AWT Technology Supplement 2020

the Analyst The Voice of the Water Treatment Industry

1300 Piccard Drive, Suite LL 14 • Rockville, MD 20850

Fall 2020

Keys to Reliable Makeup Water Treatment for Boilers Katie Perryman, Ed Sylvester, and Brad Buecker, ChemTreat, Inc.

Why the Steam Drum Is Crucial for Ensuring Proper Boiler Water Chemistry Colleen Sholl, P.E., HDR Inc.

Diagnosing Heat Exchanger Failures in Waste Heat Steam Generation Systems Edward S. Beardwood, Solenis LLC

Optimization of Condensate Treatments Using a Computer Modeling System

Richard Salazar, Suez Water & Technologies Solutions Technology Supplement to the Fall 2020 Analyst

Published by

COVER Firetube boilers at a light industrial plant.

Photo courtesy of SUEZ Water Technologies and Solutions.

Fall 2020

Technology Supplement 2020

Table of Contents 6 Keys to Reliable Makeup Water Treatment for Boilers

26 Diagnosing Heat Exchanger Failures in Waste Heat Steam Generation Systems

Katie Perryman, Ed Sylvester, and Brad Buecker, ChemTreat, Inc.

Tube failures in steam generators can be initiated by many factors. While the conditions of the steam generator and steam-generating tube surfaces observed and the chemistry of the water and deposits analyzed may suggest that improvements are required in the chemistry to prevent said failures, the actual pathway of the corrosion incurred is more important. The obvious can lead to a perceived cause of failure. Under such circumstances, subsequent failures are to be expected when the same operational environment reoccurs. The non-obvious signs take more effort to rationalize. However, though not novel, the extra effort is required to obtain the actual root cause to ensure the failure is not repeatable.

High-purity water is typically a must for power-producing steam generators, as the high-temperature/pressure conditions require control of impurities to low part-per-billion (ppb) concentrations to prevent serious corrosion and fouling.

For the many low-pressure boilers at industrial plants around the country, however, water-purity requirements are usually not as stringent. Yet, incidents where poor design or failures in the makeup water treatment system have induced severe scaling and corrosion have been recorded for decades and continue to occur. This article provides insight into the importance of makeup water treatment for low-pressure boilers and outlines modern technologies for producing good-quality makeup water at reasonable cost.

36 Optimization of Condensate Treatments Using a Computer Modeling System

16 Why the Steam Drum Is Crucial for Ensuring Proper Boiler Water Chemistry

Edward S. Beardwood, Solenis LLC

Colleen Sholl, P.E., HDR Inc.

Richard Salazar, Suez Water & Technologies Solutions

Selecting a proper condensate treatment program and monitoring the system can be complex. Utilizing a CMS to predict performance, evaluate chemical programs, and optimize treatments can simplify the process. The CMS model has been used and has improved steam condensate treatment results at several industrial plants. This technology can also help many others improve the performance of their condensate treatment programs.

While the boiler steam drum is often seen as simply a storage vessel where water and steam separation occur, it is a far more complex part of the overall steam/water cycle. This article will discuss examples of mechanical and operational problems commonly experienced with boiler steam drums and the impacts that these problems can have on cycle chemistry using a case study approach. It will describe the recommended methods and procedures for conducting routine drum testing to aid in identification of developing or trending issues.

Advertising Index 14 Browne Laboratories, Inc.

16 North Metal & Chemical Company

7

Chem-Met Company

15 QualiChem, Inc.

2

Environmental Safety Technologies

44 Special Pathogens Laboratory

22 Myron L Company

43 Walchem, IWAKI America Inc.

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the Analyst Technology Supplement 2020

1300 Piccard Drive, Suite LL 14 Rockville, MD 20850 (301) 740-1421 • (301) 990-9771 (fax) www.awt.org

2021 AWT Board of Directors

Calendar of Events Association Events Technical Training Seminars (East)

President-Elect

March 17–20, 2021 (Tentative) Graduate Annapolis Annapolis, Maryland

Secretary

2021 Business Owners Meeting

President

Michael Bourgeois, CWT Matt Jensen, CWT

Stephen C. Hallier, CWT

Immediate Past President

September 21, 2021 (Tentative) Providence Convention Center and Omni Hotel Providence, Rhode Island

Directors

2021 Annual Convention & Exposition

Treasurer

Noah Baskin

Thomas Brandvold, CWT John D. Caloritis, CWT Mark Coldren, CWT Stephanie Keck, CWT Fred Shurtz

Ex-Officio Supplier Representative

Garrett S. Garcia

Past Presidents

Brian Jutzi, CWT Jack Altschuler Bruce T. Ketrick Jr., CWT John Baum, CWT Bruce T. Ketrick Sr., CWT R. Trace Blackmore, CWT, Ron Knestaut LEED AP D.C. “Chuck” Brandvold, CWT Robert D. Lee, CWT Mark T. Lewis, CWT Thomas Brandvold, CWT Steven MacCarthy, CWT Brent W. Chettle, CWT Anthony J. McNamara, CWT Dennis Clayton James Mulloy Bernadette Combs, CWT, Alfred Nickels LEED AP Scott W. Olson, CWT Matt Copthorne, CWT William E. Pearson II, CWT James R. Datesh William C. Smith John E. Davies, CWT Marc Vermeulen, CWT Jay Farmerie, CWT David Wagenfuhr Gary Glenna Charles D. Hamrick Jr., CWT Casey Walton, B.Ch.E, CWT Joseph M. Hannigan Jr., CWT Larry A. Webb Mark R. Juhl

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Executive Director

Heidi J. Zimmerman, CAE

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Sara L. Wood, MBA, CAE

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Angela Pike

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Grace L. Jan, CMP, CAE

Associate Meeting Planner Kiki DeVane

Exhibits and Sponsorship Manager

Barbara Bienkowski, CMP

Marketing Director

Jennifer Olivares

September 22–25, 2021 Providence Convention Center and Omni Hotel Providence, Rhode Island

2022 Annual Convention & Exposition September 21–24, 2022 Vancouver Convention Centre Vancouver, Canada

2023 Annual Convention & Exposition

October 4–7, 2023 Amway Grand Hotel and Grand Rapids Convention Center Grand Rapids, Michigan Also, please note that the following AWT committees meet on a monthly basis. All times shown are Eastern Time. To become active in one of these committees, please contact us at (301) 740-1421.

Second Tuesday of each month, 11:00 am – Legislative/Regulatory Committee Second Tuesday of each month, 2:30 pm – Convention Committee Second Wednesday of each month, 11:00 am – Business Resources Committee Second Friday of each month, 10:00 am – Special Projects Subcommittee Second Friday of each month, 11:00 am – Cooling Subcommittee Second Friday of each month, 2:00 pm – Pretreatment Subcommittee Third Monday of each month, 9:00 am – Certification Committee Third Monday of each month, 3:30 pm – Young Professionals Task Force Third Tuesday of each month, 3:00 pm – Education Committee Third Friday of each month, 9:00 am – Boiler Subcommittee Third Friday of each month, 10:00 am – Technical Committee Quarterly (call for meeting dates), 10:00 am – Wastewater Subcommittee

Marketing Coordinator

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The Analyst Staff Publisher

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Michael Henley, (303) 745-3890, mdhenleywater@gmail.com

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The Analyst is published quarterly as the official publication of the Association of Water Technologies. Copyright 2020 by the Association of Water Technologies. Materials may not be reproduced without written permission.

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Other Industry Events

BOMA, Winter Business Meeting, January 25–27, 2021, Virtual AWWA, AWWA-WEF Utility Management, February 23–26, 2021, Atlanta, GA CTI, Annual Conference, February 7–11, 2021, New Orleans, LA ASHRAE, AHR Expo, March 15–17, 2021, Chicago, IL ACS, Spring National Meeting & Expo, March 21–25, 2021, San Antonio, TX AWWA, Membrane Technology Conference, March 22–25, 2021, West Palm Beach, FL NACE, Corrosion Risk Management Conference, April 18–22, 2021, Salt Lake City, UT WQA, Convention and Expo, April 27–29, 2021, Las Vegas, NV AWWA, Annual Conference & Expo, June 13–16, 2021, San Diego, CA ASHRAE, Annual Conference, June 26–30, 2021, Phoenix, AZ BOMA, International Conference and Expo, July 18–21, 2021, Boston, MA ASHE, Annual Convention & Expo, August 2–5, 2021, Chicago, IL ACS, Fall Meeting & Expo, August 22–26, 2021, Atlanta, GA USGBC, GreenBuild, September 21–22, 2021, San Diego, CA WEFTEC, Annual Technical Exhibition and Conference, October 16–21, 2021, Chicago, IL IWC, Annual Conference, November 7–11, 2021, Scottsdale, AZ RETA, Annual Convention, November 8–11, 2021, Schaumburg, IL

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the Analyst Technology Supplement 2020

President’s Message

By Michael Bourgeois, CWT

We all know the critical importance of boiler water treatment, whether for corrosion protection, heat exchange, or production of high-quality steam. As water treatment professionals, it is important that we know about the processes behind the solutions we provide to our customers so that we can effectively troubleshoot and offer the best advice possible.

The articles in this Technology Supplement will review some critical areas of boiler treatment, including makeup water treatment, understanding the steam drum, heat exchanger failures, and optimizing condensate treatments.

information helpful.

This is great information for water treatment professionals. The articles in this supplement are provided to offer you tips, advice, and knowledge that will help you and your business succeed. We hope you find this

As always, I welcome your feedback and can be reached at president@awt.org.

Save the Date

Education

Advocacy

Networking O4 S H + X 2 a >C

– X H + 2 O CaS 4

2021

Annual Convention & Exposition SEPTEMBER 22-25, 2021

Rhode Island Convention Center | Providence, Rhode Island

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the Analyst Technology Supplement 2020

Why Boilers Matter Boilers. That simple word conjures up multiple images from the early years of the United States as our nation pushed westward.

In the lore of yesteryear, boilers fueled the industrial revolution and the paddlewheel boats that plied back and forth on the waters of the Mississippi and other major rivers in the 1800s.

Likewise, they drove the steam locomotives of the early railroads and up until the 1940s and 1950s, when diesel and electric engines supplanted boilers as the power source of railroads.

They helped move the United States forward well before the electrification of our nation.

But in 2020 and beyond, boilers continue to hold an important role in our lives. They provide heat for many of our homes and institutional and commercial buildings, are important to many industrial processes, and generate our electricity.

For AWT members, boiler water treatment is an important market and includes everything from boilers found in apartment complexes, commercial buildings, institutions, and industrial plants. From a water treatment perspective, boilers may only require simple processes such as softened or chemically treated water to control scaling and corrosion. Or, at higher pressures, ion exchange or reverse osmosis may work well. But sub- and supercritical boilers can call for the use of complicated treatment systems that produce even an ultrapure quality water. Figure 1 is an example of a boiler used in an industrial facility that makes solar panels in Oregon.

Figure 1: Industrial boiler at a photovoltaic manufacturing plant.

By Mike Henley, Technical Editor

Information Administration reported that approximately 83% of U.S. electricity is produced using fuels often requiring boilers—nuclear, coal, and natural gas. Renewable energy sources account for the 17%, but two types of renewable energy—geothermal and biomass—also will use boilers. One type of fossil fuel—natural gas—will be used at plants that do not always use boilers (simple cycle). But combined-cycle facilities will have heat recovery steam generators. The simple point: boiler water treatment in power plants remains an important market for the foreseeable future, even with the moves to increase renewable energy use. Likewise, as noted, boiler water treatment for different industrial and heating applications remains a critical market that the AWT addresses. Table A details the energy sources used to produce electricity in the United States in 2019.

Table A: U.S. Energy Sources Used to Generate Electricity** Energy Source

Percent*

Renewable Wind

7.3%

Hydro

6.6%

Solar

1.8%

Biomass

1.4%

Geothermal

0.4%

Fossil Petroleum

1%

Coal

23%

Natural gas

38%`

Nuclear Nuclear

20%

Notes: *Total sum of all sources may not equal 100% because of rounding. **2019

Source: Electric Power Monthly (February 2020).

This Technical Supplement is focused on this important topic and includes four articles looking at some key areas of successful operations. Short introductions to these papers follow.

Authors Katie Perryman, Ed Sylvester, and Brad Buecker (“Keys to Reliable Makeup Water Treatment for Boilers”) examine the importance of makeup water treatment for low-pressure boilers to prevent scaling and corrosion problems at industrial plants. Their focus is on low-pressure steam systems (under 900 pounds per square inch gauge [psig]) and frequently between 50 and 600 psig and ways to improve the makeup water used in these types of boilers.

Briefly, to illustrate the value of the boiler water market, one can see the importance of boilers by simply looking at the power generation industry. In February 2020, the U.S. Energy

In her technical article, Colleen Scholl (“Why the Steam Drum Is Crucial for Ensuring Proper Boiler Water Chemistry”) looks at how steam drums impact boiler water chemistry. Ms. Scholl notes that improper operation, mechanical issues, or a lack of 6

the Analyst Technology Supplement 2020

routine maintenance can cause poor boiler water quality and corrosion or fouling of downstream equipment. The article describes recommended methods and procedures for conducting drum testing to help identify potential issues.

