The cycle chemistry treatments and control on fossil and combined cycle plants influence a high percentage of the availability, reliability and safety issues experienced on these plants worldwide. As this is a very large and important area for fossil and combined cycle plants, Structural Integrity decided to describe it in three parts. The first part introduced the equipment and materials of construction and how reliability depends on various protective oxides, the formation of which relates directly to the cycle chemistry treatments that are used in the condensate, feedwater, boiler / HRSG evaporator water, and steam. This second part will delineate the damage and failure mechanisms influenced by not operating with the optimum treatments when the protective oxides break down. The third article will describe the key analytical tools which we developed to identify whether these failure and damage mechanisms will occur by identifying the number of Repeat Cycle Chemistry Situations (RCCS).
1.1.1 Overview of Cycle Chemistry Influenced Damage/Failure Mechanisms
It is not surprising that because the cycle chemistry “touches” all the parts of a generating plant that it controls the availability and reliability of these plants. It has been suggested over the last 10-20 years that the cycle chemistry influences about 50% of all the failure and damage mechanisms in conventional fossil plants, and because of the added complexity of combined cycle / HRSG plants with multiple pressures this number may be as high as 70%. The statistics of cycle chemistry influenced failure and damage mechanisms in conventional fossil and HRSG plants have changed very little over the last 25 years or more. These can be categorized as follows:
It is important to note that although FAC and UDC mechanisms occur at opposite ends of the fossil and combined cycle / HRSG plants, they are linked by the corrosion products generated by the corrosion and FAC mechanisms in the fossil feedwater systems and the low pressure parts of the HSRG respectively. These corrosion products subsequently transport to, and deposit in, the fossil waterwalls and HRSG HP evaporator tubing where they form the basis of the under-deposit corrosion damage mechanisms. This link forms the main focus of cycle chemistry assessments in fossil and HRSG plants, which identify the precursors or active processes, which left unaddressed, will eventually lead to failure / damage by one or both mechanisms. Acting proactively will remove the risk for both, and it is clear that avoiding FAC is an essential part of ensuring that UDC will not occur.
Because of the vast array of publications on cycle chemistry influenced failures and damage which is available in the literature there is only time in this Part 2 article to provide a few abbreviated examples of the mechanisms of FAC, UDC and deposition, and of phase transition zone damage in the steam turbine.
1.1.2 Flow-Accelerated Corrosion (FAC) in Fossil and Combined Cycle/HRSG Plants
The mechanism of FAC is the same in both plants but the location of damage is different. In fossil plants FAC predominates in the feedwater systems whereas in combined cycle plants it is primarily located in the low pressure/temperature circuits of the HRSG. FAC involves the accelerated dissolution of the protective oxide (magnetite) on the surface of carbon steel components caused by flow and the mechanism is illustrated in Figure 1.
FAC in Combined Cycle / HRSGs. All the HRSG components within the temperature range (212 – 572°F, 100 – 300°C) are susceptible to FAC which involves both the single- and two-phase variants predominantly in low temperature (LP, IP and HP) economizers / preheaters and evaporators (tubes, headers, risers and drum components such as belly plates). The same components can also be susceptible to FAC in HRSG designs where the nominal HP evaporator circuit operates for significant periods of time at temperatures < 572°F (300°C); for example, the HP evaporators in older dual-pressure HRSGs, HRSGs where there is only one pressure stage, and high pressure evaporator circuits in plants running for extended periods at low load with sliding pressure operation. A quite comprehensive listing of locations of FAC in combined cycle / HRSGs is provided in Table 1 below.
Table 1. Locations of FAC in Combined Cycle / HRSG Plants
(Adopted from R.B. Dooley and R.A. Anderson, Assessments of HRSGs – Trends in Cycle Chemistry and Thermal Transient Performance, PowerPlant Chemistry, 2009, 11(3), 132-151)
FAC in Air-cooled Condensers (ACC). An increasing number of plants worldwide are equipped with air-cooled condensers (ACC). Operating units with ACC at relatively low condensate pH (9.0 – 9.4) will result in serious corrosion and FAC in the ACC tubes, most predominantly at the entries to the cooling tubes. The potential for air-cooled condensers (ACC) to act as a major source of corrosion products needs to be considered in developing the optimum cycle chemistry control for plants. Whether this is occurring can easily be determined by monitoring the total iron at the condensate pump discharge (CPD). A condensate / feedwater pH of around 9.8 (as measured at 25 °C) will be needed to reduce the FAC to low enough levels to observe total iron values at the CPD of around 5 μg/kg (ppb) or less. Alternatively, a film forming amine product (FFAP) can be used as described in Part 1. Operating with elevated pH and/or an FFAP to control low temperature FAC in the ACC will also assist in addressing two-phase FAC in the other areas of the plant.
