reason, stainless steel blunt-tip powder-actuated threaded stud fasteners entered the market in 2003. Unlike ballistic point fasteners, blunt-tip fasteners are driven into small pre-drilled holes and do not penetrate through base steel that is 5/16" thick or greater.

Blunt tip fasteners are assembled with three elements: A 4.5 mm diameter blunt-tip stainless steel shank with a forged head, a stainless steel threaded sleeve mounted to the shank and an optional stainless steel and neoprene sealing washer. The pre-drilled pilot hole is drilled with a 4 mm stop-type bit that scrapes away protective coatings on the base steel when it reaches the required drilling depth. This provides a visual indication for quality assurance, although obviously it also removes the coating locally at the intended fastening location. The fastener's sealing washer protects this small area, eliminating the need for coating repairs.

The fastener's blunt tip is chamfered, which facilitates centering in the pilot hole. It is driven into the pilot hole using a specific powder-actuated tool. Because the shank diameter is 0.5 mm larger than the pilot hole, fastener installation displaces the base steel. Residual elasticity results in the base steel clamping around the fastener shank, creating a friction hold. Additionally, the driving process generates local heat substantial enough to partially fuse the fastener shank to the steel. When driven into carbon steel, the fastener's allowable tension capacity is in the range of 400 to 500 pounds, depending on the base steel tensile strength, using a 5:1 safety factor.

Static electric grounding and bonding connections to steel are often made with welded studs, drilling and tapping, or exothermic welds. One blunt tip fastener on the market is also listed by Underwriters Laboratories as a grounding and bonding connector. These fasteners have been used in lieu of these traditional methods inside power plants, oil refineries and other industrial facilities.

Strut is frequently welded to structural steel for a variety of electrical, mechanical and instrumentation supports, although many contractors now use ballistic point powder-actuated fasteners instead. Blunt tip fasteners have been substituted for strut welding on many projects due to the labor savings realized by avoiding surface preparation and coating repair. Blunt tip fasteners have also been used on projects where ballistic point fasteners were prohibited by the engineer or owner. For these reasons, blunt tip fasteners are now included in various construction standards for several large plant owners and engineering, procurement and construction firms.

Cable tray hold-down clips are commonly attached to structural steel by welding threaded studs or by drilling and through bolting. Blunt tip fasteners have been used to replace both methods. Other times, strut is welded to the steel flanges and cable trays laid on top, using strut accessories and bolts to fasten the hold down clips. As discussed in the previous paragraph, blunt tip fasteners have also been used for this specific strut-to-steel attachment.

Steel grating is typically fastened to steel beams with self-drilling screws and saddle clips. However, screws will penetrate through thin steel flanges and damage protective coatings on the underside. As long as the base steel is thick enough, blunt tip fasteners will eliminate this concern. There are tools on the market that can install blunt tip and other types of powder-actuated grating fasteners with grating panels already in place. Some blunt tip fastener and grating clip assemblies designed for heavy industrial environments have also been evaluated for resistance to loosening under vibration.

Example: Strut Fastened to Structural Steel

Action Electrical & Mechanical Contractors was awarded a subcontract to install lighting and receptacles at the Southern Co. Plant Scherer Unit 3 SCR-FGD addition project in Juliette, Ga. As part of the work, Action needed to attach approximately 1,700 pieces of strut to painted structural steel for conduit and fixture supports. Action prefers to use powder-actuated ballistic point stud fasteners for such strut attachments. However, to prevent paint damage Southern Co. would not allow fasteners to penetrate through the structural steel flanges.

Action's Construction Manager Brian Carbonneau knew that welding strut would be even more expensive. He determined that blunt tip powder-actuated fasteners would be the most cost effective solution. Using the manufacturer's field support both on site and at the Engineer's office, Action secured approval and got their installers trained. Carbonneau calculated a total installed cost savings of 70 percent using blunt-tip fasteners instead of welding, including a 93 percent labor savings.

It is worthwhile for owners, contractors and engineers to explore alternative construction methods to minimize the cost and schedule implications of field welding and coating repairs. For supplementary steel and light-duty fastening applications like the ones discussed in this article, the time and cost savings can be considerable.

Author: Todd Padezanin is a Project Manager with Hilti North America's Energy and Industry division, covering power, oil and gas and chemical industry projects in the northeastern United States. He has a B.S. in Civil Engineering and Engineering and Public Policy from Carnegie Mellon with professional experience in structural design, value engineering, business development, product management and project management.

Trends in Packaged Boiler Design

By Jason Jacobi, Sales Manager, V. Ganapathy, Boiler Consultant and Muthu Veeramuthumoni, Engineering Manager, Cleaver-Brooks Engineered Boiler Systems

Designing large package boilers is more challenging than ever. Demand from the marketplace is increasing for special features including low emissions, quick startup requirements, hot standby operation, heavy cycling ability, high turndown and increased efficiency, to name a few. It is no longer feasible for a plant engineer to select a boiler out of a catalog expecting that it will meet his exact needs. The same holds true for boiler manufacturers, who must evaluate several heat transfer scenarios before arriving at a final design. The standard boiler models developed decades ago may not be suitable for today's needs. New boilers have to be engineered carefully, taking into consideration burner requirements such as excess air, flue gas recirculation (FGR) and burner flame shape, which impacts the furnace geometry. Boiler heating surface and tube spacing has to be optimized to obtain good thermal performance and low fan power consumption over a wide load range. Performance of ancillary equipment has to be evaluated to ensure proper integration. In short, custom design is the key to success in today's industrial watertube boiler market.

This article outlines two unique boiler systems recently engineered and supplied by Cleaver Brooks Engineered Boiler Systems group that are in successful operation in North America. The first is a 150,000 lb/hr, 650 psig, 750 F superheated Nebraska D-type standby boiler for a city utility power plant. The second is a 426,000 lb/hr, 550 psig saturated Nebraska boiler for an oil major with an elevated steam drum and an innovative closed-loop glycol heat recovery system to boost efficiency. Both systems are natural gas fired.

