CYCLE CHEMISTRY COMMISSIONING

Otakar Jonas, P.E., Ph.D.

Lee Machemer, P.E.
Jonas, Inc.
1113 Faun Road
Wilmington, DE 19803 USA

Abstract

This paper presents an outline of cycle chemistry commissioning guidelines and a brief
description of selected case histories where delays of commercial operation and equipment
damage resulted from insufficient water chemistry-related commissioning. Operation delays
have resulted in cost penalties of millions of dollars (at ~$300,000/day) and the equipment
damage has been as high as $100 million in one unit. The ultimate root cause of the above
problems is poor system management by OEMs, architect engineers, operators, and chemistry
consultants. The technical root causes, all of them predictable and correctable, include bad
design and material selection, water treatment system operation and chemicals, instrumentation
and chemical control not ready, corrosion during equipment storage, high boiler carry-over, and
lack of operator and chemist training.

Introduction

Commissioning delays and equipment damage as a result of inadequate commissioning have

been a major problem for over 50% (estimate) of new units of all types and for older units after
upgrades and operation and chemistry changes. Today, most of these problems can be avoided
because there is sufficient knowledge in the areas of water chemistry and corrosion [1 to 29] and
ample experience. It is mostly a problem of the transfer and use of the knowledge and of
management.

During commissioning, the risk of water chemistry-related delays is high, while at the same time,
the analysis and control of cycle chemistry is typically at its lowest level in the life of the unit.
Many problems can be avoided if the proper steps are taken throughout the design, construction
and commissioning of the unit. These delays are a result of the lack of readiness of the cycle
chemistry-related equipment, accumulation of corrosion products, the use of the wrong water
treatment chemicals, and a general neglect of cycle chemistry and corrosion.
A solution to reduce the frequency of cycle chemistry-related delays is to implement Cycle
Chemistry Commissioning Guidelines for all new plants, major equipment upgrades, and after
operation (load increase, base load to cycling, etc.) and water chemistry changes. This paper
outlines such a document and presents case histories where the use of these Guidelines could
have prevented problems and saved millions of dollars.

Commissioning Guidelines

The Cycle Chemistry Commissioning Guidelines are a combination of action items and
checklists for verifying that all cycle chemistry-related equipment is operational and in good
condition, personnel are properly trained, and procedures are in place for sampling, analysis and
control of cycle chemistry parameters. In order to be the most effective, the Guidelines must be
customized for each plant based on cycle design and type of operation.

The purpose of the Guidelines is to prevent delays in the commissioning activities and prevent
short- and long-term cycle chemistry and corrosion problems. To achieve this, the Guidelines
contain all of the steps which must be taken to ensure the entire cycle is as clean as possible so
that the cycle chemistry can quickly be brought within recommended limits. They also make sure
that the water and steam sampling and analysis systems are prepared to obtain and analyze water
and steam samples at the first fire. The Guidelines are most effective when they include the cycle
design review, material selection, and water chemistry control (water treatment and monitoring)
verification. This requires the cooperation of OEMs, architect engineers, owners, and operators.

The following are the topics which should be covered in the Commissioning Guidelines:
• Review of cycle and component design (chemistry vs. corrosion, impurity transport, flow-
accelerated corrosion, heat flux, stresses, etc.) [1 to 8]
• Water chemistry control and management guidelines - plant specific [9 to 20]
• Equipment preservation during manufacture, transport, storage, erection, and layup and the
subsequent removal of preservatives
• Training of operators and chemists before the start of commissioning
• Manuals
• Inspections of cycle chemistry-related equipment
• Maintenance procedures
• Pre-operational cleaning (acid, steam/air blow) and hydrotesting [26 to 28]
• Pre-steaming checks - boiler, turbine, condensate polishing, condenser, etc.
• Performance testing - steam purity/carry-over, boiler hideout, iron transport, etc. [2, 9 to 23]
• Sampling system design and operation [21 to 23]
• Cooling water system
• Chemical discharges/disposal
• Chemical laboratory
• Safety issues [8]
• Commissioning schedule

Each topic should have its own action items and a checklist of tasks to be signed off at different
times during the plant design, construction and commissioning processes. Individual items in the
checklist should be assigned to the contractor and owner representatives, and the timing of the
checks should be coordinated with the erection and commissioning schedule.

In order to be an effective document, management must be involved in its application and require
that all pertinent items be signed off before proceeding. These Guidelines would not be a
substitute for other commissioning and operation documents.

Design Review - The purpose of the steam cycle design review [2 to 8] is to theoretically
establish cycle chemical transport characteristics such as sources, transport, and removal of
corrosion products, deaeration characteristics, effects of condenser leaks and air inleakage, and
decomposition and transport of organics. The review of component design should focus on
concentration of impurities on component surfaces (i.e., boiler tubes and turbines), and on the
effects of heat transfer and stress on corrosion, stress corrosion, and corrosion fatigue.