Author Ted Beardwood (“Diagnosing Heat Exchanger Failures in Waste Heat Steam Generation”) looks at steam generator failures. Sometimes these failures occur because plant operators misdiagnose the root causes. In his article, he looks at a facility that had operational problems with its heat exchanger but then had successful operations after changes were made in the treatment process, based on a study to determine the earlier failure causes.

Richard Salazar’s “Optimization of Condensate Treatments Using a Computer Modeling System” examines an alternate way to select steam and condensate chemical treatment programs for boilers using a computer modeling system (CMS). CMS will simulate the effects of different chemical treatments and operating conditions.

We hope you enjoy learning more about the technical aspects of boiler water treatment and gain a deeper appreciation for this important market for AWT members.

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Keys to Reliable Makeup Water Treatment for Boilers Katie Perryman, Ed Sylvester, and Brad Buecker, ChemTreat, Inc.

High-purity water is typically a must for power-producing steam generators, as the high-temperature/pressure conditions require control of impurities to low part-per-billion (ppb) concentrations to prevent serious corrosion and fouling. For the thousands upon thousands of low-pressure boilers at industrial plants around the country, however, water-purity requirements are usually not as stringent. Yet, incidents where poor design or failures in the makeup water treatment system have induced severe scaling and corrosion have been recorded for decades and continue to occur. These can lead to lost production and costly equipment repair or replacement. This article provides insight into the importance of makeup water treatment for low-pressure boilers and outlines modern technologies for producing good-quality makeup water at reasonable cost.

attention to the makeup water system (and often condensate return chemistry). This frequently seems to occur as the result of plant management, operators, or technical staff focusing on process chemistry and engineering, with steam generation (and cooling water systems) appearing as rather nebulous entities that require less attention.

Most of the boilers in large industrial plants are the watertube style, frequently of the package type, although large boilers may be field-erected. Steaming rates (pounds per hour [lb/h]) are usually in the five to six-figure range. Commonly, these boilers include superheaters to raise the steam temperature above the saturation point and ensure the steam has the proper energy and/or remains dry until the point of use. For boilers that supply turbines, superheating is required to prevent excessive condensation in the turbine that could damage blades.

Low-Pressure Steam Generators

Low-pressure steam (pressures below 900 pounds per square inch gauge [psig] in general, and often between 50 and 600 psig) is used at many industrial plants around the country. For example, steam typically serves numerous processes at refineries, including as an integral heat source in atmospheric distillation, and in cracking and reforming processes. Steam feeds turbines for blast furnace air production at integrated steel mills; digesters and concentrators at paper mills; evaporators, crystallizers, and reaction vessels at chemical plants; and building heat systems everywhere. The list goes on and on.

Makeup Treatment Issues

Probably from the time humans first began to heat water for personal needs, our species has observed deposition in heated vessels. These issues became much more acute following the invention and expanded use of the steam engine during the Industrial Revolution of the 18th and 19th centuries. The primary culprit was (and still often is) calcium carbonate deposition.

Ca 2+ + 2HCO3- + heat → CaCO3↓ + CO2 + H 2O

Eq. 1

This equation outlines the reaction of calcium ions (Ca 2+) and bicarbonate alkalinity (HCO3-) that can occur in hot water systems and boilers. A critical point to note is that CaCO3 is an inversely soluble salt, whose deposition potential increases with increasing temperature. As Figure 1 clearly illustrates, it is not a mechanism that has been relegated to the past.

The stimulus for this article comes from direct experience by the authors and too-frequent reports from our colleagues, who, upon entering plants for the first time find steam generators with serious scaling, corrosion, or steam purity issues that can be directly traced back to either poor design or inadequate

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Figure 1. Boiler deposition.

As makeup water passes through the vessel, calcium (Ca 2+) and magnesium (Mg2+) exchange for sodium. The strongest affinity is for calcium followed by magnesium, so as a service run progresses, the resin develops stratified layers.

Figure 4: General schematic of the exchange layers that form in a softener during a service run.

As steam generators increased in pressure and power in the last century, methods to minimize and control CaCO3 scaling became necessary. A common solution from the 1930s onward has been makeup water sodium zeolite softening, a technology that became practical with the development of synthetic ion exchange resins (Figure 2).

Figure 2: Ion-exchange resin beads.

The softened stream, with hardness removed, still contains the other dissolved ions, including alkalinity, chloride (Cl-), sulfate (SO42-), and silica (SiO2). When the bed reaches exhaustion, it is regenerated with a brine solution that drives the hardness ions off into a waste stream, which is discarded.

At this point, several features of sodium softening require some extra discussion. Many low-pressure steam-generating systems have been designed with sodium softening as the core boiler makeup treatment method, with no further treatment. And indeed, this may be sufficient for numerous steam generators. Table A outlines some general guidelines, extracted from a well-known American Society of Mechanical Engineers (ASME) source, regarding impurity limits in low- to medium-pressure watertube industrial boilers.

Table A: Guidelines for Impurity Limits in LP Industrial Boilers Drum Operating Pressure (psig) Feedwater

0–300

301–450

451–600

Dissolved oxygen (mg/L) measured before oxygen scavenger injection

<0.007

<0.007

<0.007

Total iron (mg/L as Fe)

≤0.1

≤0.05

≤0.03

Total copper (mg/L as Cu)

≤0.05

≤0.025

≤0.02

Total hardness (mg/L)

≤0.3

≤0.3

≤0.2

pH at 25°C

8.3–10.0

8.3–10.0

8.3–10.0

Non-volatile TOC (mg/L)

<0.1

<0.1

<0.05

Oily matter (mg/L)

<0.1

<0.1

<0.05

Silica (as SiO2)

≤150

≤90

≤40

Total alkalinity (mg/L as CaCO3)

<700

<600

<500

Free hydroxide alkalinity (mg/L)

NS*

NS*

NS*

Specific conductance (µmhos/cm @ 25°C)

5,400–1,100

4,600–900

3,800–800

1.0–0.2

1.0–0.2

Feedwater

Each of these beads contains billions of active sites, which, for sodium softening, are typically sulfonic acid groups with sodium attached (SO3–Na+). Figure 3 illustrates a basic configuration of a softening vessel.

Figure 3: Illustration of an ion-exchange vessel.

Boiler Water

Total Dissolved Solids in Steam TDS maximum (mg/L)

1.0–0.2

*NS = Not specified

Note: This data was extracted from Table 1 in Reference 1. The booklet contains many additional details on these guidelines.

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Keys to Reliable Makeup Water Treatment for Boilers continued

The data indicates that a significant amount of alkalinity can be tolerated in low-pressure boilers, and for many applications, some alkalinity may be desirable, as it helps protect metal surfaces from corrosion, a point we will return to later. However, HCO3-, upon reaching the boiler, is in large measure converted to CO2 via the following reactions in Equations 2 through 4.

2HCO3- + heat → CO32- + CO2↑+ H 2O

Eq. 2

CO32- + heat → CO2­↑+ OH-

Eq. 3

The conversion to carbon dioxide (CO2) from the combined reactions may reach 90%. CO2 flashes off with the steam, and when the CO2 re-dissolves in the condensate, it can increase the acidity of the condensate return.

CO2 + H 2O ⇔ H 2CO3 ⇔ H+ + HCO3-

Eq. 4

Although the pH generated by this reaction has a relatively mild lower limit, the acidity is more than enough to cause significant carbon steel corrosion in condensate return systems. For example, 3 parts per million (ppm) of CO2 in pure steam condensate will lower the pH to 5.26. If dissolved oxygen is present in the system, corrosion can be greatly magnified.

A unit operation that can minimize production of CO2 in the steam generator is illustrated in the following fundamental diagram.

Figure 5: Makeup water treatment system with decarbonator.

Note the inclusion of a forced-draft decarbonator with acid injection to the feed. The acid conditioning forces Equation 4 to the left, and a well-designed decarbonator can reduce the CO2 concentration to a low parts-per-million (ppm) level. Caustic feed downstream of the decarbonator then raises the pH of the water to make it less corrosive on its path to the boiler. Note: If steam attemperation is provided by direct injection of feedwater from the deaerator, then caustic cannot be used to raise the pH. A nonvolatile compound (e.g., ammonia, an amine) is required.

Another issue briefly hinted at above now requires a bit of discussion. With too-frequent regularity, when technical representatives begin visiting a plant for the first time, they find boilers with scale deposition, corrosion, or both. In many cases, plant personnel will reveal softener problems that have led to hardness breakthroughs. Equation 1 and Figure 2 illustrate the potential effects of such difficulties. But even a softener/decarbonator operating properly still allows many ions, such as chloride and sulfate, to enter the boiler. Without close attention to boiler water chemistry and boiler blowdown control, the accumulation of these ions can cause corrosion and other problems, including foam formation in boiler drums. This in turn can lead to steam contamination and downstream issues. To re-emphasize, steam generator makeup system and boiler water chemistry control require just as much attention as process operations.

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Keys to Reliable Makeup Water Treatment for Boilers continued

Something Better Than Softening?

For modern makeup systems, reverse osmosis (RO) offers a reliable alternative to softening, where even basic systems can remove 99 plus percent of all ions from water. The osmosis process has been known for years. Two solutions of different concentrations, when separated by a semi-permeable membrane that only allows water to pass, will induce water in the dilute solution to move through the membrane to the other solution to balance the concentration. This phenomenon induces an osmotic pressure on the membrane until the solutions reach equilibrium. As the name reverse osmosis implies, the reaction is operated in reverse, and pressure produces purified water from a more concentrated stream.

The potential application of RO as a makeup water treatment method became well known in the last century and became popular with the development of and improvements to spiral-wound membrane technology.

Figure 6: Cutaway view of a spiral-wound RO membrane. This photo by unknown author is licensed under CC BY-NC.

Figure 8: General schematic of crossflow filtration.

The feed flows parallel to the RO membranes, and pressure forces pure water through the membranes while the impurities are carried away with the reject. Only a few of the smaller monovalent ions (Na+, Cl-, silica, HCO3-) pass through the membrane. However, while crossflow filtration is designed to keep impurities suspended in the reject stream, it is inevitable that even with exceptionally clean makeup, compounds will gradually build up on the membrane surfaces. Typically, residual suspended solids that are not captured by pretreatment will accumulate in the lead membranes of an RO system. Conversely, because dissolved ions concentrate as the water passes from one membrane to the next, scaling becomes an increasing concern in downstream elements.

The basic RO system is a two-stage, single-pass type, as outlined in Figure 9.

Figure 9: General schematic of a two-stage, single pass RO.

A flat membrane sheet has several layers as a backbone, which are all wrapped around a central, perforated plastic core.

Feed enters the front end of each element and flows along the feedwater carrier while pressure pushes water through the membrane. The purified water, known as permeate, flows to the central core, and the increasingly concentrated feedwater (reject) exits the element.

Each RO pressure vessel typically has several elements arranged in a series.

Figure 7: Basic diagram of RO elements in a pressure vessel.

O-rings seal each element along the walls of the pressure vessel so that the feedwater does not short-circuit any of the elements.

A typical RO pressure vessel will have five or six elements.

The configuration is designed to process the water via the mechanism known as crossflow filtration.

A critical feature of RO is illustrated in this diagram. With â&#x20AC;&#x153;normalâ&#x20AC;? feedwaters, approximately 50% of the feedwater is converted to permeate in each first-stage pressure vessel. This means that without further processing, 50% of the feedwater would be wasted. In the two-stage design shown above, the raw feedwater flows through six parallel pressure vessels in the first stage, and the reject from these vessels is routed through three additional pressure vessels in the second stage. Total water recovery increases to 75%.

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Keys to Reliable Makeup Water Treatment for Boilers continued

For some applications, especially those for ultra high-purity water production, two-pass RO is common. In this configuration, the permeate from the first pass is treated in a separate set of membranes. Because the feedwater has already been significantly purified, 85% to 90% recovery from the second pass is achievable. The reject is recycled back to first pass inlet, and no water is discharged to waste from the second pass.

“RO has become quite popular for a number

RO has become quite popular for several applications in recent years, especially for steam-based power generating units. RO plus polishing mixed-bed ion exchangers or electrodeionization can produce the high-purity water needed for steam generation.

purity water needed for steam generation.”

RO Fouling and Scale Control

RO membranes, especially the lead elements, are susceptible to particulate fouling. An important measurement for determining this fouling potential is the silt density index (SDI).