The cycle chemistry influenced damage in ACC can be best described through an index for quantitatively defining the internal corrosion status of ACC. This is known by the acronym DHACI (Dooley Howell ACC Corrosion Index). (Source: R.B. Dooley, D. Aspden, A.G. Howell and F. du Preez, Assessing and Controlling Corrosion in Air-cooled Condensers, PowerPlant Chemistry 2009, 11(5), 264-274). The index separately describes the lower and upper sections of the ACC. The index provides a number (from 1 to 5) and a letter (from A to C) to respectively describe / rank an ACC following an inspection. For example, an Index of 3C would indicate mild corrosion at the tube entries, but extensive corrosion in the lower ducts.
The DHACI can be used to describe the status of a particular ACC in terms of its corrosion history and is a very useful means of tracking changes that occur as a result of making changes in the cycle chemistry. Additionally, the index provides a convenient tool for comparison between different units worldwide. This can aid in determining whether some cycle chemistry factor in effect at one station, e.g. use of an FFAP rather than ammonia, is yielding better results.
1.1.3 Failure / Damage Mechanisms in Fossil/HRSG Plants: Highlighting Deposition & the Underdeposit Corrosion (UDC) Mechanisms
The three UDC mechanisms, hydrogen damage, acid phosphate corrosion and caustic gouging, occur exclusively in fossil waterwall and HRSG HP evaporator tubing, and all require relatively thick porous deposits and a chemical (either a contaminant or non-optimized treatment) concentration mechanism within those deposits. UDC damage can occur early in the life of a plant due to the inverse relationship between deposit loading / thickness and the severity of the chemical excursion.
For hydrogen damage (HD), the concentrating corrodent species is most often chloride which enters the cycle through condenser leakage (especially with seawater or brackish water cooling) and via slippage into demineralized makeup water in water treatment plants where ion exchange resins are regenerated with sulfuric or hydrochloric acid. (Source: R.B. Dooley and A. Bursik, Hydrogen Damage, PowerPlant Chemistry, 2010, 12(2), pp 122-127).
Acid phosphate corrosion (APC) relates to a plant using phosphate blends which have sodium-to-phosphate molar ratios below 2.6 and/or the use of congruent phosphate treatment using one or both of mono- or di- sodium phosphate. (Source: R.B. Dooley and A. Bursik, Acid Phosphate Corrosion, PowerPlant Chemistry, 2010, 12(6), pp 368-372).
Caustic gouging (CG) involves the concentration of NaOH used above the required control level within caustic treatment, or with the use of coordinated phosphate with high levels of free hydroxide, or the ingress of NaOH from improper regeneration of ion exchange resins or condenser leakage (fresh water cooling). (source: 14. R.B. Dooley and A. Bursik, Caustic Gouging, PowerPlant Chemistry, 2010, 12(3), pp 188-192).
The UDC mechanisms of hydrogen damage and caustic gouging have been well understood in fossil plants for over 40 years, and the acid phosphate mechanism since the early 1990s. Despite this, these mechanisms have become frequent problems worldwide in HRSGs. This may be because until recently the understanding of how the initiating deposition takes place in HRSG HP evaporator tubing has been less well understood than in fossil plants as well as the level of deposits necessary for these mechanisms to initiate by concentration within thick deposits. This has changed recently with work we’ve initially conducted: information from over 100 HRSGs worldwide has led to a new understanding on where to sample and how to analyze HRSG tubes for deposits and how to determine if the HRSG needs to be chemically cleaned. This will be published as an IAPWS Technical Guidance Document in September 2016 (see bibliography).
Deposition in HRSG HP Evaporators. Deposition and the UDC mechanisms can occur on both vertical and horizontal HRSG HP evaporator tubing. On vertical tubing the deposition usually concentrates on the internal surface (crown) of the tube facing the gas turbine (GT). It nearly always is heaviest on the leading HP evaporator tube in the circuit as these are the areas of maximum heat flux. Area of concentration can be the tube circuits adjacent to the side walls or to the gaps between modules due to gas by-passing. The UDC mechanisms usually occur in exactly the same areas. On horizontal tubing in vertical gas path HRSGs both deposition and the UDC mechanisms occur on the ID crown facing towards or away from the GT.
Examples of deposit loadings from over 100 HRSGs worldwide were analyzed and used to develop the new IAPWS Deposit Map shown in Figure 2. Plants included cover a very wide range of HRSGs from 17 HRSG manufacturers with HP drum pressures spanning the range 8.9 to 15.2 MPa (1300 to 2200 psi) and with deposits up to 136 mg/cm2 (125 g/ft2).