Boiler Design

The 150,000 lb/hr Nebraska boiler system is unique in many ways. The boiler operates as a standby boiler in conjunction with the main gas turbines and heat recovery steam generators (HRSGs) at a city utility and is designed to operate as an integral part of the overall plant. Several custom-engineered features are summarized below.

The system is "future 15 ppm ready." It is currently operating at 76 ppmv NOx in accordance with current emissions regulations in the area. However, the city engineers wanted to plan ahead and purchase a system that can easily be converted to lower emissions in the future. The excess air and FGR rates were determined to be 15 percent and 5 percent respectively for meeting 76 ppmv. However, to meet the future 15 ppmv NOx limit, 20 percent excess air and 25 percent FGR are required. This has a significant impact on the overall boiler design due to the large variation in flue gas flows as seen in Table 1.

Several options were modeled with bare and finned tubes in the convection bank. An optimum configuration was arrived at considering the gas pressure drop, economizer exit gas temperature and fan power consumption. Multiple rows of finned tubes of density 3 fins/in were used in the low-temperature zone of the convection bank to optimize the energy transfer. The "approach" point (temperature difference between saturation and water temperature leaving the economizer) will be affected by the large variations in flue gas flow through the boiler. The approach point is particularly important as the water leaving the economizer is used to condense steam for use as sweetwater for the interstage spray desuperheater. Boiler bank tube spacing is wider than normal to accommodate the variations in flue gas flow through the boiler. This custom approach alleviates the city utility's concerns about future emissions regulations. Only the FD Fan and burner spuds need to be replaced should regulations become more stringent.

As an auxiliary boiler, the unit will be in standby condition most of the time, but must be able to achieve full load within four to five minutes upon a system trip of the main HRSGs. This requirement was achieved with some outside-of-the-box thinking. Cleaver-Brooks' proprietary Natcom burner includes a "center core" stabilizing gas injector that is usually used to improve flame stability and turndown. For this application, the center core is also used as a second smaller burner during hot standby. Heat input is approximately 5 percent MCR. This maintains the boiler at pressure so it can be ramped to full load in a short period. A small dedicated fan is used during hot standby to avoid operating the main FD Fan, which saves considerable money over time. An added benefit of this design is that the air purge cycle normally specified by NFPA is not required since the burner is already running. Once the main fan is started up, the main gas lances are lit off and the unit can immediately begin ramping, which saves time. A lower drum steam heating coil is also provided to further assist in maintaining the boiler in hot standby conditions.

The feedwater for the boiler is condensate from the steam turbine at about 90 F. The city engineers chose not to use a traditional deaerator for this system, which preheats the condensate in a typical system. As such, this cold condensate must be preheated above the flue gas water dew point prior to entering the economizer to avoid corrosion. The city utility engineers wanted a large margin to ensure no condensation occurred. Therefore, 200 F was chosen as the inlet feed water temperature. A shell-and-tube heat exchanger was selected to preheat the condensate. Also considering the extended operation at low loads, a parallel water flow economizer was specified by the city engineers to further avoid corrosion.

A dual-stage superheater system was provided. This design incorporates interstage spray attemperation to maintain a steady steam temperature over turndown. A modulating control valve varies the amount of spray injection based on a signal from a temperature transmitter located downstream in the main plant piping. The second stage superheater ensures that the spray water is fully heated which avoids the potential for any water droplets eventually reaching the turbine blades.

Since the customer did not want to inject the condensate directly into the steam for superheater temperature control, a sweetwater condensing system was used. This approach ensures high purity at the main steam outlet since it avoids adding the solids typically entrained in boiler feed water (or condensate in this case). A heat exchanger located between the economizer and the steam drum is used to condense steam into water, which is used for spray attemperation. Calculations had to be done at various loads to ensure the physical location of the exchanger provided adequate head for spray after accounting for the line and superheater steam side losses.

The system is capable of operating from 10 to 100 percent. Due to this fact, the pressure drop in the superheater had to be reasonably high at full load to account for the large variation in flow. At lower loads, the steam side pressure drop can be small, resulting in non-uniformity of flow inside the tubes. This approach reduces the potential for premature tube failure. Also the location of the superheater in the convection bank was optimized considering the steam temperature variations with load.

Welded tube-to-drum connections were used in the boiler bank and furnace instead of the typical rolled joints to minimize thermal stresses due to cycling operation and fast load changes.

Table 1 shows the predicted performance of the boiler. Performance tests done during start-up closely matched the predicted values within instrument errors. Note the large difference in flue gas flows due to higher excess air and FGR rates. Standard natural gas is the fuel used. Note the variations in flue gas quantities for future conditions of lower NOx. The system was optimized for both emissions scenarios.

Large Package Boilers

Designing package boilers greater than 250,000 lb/hr steam capacity is quite a challenge given the shipping limitations in the U.S. and Canada. Typically, these larger boilers are field-erected designs built on-site by a costly army of workers. Working to address the large steam demands of the marketplace, Cleaver-Brooks developed a novel modularized design, using concepts widely used in the design of their HRSG and waste heat boilers, namely an elevated steam drum. Removing the drum from the boiler profile allows for larger furnaces and tube banks within the same shipping envelope, thus increasing capacity.

The main boiler modules were fully shop-assembled, hydrotested, insulated, lagged and each shipped as one piece. The steam drums were hydrotested, insulated, lagged and shipped separately. Once at the jobsite, the steam drums were connected to the main boiler module by an external downcomer and riser system, the sizing of which was arrived at after a careful evaluation of the boiler circulation. The unheated downcomers ensure superior natural circulation, a common feature for HRSGs. The downcomer/riser piping is pre-fabricated and only 28 field pipe welds were required to complete the pressure vessel. Once the burners were mounted, each complete packaged boiler was ready to be piped up and put into service.