Usually, 5-micron (µm) depth filters are placed ahead of the RO to minimize the potential for particulate fouling. The SDI tests should be performed on the effluent from these filters. The SDI test is straightforward. A flowing sample of RO feedwater, downstream of the cartridge filters, is routed through a 0.45-µm filter at 30 psig pressure. Measurement is taken of the time for 500 milliliters (mL) of water to pass through the filter at the beginning of the test (ti) and again after 15 minutes (tf ). The SDI is calculated as shown in Equation 5: SDI15 = (1-(ti /tf ))/T x 100

Eq. 5

As an example, consider the following data taken from an operating RO unit: ti = 34 seconds (s) tf = 66 s

T = 15 minutes (min) SDI15 = 3.2 A general rule of thumb is that the SDI should be at least below 5 and preferably below 3. However, SDI should not be the only criteria that determines suitability of a RO application. The type of water and/or the nature of contaminants should also be considered. For example, in one application, the SDI readings of the RO feed always ranged between 1 and 3. Yet the membranes fouled with exceptionally fine iron oxide particles.

of applications in recent years, especially for steam-based power generating units, where RO plus polishing mixed-bed ion exchangers or electrodeionization produce the high-

Scale formation is another issue that requires attention. When water flows through an RO pressure vessel, the concentrate continually accumulates dissolved solids, which increases the scaling potential. Calcium carbonate and sulfate can build up to a point where precipitation begins to occur. Other possible deposits include silica and alkaline metal silicates, strontium sulfate, barium sulfate, and calcium fluoride. While pretreatment can reduce the concentrations of many scale-forming compounds, the remainder may still cause problems. Barium and strontium sulfate scales are especially difficult to remove. Reputable membrane manufacturers have developed programs to calculate the solubility limits for these salts. The program will warn the user if any solubility limit is exceeded. The programs also provide “normalization” calculations of the RO system, as is described later.

Antiscalant feed is typical for RO systems. Common antiscalants include polyacrylates and phosphonates. The correct antiscalant or blend can control calcium sulfate at a factor of 7 above the saturation limit, strontium sulfate 800% above the saturation limit, and barium sulfate 6,000% above the saturation limit.

Pretreatment chemicals can affect membrane performance.

Coagulating agents of the cationic variety and, most notably, aluminum compounds and some organic coagulants/flocculants, are particularly troublesome to RO membranes. If these agents are present, methods to remove them should be considered. Chlorine, usually introduced as bleach, injected into the primary plant makeup to control microbiological fouling will react with nitrogen atoms in RO membranes and irreversibly damage the materials. Chlorine should be removed upstream of the RO, but the absence of any biocides leaves the membranes in danger of microbial attack. Figure 10 shows how biofouling can damage a membrane element.

Figure 10: (Left) Severe microbiological fouling evident at the inlet end of an RO membrane. Photo by Brad Buecker.

(Right) Severe biofouling on a RO membrane feed spacer. Photo by Li Yang.

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Keys to Reliable Makeup Water Treatment for Boilers continued

Biological fouling can cause irreversible damage to membranes because the deposits cannot be completely removed by standard cleaning methods. It is imperative to minimize conditions that can lead to microbiological deposition. Alternative techniques to chlorine are available to minimize microbe deposition within membranes. One is periodic treatment with a non- or mildly oxidizing biocide (frequency depends on fouling potential). A popular choice is dibromo-nitrilo-propionamide (DBNPA). A DBNPA chemical diagram is shown in Figure 11.

Figure 11: Basic chemical structure of DBNPA.

by a failed or degraded membrane, which might otherwise be attributed to temperature effects.

A two-step cleaning process is often employed to remove the potentially wide variety of foulants that can accumulate in RO membranes. Typically, in the first step, a high-pH (12 at 95 °F) solution is circulated throughout the membranes. The alkaline solution removes organic compounds, microbiological and otherwise, that have accumulated. This stage is followed by a rinse and often a low-pH stage with citric acid as the key ingredient.

Low pH helps remove soluble mineral salts such as calcium carbonate, while the citric acid will chelate metals, most notably iron. The inclusion of a heater in the cleaning loop can significantly speed up the process.

An important concept is to clean each stage separately. Otherwise, extracted impurities from one stage may foul the other, and vice versa. Also, cleaning systems are typically designed with cartridge filters in the cleaning loop to collect solids during the process. These filters should be replaced after each step in the cleaning.

DBNPA is a fast-acting biocide that can be readily removed from any discharge by raising the pH to around 9, or commonly, treating with sodium bisulfite. Another possibility is a specialized version of chlorine dioxide (ClO2).A Such a product may sound surprising, as chlorine dioxide can act as a strong oxidizer in cooling water applications. However, in this case, the chlorine is not free, and thus does not react with nitrogen atoms in the membranes.

RO Cleaning

Even with well-controlled pretreatment and antiscalant chemistry, RO membranes will still collect deposits. The lead elements gather residual colloidal and suspended solids, while the downstream elements, especially those in the second stage, see higher concentrations of dissolved ions that may precipitate. Compounding the issue is that the pressure required to push water through the membranes can hold some of these particles in place. If impurities accumulate unchecked, the eventual result is irreversible membrane fouling.

Therefore, normalization programs are key for determining the need for and scheduling of RO cleanings. Temperature has a significant impact on permeate flux and pressure, and temperature changes can mask flow and pressure variations caused by suspended solids or scale buildup. Normalization programs use temperature, pressure, and flow measurements to provide corrected values for all temperature conditions. A common rule of thumb is to schedule a cleaning when the normalized value has dropped 10% to 15% from the baseline. Normalization programs can also help detect an increase in salt passage caused

The foregoing is general guidance only. Please consult your RO manufacturer for specific guidance.

RO Waste Stream Issues

As noted, a typical two-stage, single-pass RO system recovers approximately 75% of the inlet feed and produces a waste stream (reject) of the remaining 25%. This stream must be disposed somewhere. For plants with cooling towers, the basin of one of the towers is often an ideal location for the reject. Alternately, many plants have wastewater treatment facilities to condition discharge water before release to the environment. RO reject is basically plant makeup concentrated by a factor of four, so it should not overload the wastewater treatment equipment.

Makeup Water Treatment Issues Related to Boiler Water Treatment

A variety of treatment programs are available for low-pressure boilers, which may include phosphates, organic polymers, and sometimes chelating agents. These should be tailored to the chemistry of the water entering the boiler from both the makeup source and condensate return. A change from softened water to RO permeate can have a significant impact on boiler water treatment and even feedwater treatment. Higher purity waters are often known as â&#x20AC;&#x153;hungryâ&#x20AC;? water because the lack of dissolved ions induces metals to give up ions to the water.

Bicarbonate ions, even though they can react with calcium to form scale, will in many cases form a loose, protective layer on metals. For plant personnel considering a change from softened water to RO, these and other factors should be considered before making the switch. And, given that boilers should see a lower influx of hardness, the treatment program may need modification to account for this changed chemistry. A factor of 13

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Keys to Reliable Makeup Water Treatment for Boilers continued

major importance at many plants is the ratio of makeup water to condensate return. If the latter is much higher than the makeup flowrate, condensate return chemistry can dominate the selection of the best boiler water treatment program.

Katie Perryman is manager of ChemTreat’s pretreatment team as well as the company’s Early Career Program. Her career at ChemTreat has focused on membrane separation and ion exchange with an emphasis on consulting and troubleshooting of pretreatment systems in different water treatment applications. Ms. Perryman holds a B.S. in chemistry from Virginia Tech. She may be contacted at katieh@chemtreat.com.

Reference

1. ASME (1994). “Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers,” The American Society of Mechanical Engineers, New York, New York.

Endnote

Ed Sylvester is the director of filtration, ion exchange, and membrane technologies at ChemTreat. He has more than 41 years of experience in water treatment, including product development, troubleshooting, corporate training, and conference presentations. Mr. Sylvester may be contacted at edwards@chemtreat.com.

ChemTreat’s CL3000, a specialized version of chlorine dioxide (ClO2), is the cleaning product referenced in the text.

A

Disclaimer: This discussion represents good engineering practice developed over many years. However, it is the responsibility of plant owners, operators, and technical personnel to set up reliable chemical feed, control, and monitoring systems based on consultation with industry experts. Many additional details go into the design and subsequent operation of these technologies than can be outlined in this article.

Brad Buecker is senior technical publicist with ChemTreat. He has many years of experience in or affiliated with the power industry, with nearly two decades of it in steam generation chemistry, water treatment, air quality control, and results engineering positions. Mr. Buecker has authored many articles and three books on power plant water/steam chemistry and air pollution control topics. He has a B.S. in chemistry from Iowa State University. Mr. Buecker can be reached at bradley.buecker@chemtreat.com.

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Why the Steam Drum Is Crucial for Ensuring Proper Boiler Water Chemistry Colleen Sholl, P.E., HDR Inc.

Abstract

Introduction

This article will discuss examples of mechanical and operational problems commonly experienced with boiler steam drums and the impacts that these problems can have on cycle chemistry using a case study approach. It will describe the recommended methods and procedures for conducting routine drum testing to aid in identification of developing or trending issues.

Steam separation typically occurs in two stages within a steam drumâ&#x20AC;&#x201D;primary separation and secondary separation. Primary separation is normally accomplished with baffles and centrifugal, inertial, or chevron-type separators. Secondary separation is generally achieved using mesh pads, screens, or corrugated

While the boiler steam drum is often seen as simply a storage vessel where water and steam separation occur, it is a far more complex part of the overall steam/water cycle. Mechanical and operational problems in the steam drum can have a significant impact on cycle chemistry and, therefore, the rest of the plant.

Improper operation, mechanical issues, or lack of routine maintenance can cause poor steam quality, poor boiler water quality, and corrosion or deposition of downstream equipment.

Whether one is considering a traditional boiler steam drum or steam drums on a heat recovery steam generator (HRSG), the steam drum is viewed by some as a wide spot in the line or, more frequently, as a simple storage vessel where water and steam separation occurs. True, water and steam separation occur here, but it is that very fact that makes the operation and maintenance of the steam drum and its ancillary equipment key factors in achieving good cycle chemistry control throughout the entire steam/water cycle.

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plates framed at the steam outlet of the drums that act as final stage scrubbers. Effective separation is a function of both design and operational factors. Design factors include items such as drum dimensions (length and diameter), type and arrangement of separation equipment, and arrangement of drum inlet and outlet connectionsâ&#x20AC;&#x201D;factors that are pre-existing and out of the control of plant operational staff (1).

The operational factors or how the plant is run are the factors that plant operational staff can control or influence and include drum level control and surges or swings in plant operations.

High-efficiency separation is crucial in minimizing carryover of water droplets, which can cause thermal damage in downstream equipment, and carryover of dissolved solids present in those water droplets, which can result in the formation of deposits in downstream equipment (1).

lems or for making chemistry adjustments. Drum blowdown should be placed in manual (if automatic control is provided) and maintained at a constant flowrate throughout the duration of the testing. Prior to beginning carryover testing, any issues or upset conditions associated with chemical additions should also be resolved and chemical concentrations stabilized. Previous carryover testing results and steam drum mechanical carryover design data should be available for evaluation purposes once the test data is collected. Figure 1 shows the primary (top) and secondary (bottom) steam-water separation equipment.

Figure 1: Primary (top) and secondary (bottom) steam-water separation equipment.

Very few plants today perform routine carryover testing of their steam drums. Online continuous monitoring of a limited number of steam purity and drum water quality parameters has taken the place of routine carryover testing. Performance of this testing on a routine basis can serve as an important cycle chemistry troubleshooting tool, as carryover due to mechanical or operational issues (i.e., poor steam separation) is the most common cause of drum-related cycle chemistry issues.

Carryover testing should be performed every six months at a minimum, and more frequently if the unit has a history of carryover problems or a problem is suspected. For this assessment, sodium is most commonly used as the tracer ion for testing since online analyzers for determining low-level sodium are commonly provided, and sodium salts such as sodium hydroxide and/ or trisodium phosphate are used for pH control in many steam drums, making supplementary chemical additions unnecessary or at least minimizing a supplemental addition. These sodium salts also have good solubility and a relatively low volatility at typical drum operating conditions, making them suitable tracers for testing purposes (2).

Drum Carryover Testing

Preparation for assessment. Carryover testing should be conducted at stable full load unit operating conditions. The rate of carryover is dependent on steaming rate (unit load), drum operating pressure, and drum water level. Carryover generally increases slowly as the unit approaches full load and then quickly peaks at its maximum. Drum level can also impact carryover, with higher than normal drum levels resulting in higher carryover rates. Normalizing unit operations at full load design operating conditions prior to conducting the testing standardizes the results for comparison during future tests and provides the best conditions for check against design parameters.

It may be desirable to also conduct the same testing at additional loads at which the plant frequently operates to provide additional data for troubleshooting suspected carryover prob-

If using online sodium analyzers for testing, the units should be configured to sample and test for saturated steam and for drum blowdown for the unit to be tested and the sample lines flushed.

Separate analyzers are needed for testing the saturated steam and the blowdown to avoid cross contamination of samples and to provide timely samples. If two independent sodium analyzers are not available, utilizing another testing method for the blowdown is preferred since the concentration of sodium in the 19

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Why the Steam Drum Is Crucial for Ensuring Proper Boiler Water Chemistry continued

blowdown sample is greater and therefore, less susceptible to error in collection and testing (3). The flowrate through the sample lines should be checked to ensure that velocity is approximately 6 feet per second (ft/s) with sample surplus flow going to drain.

The amount of time required to adequately flush the sample line depends on the length of the line and the size of the sample tubing.

Table A, adapted from ASME’s Consensus on Operating Practices for the Sampling and Monitoring of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers, provides recommended flushing times for various sizes of commonly used sample tubing. Best practices dictate a minimum of three pipe volumes be run through the system before it can be ensured that a sample is representative (4, 5). Using the table—if the sample line is constructed of 3/8-inch tubing with a wall thickness of 0.049 inches, the required flush time would be 4.3 seconds per foot (s/ft) of sample line. So, if the sample line from the pipe tap to the sample panel is 500 ft, the required flushing time is 2,150 s, or a minimum of 36 minutes. The sample flowrate should not be readjusted after or during the flush period.

