the effects of ammonia and organic amines on the water chemistry of gas turbine heat recovery steam generators and associated equipment

Transcription

1 Water Technologies & Solutions technical paper the effects of ammonia and organic amines on the water chemistry of gas turbine heat recovery steam generators and associated equipment Authors: James O. Robinson Gregory J. Robinson SUEZ Trevose, PA In the late 1980 s gas turbine heat recovery steam generators (HRSGs) that use the low-pressure (LP) evaporators as a source of feedwater for the intermediate-pressure (IP) and high-pressure (HP) evaporators as well as steam attemperating water were introduced. Many of the LP evaporators in these systems experienced substantial metal wastage in the two-phase areas, most commonly at the tube bends near where the steam generating tubes enter the steam drum and in the steam-water separators. Originally referred to as erosion-corrosion, this metal wastage is now commonly called flowaccelerated corrosion, or FAC. 2010, General Electric Company Figure 2 Flow accelerated corrosion in LP evaporator steam-water separator 25 Figure 1 Flow accelerated corrosion in LP evaporator generating tube These were not the first gas turbine LP waste heat evaporators. What was different about the new units compared to the previous, more reliable units that only experienced erosion-corrosion at the economizer inlets? In retrospect, the answer seems obvious, but at the time, many struggled to recognize that the conventional alkaline phosphate treatment that provided a liquid phase near 10 or greater throughout the original LP evaporators was very highly protective of the iron oxide surfaces. Find a contact near you by visiting and clicking on Contact Us. *Trademark of SUEZ; may be registered in one or more countries SUEZ. All rights reserved. TP1206EN.docx Feb-15

2 The introduction of a design that could not use this tried and proven chemical treatment technology created risks not encountered with the previous HRSG configurations. Eventually, it became apparent that it is very important to maintain adequate in the liquid of all two-phase areas throughout the LP and IP evaporators to control potential FAC problems. As a result of investigations for the nuclear plant pressurized water reactor steam generators, the Electric Power Research Institute (EPRI) reported that two-phase FAC can usually be effectively controlled by maintaining the at the operating temperature one full unit above the of pure water at that temperature (Dooley, 2009). Based at least partially on this information the recommended LP evaporator levels have been increased and many plants are now successfully control ling two-phase FAC by maintaining a minimum 25 ºC of 9.5 or 9.6 in the LP and IP evaporator blowdown water. In some instances, lower levels have been successful, especially with the use of properly selected organic amines. This is primarily due to the amines favoring the liquid phase over the steam phase. In contrast, ammonia favors the steam phase over the liquid phase (Figure 3). This is important because with properly selected amine treatment, the of the liquid in two-phase areas will be at least as high, and likely higher, than the of the stream being tested. On the other hand, with ammonia only treatment, the of the liquid in two-phase areas will be lower than the of the stream being tested. Numerous papers have documented the ability of properly selected neutralizing amines to control flow accelerated corrosion in the LP evaporators, IP evaporators using all volatile treatment (AVT) and air cooled condensers (Carvalho, 2001), (Robinson, 2009), (Robinson, 2011), (Parker, 2013). Distribution Ratio Distribution Ratios Vary WIth Pressure Pressure, PSIG Figure 3 - The steamwater distribution ratios of ammonia (dashed red line) and ethanolamine (solid blue line) vary as a function of system pressure (temperature) and. This chart depicts the distribution ratio values at a liquid phase of 9.6. A distribution ratio over 1.0 means the concentration in the steam is greater than the concentration in the liquid phase and a distribution ratio less 1.0 means that the concentration in the liquid is greater than the concentration in the steam. These papers also discuss the formation of amine thermal decomposition products, ammonia, carbon dioxide, acetate and formate. It is well known that the carbon dioxide, acetate and formate affect the cation conductivity of the cycle water, perhaps making cation conductivity less useful as a detector of mineral contaminants such as chloride and sulfate. It has also been postulated that these products of organic amine decomposition may cause corrosion problems in evaporators and steam turbines. While the authors cannot state that this will never happen, organic amines have been used to treat steam systems since the 1940s and we are unaware of any such problems ever being reported. Page 2 TP1206EN.docx