Water-Cooled Furnace Design

A completely water-cooled membrane boiler design is a feature of Cleaver-Brooks' Nebraska boilers. This design has been in operation for nearly two decades. Traditionally, burner front wall designs include refractory, which re-radiates energy back to the flame. This increases local combustion temperatures and generates additional NOx. Some older designs also had refractory around the burner throat and on the floor. Much of the NOx formation occurs at the front end of the furnace, hence a membrane front wall with a refractory-free burner throat helps reduce NOx. Additional advantages of completely water-cooled designs include:

  • Lower heat flux for a given volume, about 9 to 12 percent, due to the higher effective area for a given furnace volume
  • Lower area heat release rate
  • Lower excess air or FGR rates may be used due to less intense combustion process compared to a refractory lined furnace
  • Furnace is leak proof and hence no bypass of gases to second pass, which results in larger CO formation and inefficiency
  • No refractory maintenance concerns, no refractory gas seals
  • Startup rates can be faster as concerns with refractory breaking or cracking are absent
  • No casing leaks or corrosion concerns as the furnace is leak proof in a fully membrane wall unit
  • Minimum thermal stresses between casing and tubes during startup or shut down as the entire enclosure is at a constant temperature equal to the saturation temperature of steam.

High Efficiency Design

In order to improve the boiler efficiency, a closed-loop glycol recirculation system was used. Heat is scavenged from the stack and pumped to a series of air preheaters to maximize efficiency. The typical exit gas temperature in a package boiler with economizer is 300 F. With the glycol system, the exit gas temperature could be lowered to less than 200 F, even with 230 F feed water, since the final heat sink is the glycol scavenger and not the economizer. With 200 F exit gas temperature, the boiler efficiency is at least 2 to 3 percent higher than usual, which results in substantial reduction in fuel costs for such a large packaged boiler. This approach is far superior to tubular air heaters or air-to-air exchangers used in older designs. The flue gas side pressure drop is also lower with these finned tube coils.

The jobsite was located in the Northern Canadian Oil Sands region, which experiences harsh winters. The first stage inlet air heater increases combustion air from a minimum -40 F to approximately 50 F before entering the FD Fan. Fan reliability is improved and capital cost is reduced. The second stage inlet air heater increases the air temp into the burner significantly, which reduces fuel consumption. Since this hot inlet air is downstream of the FD Fan, the power consumption is reduced compared to single-stage air heater system located upstream of the fan. A bypass system helps limit the air temperature into the fan during the summer.

The engineering experience gathered during the design, fabrication and commissioning of steam generators has re-assured the Cleaver-Brooks team that large package boilers can be custom-engineered and built cost-effectively while meeting a variety of unique customer needs.

The standard boiler vessel concept has been replaced by the benefits of custom design. Job-specific needs such as low emissions, quick start-up, standby operation, turndown and superheat have to be reviewed on a case-by-case basis. Furnace geometry and evaporator tube spacing should be modified in order to optimize the performance. Finned tubes may be considered to minimize the gas pressure drop and the footprint while also meeting the desired thermal performance. All design decisions should be driven by the need to increase efficiency. By analyzing these criteria and more, maximum value can be realized for new boiler owners.

Best Practices in Cooling Tower Reconstruction

By Greg Coy, Global Product Manager, Aftermarket Services, SPX Cooling Technologies Inc.

After many years of operation, cooling towers may require more than small repair work and individual component replacement to return the thermal performance necessary to support plant processes. Above and beyond thermal performance is the need to address durability of the tower. Replacement of the heat transfer media ("fill") in an older tower will boost cooling capacity short-term, but unless structural integrity is addressed, there will be no improvement in the longevity of the tower.

Wood cooling tower prior to reconstruction

The structures of older wood-construction towers, for example, have no doubt seen an inherent loss of strength depending on variables such as wood species and operating conditions. Spot repairs are an inexpensive approach to maintain operability; however, they do not address the potential loss in the structural safety factor of the tower. With proper guidance, a successful tower reconstruction project can achieve returns in both cooling capacity and structural integrity, thus extending the life of the tower.

With these goals in mind, how can you plan and execute a successful project and avoid potential reconstruction pitfalls? Regardless of your experience with cooling tower reconstruction, a review of industry best practices will help ensure your success.

Know your intentions. Occasionally, user requirements are limited to what might be termed "professional maintenance." That is to say, the owner wants the tower restored to operational dependability by replacing specific components. Where the required restoration is relatively minor, and the cooling capacity of the tower is considered non-critical, competent specialists in the field of maintenance and repair will normally be satisfactory.

Usually, however, the thermal capability of the tower is of concern as is structural, mechanical and operational integrity. Capital investment to reconstruct the tower can yield substantial and quick returns with the implementation of the latest technological developments in the industry. In these cases, it is recommended that you contact only those companies who design, manufacture and construct cooling towers or their authorized representatives.

Plan for safety. Inspection and reconstruction personnel should be sufficiently trained in cooling tower access and should implement a full job safety analysis (JSA) before accessing any cooling tower. Cooling towers have some inherent dangers such as high voltage power, fall hazards, trip hazards and areas for cuts, scrapes, and bruises. JSA's should address all hazards that are specific to the tower being inspected. The JSA should define appropriate mitigation plans for each hazard including items such as lockout/tagout, personal protective equipment and fall protection.