Performance Testing - should include experimental determination of the cycle chemical

transport characteristics, in particular boiler carry-over and steam purity, boiler hideout,
deaeration, makeup and polisher performance, and iron transport. It may require intensive two-
week monitoring of water and steam chemistry under anticipated operating conditions.
Additional chemists and consultants may be needed. This does not have to be performed during
commissioning, but it should be done within the first two months of normal operation.

Case Histories

There have been many commissioning delays and later problems which have occurred as a result
of cycle chemistry-related issues which should have been found during commissioning. There
have also been good experiences with units where water chemistry commissioning, design
review, and performance testing have been applied. The first example is of a new 800 MW, 3
pressure, 1920 psig HP boiler pressure combined cycle unit with an air cooled condenser and
powdered resin condensate polisher where commissioning guidelines have been implemented
from the design phase to commercial operation. Water treatment is AVT with ammonia and
hydrazine except for the LP boilers which use congruent phosphate treatment. HRSG pre-
operational chemical cleaning was with citric acid and steam piping was cleaned using extensive
air blow. This unit experienced no water chemistry related delays and water chemistry guidelines
were met during commissioning. A summary of water and steam chemistry for this unit is given
in Table 1.
 Table 1

Summary of Water and Steam Chemistry During and After Commissioning of a Combined
Cycle Unit for which Water Chemistry Commissioning Guidelines were Used

Parameter HP Economizer Inlet HP Boiler Water HP Superheated Steam

Sodium (ppb) 0.28 44 0.28

Chloride (ppb) 0.8 170 < 0.2

Sulfate (ppb) < 0.5 9.1 < 0.5

TOC (ppb) N/A N/A 7

Iron (ppb) 8.1 12 0.3

N/A - Not Analyzed

Table 2 gives examples of commissioning related problems for combined cycle and conventional
fossil units. Illustrations of the problems are shown in Figures 1 to 5. The problems include cycle
contamination because of undetected condenser leaks, corrosion of equipment during
unprotected storage, high cation conductivity of steam because of decomposition of organic
water treatment chemicals, poor performance of condensate polishers and subsequent turbine
corrosion, high boiler carry-over leading to turbine deposits and stress corrosion cracking, and
flow-accelerated corrosion.

Table 2

Examples of Problems Experienced During Commissioning

No. Problem Root Cause Solution

Combined Cycles
1 Corrosion of HRSG panels HRSGs not completely drained Preoperational chemical
after hydrotesting during after the factory hydrotest and cleaning; not originally
storage and shipment not protected during shipment planned
and storage

2 Corrosion of HRSG during Unit not properly stored during No action taken
unprotected storage - 11 tons construction and heavy
of Fe removed during pre-op corrosion of boiler surfaces by
cleaning wet salt air.
3 Cycle contamination with Condenser tubes buckled and Plug leaking tubes, fill and
seawater - several condenser pulled away from tube sheets, drain both HRSGs four times,
tube leaks during tubes rupture due to improper operation on turbine bypass
commissioning, including venting, lack of monitoring, for 7 days to achieve HP
three major leaks (chloride poor communication between steam purity limits
up to 16,000 ppm in boiler chemists and operators
water)

4 During commissioning, unit 23 condenser tubes had broken, Two chemical cleanings were
was shut down due to failure resulting in massive required (see details in Case 5
of the HP steam bypass contamination of system, leak below) and commissioning
valve to close past 45% due not detected due to inoperable was delayed over 7 months
to heavy dark gray deposit and insufficient monitoring,
(47.7% Cl) disregard for chemistry

5 Brackish water Chemical cleaning of the HRSG Inspections, testing to

contamination (Case 4) after a condenser leak was determine how to clean
results in heavy deposits poorly controlled and the high system, second corrective
(0.25 inch (6 mm) thick in concentrations of chloride and chemical cleaning using a
primary superheater tubes iron in the system overwhelmed special phosphoric acid
(Figure 1). Corrective the citric acid and inhibitor. solution was performed
chemical cleaning stopped before the citric acid cleaning
due to iron citrate and tarry was restarted
organic deposit formation;
Figure 2

6 Steam cation cond. limits not The organic water treatment Water treatment programs
met due to high chemicals being used were modified to use non-organic
concentration of organic breaking down in the boiler and water treatment chemicals
acids. These acids also superheater to form volatile such as ammonia, hydrazine
increased flow-accelerated organic acids which were (carbohydrazide), and sodium
corrosion of carbon steel transported throughout the cycle phosphate or scavenger
components resulting in high concentration reduced
iron in boiler water.
Occurred in many HRSGs.