Table A: Flush Times Required for Representative Sample Collection

Sample Tubing Size (inches)

Wall Thickness (inches)

Tube ID (inches)

Recommended Purge Time at Flowrate of 500 mL/min (s/ft)

¼-inch tubing

0.035 0.042 0.049 0.058 0.065

0.180 0.166 0.152 0.134 0.120

1.8 1.5 1.3 1.0 0.8

3/8-inch tubing

0.035 0.042 0.049 0.058 0.065

0.305 0.291 0.277 0.259 0.254

5.2 4.7 4.3 3.7 3.6

½-inch tubing

0.035 0.042 0.049 0.058 0.065

0.430 0.416 0.402 0.384 0.370

10.3 9.6 9.0 8.2 7.6

Note: ID = inside diameter Source: Reference 4

Most steam drums are provided with multiple saturated steam take-offs, with each take-off having its own sample collection nozzle. The sample lines from each take-off are commonly tied together to produce a composite saturated steam sample that is then routed down to the sample conditioning equipment for pressure reduction, cooling, and measurement. In other instances, the saturated steam sample is collected at a single location after the various saturated steam take-offs have been combined into a common steam header upstream of the superheater. If the plant is provided with the capability, it is most desirable to sample the saturated steam from each individual take-off to evaluate the carryover.

This permits the steam purity to be evaluated along the entire length of the drum and helps to identify any location along the length of the drum where degradation or damage to the steam separation devices may have occurred. According to the Electric Power Research Institute (EPRI), there have been numerous instances reported where excessive carryover was discovered in only one area of the drum, and the damage to the steam separation equipment may have been missed or underappreciated if testing had only occurred on the combined saturated steam sample (2).

To obtain samples that are truly representative of the bulk flow

for fluid steams that exhibit two-phase, isokinetic sampling procedures as detailed in ASTM D1066 Standard Practice for Sampling Steam should be used. Isokinetic sampling ensures that all phases of the sampled fluid enter the collection nozzle with the same velocity and direction of flow and that the flow velocity into the nozzle is the same as the sampled stream velocity (6).

Fluids exhibit different density and inertia in different phases and are, therefore, not proportionally represented in a sample that is not collected with an isokinetic device (6). To ensure that the data collected during a drum carryover test accurately measures the purity of the steam phase as well as the water droplets present in the steam, the saturated steam samples should be collected using isokinetic sample nozzles in accordance with ASTM D1066. During the test planning phase, it is important to verify that isokinetic sample nozzles are installed in the saturated steam lines where sample collection will be performed.

“The amount of time required to adequately flush the sample line depends on the length of the line and the size of the sample tubing.”

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Why the Steam Drum Is Crucial for Ensuring Proper Boiler Water Chemistry continued

Testing Procedure

Here are important steps to follow in the cooling drum testing procedure.

1.

Walk down the unit and confirm sampling system configuration and valve alignments. Verify that all valves are functional and do not leak. Confirm that the sampling conditioning system is in service, lines are properly flushed, and uniform flowrate is provided to the instrumentation and/or grab sample points.

2.

Verify calibration of all testing instrumentation and online analyzers.

3.

Ensure that the unit is operating at steady design load and will likely remain so for the duration of the testing. Ensure that the drum blowdown is fixed at a constant flowrate.

Note the operating load, steam flowrate, and continuous blowdown flowrate (if available). It is recommended that testing commence one hour or more after steady state operating conditions have been established to minimize error potential due to transient conditions.

4.

If the unit is operating on all-volatile treatment (AVT) chemistry, administer a small dosage of sodium hydroxide to the steam drum to boost sodium levels and provide sufficient sodium for testing.

5.

If the unit is operating on caustic or phosphate treatment, discontinue feed temporarily to the drum while samples are collected and analyzed.

6.

Collect and analyze samples from the saturated steam (drum steam) sample point(s) and the drum continuous blowdown. To achieve the best accuracy, the steam sample and the blowdown sample should be taken and analyzed within 5 minutes of each other. If the plant has the capability to rotate between multiple saturated steam take-offs, each take-off should be sampled individually (by closing the isolation valves on the other take-offs). After each sampling, the steam sample line should be flushed to avoid cross contamination of subsequent samples. Record the measured sodium concentration for each saturated steam sample location and the corresponding drum water sodium concentration.

7.

Wait approximately one hour and repeat the process outlined in Step 6.

8.

Confirm that the data collected in Step 6 is consistent with the repeated testing conducted in Step 7. The expectation is that the results should be comparable during repeat testing at each saturated steam take-off (within about 10%). If there is large variation in the data, wait one hour and repeat the testing process again or until repeatable results (again within about 10%) are achieved.

The following data should be collected for each saturated steam take-off test point: •

Continuous blowdown sodium (microgram per liter [µg/L], as Na)

•

Saturated steam sodium (µg/L as Na)

•

Carryover (Saturated Steam/Na/Blowdown Na)

•

Calculated carryover (Saturated Steam Na/Blowdown Na) * 100%

IAPWS document TGD1-08 (3), Technical Guidance Document: Procedures for the Measurement of Carryover of Boiler Water into Steam, and Appendix F of EPRI Technical Report 3002001381 (2), Comprehensive Cycle Chemistry Guidelines for Combined Cycle/ Heat Recovery Steam Generators, provide additional detail on performing carryover testing as well as additional background information that may be useful in planning and conducting this testing.

Interpreting the Results

From the data collected during the testing process, the total carryover can be calculated by dividing the concentration of the sodium in the saturated steam by the concentration of the sodium in the drum blowdown and multiplying the result by 100%. An average total carryover can be determined (useful if multiple saturated steam take-offs were tested) by summing the individual test results and dividing by the number of tests conducted. For drums operating at less than 2,500 pounds per square inch gauge (psig), the vaporous component of the total carryover is less than 0.01%, allowing the assumption that the measured total carryover using the process above is approximately equal to the mechanical carryover (2). If the drum operates at 2,500 psig or greater, the vaporous carryover needs to be determined from the applicable charts or tables and subtracted from the total carryover to accurately determine the mechanical carryover. Appendix F of EPRI Technical Report 3002001381 provides tabulated data on volatile carryover of sodium at various operating pressures at or above 2,500 psig that can be used for this calculation.

Once the mechanical carryover rate has been determined, the results can be compared to the design values for the steam drum to evaluate performance and potential separator degradation or damage. These results should also be compared to the previous carryover testing results to identify trends and determine the need for inspection of the steam drum internals or planning for repairs. If variations in mechanical carryover are noted between the various saturated steam take-offs, there is likely localized damage to the steam separation equipment, and plans for inspection and repair should be made as soon as practical.

If needed, the cycles of concentration in the steam drum can be adjusted downward (by increasing the continuous blowdown from the drum) as required to maintain the required steam quality for the steam turbine and other steam users.

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the Analyst Technology Supplement 2020

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Why the Steam Drum Is Crucial for Ensuring Proper Boiler Water Chemistry continued

Case Studies

drum was performed manually with the operations staff, adjusting the pump stroke and speed as required after performing routine testing. These manual chemical feed adjustments resulted in overfeed-underfeed swings in chemistry as the operators struggled to locate the optimal dosing rates. This further exacerbated the control of chemistry throughout the system, resulting in a downward spiral where blowdown and chemical feed to the steam drum were almost constantly being adjusted as chemistry spiraled out of control.

The following case studies highlight a number of challenges related to steam/water cycle chemistry where issues (mechanical, chemical, or otherwise) originating in the steam drum were found to be the root cause of the chemistry issue. These case studies illustrate the importance of proper design, operation, and maintenance of this piece of equipment and its ancillary devices.

After weeks of operation in this fashion, the boiler was taken back offline and the drum opened. The first and most obvious thing noted as the drum was opened was a significantly higher operating water line in the drum. Further investigation revealed that a new process used to calibrate the drum level instrumentation during the previous outage resulted in a miscalibration of the devices and the drum operating with a significantly higher drum level than what the instrumentation was indicating. The devices were re-calibrated, and water chemistry quickly returned to normal once the unit was placed back into service.

While carryover, due to one mechanism or another, is the most frequently encountered chemistry challenge, other issues rooted in the design, maintenance, or operation of the steam drum or its ancillaries can also cause chemistry issues throughout the unit. These issues may include improper cleaning, improper blowdown control, improper chemical feed control, partitioning of amine/ammonia in drum, location of chemical feeds, or use of inferior pH adjustment products.

Study #1 Calibration and routine maintenance of all steam drum instrumentation is critical to ensuring that operations are properly monitored and that adjustments can be made based on reliable information. The first case study presents a situation where the level instrumentation on the steam drum was not calibrated properly, resulting in chemistry issues throughout the cycle.

Lack of automation on the blowdown equipment and the drum chemical feed systems also exacerbated the problem. In a practical guide to boiler operations published in its journal, the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) listed improper boiler blowdown techniques as one of the most common causes of catastrophic boiler failure. According to ASHRAE, a properly designed and operated continuous blowdown system constantly monitors boiler water conductivity and adjusts the blowdown rate to maintain compliance within a certain control range (7).

After a scheduled maintenance outage, the high-pressure drum boiler at this industrial facility came back online. The plant operated using a phosphate program, and chemistry had been well maintained with very few excursions prior to its shutdown.

However, just a few days after returning to service, the plant chemist began noting elevated sodium and silica levels in the condensate system. Little monitoring was available on the steam itself, but chemistry in the drum boiler water appeared to be within specification. Grab sample testing confirmed the online chemistry instrumentation readings.

Despite the confirmation received on the online chemistry instrumentation, the plant decided to manually open the boiler blowdown until the condensate sodium and silica returned to specification. As expected, the increased boiler blowdown decreased the sodium and silica levels throughout the system; however, it also threw the chemistry in the steam drum into an upset condition. Control of chemical addition to the steam

Study #2 At first glance, the situation at the Case Study #2 facility was eerily similar to the situation experienced at the Case Study #1 facility. After coming back from a routine maintenance outage, the plant was starting to experience high silica readings throughout the system. Above-specification silica readings were noted in the condensate, feedwater, and steam, while the silica concentration within the steam drum itself was slightly elevated but remained within specification. Increasing the blowdown from the unit helped to keep the silica within ranges where the unit could remain in operation, but the water wastage from the unit was a concern for plant management, so testing was conducted to troubleshoot the problem.

The first attempt to troubleshoot the problem was to lower the operating drum level to determine whether foaming or an issue with the level instrumentation was at the heart of this problem. The plant had experienced some foaming issues in another boiler drum at this facility due to organics present in the boiler water. Therefore, the plant was initially convinced that foaming was the root cause. However, the drum level change experiment produced a minimal change in the concentration of silica in the steam, and no organics were found during sampling and testing.

Carryover testing on this steam drum was then performed to further troubleshoot the issue. It had been many years since the baseline carryover testing was completed, and no subsequent testing had been conducted since, so there was limited information to baseline the unit. Design information for the unit found in the plant files specified a guaranteed 0.125% mechanical carryover for the equipment. Sodium was used as the â&#x20AC;&#x153;tracerâ&#x20AC;? chemical during the testing, and saturated steam samples were able to be collected via two takeoff locations. Based on the data collected during the testing, one of the two saturated steam 24

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Why the Steam Drum Is Crucial for Ensuring Proper Boiler Water Chemistry continued

takeoff points had a much greater sodium carryover than the other takeoff; predicted total carryover far exceeded initial predictions based on operating pressure and design data on one end of the boiler drum as compared to the other end of the drum.

When the unit was finally able to be brought offline for inspection, there was evidence of significant damage to a set of demister pads on the end of the drum that displayed excessive carryover during the carryover testing. After replacement of the demister pads and repair of the supports, the unit chemistry quickly returned to normal upon return to service.

Study #3 Selection of the right cycle chemistry program given the design of the plant is crucial to minimizing corrosion and deposition throughout the entire cycle. However, contrary to popular belief, chemistry programs are not “one size fits all” templates and application of recommendations provided by trade organizations. Guidelines such as those developed by EPRI, the American Society of Mechanical Engineers (ASME), and the International Association for the Properties of Water and Steam (IAPWS) require the end-user to evaluate the system design and operation independently and apply those recommendations in a fashion that considers and balances multiple site-specific requirements, such as corrosion and deposition minimization, economics, operational scenarios, and skill level of plant staff.

Case Study #3 involves a 2 x 1 combined-cycle power plant with high pressure (HP), intermediate pressure (IP), and low pressure (LP) steam drums. The plant was designed with a feed forward low-pressure steam drum and was equipped with a single injection point for feeding a pH-adjusting agent downstream of the condensate pumps. The chemical injection locations normally provided on the HP, IP, and LP steam drums were capped and plugged, as the plant was designed to operate utilizing an AVT program, as recommended by most organizations for an all-ferrous metal system. Based on recommendations from the plant designers, the plant was operating utilizing aqueous ammonia as the pH-adjustment chemical injected in the condensate system to maintain a pH of 9.6 to 10.0, in accordance with the latest HRSG/combined-cycle chemistry recommendations.