3 effects of ammonia and amine treatment on HP evaporator chemistry In addition to the beneficial effects of high levels of ammonia and/or the use of less volatile amines to control FAC in the LP and IP evaporators, plant operators need to consider the effects of this treatment on the HP evaporator controls. Due to the potential for acidic phosphate hideout and associated corrosion during duct firing, many plants operate with low levels of phosphate in the HP evaporators with the intention of maintaining a minimum sodium to phosphate mole ratio of 3.0 to 1.0, or more correctly, a minimum sodium hydroxide to phosphoric acid mole ratio of 3.0 to 1.0. In practice, this ratio is never measured directly, but assumed from the phosphate- relationship. Figure 4 Acidic phosphate corrosion in HP evaporator. Much of the literature on this topic provides phosphate- relationships based only on sodium hydroxide and phosphoric acid solutions. This literature also recommends that plant operators measure the HP evaporator ammonia and adjust the measurement for the amount of ammonia present. However, many plants do not make this adjustment on a regular basis, if at all. Neglecting this step is not often of great significance when six or more ppm of phosphate is being maintained in the evaporator water since the relatively small levels of ammonia and/or organic amine normally present will have only a small effect on the evaporator water measurement. The need for correcting the HP evaporator water for the effect of ammonia and/or organic amine is critical for HRSGs that require a high feedwater to control LP evaporator FAC and low phosphate levels to avoid acid phosphate hideout in the HP evaporator. Figure 5 shows the effect of maintaining the feedwater at 9.6 with ammonia and an ammoniaorganic amine blended product on the of an 1800 psig HP evaporator water containing trisodiumphosphate (TSP). If the operator relies on the traditional phosphate- charts to establish their operating controls, the normally recommended minimum of 9.0 in the HP evaporator water appears to assure that with 1 ppm of phosphate, the sodium to phosphate mole ratio will be greater than 3.0/1.0. However, when the feedwater treatment chemicals are accounted for, the minimum required level to assure at least a 3.0 to 1.0 sodium to phosphate mole ratio is approximately 9.4 for ammonia only treatment and 9.6 for the ammonia-amine blend. Not making this needed adjustment exposes the evaporator to a significant acidic corrosion risk. Effect of Ammonia and Amines on of HP Evaporator Water Phosphate, ppm TSP TSP + NH3 Figure 5 - The effect of ammonia and an ammonia - amine blend on the minimum HP evaporator water required to maintain a 3.0/1.0 sodium hydroxide to phosphoric acid mole ratio increases with decreasing phosphate levels. (HP evaporator feedwater is 9.6.) Ignoring the effect ammonia and amines have on the HP evaporator measurement during an acidic chloride excursion further increases the risk of corrosion damage. Figure 6 depicts the effect acidic chloride contamination will have on the measured of an 1800 psig evaporator water containing one ppm of phosphate from the feed of trisodium phosphate and a feedwater of 9.6 from ammonia treatment of the LP evaporator. TP1206EN.docx Page 3

4 Note that one ppm of acidic chloride contamination only lowers the evaporator water from 9.45 to 9.2. Reference to the conventional phosphate- control chart may mislead the operator in to believing that the water chemistry is satisfactory. However, if the operator compensates for the effect of ammonia on their measurement, they will note that the provided by the solid chemicals is only 5.1 and the sodium hydroxide to phosphoric acid mole ratio has slipped to 0.4, a major potential for acidic corrosion damage. It is important to understand that while the presence of ammonia in the evaporator boosts the of cooled evaporator water samples, it has very little effect on the of the water at the temperature of the evaporator. Na/PO 4 =0.4 Effect of Acidic Chloride on HP Evaporator Na/PO 4 =0.4 Chloride, ppm plants using phosphate treatment to use this technology to monitor the HP evaporator water. Cation conductivity monitoring of the HP evaporator water can often be the most sensitive indication of contamination that may lead to acidic corrosion problems. Figure 7 shows the effect chloride contamination has on the cation conductivity of HP evaporator water that is treated with trisodiumphosphate to produce one ppm of phosphate Effect of Acidic Chloride Contamination on 25 ºC and Cation Conductivity Chloride, ppm us/cm Figure 6 The effect of acidic chloride contamination on the of 1800 psig HP evaporator water containing one ppm of PO 4 from trisodiumphosphate feed when the evaporator feedwater is treated with ammonia to a of 9.6. The dotted blue line represents the 25 ºC of the evaporator water. The solid red line represents the 25 ºC of the evaporator sample after the effect of ammonia on the measurement is removed. what else can be done? The chloride contamination could be easily detected if the plant is monitoring the boiler blowdown cation conductivity. While it is common practice in many plants to monitor the cation conductivity of the feedwater and steam, it is not nearly as common for Figure 7 Cation conductivity of the HP evaporator blowdown water (dashed red line) is an effective means of detecting potentially corrosive acidic boiler water contamination even when the (solid blue line) is only slightly changed. In addition, models can be developed using SUEZ s proprietary CMS modeling system (Robinson, 1994) to provide the operator phosphate- control charts that compensate for the effect the feedwater treatment has on the HP evaporator water measurement. These models take into account the amount and type of treatment present in the LP evaporator feedwater, the amount of steam generated in the LP evaporator, the LP and HP evaporator operating pressures and the amount of caustic and phosphate desired in the HP evaporator Page 4 TP1206EN.docx

