In the electric-power industry, natural gas is considered a clean-burning fuel. But gas-side fouling of heat-transfer surfaces within an HRSG isn’t just related to the fuel, HRST Inc’s Patrick Walker told the editors. Other fouling factors can include geographic location, operational profile, component failure history and trends, and /or emissions control equipment. All can contribute to overall fouling and fouling rates.

Several types of foulants are common to operating HRSGs—including rust, insulation, ammonia salts, and sulfur compounds. Here are some background facts on each, provided by Walker:

Rust is the prevalent type of fouling (Fig 1). Most tubes and fins are carbon steel and subject to oxidation (rust scale formation). The oxidation rate increases as water or water-vapor levels increase, either during operation or while offline.

During operation, water can be introduced by upstream tube leaks or from SCRs using aqueous ammonia in their injection systems. Offline, leaking roof doors and penetration seals, open or missing dampers, casing cracks, and failed insulation lagging can allow moisture to enter the unit slowly. HRSGs in geographic areas characterized by high relative humidity are subject to higher oxidation rates.

Insulation fouling of heat-transfer surfaces is common, but mostly observed as a few small localized patches stuck to the finned tubes throughout the access lanes. A major insulation fouling issue usually appears when a plant has experienced a liner failure, or has significant liner gaps present, and the insulation has been sucked out and deposited downstream (Fig 2).

Insulation from a catastrophic liner failure usually deposits on the first three rows of tubes, which catch most of the liberated material. However, small fibers migrate downstream and plate out on other panels or on catalyst for emissions control. The SCR and/or CO catalysts act as large filters for airborne insulation, increasing the pressure drop across the catalyst. If fouling is severe, it can force a unit to trip offline or to run at partial load until the issue has been corrected.

Ammonia salts typically are found in units with SCRs. Salt formation is believed limited by the amount of sulfur in the exhaust gas and its reaction with excess ammonia (so-called ammonia slip). Salt precipitates on cooler metal surfaces downstream in the unit (Fig 3). The salt buildup can vary from a light powdery deposit to a dense solid coating.

These types of salts usually are difficult to remove once well-established on the heat-transfer surfaces. Many plants have switched from a reactive to a proactive cleaning approach to keep fouling rates under control, as well as to prevent the foulant from bridging the gaps between fins.

Sulfur compounds. Heavy sulfur buildup is common in units operating primarily on fuel oil (Fig 4). Lighter fouling can occur in HRSGs at plants burning high-sulfur natural gas in the gas turbine or duct burners. Trace amounts of the odorant mercaptan (added to some natural gas to facilitate leak detection) will add to the overall sulfur content in the fuel.

Wetted sulfur deposits are very corrosive and can cause tube failures fairly quickly if conditions are “favorable.” Many times the sulfur deposits are sticky in nature and the foulant will “jump” from the tube that you are cleaning and stick to neighboring tubes.

Thermal performance of the HRSG is diminished because the foulant can act as a thermal shield, Walker reminded, reducing the transfer of energy from the turbine exhaust gas to the working fluid. As sections of the HRSG become fouled and no longer absorb the intended energy from the exhaust, downstream components can become exposed to elevated exhaust-gas temperatures which can cause them to over-perform compared to original design. Such over-performance, Walker said, can cause steaming and downflow instability issues with economizers, as well as increased flow-acceleration corrosion (FAC) risks in certain areas.

Foulants also contribute to reduced efficiency of the gas turbine, he continued, because they increase backpressure through the HRSG. Assuming an additional 4 in. H2O of backpressure caused by gas-side fouling, a 7EA or 7FA gas turbine could experience a power output loss of 0.42% to 0.56%, or a heat-rate increase of 0.42% to 0.56%, and experience an increase in exhaust gas temperature of from 1.9 to 3 deg F. Even a slight increase in exhaust-gas temperature could prove problematic for metals near design temperature limits.

While it may seem that a higher gas temperature would benefit boiler thermal performance, the reduction in heat-transfer performance attributed to the fouling typically is sufficient to negate any performance improvement from higher HRSG inlet temperature. As the foulant continues to build over time and the backpressure approaches the upper-limit set point for the gas turbine, the unit will become more susceptible to trips or run-backs, especially in the colder times of the year.