Inspect your tower. The scope of work for your reconstruction project needs to be defined by the findings and recommendations of an experienced cooling tower professional. A thorough inspection should include the following:

  • Deterioration in tower structural elements
  • Clogging or damage to fill
  • Missing nozzles or leaking pipes
  • Wear and corrosion of mechanical components
  • Deterioration of ladders and guardrails
  • Condition of drift eliminators and louvers.
Post-reconstruction showing FRP structural enhancements

Whether you pre-select a company in which you have confidence, or award the contract on the basis of competitive bidding, the effort should begin with an inspection of your tower by each bidder. Although such inspections will usually involve some cost to you, they are essential to the process. Only by inspecting the tower can the successful bidder determine the full scope of work required. The results of the inspection will assist you in determining the advisability of attempted reconstruction.

Define scope of work. When combining your intentions with the results of the inspection, decisions must be made to achieve plant objectives without losing sight of capital budget plans. Listen to industry leaders for guidance, as there may be new solutions that meet multiple demands of the project. For example, if your fill is clogged or damaged beyond repair, there may be an opportunity to replace with higher-performing media. A common reconstruction project where additional cooling capacity is sought involves replacing the original splash fill with PVC film fill where water quality allows. If the integrity of fill is sufficient and additional thermal performance is not sought, simply cleaning the fill may meet project intentions.

Reconstruction also presents an excellent opportunity to upgrade the structural components of the tower. Replacement of wood with fiberglass reinforced plastic (FRP) is an excellent choice when the lifespan of the tower is a top priority. For example, during a reconstruction job to a wood cross-flow tower at a coal-powered baseload plant, a customer may choose to make structural upgrades such as:

  • Hot water deck and deck supports from plywood to FRP
  • Canopy deck and deck supports from wood to FRP
  • Circumferential girts at the louver face from wood to FRP
  • Steel riser support beam from carbon steel to stainless steel
  • Circumferential walkway from wood to FRP
  • Pipe saddle supports from wood to FRP ( for submerged wet material area)
  • Splice plates for the structure from wood to FRP.

Pre-test the tower. It is not enough to know the original design performance of the tower. Age and physical deterioration will undoubtedly have taken its toll on the tower's capacity. A performance test prior to reconstruction gives the bidder a starting point to establish his promise of capacity improvement—and gives you a reference point for evaluating the final results. The Cooling Tower Institute (CTI) has published thermal test code ATC-105 by which the performance of a cooling tower can be accurately determined.

However, because rather specialized instrumentation is required to determine precise water flow rates, air rates and temperatures, full-scale performance testing may require the assistance of an outside agency. A reputable cooling tower company should have both the trained personnel and the instrumentation required to accurately establish the tower's performance level. CTI can provide you with assistance in locating a reputable cooling tower company to perform the recommended performance testing. The test will not be without cost, but will yield critical knowledge.

Be selective. Choose the company which you feel knows most about your type of tower, and from whose efforts you will gain the greatest benefit. Consider these questions when evaluating a bid:

  • Are you confident their scope is comprehensive enough to achieve the goals of the project?
  • Are the bids you are comparing truly an "apples-to-apples" when considering price and scope?
  • What is their history and reputation in meeting outage schedules and completing projects on-time?
  • How does their safety record compare with other bidders?
  • Do they have your required goal in mind?
  • Are they able to provide a temporary cooling solution (if needed)?
  • Whose fill, nozzles, drift eliminators, fans, speed reducers and so on, will be used, and are those components capable of working well together?
  • Where will the responsibility for overall warranty be?

As the purchaser of a service, it is your responsibility to seek satisfactory answers to these questions. Ask for multiple references from each supplier to be confident that the company you select has an excellent reputation in the industry.

Post-test the tower. A performance test after the work has been completed establishes the level of performance improvement, and determines whether or not the guarantee has been met.

Outline your future maintenance schedule. Ask your supplier for recommendations on scope and timing of the maintenance required to prevent or reduce the degradation of your cooling tower. At a minimum, every cell of your cooling tower should receive an annual professional inspection of the following components:

  • Gearbox
  • Gearbox oil and seals
  • Driveshaft
  • Water basins
  • Fan stacks
  • Fan tip clearance and pitch
  • Fill Water piping and nozzles
  • Ladders and other safety components.

Also note that some cooling tower reconstruction companies can provide proactive maintenance services. Be sure to ask for a proposal in your bid. Considering the heavy demands placed on the cooling towers at your power plant, proactive maintenance is essential in extending the length of time between repairs and reconstruction. Recent collapses of aged towers across the industry highlight the extreme risks associated with lack of maintenance, including lost revenue, extraordinary costs and injury to personnel while emphasizing the importance of proper inspections, testing and repairs.

Small repair work and component replacement are sometimes not enough to address durability and structural integrity issues. With detailed planning for ultimate objectives and safety, experienced inspection, clear scope of work, careful selection of suppliers, pre- and post-testing and planning for future maintenance, towers can be successfully reconstructed with returns in cooling capacity, structural integrity and longevity of the tower.

Mass Concrete and Power Generation

By John Gajda, P.E., and Jon Feld, EIT, CTL Group

Construction for new power generation facilities, whether it's wind, solar, geothermal, coal, gas or nuclear, often involves massive concrete placements. Owners expect concrete structures to have minimal cracking and a long service life. Decisions and practices prior to and during construction determine whether or not the concrete of such placements crack and can also affect whether or not the concrete achieves the desired service life.

Concrete setting and strength development is due to hydration of the cement and other cementitious materials (such as fly ash) in the concrete mix. Hydration generates significant amounts of heat. In thin placements that are one to two feet thick, this heat is dissipated almost as quickly as it is generated. In thicker placements, the heat cannot escape as quickly as it is generated, and temperatures in the concrete increase. Depending on the concrete and the thickness of the placement, internal temperatures can become excessively high before the concrete begins to cool. High internal temperatures can cause large temperature differences between the interior and surface of the concrete. Temperature differences cause thermal stresses, which if excessive, result in cracking of the concrete.

A steam generator turbine support structure under construction. Photo courtesy Braxton Plyler, The Industrial Co.