A target pH of 9.5 to 9.8 was established in the LP steam drum water to minimize the potential for flow-accelerated corrosion.

The challenge that the plant encountered in this case was an inability to maintain the operating pH range both in the condensate and in the LP steam drum using aqueous ammonia as the chemical of choice. To maintain the low level of the operating band in the LP drum water at 9.5, the plant needed to add sufficient ammonia to increase the pH of the condensate to about

10.2. However, even with the elevated condensate pH, the plant was struggling to maintain a desirable operating pH in the IP and HP feedwater systems and in the IP and HP steam drums.

Due to the tendency for ammonia to volatize with the steam in the LP drum, the IP and HP systems pH levels were depressed, leading to corrosion forming in these portions of the system.

To rectify the situation, the plant conducted a series of trial tests using different amine blended products to try and find a product that achieved the target pH in the condensate, the target pH in the LP system, and the target pH in the IP and HP systems, and achieved their chemistry goals in a cost-effective manner. Several different products were tested, with the desire to maintain the single injection point in the condensate system for simplicity’s sake. After several trial runs, the plant settled on a blended ammonia and monoethanolamine as the best performing option. They also added an additional amine injection point in the suction line to the boiler feedwater pump to supplement the current injection location in the condensate system.

One lesson learned that the plant took away from this experience was that regardless of recommendations by the plant design team, for the next combined-cycle plant that is was looking to construct, it would keep intact alternative chemical locations at all three steam drums to allow for flexibility in optimizing the cycle chemistry.

Study #4 An inadequate or incomplete chemical cleaning can be just as bad, or even worse, than no chemical cleaning at all. In Case Study #4, a new boiler was constructed, and chemical cleaning of the water side was completed in a rushed fashion to meet a slipping schedule. Also, due to a compressed schedule, limited inspections were performed to verify the cleanliness of the unit: the steam drum was not opened for inspection.

After chemical cleaning, the plant attempted to quickly move the unit into the startup process. Throughout the next few weeks, heavy iron transport was observed throughout the system, resulting in plugging of a number of the sample panel lines. Side-stream filters were installed in an attempt to remove some of the iron transport in the system. After several days of limited progress, the unit was taken offline and a thorough inspection was performed.

The appearance inside the steam drum was not visually appealing. Large volumes of debris were found, particularly in the boiler steam drum, as well as areas of inadequate passivation.

Due to the way that the vents and drains were configured on the drum and the natural holdup in the drum, it was suspected that poor venting and draining occurred during the cleaning

“The devices were recalibrated and water chemistry quickly returned to normal once the unit was placed back into service.”

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process, despite constant monitoring of pressure throughout the process. Lack of circulation in the steam drum during cleaning and air-locking in the top section of the drum were suspected as the causes of the inconsistent passivation noted through the drum. Other areas of the steam/water system, on the other hand, including the downcomers, looked remarkably well with relatively clean and well-passivated pewter gray surfaces. The plant decided that the best path forward was to redo the chemical cleaning.

The lessons learned from this case study are multiple. First, the design for the chemical cleaning was not ideal and resulted in inadequate venting and draining of the drum during the cleaning process. This design was modified during the second cleaning of the unit. Secondly, the plant implemented a total suspended solids endpoint for confirmation that adequate flushing had been achieved after chemical cleaning. The first chemical cleaning process criteria only included a conductivity endpoint for flushing operations. Finally, for the post-chemical cleaning, the plant performed a full and thorough inspection of the unit, including opening and inspecting the steam drum, before signing off the process as complete and acceptable with the cleaning contractor.

Final Thought

The aim of this article was to examine mechanical and operational problems commonly experienced with boiler and HRSG steam drums, and what chemistry challenges and other issues these can create throughout the entire steam-water cycle. The steam drum is often viewed by some as a wide spot in the line, or more frequently, as a simple storage vessel where water and steam separation occurs. This is true and a key reason why the operation and maintenance of the steam drum is important to good cycle chemistry in a boiler system. Routine carryover testing is relatively easy to perform and a valuable tool for detection and diagnosis of mechanical and operational issues associated with boiler and HRSG steam drums.

References

1. Babcock and Wilcox (1992). Steam: Its Generation and Use, 40th ed., Babcock and Wilcox, Barberton, Ohio.

2. EPRI (2013). “Comprehensive Cycle Chemistry Guidelines for Combined Cycle/Heat Recovery Steam Generators”, Technical Report 3002001381, Electric Power Research Institute, Palo Alto, California.

3. International Association for the Properties of Water and Steam (2008).

“Technical Guidance Document: Procedures for the Measurement of Carryover of Boiler Water into Steam”, IAPWS TGD1-08, website: www.iapws.org.

4. American Society of Mechanical Engineers (2006). “Consensus on Operating Practices for the Sampling and Monitoring of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers”, CRTD-Vol. 81.

5. American Society of Mechanical Engineers (1994). “Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers”, CRTD-Vol. 34.

6. ASTM (2018). “Standard Practice for Sampling Steam”, #D1066-18e1, ASTM International, West Conshohocken, PA. 7. Reeves, W.L. (September 2001). “Avoiding Boiler Problems”, ASHRAE Journal, American Society of Heating Refrigerating and Air-Conditioning Engineers, Atlanta, Georgia.

Author Colleen Scholl is senior vice president with HDR and a technical expert consultant who has more than 25 years specializing in water and steam/water cycle chemistry within the industrial sectors. Ms. Scholl holds B.S. and M.S. degrees in engineering fields as well as an MBA. She is currently the chairperson of the ASME Research and Technology Committee on Water and Steam in Thermal Systems.

Ms. Scholl can be contacted at Colleen.Scholl@hdrinc.com.

This paper was presented at the 2019 International Water Conference, which was conducted November 10-14, 2019, in Orlando, Florida. More information about the IWC is available at www.eswp.com.

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Diagnosing Heat Exchanger Failures in Waste Heat Steam Generation Systems Edward S. Beardwood, Solenis LLC

Steam generator failures occur for a variety of reasons, and sometimes the root cause(s) are misdiagnosed, leading to reoccurrence of the failures. Tube failures are not necessarily required to impact the degradation of system performance.

In manufacturing, where a process may run at high temperatures to allow for completion of chemical reactions, eventually the process will need to be cooled. The process side that requires cooling maybe a gas, vapor, liquid, or solid smelt. If the process-side temperatures are extremely high, and cooling to well above the atmospheric boiling of water is required, this waste heat is converted to steam via a waste heat boiler. The components of waste heat steam generation systems are typically not readily identifiable and accessible within a process unit. A waste heat steam generation system may look like a typical â&#x20AC;&#x153;Oâ&#x20AC;? type water tube boiler inserted into a gas exhaust flue stack, or it may be more complex. The complexity will depend on the number of unit processes that require cooling and the required pressure and temperature of the produced steam needed to operate the manufacturing process.

Remote steam drums are associated with these complex systems, and multiple pressures may apply. A centrally located

feedwater plant that produces a mixture of pretreated makeup water and returned condensate is deaerated and then transported to process units within the manufacturing site for use in the waste heat steam generation system. The system may consist of unit processes such as preheaters, economizers, and steam-generating shell-and-tube heat exchangers, operating in a thermosiphon fashion, and the steam water mixture is then sent to a remote collection drum for steam separation that may or may not have an associated process or externally fired superheater and associated steam attemperation station.

Forms of corrosion and fouling within these systems will vary depending on which unit process is affected and the process-side temperatures and impurities. In fact, low process-side temperatures can enhance fouling and dew point corrosion rates, reducing product throughput and asset life expectancy.

Cooling or water/steam-side corrosion have been due to flow accelerated corrosion (FAC), oxygen pitting, steam collapse, under deposit corrosion (UDC), cracking due to corrosion fatigue (CF), stress corrosion cracking (SCC), or overheating (creep from deposition, departure from nucleate boiling, or steam stalling). Steam stalling can occur when excessive heat input 27

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into a steam generating tube or rapid drop in outlet steam throttle pressure upsets occur; steam then fills a portion of the tube length and stops natural thermal syphon recirculation. Fouling is brought on by impurity deposition, whether it be from hardness salts or transported corrosion products/particulates in the feedwater. Should poor steam purity maintenance practices also exist (1), these impurities can cause fouling and corrosion within superheaters, turbine drives, and downstream process steam consuming unit process equipment.

“Steam stalling can occur when excessive heat input into a steam-generating tube or rapid drop in outlet steam throttle pressure upsets occur; steam then fills a portion of the tube length and stops natural thermal syphon recirculation.”

There are also specific memorable failures within these types of systems. Here are a few examples: 1. Excess process heat input charge compared to design or missing baffles and/or insulation on the gas process side, leading to departure from nucleate boiling (DNB) and disrupting circulation to a point of steam stalling the tube steam water mixture flow.

2. For vertical units, forgetting to reinstall feedwater lines and associated baffles as per design into the process heat exchange unit, allowing too much cooling in one area and too little in another area of the tube sheet-to-tube weldment areas. This then causes deposit formation on the waterside at the tube-to-tube sheet, resulting in wick boiling and UDC. It also causes the process gas areas to operate below 750 °F, with the potential for localized dewpoint corrosion and uneven expansion and contraction stresses of tube to tube sheet welds, which can fail due to corrosion fatigue.

3. Forgetting to reinstall tabulators and baffles on the process gas side that evenly distributes the gas charge for even cooling. Thus, avoiding the potential for the two preceding failures to occur over time.

4. Lack of vents or unopened vents on vertical process heat exchange shell-and-tube units with shell-side cooling. These vents are installed under the top baffle and are connected to the remote steam drum. They are used to evacuate accumulated steam below the baffle to enhance circulation and metal wetting and to avoid tube-and-tube sheet thinning from evaporative concentration of corrosive ions in the water phase at the steam phase interface without washout.

Maintenance of the water quality and chemistry can be difficult because of accessibility and/or the lack of availability of the operations staff within the production unit. Process side or production and its control receives all the attention, the cooling and steam production side are orphans and receive little attention until the process side slows because of their poor performance. By this time, it is too late and the facility must take a forced outage. Let us now look at two case histories that have a combination of fouling and corrosion issues. These waste heat steam generation systems are examples of a complex system and a conventional cross-drum water tube boiler.

Case History 1 (Complex System)

The operational design of these affected waste heat steam generators had not been previously obvious to identify or warn of a potential problem. That is, there were two mass balances associated with the steam production. The waste steam generation system consists of a feedwater preheater/gas cooler (20% of steam production) and a salt cooler (80% of steam production), with an associated 450 pounds per square inch gauge (psig) (440 to 480 operational range) remote steam drum, as illustrated in Figure 1. There are four such trains associated with each salt reactor. Both the salt and off gas entered the shell-and-tube vertical thermos-siphon steam generators at 427 °C (800 °F).

The salt cooler has boiler water on the tube side, while the gas cooler has a mixture of feedwater and recycle steam drum water on the shell side.

The feedwater is a blend of untreated condensate that is deaerated and then chemically adjusted in the deaerator storage section pumped forward to be blended with purchased chemically treated deaerated feedwater from a neighboring plant prior to entering the waste heat steam generation circuit. The makeup water was pretreated with clarified filtered softened water up until mid-2001, and then polishing with reverse osmosis (RO) was instituted. An upset in the pretreatment system had occurred in early 2003. A salt cooler failed in 2003. Another salt cooler failed in spring 2004, followed by another salt cooler and a gas cooler in the fall of 2004. Based on the 2003 upset in pretreatment and makeup/feedwater quality and the three heat exchanger failures, chemical cleaning of all the waste heat steam generator heat exchangers was performed by the end of 2004.

Approximately three months later, another salt cooler in service for 11 months failed.

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“Maintenance of the water quality and chemistry can be difficult because of accessibility and/or time available of the operations staff within the production unit.”

Figure 1: Generalized layout of steam generation system.

A full review of retained failed specimens, metallurgical reports, deposit analysis, chemistry logs, and additional sampling and testing was initiated. It had been suggested by other consultants that the failures were due to poor deaeration and chemical oxygen scavenging. They came to this conclusion because they found pitting in the gas cooler bundle that was believed to be caused by iron corrosion product generation and poor conditioning by the polymeric dispersant in use to transport corrosion products out of the boiler system. This was evidenced by salt coolers that had some tubes blocked by iron-containing deposits However reasonable and simple to correct, the metallurgical analysis and full deposit analysis as well as deposit morphology could not substantiate this as the root cause. It should be noted that prior to the failures, only sulfite was added to the site’s deaerator storage section, and it was later realized an increase in the site feedwater pH required improvements from the existing 6.0 to 7.0 range. This took time to implement. In addition, with variable imported feedwater iron values of 0.07 to 0.17 milligrams per liter (mg/L), it was decided to feed a polymeric iron dispersant to the site feedwater. This was implemented in late fall 2004.

Let us look at the failure fingerprints that may have been misleading and the investigative action taken to arrive at a root cause and the validation outcome. The salt cooler metallurgical photographs reveal both deposit and attack, as well as the failure that was incurred at the bottom of the tube inlet near

the first baffle, which is adjacent to the hot salt (800 °F, sodium nitrate/potassium nitrite [NaNO3/KNO2] mixture) inlet.