OEMs often look to promote and sell gas-turbine upgrades that can reduce the current low-load range, increase overall output, and reduce fuel cost and emissions—among other benefits. But these upgrades also can increase the mass flow of exhaust gas through the HRSG, Walker advised, which can compound the backpressure limits on combined cycles already approaching the upper deltaP limits for turbine trips and run-backs.

Imagine spending several million dollars for turbine upgrades only to find out that full-load operation may not always be possible because of backpressure limitations. It has happened.

It’s important to recognize that complete HRSG debris removal and a full return to first-fire backpressure conditions are both unrealistic. The amount of heat-transfer surface in a given module can be staggering.

Perspective: A 36-ft-wide harp having 16 rows of 61-ft-tall × 2-in.-diam tubes with 0.75-in.-long fins spaced at six fins per inch has more than 750,000 ft² of surface area to clean. That translates to an area of about 17.2 acres, or roughly the equivalent of 13 professional football fields (including the end zones). Cleaning that much surface using only tube lanes for access is challenging.

With traditional CO2 surface blasting effective for only the first two to four tube rows of the module (depending on tube geometry), Walker pointed out that leaves more than half of the tubes virtually untouched when the harp is cleaned from both the upstream and downstream sides.

The deeper the bundles, the less effective traditional CO2 surface blasting alone will be at removing debris. In some cases, surface blasting can drive the debris deeper into the bundle, where it is out of sight and difficult to reach. If the foulant is sticky in nature a flow-path dam can be created deep in the bundle with significant impact on backpressure.

Tube spreading. HRST Inc has designed and patented tube-spreading equipment and a cleaning process for accessing the deeper portions of tube bundles generally inaccessible by traditional surface blasting techniques. The tube spreading process is the most critical component of this deep cleaning approach and should be handled with caution.

Damage can result from tube spreading when improper tools are used, stress calculations are not performed for each of the individual panels being cleaned and/or the company performing the tube spreading does not have a good understanding of all potential limitations. Pre-existing conditions like stress-corrosion cracking (SCC), significantly bowed tubes, and rolled tube joints must be considered when developing a tube spreading plan.

There is no perfect solution to gas-side cleaning. This is evident by the various methods that have been developed and used—including sootblowers, acoustic horns, sand/grit blasting (CO2 blasting is a derivative), water washing, compressed-air blasting—even explosives.

Preparation. When considering the need for gas-side cleaning, it is important to know which sections are contributing the most to the excessive backpressure, Walker said. At most plants, backpressure monitors are located at the GT outlet and on either side of the catalyst (if present).

Planning for a cleaning often will require installation of some type of data collection device in multiple access lanes throughout the HRSG. These devices do not have to be elaborate or expensive (think of U-tube manometers), or though they can be (think of wireless deltaP transmitters linked to the DCS historian).

Once data are collected, bundles can be rated in terms of excess deltaP over design conditions by referencing OEM manuals. This information then can be used to direct cleaning efforts, combined with visual inspections from the access lanes and borescope inspections into the tube banks.

Before selecting a company to perform gas-side cleaning, do your due diligence and research all potential vendors. A few hours spent vetting candidates can save time and money in the long run, Walker suggested. Don’t hesitate to ask for the following information:

• Experience modification rate (EMR), OSHA 200 logbook, or equivalent.

• An explanation of how the cleaning contractor plans to remove the foulant present at your site, plus contingency plans. Remember that different types of fouling can require different cleaning approaches. Example: If the foulant is mainly rust and lightly adhered, then compressed air alone often is sufficient to remove the debris. But if the foulant is sticky, or concrete-like, more aggressive forms of cleaning will be required.

• How the contractor determines what is “clean.” Agreeing on criteria beforehand will save time during final inspections and sign-offs for work performed.

• The type of equipment to be used, and processes to be followed, during the cleaning work. If any tube spreading is involved, make sure the proper stress calculations are performed on the sections to be cleaned.

• References from previous clients, especially those with equipment and fouling similar to yours.