In many cases, concrete placements are completed without incident. Often, this is due to proper preplanning and the use of appropriate measures during and after placement. Sometimes, a successful placement happens due to good fortune (the concrete mix was appropriate, particular practices were used, the weather cooperated, and so on). Other times, the placement does not turn out as planned. For example, the concrete structure may crack (sometimes excessively), or uncontrolled high temperatures in the placement may damage the concrete.

Standards and Limits

Concrete placements in which internal temperatures are high and/or temperature differences are large are called "mass concrete." Publications by the American Concrete Institute (ACI) Committee 207 address such placements. These documents provide a definition for mass concrete, provide historical perspective and provide guidance on what others have done/found via experience. However, ACI 207 documents do not specify requirements for mass concrete construction and do not provide limits regarding what is acceptable or unacceptable.

As the title implies, "Specifications for Structural Concrete," which is a document by ACI Committee 301, provides specification requirements for all types of concrete placements, including mass concrete. In the current (2010) version of the ACI 301 document, the determination of what is considered mass concrete is left to the discretion of the design engineer; however, it is recommended that placements four feet thick and greater be considered mass concrete. Additionally, the specification recommends that thinner placements be treated as mass concrete when a high strength concrete is used.

Further, ACI 301 requires that, unless otherwise specified, the maximum temperature of the concrete after placement not exceed 158°F, and that the temperature difference within the placement not exceed 35°F. Temperatures in the mass concrete placements must be monitored, and measured temperatures determine when measures to control temperatures in the concrete are no longer required. This occurs when the hottest portion of the concrete cools to within 35°F of ambient. These requirements are different than historical construction practice, where temperatures were controlled for only a certain period of time regardless of whether this period was longer than needed, or shorter than required (which was typically the case).

A maximum temperature of 158°F after the concrete is placed is specified because some concretes can be permanently damaged at temperatures greater than this limit. High internal concrete temperatures can result in a long-term durability issue known as DEF (delayed ettringite formation). DEF, although rare, can significantly reduce the service life of concrete. Damage from DEF (internal expansion and cracking), typically does not occur for years after the time of construction, if it occurs at all.

A maximum temperature difference of 35°F has historically been used to minimize thermal cracking in mass concrete placements. Not all concretes are equal, and some can withstand a higher temperature difference without resulting in thermal cracking. The type of aggregate in the concrete generally determines the temperature difference the concrete can withstand. Concrete with limestone, basalt or granite coarse aggregates typically can withstand a higher temperature difference than concretes with other types of coarse aggregates. If the temperature difference in a placement exceeds what the concrete can tolerate, cracking will occur. This type of cracking, if it occurs, typically occurs within the first week or two after the concrete is placed.

The Concrete Matters

So far, the focus has been on the problems with high temperatures in concrete, and how the specifications have been written to address these concerns. As previously noted, through proper planning and preparation, decisions can be made and practices can be implemented to avoid damaging temperatures and temperature differences.

The first step is to select a concrete mix design that is suitable for the placement. The concrete needs to achieve the required design strength and be suitable for the expected environmental conditions. Beyond this, the concrete should have a low temperature rise, be placeable, workable, finishable, and user-friendly.

The temperature rise of the concrete can be estimated from the following formula, where the effects of the various cementitious materials are considered:

Rise (°F) = 0.16*(Cement + 0.5*FAsh + 0.9*Slag + 1.2*SF)


  • Cement is the amount of Type I/II cement in the concrete in units of lbs/cuyd of concrete.
  • FAsh is the amount of class F fly ash in the concrete in units of lbs/cuyd of concrete. The calcium oxide content of the fly ash is assumed to be less than about 6 percent by weight of the fly ash. If the concrete contains class C fly ash, which has a much higher temperature rise than class F fly ash, treat the class C fly ash as if it were slag cement.
  • Slag is the amount of slag cement (ground granulated blast furnace slag) in the concrete in units of lbs/cuyd of concrete. No distinction is made regarding whether ASTM C989 Grade 100 slag cement or Grade 120 slag cement is used.
  • SF is the amount of silica fume or metakaolin in the concrete in units of lbs/cuyd of concrete.

This formula is based on the authors' experiences with commonly available cementitious materials. The water-to-cementitious-materials ratio may affect the temperature rise and is not addressed in this formula. Concrete with other types of cement may have a lower temperature rise, so this formula is only an approximation. Most importantly, this formula is not applicable for concretes in which the cementitious materials consist of more than 40 percent fly ash, less than 40 percent or more than 65 percent slag cement, contain both fly ash and slag cement, contain both silica fume and metakaolin, contain more than 10 percent silica fume, or contain more than 15 percent metakaolin.

The maximum temperature in a mass concrete placement having a thickness greater than about six feet is the sum of the temperature rise (from the above formula) and the initial concrete temperature (the temperature of the concrete at the time it is placed into the formwork). For example, if the temperatures rise is 100°F for a particular concrete, the initial concrete temperature should not be greater than 58°F or the maximum temperature of the concrete after placement will exceed 158°F.

Concrete purchased from a ready-mix supplier typically arrives on the jobsite with a temperature in the range of 60 to 95°F unless special measures are used to precool the concrete. During winter months when concrete materials are heated, concrete typically arrives with a temperature of 60 to 70°F. During warmer months, concrete typically arrives on site with a temperature that is 5 to 10°F warmer than the average daily air temperature.

Precooling concrete can be expensive. When considering a summertime placement of the concrete in the example above, the cost to precool the concrete may approach the cost of the actual concrete. This illustrates the potential costs of not selecting a low temperature rise concrete.

A typical 4,000 psi concrete can have a temperature rise as low as about 70°F, depending on the types and quantities of cementitious materials used in the concrete. Planning for a mass concrete placement by selecting a mix design with a low temperature rise can save time and money and reduce construction efforts when placing the concrete.