Figure 2 shows a failed section below the baffle. On the right side is a piece of the tubing, while the left side shows localized corrosion beneath the cleaned deposit area. The whitish yellow material is from salt intrusion after failure and depressurization.

Below the baffle area of failure, the tube was partially blocked with deposits at 50% diameter reduction. While the area above the baffle area of failure is completely blocked, as seen in Figure 3, an overall set of deposit probable combinations from SEM/ EDS analysis is provided in Table A. It should be noted that these types of analysis are semiquantitative and that the deposit analysis of the unblocked areas had a 1% solution pH of 10.6, and the blocked tube portion had a 1% solution pH of 11.7. The failed gas cooler tube extracted from the upper section overview illustration can be found in Figure 4. A closer view of the fractured upper section near the hot gas tube sheet inlet reveals aggressive UDC attack. The deposit probable combination from the scanning electron microscopy/ energy dispersive X-ray spectroscopy (SEM/EDS) analysis of the deposit is presented in Table A and was found to have a pH of 10.6.

Localized attack throughout the upper portion of the gas cooler tube between the tube sheet and baffle joint was observed after cleaning, as illustrated in Figure 5. The localized oxygen pitting corrosion, as noted earlier, was only seen in the lower entrance 29

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sections of the gas coolers, as illustrated in Figure 6 (after cleaning). Also, high loadings of hard chip scale accumulated in the bottom inlet areas built up from the tube sheet. All steam drums contained chip scale exfoliates from the shell walls (see Figure 7). All the affected steam-generating tubes had porous deposits, contained sodium, and had localized UDC attack associated with them. In fact, the salt cooler deposits clearly revealed particulate deposits entrapped or embedded in flow-obstructing chip scale (see Figure 8).

The bottom distribution dish of the salt coolers also contained chip scale fragments that had been delivered via the internal feedwater line connecting the steam drum and bottom distribution dish of the waste heat steam-generating heat exchangers.

Table A: Case History 1â&#x20AC;&#x201D;Deposit Analysis From the Waste Heat Steam Generation System Constituent (%)

Steam Drum

Salt Cooler

Salt Cooler

East End

Bottom Had Chips

Failed #1 Composite

Failed #1 Red Deposit

Failed #1 Tube Black Deposit

Upper Zone

Iron oxide (hematite)

46.4

45.1

45.9

47.3

27.9

51.6

Serpentine

17.6

11.3

<1.0

<1.0

1.7

2.5

Calcium hydroxyapetite

7.1

2.6

<1.0

<1.0

<1.0

<1.0

Magnesium hydroxide

6.8

12.7

<1.0

<1.0

Basic Mg PO4 1.6

5.2

Calcium silicate dehydrate

1.8

5.2

<1.0

<1.0

<1.0

0.6

Uncombined LOl

5.9

3.6

<1.0

<1.0

<1.0 (sulfite 6.5)

<1.0

Calcium sulfate DI hydrate

<1.0

9.6

1.9

5.8

1.7

9.5

Iron phosphate

<1.0

<1.0

1.1

<1.0

<1.0

<1.0

Sodium hydroxide

<1.0

<1.0

6.6

<1.0

<1.0

29.1

Sodium silicate

<1.0

<1.0

10.9

12.5

<1.0

<1.0

Sodium sulfate dehydrate

<1.0

<1.0

33.9

44.9

74.8

19.3

Silica

<1.0

<1.0

<1.0

14.7

3.2

<1.0

Sodium chloride

<1.0

<1.0

<1.0

1.0

7.1

8.4

K, Mn, Al, Cu hydroxide

<1.0

<1.0

<1.0

6.6

0.6

<1.0

Total

85.6

90.1

100.3

135.5

125.1

125.6

Figure 2: Salt cooling tube below the inlet baffle. The image on the right shows a close up of failed area of the tube.

Gas Cooler

Figure 3. Salt cooler tubing section above baffle failure site.

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Figure 4: Remains of baffle in upper section of the gas cooler after the tubes were removed.

Figure 5: Localized UDC in the upper section of the gas cooler near the baffle.

Figure 6: Outside diameter surface of the lower section of the gas cooler after cleaning.

Figure 7: Chip scale in steam drum.

Figure 8: Salt cooler deposits and complete tube blockage near the inlet baffle.

We will now discuss further information that negates the suggested root cause of the failure being associated with pitting in the gas coolers that did not lead to gas cooler tube failures, in addition to the poor ability of the polymeric dispersant to transport chip scale out of the steam generating circuit to avoid tube failures in the salt coolers. The latter is hard to envision, as transport from the salt cooler, if possible, would result in natural settling in the low-velocity steam drum, where the chip scale was originally derived from. The cause was complex and the upset associated with pretreated makeup water contained in the imported feedwater only increased the complexity of the problem to be resolved.

Continuous oxygen analysis of the site’s deaeration equipment under the worst conditions associated with condensate washing of the batch refiners to remove gum deposits revealed dissolved oxygen values of 1 to 10 µg/L during the first hour of the wash and then typically in the 1 to 3 µg/L range. The combined site and imported deaerated feedwater contained 1 to 6 µg/L, averaging 1 to 3 µg/L dissolved oxygen. The cause of pitting was from the use of cold city water to flush the gas coolers for 1 hour and hold 7 hours in order to cool down and to maintain the gas cooler environment acceptable for workers to clean the gas side of foulants. This process is only done once per year now that the feedwater preheaters were installed ahead of the gas coolers.

The most likely cause of failure was due to iron fouling of the upper zone of the gas coolers with porous, iron-based deposits leading to wick boiling (2, 3) and UDC. Excess particulate iron and iron deposit spalling from the gas cooler (i.e., deposit surface had excessive grazing/cracking associated with it) coated the steam drum shell and fouled portions of the salt cooler.

However, the salt cooler failure was from chip scale occlusion allowing for further entrapment of particulate iron that then blocked the tubes. All salt cooler failures were associated with blocked tubes, as seen in Figures 3 and 8. To confirm the causes of the facility’s problems, we examined the apparent problems in the facility. The following paragraphs explain our findings and 31

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the changes that were implemented, which have allowed this plant to have trouble-free operation for 15 years.

Although composite feedwater iron values had been variable and in excess of the ASME Guidelines (i.e., 0.03 to 0.05 mg/L) the iron recoveries improved to in excess of 100% across the salt cooler once supplemental iron dispersant was added at the site. These were then questioned. The work included a water quality survey in several locations. The testing examined several variables, including iron. This work aimed at developing a water system mass balance to ensure that the calculated ionic iron balance was valid. The iron recoveries as previously noted were not as high as originally estimated. The upper section of the gas cooling is a steaming economizer, producing 20% of the total output while recycling steam drum water that is cycled up by the salt cooler and diluted by incoming feedwater, which is a blend of imported boiler feedwater (70–80%) and deaerated system condensate (20–30%). Simply put, there are two mass balances operating in this steam-generating circuit, which requires weighting correction factors that are derived from the simplistic statements above and the calculated actual steam quality (i.e., steam-to-liquid ratio, 10%) produced on said mass balance.

It was also found that iron increases across the feedwater system as well as the preheater and gas cooler. Concurrently, the gas cooler at times had increases and, at times, iron loss, in the upper section as the preheated water transitioned through it to the recycle steam generation zone. It was found that the iron dispersant concentration was satisfactory for iron control in the salt cooler; however, it was too low in the gas cooler recycle zone. The salt cooler also operated a slightly higher dissolved solids concentration than the common steam recirculation drum. Upon further investigation, it was noted that the continuous blowdown line was only a shell nozzle near the gas cooler steam water mixture return line. The bottom blowdown of this drum was below the continuous blowdown at the far end of the main steam outlet and steam separator drain lines.

Thus, the highest concentration liquid is not sampled or blown down. Plus, should chip scale be present in the steam drum, by virtue of the bottom blowdown location, it would cause chip scale to sweep across the inlets to the down comers feeding both the salt and gas coolers. While the latter case can only be prevented by the avoidance of chip scale production, the former can be corrected, and a multi-port continuous blowdown line skimmer was designed to evacuate concentrated impurities containing boiler water the full length of the steam drum.

Additionally, variability was found in the imported feedwater conductivity (40 to 140 microsiemens per centimeter (µS/cm). A common tracer for the dispersant in the imported feedwater was not corrected for the determination of iron dispersant added to the site’s feedwater.

Hence, variability existed in the actual cycles of concentration maintained versus perceived as well as iron dispersant under treatment. At times, there was insufficient blowdown and iron dispersant treatment, and at other times, there was excessive blowdown and further depression in iron dispersant treatment.

The vents on the gas cooler upper section were found to be wide open and functional, ensuring that no steam locking, evaporation to dryness, and associated corrosion would take place.

However, the iron pickup through the circuit needed to be addressed, so it was further evaluated with respect to flow-accelerated corrosion, where in single phase is prevalent at the preheater (240 to 350 °F) through to the upper steaming section of the gas cooler (inlet temperatures of 380 to 385 °F) wherein two-phase flow transitions (300 to 400 °F).

The outcome of the investigative work associated with improved sampling and defining appropriate correction factors that aligned the mass balances, recycle, and feedwater variabilities allowed for updating the operational control of the steam generation system. Table B reveals acceptable results for avoiding flow accelerated corrosion.

Table B: pH/ORP Survey

“OH” Alkalinity mg/L

pH

ORP mV

High-pressure condensate

0

7.7–9.0

20–70 Positive

Low-pressure condensate

0

8.5–9.2

60–120 Positive

Condensate storage

0

8.0–9.0

100–190 Positive

Deaerated feedwater

0

8.7–9.3

30–100 Positive

Preheater

0

9.0–9.3

50–70 Positive

Gas cooler inlet

0

9.0–9.3

30–70 Positive

Gas cooler outlet

0–26

9.8–10.5

20–90 Negative

Steam drum

80–120

11.2–11.5

50 Negative

Salt cooler

80–160

11.2–11.5

35 Negative

Sample Location

The improved pH values alone reduced the boiler feedwater iron pickup through the preheater and gas cooler inlet. No longer were there two to three times the preheater inlet irons seen at the gas cooler inlet. Iron recoveries were tracked with respect to boiler feedwater cycles and iron dispersant concentrations present via traced verification. A summary of numerous sample data and workups are presented in Table C. Both dissolved and suspended iron values were tracked. A transition from dissolved to suspended takes place at the deaerator and forward into the steam generators. The suspended iron recoveries always outpaced the dissolved iron. Total iron is reported in Table C.

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Table C: Iron Dispersant Trial Results Dispersant Residual, mg/L

Boiler Feedwater Cycles of Concentration

Percent Iron Recovery1

None

16–24

<10

50

40–80

<20

100

20–30

39.7

200

20–30

82.7

20

8 Gas Cooler Outlets

71.8

Iron concentration at gas cooler inlet ranged from 0.077 to 0.151 mg/L, averaging about 0.100 mg/L. 1

To maximize the iron recoveries in the upper recycle zone of the gas cooler, steam drum, and salt cooler, a limit was set on the boiler feedwater cycles, maximum theoretical cycled boiler feedwater iron, and iron dispersant concentration. Due to variability in the conductivity of the imported feedwater, background tracer presence, and final composite boiler feedwater iron concentration, the cycles of feedwater concentration were set on gas cooler inlet conductivity times 25 to 35, with a theoretical total boiler water (i.e., steam drum and salt cooler) iron range of 2.5 to 3 mg/L. A correction factor for the iron dispersant tracer was developed, and the steam drum residual as product was set at 300 to 400 mg/L, which, in turn, ensured 40 to 50 mg/L presence in the salt cooler upper zone.

These program modifications and tracking of fouling presence in the salt cooler (i.e., increased salt valve opening compared to the normalized butane charge) and gas cooler (i.e., decreasing steam flow to the feedwater preheater) were instituted. After an uninterrupted run of six months, the waste heat steam generator heat exchangers were removed for video probe inspection.

There was no chip scale, particulate iron deposition, or surface foulants found in the salt cooler tubes. No iron accumulated in the gas cooler inlet and upper recycle zone/outlet. No sharp ridges were found on the surfaces of the tubes in the upper section, nor was there any indication of porous iron deposition or scabbing occurring in the upper section of the gas cooler. All areas associated with wire brushing to bare metal in the steam drum remained free of re-deposition.

Case History 2 (Simple System)

A 650-psig waste heat steam generator, producing 180,000 pounds per hour (lb/h) of saturated steam, experienced numerous tube failures after 12 years of operation with no previous history of failures. Due to restrictions on internal chemical treatment in another steam generator within the plant, this unit was operated on all-volatile treatment from startup.

The steam generator is a cross-drum design and employs a multiple burner arrangement and a long cylindrical furnace without water walls. There are 66 rows of tubes across and 20 rows front to back. The first two rows of tubes are screen tubes that absorb mostly radiant heat. These tubes are not finned because of the high thermal absorption possible from radiant heat. Subsequent

rows are finned tubes to improve heat absorption in this area of convection heat transfer. The third and fourth rows were designed to have two fins per inch to avoid excessive thermal absorption, and the fifth through the 20th rows were designed to have six fins per inch to capture the reduced thermal energy further back in the steam generator. In actuality, the tubes were reversed so the third and the fourth rows contained tubes with six fins per inch.