Some general comments reproduced from the IAPWS document can be made about the three colored cloud regions:
This new concept contained within the background of the Deposit Map for avoiding deposits which are thick enough to allow concentration provides the first step of avoiding UDC.
1.1.4 Steam Turbine Phase Transition Zone Failure/Damage
Impurities in the steam from the superheater and reheater of plants may cause deposits and corrosion in steam turbines and thus the steam purity controls most corrosion processes and is vital to plant reliability. These problems can usually be avoided by following the guidance in the IAPWS Steam Purity Technical Guidance Document which needs to be compatible with the condensate, feedwater and boiler/ evaporator chemistries introduced in Part 1.
The four most important corrosion-related failure / damage mechanisms in the low pressure (LP) steam turbine are deposition, pitting, corrosion fatigue and stress corrosion cracking. The local steam environment determines whether these damage mechanisms occur on blade and disk surfaces. The phase transition zone (PTZ), where the expansion and cooling of the steam leads to condensation, is particularly important. A number of processes that take place in this zone, such as precipitation of chemical compounds from superheated steam, deposition, evaporation, and drying of liquid films on hot surfaces, lead to the formation of potentially corrosive surface deposits. Understanding the processes of transport, droplet nucleation, the formation of liquid films on blade surfaces, and concentration of impurities is vital to understanding how to avoid corrosion related damage, and to improve unit efficiency/capacity.
The following two cycle chemistry operating regimes are identified as relevant to steam turbine corrosion. Of course, adequate materials properties (composition, structure, internal stresses, etc.) and design (temperature, stresses, crevices, etc.) also play essential roles.
Thus, if adequate layup protection (dehumidified air (DHA)) is not provided, serious corrosion damage may occur even with the best operating chemistry, materials, design, and with only few major deposits.
Impurities can enter the steam by the following processes:
A complete description of the chemistry in the PTZ of the LP steam turbine includes the processes of moisture droplet nucleation, liquid film formation on turbine parts, deposition of oxides and impurities on surfaces, and how inadequate shutdown practices results in pitting. The major failure mechanisms of corrosion fatigue and stress corrosion cracking are initiated at pits so this sequential process is most important.
Steam Purity Limits. For plants with condensing turbines operating with superheated steam the following guidelines limits are suggested by IAPWS:
These limits are considered as the normal operating values during stable operation to avoid the steam turbine damage mechanisms and are consistent with long-term turbine reliability.
Steam Purity Startup Limits. Steam should not be sent to the turbine if the concentration of sodium exceeds 20 ppb (μg/kg). The immediate need at startup to ensure compliance with this limit requires a sodium monitor for steam. Steam also should not be sent to the turbine if the CACE (cation conductivity) exceeds 0.5 μS/cm. Allowance may be given to possible contributions from carbon dioxide and for sodium in units that only use tri-sodium phosphate in the boiler / evaporator water. The actual contribution of carbon dioxide must be measured and regularly verified for the specific plant. Degassed CACE can help to estimate the contribution of carbon dioxide.
Table 2. Steam purity for condensing turbines with superheated steam in fossil and combined cycle / HRSG plants.
Unit Shutdown Limits. In addition to operating with a set of normal and action levels it is also necessary to define a set of cycle chemistry conditions under which a unit must be shut down because of severe contamination. Shutdown conditions usually involve defining a steam CACE that indicates serious acidic contamination. Typically, a value of 1 μS/cm can be used under conditions that coincide with other upset conditions in the steam / water cycle. Carbon dioxide from air in-leakage or certain conditioning agents may warrant a less stringent CACE.
Here we’ve provided a brief overview of the most important cycle chemistry influenced failure and damage mechanisms in fossil and combined cycle plants. The third article in this series will describe the assessment methodology we developed to identify proactively if any of these mechanisms will occur in a plant. It will illustrate how RCCS can identify how operating outside of optimum treatments and without adequate cycle chemistry control systems (monitoring, instrumentation, analysis, etc) will lead to failure / damage of the plant.
There are a plethora of international guidelines and guidance available in many countries of the world for the reader: IAPWS (International), EPRI (US), VGB (Germany), JIS (Japan), Russian, Chinese, Manufacturers of major fossil and combined cycle / HRSG equipment (International), Chemical Supply Companies (International). Structural Integrity Associates uses the Technical Guidance Documents (TGD) of the International Association for the Properties of Water and Steam (IAPWS) in all the cycle chemistry related plant assessments and root cause analyses conducted. These are freely downloadable on the IAPWS website (www.IAPWS.org). These have been used as the reference materials throughout this document and full attribution is given to IAPWS.