To ensure that the temperature difference does not exceed the typical 35°F limit, the concrete must be protected after placement. Protection consists of insulating all formed and finished concrete surfaces with insulating blankets, extruded polystyrene board insulation or other appropriate water-resistant insulating materials. Insulation is typically required regardless of the season and location (even if the placement was in Texas this past summer, for example, where the daily ambient air temperature was over 100°F).

In some cases, wood formwork may provide the required side surface insulation during summertime placements. However, because the top surface must also be protected, insulating blankets are typically installed on the top surface and draped over the side formed surfaces (over the formwork). Insulation slows the escape of heat from the surface of the placement but has almost no effect on the maximum temperature within the concrete in a mass concrete placement.

The concrete must be insulated until the interior cools adequately. This occurs when the interior cools to within the temperature difference limit (typically 35°F) of ambient. Removing insulation before this time will cause the surface to rapidly cool, which can thermally shock the concrete and cause cracking of the concrete surface.

The time that insulation must remain in place depends on the maximum temperature in the concrete, the insulation R-value and weather conditions. For a six-foot-thick slab on ground insulated with one layer of typical concrete insulation blankets, a reasonable estimate for the cooling rates is about 3°F a day during cold-weather placement conditions and about 6°F a day during hot-weather placement conditions. A reasonable estimate for the cooling rate of a six-foot-thick wall is about 6°F a day, regardless of the season. For a typical 4,000 psi concrete in a six-foot-thick wall placement, this means that insulation is required for 2½ to three weeks after the concrete is placed. Thicker placements require insulation for longer periods; if the thickness doubles, the time roughly quadruples.

Time-Saving Measures

Measures to control mass concrete temperatures and temperature differences can significantly impact construction schedules. Special measures can be used to reduce the time of insulation and the time of construction.

One such measure is to place the concrete in two distinct placements (for example, construct a six-foot-thick slab as two three-foot-thick slabs). While this practice may not be appropriate for all structures and may end up costing more when joint preparation and extra rebar are considered, this practice may eliminate the need for insulation and will increase the cooling rate of the individual placements. This strategy only works when adequate time is provided between the two placements. If the upper slab is constructed, for example, on the lower slab the day after the lower slab is placed, the combined slab will behave as a single six-foot-thick placement. Adequate time (at least a few days) is required between the placements to allow the heat to escape from the lower slab.

Another measure is to install a network of plastic pipes in the placement before the concrete is placed. Water is circulated through the pipes, which rapidly removes the internal heat from the concrete. The spacing of the pipes determines how quickly the concrete cools back to ambient. With a uniform layout of pipes, the time of insulation can be as short as ½ to one week. Cooling pipes also effectively reduce the temperature rise of the concrete. There are no approximations and rules of thumb that can be universally applied to the use of cooling pipes, other than that cooling pipes add cost.


Massive placements require special considerations to prevent damage to the concrete. Expect the concrete to be insulated after placement for periods of up to several weeks or longer. ACI 207 documents provide guidance and ACI 301 provides specific requirements for controlling temperatures and temperature differences in mass concrete placements, not all of which have been described in this article. Through proper planning and procedures, mass concrete placements can be constructed without issue, without adversely affecting schedule, and the expected service life can be achieved.

Authors: John Gajda is a licensed Professional Engineer in 20 states and one Canadian province, is the chairman of ACI Committee 207 "Mass Concrete" and is a senior principal engineer with CTLGroup in Skokie, Ill. Jon Feld, EIT, is a mass concrete specialist with CTLGroup in Skokie, Ill.

Chemical Cleaning the Generator Stator Cooling Water System at STP Unit 1

By Sean Ricker and Robert Bjune, South Texas Project, and Matthias Svoboda, Alstom Power Service

The South Texas Project (STP) is a two-unit nuclear facility southwest of Bay City, Texas. Both units are Westinghouse pressurized water reactors with Westinghouse main electric generators. The electric generators are rated at 1,504 MVA and have an average electrical output of 1,400 MWe. Unit 1 began commercial operation in 1988 and Unit 2 in 1989.

The generator rotor and core are cooled by hydrogen gas. The stator bars are cooled by a Westinghouse designed stator cooling water (SCW) system. Each generator has 72 stator bars consisting of 36 top bars and 36 bottom bars stacked two to a slot. All stator bars are hydraulically in parallel. The cooling water is deionized via a mixed-bed demineralizer, at a low dissolved oxygen (<50ppb as per original equipment manufacturer specifications) and neutral pH. The source of makeup to the system is deionized water at a dissolved oxygen level of 10 to 15 ppb. The makeup is run through the demineralizer prior to service to reduce conductivity to 0.055µS/cm. Makeup to the system during operation is negligible as the system is very tight with few leaks.

During operation the chemistry of the SCW systems has been maintained extremely well. Conductivity is almost without exception <0.1µS/cm, DO is typically <5ppb. These values have been maintained this way for the life of the plants. Continuous online monitoring is utilized for conductivity and DO and backed up by periodic sampling by chemistry.

The lay-up of the SCW system during outages has primarily been maintenance driven. During outages in which the stator must be vacuum dried it was done so (for example, for DC Hipot testing). This was typically only every six to 10 years. However, when not required to be dried the system was merely drained to the extent possible given the existing piping, and left open to air for the duration of the outage.

Stator Cooling Water System Problems

Throughout the units' more than 20 years of service, the SCW systems have been operated and laid up nearly identically. The only exception came in 2003 when Unit 1 entered an extended outage (6 months). During that time the SCW system was operated intermittently and chemistry values were not always kept in their ideal bands. Prior to that outage both units ran with copper levels <10 ppb. However, following the extended outage Unit 1 regularly ran with copper concentrations near the alert limit of 20 ppb.