The fuel is a mixture of several waste hydrocarbon streams and natural gas. Normally this gas temperature runs between 1,470 and 1,650 °F. A safety shutdown is provided to avoid this potential overheating and it is set at 2,190 °F. One of the streams contains approximately 95% water.

The operation appeared to be normal for most of the day, until approximately 7:30 pm, when there was a sudden surge in steam production and in furnace temperature. The boiler tripped out on high furnace temperature, and the temperatures began to drop. Steam continued to be produced for 15 minutes at a low rate as the furnace cooled. The boiler was restarted, and it was noted that it required an unusual amount of boiler feedwater to maintain the steam drum level and that the the steam pressure was slightly lower than before the incident. It appeared that a steam leak had occurred in the boiler tubes.

Immediately prior to this event, there was a problem controlling the level of solvent in a separator, and a slug of liquid solvent was fed to the waste gas burners. It was suspected that this additional solvent fuel caused the temperature to increase in the furnace gas, which eventually led to a boiler trip. The shutdown sequence shuts off the fuel to the burner and initiates a low-flow air purge into the furnace.

During normal operation of the boiler, water cools the boiler tube metal to within 75 °F of the saturation temperature of the steam. This means that the tube wall temperature cannot exceed 552 °F when clean. As an insulating layer of deposited iron accumulates within the tube, the wall temperature will increase proportionately. The alloy used in these tubes would have 55,000 to 60,000 psi strength at clean metal temperatures.

As the temperature increases, the strength drops dramatically.

It is only 9,500 to 10,000 psi at 2,190 °F, where the maximum furnace temperature could occur before shutdown. It is important to note that the stress within the tube is not the same as the pressure in the vessel; it is much higher, depending on the configuration of the metal. A phenomenon known as “hoop stress” determines the stress within tubes, and it is based on the wall thickness and tube diameter plus the internal pressure.

These tubes operate under a stress of 10,400 psi. This means that the tubes had to be subjected to a temperature greater than the wet tube maximum of 464 °F. This wet tube temperature is based on a tube in the nucleate boiling range. It would require a metal temperature in excess of 1,740 °F for the metal to fail, so it is not likely that it was wetted with liquid water at failure. It is 33

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â&#x20AC;&#x153;The damaged tubes would exhibit a thin-lipped burst pattern typical of short-term overheating. Consequently, the initial consensus was that short-term overheating was the root cause of the failures.â&#x20AC;? unlikely that deposition alone was sufficient to triple the metal temperature.

It was proposed that some of the additional solvent that was fed into the boiler was still in the furnace beyond the burner area when the boiler tripped. It was burning, and the cooling effect of the water-laden waste streams was suddenly stopped. This allowed the temperature to increase in the furnace to almost 3,000 °F in the gas to the tubes. Note that this burning material would have been downstream of the thermocouples used to monitor gas-side temperature. The actual temperature would be a function of the available air and volume of solvent to burn.

This condition may have lasted for only a short period of time, but it would account for the high steam rate.

The steam rate jump suggests that this additional heat input exceeded the design heat flux for the convection tubes by more than the 30%. Due to the finned tube configuration, they suffered most of the heat flux increase. The screen tubes would have taken little of this heat out of the gas because they are smooth, thus allowing the hot gas to overload the finned tubes.

Judging by the level in the steam drum, the generating tubes did not run dry, so it is probable that the heat flux was sufficient to form a steam blanket within the hottest tubes and cause the metal overheating. This DNB (4) is a well-known cause of boiler tube failure and easily recognized from an inspection of the failure site.

When a boiler is suffering from excessive deposition, the tubes will operate at excessive temperatures for a prolonged time period, and the failure will be characterized by a longitudinal crack. The edges of the crack will have essentially the same metal thickness as the remainder of the tube. There is little deformation or stretching of the metal surrounding the crack. When DNB occurs, the metal yields dramatically and there is considerable stretching of the edges to form a thin-lipped burst.

The tube failures were mapped as to location in the steam generator. Thermal excesses and/or inadequate flow led to DNB and steam blanketing. This resulted in the formation of porous, scab-like deposits that allowed boiler water to penetrate.

Figures 9 and 10 illustrate the condition of the water side of the affected tube. Demineralized water was used to extract ions from the blackened deposit directly on the tube surface. Area 1 was from an unaffected surface area of the tube, and Area 2 was from an area affected by surface gouging below the deposit on the tube. The results are provided in Table D. The failed area of the tube that had the gouging contained significantly more acidizing anions, in particular sulfates. Wick boiling occurred under these deposits, leaving corrosive anions in contact with the base metal surface. The corrosion process set up by the anions contributed to tube wall thinning. Eventually, the internal pressure overcame the yield strength of the tube and failure occurred.

Figure 9: Cleaned tube.

Figure 10: Tube wall thinning and high-temperature oxide.

The failure was deemed to have occurred as a result of several factors in combination. The only mechanism that can allow the tube metal to get hot enough to fail requires steam blanketing and much hotter gas than recorded. Hence, the liquid fuel would have been in the furnace for a short period after the water laden streams were shut off. The presence of deposits in the tubes made the boiler more susceptible to the overheating.

The damaged tubes would exhibit a thin-lipped burst pattern typical of short-term overheating. Consequently, the initial consensus was that short-term overheating was the root cause of the failures.

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Table D: Water Soluble Ions Extracted From Tube Deposit Area 1 Unaffected µg/gm1

Area 2 Affected µg/gm

Sulfate

33.9

9,039.7

Chloride

<5.0

132

Sodium

83.8

344.2

Silica

60.9

119.2

Calcium (as Ca)

48.2

3257

Magnesium (as Mg)

38.7

63.7

Iron

<5.0

<5.0

Copper

<5.0

221.8

Barium

<5.0

66.2

Potassium

<5.0

625.6

Note: 1µg/gm = ppm

Additional contributing factors included significant increases in gas-side temperatures and fluctuations in steam header pressure.

The increase in gas-side temperatures accelerated the mean time-to-failure due to periodic overheating. The steam header fluctuations may have caused accelerated steam generation in the radiant tubes, resulting in steam stalling. The lack of cooling attributed to the steam stalling would also accelerate the mean time to failure.

At the operating pressure of 650 psig, the design allowable stress would be 11,800 psi, and the hoop stress would be 5,417 psi, well below the allowable stress. The measured wall thickness at the time of failure was 0.055 in. The actual allowable stress at this wall thickness and operating pressure is 14,092 psi.

This is above the allowable stress for this tube.

Ultimately, the tubes failed due to improper construction based on design, operating at gas-side temperatures above design, and poor steam header pressure control. There was nothing simple about this steam generation system.

Summary

References

1. Beardwood, E.S. (November 17-20, 2014). “Steam Purity in Heat Recovery Steam Generators,” Paper No. IWC 14-28, International Water Conference, San Antonio, Texas.

2. Banweg, A.; Mravish, N.J.; Pocock, F.J. (April 17-21, 1989). “Chemistry Guidelines for Cycling Service Steam Fossil Power Plants,” Paper No. 89, Corrosion 89, New Orleans, Louisiana, NACE International, Houston, Texas.

3. Wick, R.H. (March 1-3, 1994). “Internal Boiler Tube Deposit Weights as a Basis for Chemical Cleaning,” Paper No. 208, Corrosion 94, Baltimore, Maryland, NACE International, Houston, Texas.

4. Babcock and Wilcox (1992). Steam, Its Generation and Use, 40th ed., ISNB 0-9634570-0-4, Chapter 5, “Boiling Heat Transfer, Two Phase Flow and Circulation, Babcock and Wilcox, Barberton, Ohio.

Edward S. (Ted) Beardwood is the founder of Beardwood Consulting & Technologies Inc. (BC&T Inc.) and has more than 43 years of experience in water treatment. Before starting BC&T, his career included technical and sales positions with major specialty chemical companies, including serving as the senior global applications consultant for Solenis LLC, technical director for the Canadian operations of the Ashland Water Technologies Division, and sales representative and area sales manager for the Dearborn Division of WR Grace (now Betz/GE/Suez). His experience in the industrial water conditioning industry has ranged from full service sales, sales management, new construction and commissioning of thermal systems, laboratory management, regulatory compliance, product management, R&D, and consulting. Mr. Beardwood is a past chair of Water Technologies and the Research and Technology Committee for Water and Steam in Thermal Systems for the American Society of Mechanical Engineers (ASME), as well as a former working member of PTC – 31 Performance Test Code for High Purity Water Systems and past chair of NACE International Research Committee STG 11 on Water. Mr. Beardwood holds 13 patents. He may be contacted at ebeardwood@btcinc.org.

This paper was presented at the 2017 annual International Water Conference, which was conducted November 13–15 in Orlando, Florida. More information about the IWC is available at www.eswp.com.

Tube failures in steam generators can be initiated by many factors. While the conditions of the steam generator and steam-generating tube surfaces observed and the chemistry of the water and deposits analyzed may suggest that improvements are required in the chemistry to prevent said failures, the actual pathway of the corrosion incurred is more important. The obvious can lead to a perceived cause of failure. Under such circumstances, subsequent failures are to be expected when the same operational environment reoccurs. The nonobvious takes more effort to rationalize. However, though not novel, the extra effort is required to obtain the actual root cause to ensure the failure is not repeatable.

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Optimization of Condensate Treatments Using a Computer Modeling System Richard Salazar, Suez Water & Technologies Solutions

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Abstract

Inadequate steam and condensate chemical treatment programs can lead to unplanned or untimely operational issues and shutdowns. The key to avoiding these problems is to have a technically sound yet economical condensate treatment program designed to meet the needs of the system while accounting for operational changes that can impact the performance.

When using a conventional method of treating and monitoring the boiler condensate, a system may still be at risk for failures.

Typical condensate systems may have a chemical program consisting of volatile neutralizing amines, film-forming amines, passivating technologies, or a combination of these products.

Monitoring of a condensate system may include sampling and testing the condensate for pH, iron, and/or copper and conductivity, to name a few, but may include much more. Good steam and condensate system corrosion control may not always be consistent. Manual adjustments of chemistry that are made by operations based off the monitoring results may not be instantaneous or may not be reaching the locations where required.

This could lead to steam condensate systems being temporarily exposed to the harshest or most corrosive environments without adequate chemical protection.

This article presents an alternative approach for selecting the best steam and condensate chemical treatment using a unique computer modeling system (CMS). The CMS simulates the effects of various chemical treatments and operating conditions differently than other modeling systems (1). CMS creates one large set of equations from distribution ratios and acid dissociation constants for all chemicals in the steam. This enables the accurate prediction of pH and chemical feedrates throughout the complexities of a steam and condensate system.

In addition to discussing the CMS and the practical application of the tool, performance data from an application will be reviewed demonstrating the accuracy and value of modeling system.

Condensate Treatment Selection

When selecting a chemical treatment program for a condensate system, many factors need to be considered. A few of these factors include contaminants in the feedwater, system metallurgy, and chemical feedpoint locations. Additionally, any market authority clearances need to be considered.

There are several chemical treatment options to select from for a steam condensate system. Common chemical treatment technologies include neutralizing amines, film-forming surface adsorption corrosion inhibitors (filming amines and non-amine filming inhibitors), and passivators. Neutralizing amines are volatile chemicals that travel with steam and condense in the condensate system. They neutralize carbonic acid and elevate the pH, making it a less corrosive environment. Filming amines are surface adsorption inhibitors, where the chemical is typically fed directly into steam and will form a protective layer on metal surfaces, insulating the surface from any corrosive species.

Highly effective classes of passivators are the volatile hydroxylamines. These inhibitors promote the formation of a protective magnetite layer on metal surfaces. In some cases, filming and passivating agents can be fed together with neutralizers. While each application is a proven treatment option, there are some limitations to each option, and understanding the functions and limits of each treatment is essential.

It is important to understand the entire steam system and any limitations and regulatory concerns each system may have in determining proper chemical treatment. Even with having the proper condensate treatment, it may always be challenging to fully and consistently protect the entire system. Using an advanced CMS can help simulate and predict the outcomes and effects of varying chemicals and operating conditions on complex steam condensate systems.

Condensate Modeling System

CMS is a proprietary computer software program that can be used to develop a complete thermodynamic modeling of a given steam-water system. CMS can be used to simulate the various effects of chemicals and operating conditions on a simple or complex steam system. It provides the mass distributions and resulting system chemistry conditions of a wide variety of commonly used boiler treatment chemicals, such as phosphates, neutralizing amines, ammonia, sodium hydroxide (NaOH), as well as contaminants such as carbon dioxide (CO₂), hydrochloric acid (HCl), sulfuric acid (H₂SO₄), and organic acids. An example of a very simple model with a few inputs and calculated outputs is shown in Figure 1.

“After the required flows and constants are derived, the program calculates the solution to the coupled series of equations for that unit. The number of equations and species involved can be exceptionally large.”

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Optimization of Condensate Treatments Using a Computer Modeling System continued

Figure 1: Simplified CMS model.