5 water. For each plant multiple control charts may be needed to compensate for normal variations in feedwater and if applicable operating pressure. Figure 8 is an example control chart for a plant with an 1800 psig evaporator, that uses an ammonia organic amine blend to maintain the LP evaporator water and thus the HP evaporator feedwater at 9.6 and strives to maintain the boiler water solid chemical concentrations between that of trisodium phosphate and trisodium phosphate plus 1 ppm of sodium hydroxide. It is usually recommended that the plant have charts for each 0.1 unit variation in HP evaporator feedwater. Ammonia-Organic Amine Adjusted Phosphate- Control steam-condensate systems and protecting equipment when it is out of service. Filming amines were applied to a limited number of electric power plants in the 1950s. At that time, both Arkansas Power and Light (White, 1960) and Cincinnati Gas and Electric (Galloway, 1959) reported favorably on the out of service corrosion protection provided by filming amines. More recently, First Energy has reported on improved out of service protection and reductions in FAC from the use of filming amines (Verib, 2011). While the ability of filming amines to protect equipment is well documented, as with ammonia and neutralizing amines, it is important to consider the effects on the total system when beginning or changing an application. Will existing corrosion products be dislodged and foul downstream equipment? Will in-line instrumentation be affected? If relied on to protect out of service equipment, How long will the protection last? Will condensate polishers become fouled? These and similar questions should not prevent the application of a filming amine where it will be of benefit, but serve as a guide for items to monitor to assure a successful application for the entire system. Figure 8 Phosphate- control recommendation for 1800 psig evaporator when using an ammoniaamine blended product in a HRSG plant to maintain LP blowdown at 9.6 and the HP evaporator water with a minimum Na/PO 4 mole ratio of 3.0/1.0 and a maximum Na/PO 4 mole ratio of 3.0/1.0 plus 1 ppm of NaOH. filming amines Organic neutralizing amines are not alone in making inroads into combined cycle water treatment. There is a growing interest in the use of filming amines for the protection of two-phase areas from FAC and to all steam-water touched plant equipment when it is off line. Filming amines have been used almost as long as neutralizing amines to protect equipment by forming a non-wettable film on metal surfaces. In the industrial sector, filming amines have been particularly useful for controlling two-phase FAC in Figure 9 - The beading of water droplets placed on the surface of condenser tubes during the inspection of a combined cycle plant that is in cycling service confirms the presence of a protective film on the tube surfaces when treated with a polyamine product (Crovetto, 2011) TP1206EN.docx Page 5

6 going forward in a changing world New equipment designs and new operating requirements will continue to require changes in the technologies applied to protect plant equipment. Old and proven technologies will not always work in the new environment and leaders will be needed to step forward with new approaches that address the changing requirements. The successful application of any changes in technology must address not only the immediate needs, but it should do so with a clear view as to the effect on the total system under all likely operating conditions. That being said, while a thorough consideration of all of the effects that can be anticipated throughout the system should be made, if everyone waits for 100% assurance before acting, then nothing will be done. To meet the needs of a changing world, pioneers who are willing to take well considered risks are needed. references Carvalho, L, etal. Cation Conductivity and Power Reliability A 20 Plant Survey, International Water Conference, Pittsburgh, PA October, 2001 Crovetto, R., etal. Research Evaluation of Polyamine Chemistry for Boiler Treatment: Corrosion Protection, NACE Corrosion 2011, Houston, TX Dooley, B., Anderson, B., HRSG Assessments Identify Trends in Cycle Chemistry, Thermal Transient Performance, Power Plant Chemistry, March, 2009 Galloway, E., Filming Amines Control Corrosion in Utility Plant Condensate System, Corrosion, Volume 15, August, 1959 Parker, Nathan A., Howell, Andrew G., Neutralizing Amine Usage and Associated Changes in l Appearance of Iron Oxides on Steel Surfaces of the Condenser Steamside, Intenational Conference on Flow Accelerated Corrsion in Fossil, Combined Cycle HRSG and Renewable Energy, Arlington, VA, March 28, 2013 Robinson, J., New Computer Modeling System Improves Condensate Treatment, Corrosion Asia, Singapore, September, 1994 Robinson, James O., Organic Chemical Treatment of High Purity Boiler Feedwater Advantages and Limitations, International Water Conference, Orlando, FL November, 2009 Robinson, James O., Robinson, Gregory J. Do Neutralizing Amines Have a Role in the Treatment of High Purity Boiler Feedwater?, Electric Utility Chemistry Workshop, Champaign, IL 2011 Verib, George J., An Alternative Chemistry for Both Operational and Layup Protection of High- Pressure Steam-Water Cycles Using an Organic Filming Amine, Power Plant Chemistry, 2011, 13(5) White, J.P., Filming Amines Reduce Corrosion at Arkansas P&L, Power, April, 1960 Page 6 TP1206EN.docx