During the Fall 2009 outage, the SCW system was drained, blown down and vacuum dried to perform DC Hi Pot testing. Following startup, higher than normal copper levels were found in the system. During that 18-month operating cycle, five sets of filters became plugged and required changing and copper levels got as high as 240 ppb. This is well above the normal levels of <20 ppb.

During the resulting investigation, STP decided that their current use of 30 micron nominal string wound filters was outdated. They have since changed to an improved 30 micron absolute pleated polypropylene filter. The use of this new filter was initially thought to have been a contributing factor to the differential temperature issues but was later cleared of suspicion. They have been in service in Unit 1 since May 2011 and have been successful at maintaining low copper levels without plugging.

The rising differential temperatures were seen on both the top bars and bottom bars equally. However, the differentials themselves were actually being caused by roughly 50 percent of the top bars and 50 percent of the bottom bars rising in outlet temperatures while the other 50 percent remained stable or actually lowered in temperature. This data suggests that the 50 percent that were rising were fouling and losing flow while the others were actually gaining flow in return.

When this data was examined further it was found that those bars whose temperatures were rising had their inlet and outlet water connections lower than the bars themselves (see Figure 1 and Figure 2). This means that the bars that are drained during most outages are the ones that were fouling. Alternatively, the bars that get their water connections higher than the bars, and therefore remain filled during outages, showed little to no signs of fouling.

Cleaning the System

For chemical cleaning, acid cleaning is an efficient option. However, this poses substantial safety problems, both for handling and for the machines. It also brings complicated waste treatment. In order to minimize the risks, the machine has to be disassembled and the conductors cleaned individually. With this, only some components, but not the system, are cleaned.

Alstom's proprietary Cuproplex method is based on the complexing agent EDTA (Ethylene diamine tetra acetic acid), which is applied through the whole system by recirculation. It dissolves only copper oxides and does not react with copper metal.

The reagent and the dissolved copper are absorbed in the mixed bed and then disposed of as solid waste.

The method can be applied either during a generator shutdown (offline) or when the generator is in operation (online). The latter method was chosen in the present case, as the last planned outage was only three months before and demand was at a peak.

The progress and result of cleaning are monitored by regular water analysis. A spectrophotometer, a conductivity meter and an oxygen meter are used. Information is supplemented by data from the power plant chemical laboratory.

Leading up from 1980 to June 2011, this method has been applied in 208 cleanings, on generators from 10 different manufacturers. Included are 51 online cleanings since its first application in 1996.


One of the biggest challenges during this process was the short time between identifying an adverse trend and the need to take action. The unit was started up from a planned outage on May 5, 2011. The adverse trend of differential temperature was first identified on May 23. At that time differential temperatures were at about 14 F and 10 F (top and bottom bars respectively) and were rising at a rate of about 1 F/4 days. By June 25, when the chemical cleaning began, temperatures had risen to 18 F and 16 F. A down-power would have been procedurally required at 20 F and a shutdown at 21.5 F.

An on-line cleaning has to be prepared thoroughly and adjusted to the case at hand. Thanks to efficient communication and processes this was achieved in a short time span.

The second challenge was the timing of this event. The summer of 2011 was an abnormally hot and dry one, even by Texas standards. Power generation was at a premium and the state's power stations were regularly in a state of alert. Work that could potentially cause plant trips was minimized throughout Texas. However, STP had to decide between what was viewed as a "risky" online evolution or risk reducing power or worse. In the end, the decision was made to perform the chemical cleaning.

For STP, this process was a first-time evolution for the site, which presented another challenge. This being a first-time evolution under time pressure meant that working procedures needed to be created in a short period of time. Additionally, chemicals that had never been used on site needed to be authorized, ordered and received and unique environmental evaluations had to be performed.


The operation started on Saturday, June 25, 2011 and ended Monday, July 18 at 17:50. Throughout the cleaning the conductivity was kept within 7 ± 1µS/cm, with the exception of three deionizer resin change periods, where the reagent injection was interrupted. During the whole time the plant was operating continuously and with regard to the effects of chemical cleaning also at full availability.

Soon after the start of the cleaning the individual bar temperatures started to improve. After 48 hours the temperatures were back to normal. The cleaning was continued, as all the oxides have to be removed in order to prevent fast renewed plugging. It became apparent that the amount of oxides present was much higher than in other machines of a similar size that had problems with plugging.

This caused several challenges, as with continuing progress of the cleaning several key resources started to get short on supply. More EDTA had to be ordered, as well as personnel resources organized to guarantee continuation of the cleaning.

Cleaning Results

The total quantity of copper removed was 10.7 kg. This amounts to more than 90 percent of the oxides present in the system. More than 95 percent of this originated from copper oxides already present in the system, the rest either from metallic copper surfaces or particles. In a worst-ase scenario, assuming all of the 5 percent was from copper surfaces, this would result in a wall thickness loss of less than 0.1 µm. With oxidation, the metal removal is uniformly distributed.

This quantity of oxide is considerably more than what we normally would expect from such a machine, even considering its size.

It was decided to not continue, as further cleaning would have been inefficient and the system was already very clean considering its size.

Pressure drop across the stator, flow, as well as temperatures were already stable at design values.

The deionizer resin was changed in both vessels three times during the cleaning and once more after terminating chemicals injection.

Stator inlet pressure dropped from 36.0 psi to 29.5 psi, while flow increased from 630 Gpm to 690 Gpm. When normalized to a pressure of 32 psi, the improvement in flow was from 595 Gpm to 725 Gpm.

Temperature differentials improved from 15.7 F to 8.0 F and from 12.6 F to 3.6 F for the top and bottom bars, respectively. Average stator bar temperatures above inlet improved from 47.9 F to 45.5 F for the top bars, and from 43.1 F to 39.5 F for the bottom bars.

Strong coordination between Alstom and STP, along with clearly defined roles made a fast response possible. Staff dedicated to the cleaning on both sides enabled fast and open communication during the cleaning.