Working from a plant piping and instrumentation diagram (P&ID), or other system description, a model is easily built that can mimic any system of steam, water, or mixed phase flows. Flowrates, pressure, temperature, and concentration information are supplied for any or all points in the system. The software capabilities and application include: •

Optimization of neutralizing amine product selection, product feedrates, feed points, and treatment economics.

•

Predicts pH at temperature that is critical to establish satisfactory corrosion protection at any location in the system.

•

Simulates the pH, neutralizing amine concentrations at any location in the steam-water system and ensures active amine levels in steam do not exceed levels stipulated by regulatory authorities.

•

Can identify potential problem areas such as low pH in flash tank overhead steam and determine amine losses via blowdown and steam venting.

•

Simulates steam-water system chemistry in response to boiler feedwater contaminations. The contaminant input includes CO₂, HCl, H₂SO₄, sodium (Na) leakage, and organic acids (formic/acetic).

How a CMS Works

To model a steam system, four steps are required. First, the user must specify the required inputs of the system. The more detail provided, the more accurate the model output will be. Then, the program calculates the required parameters and calculates the solution to the resulting series of coupled equations. Last, the program displays the results of the calculations.

Required data inputs include temperature (or saturation pressure), the mass flow in two of the three streams around a specific unit (e.g., a boiler), and the concentration of chemicals in one stream. Since the program is flexible, the flows do not have to be explicitly specified but can be calculated from other streams. They can be specified as mass flows (e.g., pounds per hour [lb/h] or kilograms per hour [kg/h]) or as percentage flows through each branch of a splitter or mixer. Individual chemical concentrations can be specified in different streams.

Thus, one chemical may be initially known in the input stream, while another may be known in one of the output streams.

Using the input data, the program first calculates the flows around the unit. Then, using the specified temperature, the program calculates the vapor/liquid distribution constant Kd (T) and acid dissociation constant Ka (T) for each chemical at that temperature. The equations describing the Kd (T)’s and Ka (T)’s 38

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Optimization of Condensate Treatments Using a Computer Modeling System continued

“To organize the units, the user constructs a diagram or flowsheet with the graphical user interface built into CMS.” as a function of temperature are verified from room temperature up to the temperature corresponding to 1,800 pounds per square inch gauge (psig) (124.13 bar).

After the required flows and constants are derived, the program calculates the solution to the coupled series of equations for that unit. The number of equations and species involved can be very large. Each chemical can exist in one or more solution ionic forms as the neutral species in solution or as the neutral species in the steam phase. All forms of these chemicals interact to determine the pH. The resulting “at temperature” pH is determined by the volatility of each species and its acid/base strength. Once a solution is found, the resulting parameters, such as pH, conductivity, and alkalinity, are computed. The output can be viewed in a variety of ways.

CMS Differences From Other Modeling Programs

The CMS program improves on previous condensate work by using more sophisticated modeling chemistry. Previous programs used a simplistic, stepwise algorithm for determining the distribution of chemicals across a vapor-liquid interface. The distribution of a chemical first was determined in a unit using a pH-independent distribution ratio. Then, the pH levels of the resulting liquid and condensed steam were calculated. CMS uses a more sophisticated approach to determine chemical distributions. The vapor/liquid distribution and acid dissociation equations for all chemicals in a stream are coupled to form one large set of equations. The calculations, although more complex, give more accurate results.

Other improvements include the ability to model more complex systems and the ease with which these systems can be built and solved. The previous work could only model relatively simple condensate systems or small parts of a large condensate system.

CMS can perform calculations for many interconnected units.

The program can solve equations for large systems involving thousands of unknowns in just a few minutes. CMS can handle both small and large condensate systems. More importantly, CMS can handle multiple interconnected condensate return lines with no restrictions on how they are combined.

Within CMS, having configuration flexibility is important. To organize the units, the user constructs a diagram or flowsheet with the graphical user interface built into CMS. The solution for these more complicated networks involves the use of a special algorithm that “walks through” the diagram propa-

gating chemical concentrations and estimating pH levels until convergence is reached. Previous programs did not allow the user to easily build and modify models. Instead, a series of fixed configurations were used to model parts of condensate systems.

CMS allows users to first construct, and then easily modify custom models of the units they are interested in studying.

Complex Steam System at Southeastern University

CMS as a modeling and condensate treatment selection tool has been validated and referenced over several years in the field across many industries. This reference focuses on a light industrial application where performance of a customer’s condensate treatment approach was inadequate from a reliability and cost perspective.

A major southeastern university had three separate steam plants with varying configurations of water tube boilers generating steam for campus heating and research that produced approximately 200,000 lb/h of 150 pounds per square inch (psi) steam.

Boiler makeup water is sodium zeolite (NaZ) softened and deaerated with makeup m-alkalinity levels ranging from 50 to 100 parts per million (ppm) and dissolved oxygen levels 10 to 20 parts per billion (ppb). The condensate system contained a mixed metallurgy of mild steel and copper. Condensate return varied between 60 and 70%, and the boilers operate between 20 and 30 cycles of concentration. An all-polymer internal treatment program, inorganic sulfite-based oxygen scavenger, and a volatile neutralizing amine for the steam were being used as the boiler treatment program. In addition, the university boiler steam also required the regulatory standard 21 Code of Federal Register (CFR) 173.310 (Boiler Water Additives) (2) to be followed that states that all products in the steam should be approved for use for direct food contact. Particularly, section of 21 CFR 173.310 states the allowable neutralizing amines to be limited by the following: •

Cyclohexylamine (CHA): 10 ppm

•

Diethylaminoethanol (DEAE): 15 ppm

•

Morpholine (Morph): 10 ppm

•

Combined Total: Not to exceed 25 ppm or individual limits.

Due to logistical and existing footprint concerns at the university, the type and application of a condensate treatment was limited. Several equipment upgrades to their external pretreatment approach were and are still being evaluated to help reduce the m-alkalinity in the makeup water. A reverse osmosis (RO), chloride- anion dealkalizer, and various deionized (DI) water bottles were proposed as a potential solution. Because of the size of the campus, the location of each of the steam plants, and high costs associated with purchasing, renting, and installing capital equipment, an alternative approach was requested.

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Additionally, different volatile neutralizing amines consisting of either primary components or a blend of diethylaminoethanol (DEAE), cyclohexylamine (CHA), morpholine (Morph) were used as a condensate treatment approach with varying degrees of success. A summary of the historical performance of the various products fed with a few of the key performance indicators are shown below in Table A.

Table A: Condensate Summary of Previous Treatments and Key Performance Indicators* Amine Blend

pH

Amine (ppm)

Fe (ppm)

Fe Corrosion Rate (mpy)

Cu (ppm

Cu Corrosion Rate (mpy)

DEAE

7.1

14.9

2.3

9.7

0.9

3.6

CHA

7.0

9.9

1.9

13.3

1.1

5.4

Morph

7.6

10.0

1.2

4.3

1.2

7.7

DEAE/CHA

7.8

14.5/9.8

1.8

5.6

0.5

2.6

DEAE/CHA/ Morph

8.3

10.7/7.2/7.1

0.5

2.6

0.3

3.5

*Note: The pH, iron (Fe), and copper (Cu) in Table A are averages from multiple condensate receivers.

In a condensate system with mixed metallurgy (e.g., mild steel, copper), maintaining a condensate pH of between 8.5 to 9.2 and a corrosion rate of < 2 mils per year (MPY) should provide the optimal targets to minimize corrosion in the system. Various blends of amines were tried with varying levels of success. The data shown in Figure 2 are averages taken from several different receivers across the campus. The pH was monitored along with sampling for amine concentrations to ensure that regulatory standards were being followed. Iron, copper, and corrosion coupons were also monitored to track corrosion potential in the systems. While some areas were adequately protected, several areas were not. The blend of DEAE/CHA/Morph was much improved over the previous treatments, but that program came at a much higher cost. The program required two to three times the amount of product as the other treatments yet still had deficiencies in protecting the entire system.

One of the major limitations at the university was the 50 to 100 ppm m-alkalinity in the makeup water while following any regulatory standards, such as U.S. Food and Drug Administration

(FDA) approval, yet still providing a solid program minimizing corrosion at an economical price. An evaluation of several of our FDA-approved neutralizing amines was done using the CMS program to determine if there is a product that would meet FDA guidelines and still provide enough amine to neutralize the carbonic acid in the system.

The analysis was done inputting each unit (e.g., condensate receiver) using an average makeup alkalinity value (100 ppm), a boiler feedwater (BFW) alkalinity value (50 ppm), and a load-weighted average of the condensate return percentage (60%). After building the model and validating the accuracy with the historical treatments and data we had collected in the past, we began to evaluate other products we had not tried and new blends that were yet to develop.

Using CMS, we were able to find a high concentrated blended amine product that consisted of DEAE/CHA/Morph that would be ideal for this system. Upon presenting to the university, a trial of the condensate treatment began. The pH at each of the receivers, amine concentration in the condensate, iron levels, and corrosion coupons were monitored for performance.

As predicted in the CMS model, a significant improvement was seen in performance.

By selecting a product with different concentrations of the blended of volatile neutralizing amine, a better product was identified specifically for the university system with the varying operating conditions and limiting factors. The pH at more than 50 different condensate receivers across campus showed higher values than any other previous treatments utilized. In fact, more than 90% of the receivers sampled showed showed a pH greater than the 8.5 minimum target for a mixed metallurgy system.

The iron and copper concentrations in the condensate also decreased in comparing the volatile neutralizing tri-amine treatments. Figures 2 through 4 show a comparison of the DEAE/ CHA/Morph blended amine products. Figure 2 shows the iron levels in the condensate comparing the two different products at a few of the main condensate receivers, while Figure 3 shows the copper levels in the condensate comparing the two different products. Figure 4 displays the same data over time.

â&#x20AC;&#x153;The pH at each of the receivers, amine concentration in the condensate, iron levels, and corrosion coupons were monitored for performance. As predicted in the CMS model, a significant improvement was seen in performance.â&#x20AC;?

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Figure 2: Condensate treatment iron levels comparison.

Average Steam Condensate Total Iron levels

0.8 0.7

Total ICP Iron ppm

0.61

0.58

0.6

0.58

0.50

0.5

0.44

0.44

0.4 0.31

0.27

0.3

0.18

0.2

0.15

0.12

0.08

0.1 0.0

Sample point #1

Sample point #2

Sample point #3

Sample point #4

Sample point #5

Sample point #6

Current Amine Blend Performance after using CMS Initial Amine Blend Performance Figure 3: Condensate treatment copper levels comparison.

Average Steam Condensate Total Copper levels

0.6

0.52

0.5 0.44

Total ICP Copper ppm

0.4 0.31

0.3 0.21

0.18

0.2

0.12

0.1 0.0

0.05

Sample point #1

0.15

0.14

0.07

0.06

0.03

Sample point #2

Sample point #3

Sample point #4

Sample point #5

Sample point #6

Initial Amine Blend Performance Current Amine Blend Performance after using CMS

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Figure 4: Condensate treatment iron and copper levels over time.

Summary

Selecting a proper condensate treatment program and monitoring the system can be complex. Utilizing a CMS to predict performance, evaluate chemical programs, and optimize treatments can simplify the process. The CMS model has been used and has improved steam condensate treatment results at several industrial plants. This technology can also help many others improve the performance of their condensate treatment programs.

References

1. Robinson, J.O. (October 22-24, 2007). “New Computer Modelling System Improves Condensate Treatment”, International Water Conference, Orlando, Florida.

2. Code of Federal Register (CFR) (April 1, 2019). “Boiler Water Additives," pp. 146-147, 21 CFR 173.310.

In addition to the improved pH, iron (Fe), and copper (Cu) results, the corrosion coupons also showed improvement. The average corrosion rate decreased from 2.6 MPY down to 0.8 MPY, as shown in Table B. The amine concentrations, although different, still followed the regulatory standards required. As an additional benefit, the amount of volatile neutralizing amine required was less than the previous amine treatments due to the some of the components ability to neutralize the carbonic acid in the system. The decreased usage resulted in more than $80,000 in chemical treatment savings. While additional operational and reliability savings were also recognized by the customer, it was difficult to quantify the value of those savings.

Table B shows a summer of water treatments and performance indicators.

Richard Salazar is a senior boiler product application engineer for Suez Water Technologies & Solutions (formerly GE Water and Process Technologies). He began his career with Suez in 2002 and has 18 years of extensive water, process, and utility treatment experience. Since joining the product application engineering group, he has been involved in boiler product development projects and troubleshooting issues. He holds a B.S. in chemical engineering from Villanova University.

This paper was presented at the 2019 AWT Annual Convention, which was conducted September 11–14, 2019, in Palm Springs, California.

Table B: Condensate Summary of Treatments and Key Performance Indicators

pH

Amine (ppm)

Fe (ppm)

Fe Corrosion Rate (mpy)

DEAE/ CHA/ Morph

8.3

10.7/7.2/7.1

0.5

2.6

0.3

3.5

DEAE/ CHA/ Morph

8.7

4.9/10.0/9.1

0.2

0.8

0.1

1.1

Amine Blend

Cu (ppm)

Cu Corrosion Rate (mpy)

When the trial ended, the new blend of the volatile neutralizing amine product was deemed a success and has been implemented as their ongoing condensate steam treatment. Evaluations for an upgrade of the external pretreatment continues.

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