The short response time and following long intervention time tested both organizations. A regional service point for Cuproplex in North America allowed equipment to be set up by Alstom Richmond's expert before the cleaning team arrived from overseas.

Cleaning Results

The large amount of oxides removed suggests other sources than air leaks. Such leaks would have to have introduced half a liter of air per day in average since commissioning. It should be noted, however, that such a leak is not necessarily visible by elevated dissolved oxygen levels, as the stator winding can be a very efficient oxygen scavenger.

Leaving the system open during outages, however, opens up a near infinite pool of oxygen for the duration of the exposure. The winding's temperature distribution also points in this direction. Copper surfaces, either blank or with oxide, do not change into a deteriorating condition when dry. Reactions however take place, when wet, within a few hours. The presence of moisture, can only be eliminated by proper layup.

As is known, 10.7 kg copper (as Cu2O) correspond to 1347 grams of oxygen. This is the weight of 943 liters of oxygen (at npt conditions), or 4,500 liters of air. It also corresponds to the oxygen content of 158 m3 of air-saturated water.

Even in a machine of this size, a few kilograms of oxides can already cause considerable and visible plugging. The fact that this did not occur despite having many times over the potentially problematic oxide inventory shows that conditions in the system were quite stable during operation, allowing the oxide layer to build up without significant disturbances that would cause oxide migration.

On the other hand, had such a disturbance occurred, the resulting plugging could have been sudden and severe.

Lessons Learned

The likely source of the problems was the lay-up procedures. Often, the consequences of insufficient lay-up will only be visible years or even decades after the fact. Every original equipment manufacturer has a recommended lay-up practice for their SCW systems. In most cases, these recommendations align with EPRI recommendations, which are to leave the system in service if possible or to perform a complete vacuum dry down of the system if it will be drained for an extended period of time, typically defined as greater than three days. It is STP's belief, as well as many in the industry, that these recommendations are difficult, time consuming, costly to follow and do not guarantee success. These systems were not originally designed with consideration to lay-up as evidence by the lengths that must be taken to do so. Additionally they do not guarantee that no problems will be encountered with regards to the internal chemistry of the machine and due to the amount of disassembly required, can also create more problems than are solved. STP has decided to institute a tailored lay-up program that will achieve near similar results at a lower cost and shorter time than the current industry standard.

In future outages, STP will be leaving clean system water in the stator winding and ring headers rather than intentionally drain them as has been done in the past. In addition, the process for filling and venting has been improved through procedure revisions to capture what was once just first-hand knowledge. These procedure enhancements also serve to enhance knowledge transfer which is a current emphasis in the industry. A new operator will not have to know from experience but will just have to follow a well written procedure.

Figure 3 Stator Head Winding
View of the upper part of the stator end winding with the black Teflon hoses.

The use of argon in the system is also being considered. Despite the makeup water being at 10 to 15 ppb dissolved oxygen, the process of filling an air saturated system with water causes the air in the water to increase to levels as high as 100 ppb. It is thought that if this air can be displaced with argon (or another inert gas) that dissolved oxygen levels can be kept within operating specifications through operation, drain down, refilling, and back into operation. This should further reduce any oxidation that takes place during refills following extended shutdowns.

Despite having a good wealth of online monitoring with regards to chemistry, the site like many others relies heavily on one differential pressure gauge as an indication of flow. However, this only tells a portion of the story. As was seen in this event, a steady differential pressure indication does not necessarily mean constant flow. In the future STP will be taking system flow readings regularly in both units in order to better monitor and trend the health of the machine. This data may be able to better identify a problem at an earlier stage before the effects are seen in differential temperatures. This will allow for better planning rather than a last-minute cleaning. It will also monitor the effectiveness of the new layup techniques. A real time flow instrument is being considered for installation in the future.

Chemical Cleaning

Chemical cleaning can clean plugged hollow conductors, but once a hollow conductor is completely blocked, chemicals cannot circulate inside and the channel remains blocked. It pays to act quickly once it is established that the machine has problems. Additionally, a large oxide inventory is not necessarily visible by outward symptoms, but poses an invisible threat to the system.

The stator cooling water system is often ignored due to its inconspicuous and seemingly trouble free nature compared to other systems in a power plant. It pays off to take care of this system, though, as neglect can quickly cost a lot of money when the plant has to be shut down for several days to several weeks in the worst case.


[1] Robert Svoboda, Christoph Liehr, and Hans-Günther Seipp, "Flow Restrictions in Water-Cooled Generator Stator Coils – Prevention, Diagnosis and Removal Part 4: Chemical Cleaning of Water-Cooled Generator Stator Coils by the Cuproplex Method" PowerPlant Chemistry 2004, 6(4), 197-202.

[2] Robert Svoboda and Hans-Günther Seipp, "Flow Restrictions in Water-Cooled Generator Stator Coils – Prevention, Diagnosis and Removal Part 1: Behavior of Copper in Water-Cooled Generator Coils," PowerPlant Chemistry 2004, 6(1), 7-15.

[3] Robert Svoboda and Russell Chetwynd, "Flow Restrictions in Water-Cooled Generator Stator Coils – Prevention, Diagnosis and Removal Part 2: Detection of Flow Restrictions in Water-Cooled Generator Stator Coils," PowerPlant Chemistry 2004, 6(2), 71-79.

[4] Robert Svoboda, Christoph Liehr, and Hans-Günther Seipp, "Flow Restrictions in Water-Cooled Generator Stator Coils – Prevention, Diagnosis and Removal Part 3: Removal of Flow Restrictions in Water-Cooled Generator Stator Coils," PowerPlant Chemistry 2004, 6(3), 135-144.

[5] Turbine Generator Auxiliary System Maintenance Guides—Volume 4: Generator Stator Cooling System. EPRI, Palo Alto, CA: 2008. 1015669.

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