7 Flow-accelerated corrosion HRSGs designed using carbon Increase of pH and DO.

(FAC) of carbon steel HRSG steel in high velocity sections Newer HRSGs are designed
components. Occurred in which were within the with low alloy steels in areas
hundreds of HRSGs. temperature range where FAC is which are most susceptible to
prevalent FAC

8 Hydrogen damage of HRSG Seawater contamination of Replaced damaged tubes,

tubes and turbine pitting makeup storage barge, dumped contaminated water,
insufficient monitoring tightened chemistry control
9 Flow-accelerated corrosion Water chemistry - Replaced with stainless steel,
of IP and LP drum internals decomposition of organics, low reduced organics and
(Figure 3), Fe in blowdown pH, high conc. of oxygen scavenger
up to 15 ppm scavenger, design - high flow
velocity
Conventional Fossil Boiler Units
10 Seawater contamination - Due to improper installation and System drained and refilled 5
condenser tube leak loss of cooling water while times with demin. water.
increased sodium dumping steam, one condenser Condenser tube plugs re-
concentrations and tube plug falling out and six installed. Boiler and turbine
conductivity around the loose. The chemistry control inspection - OK. Chemical
cycle for 12-17 hours was not fully functional and control tightened
operator and chemist training
was inadequate

11 Pitting and corrosion fatigue Marginal operation of Blade redesign and

of L-1R blades in once- condensate polishers, blades replacement, improvement of
through boiler units near resonance CP operation

12 Stress corrosion of LP Operation of condensate Disks replaced, operation of

turbine disks in a polishers beyond ammonia CP improved
supercritical unit (Figure 4) breakthrough, high NaOH in
steam

13 Extensive boiler tube caustic High heat flux at MCR not Replaced tubes, changed to
corrosion (Figure 5) in high compatible with phosphate AVT
pressure drum boiler during boiler water control
one year at
MCR/overpressure [6]

14 Overheat failures of High boiler carry-over and Replaced superheater tubes,

superheater tubes within one heavy deposits in SH because of installed plug, started steam
month of operation a missing plug (for a soot chemistry monitoring
blower) in the steam drum

15 Destructive overspeed of High boiler carry-over of boiler New turbine, carry-over

new industrial turbine after water with polymeric dispersant control
16 hours of operation resulted in "gluing" of turbine
control valves in the open
position

Nuclear PWR Units

Many U.S. PWR units have been significantly damaged during commissioning and the first few
fuel cycles. The corrosion damage has been a consequence of a combination of design, wrong
water chemistry guidelines, and cycle contamination (condenser leaks, air inleakage,
malfunctioning condensate polishers) during commissioning and early operation. The results,
which have been costly to the nuclear industry include steam generator tube denting requiring
steam generator replacement, turbine stress corrosion cracking requiring whole turbine or rotor
replacement, and flow-accelerated corrosion of feedwater and wet steam piping and turbine
casing. Figure 6 is an example of steam generator water chemistry for a PWR unit using
seawater condenser cooling. It illustrates the degree of non-compliance with specified chloride
limits during early operation.

Conclusions and Recommendations

1. Many delays which have occurred during commissioning of new units could have been
avoided or greatly reduced if Cycle Chemistry Commissioning Guidelines had been used.
These problems not only add to the overall project cost, but can cause significant delays
which can result in late penalties (~$300,000/day).

Even more costly are the corrosion and scale and deposit problems which occur after
commissioning. These are often the result of marginal design of cycle components combined
with water and steam chemistry problems which were not discovered during commissioning.
Costs for these problems range from 0.1 to 100 million dollars.

2. The Cycle Chemistry Commissioning Guidelines should include sections on cycle and
component design, equipment preservation, water chemistry control and manuals, training,
discharges, and safety issues. They should be unit specific and should be jointly implemented
by architect engineers, OEMs, operators, and owners.

3. Design review of the steam cycle, material selection, sampling and instrumentation, and main
components should be performed as early as possible. It is an effective way to prevent water
chemistry and corrosion related problems. Selection of water treatment should fit the design.

4. Performance testing of the steam cycle water chemistry related characteristics during
commissioning or within ~2 months of commercial operation can prevent major corrosion
and deposition problems. It should include monitoring of all control parameters and their
conformance with guidelines and the evaluation of deaeration, makeup, condensate
polishing, and boiler carry-over and steam purity.

References
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3. O. Jonas. "Corrosion and Water Chemistry Problems in Steam Systems - Root Causes and
Solutions." Materials Performance. December 2001.
4. Low-Temperature Corrosion Problems in Fossil Power Plants - State of Knowledge Report.
Electric Power Research Institute, Palo Alto, CA. To Be Published 2003.
5. Flow-Accelerated Corrosion in Power Plants. EPRI, Palo Alto, CA. 1996. TR-106611.
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Proceedings: Second Fossil Plant Cycle Chemistry Conference. January 1989. GS-6535.
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2000 Conference. Queensland, Australia. May 15-16 2000.
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Institute, Palo Alto, CA, June 1986. CS-4629.
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 Figure 1
Heavy Deposit in HP Superheater Tube after Cycle Contamination with Brackish Water

Figure 2
SEM and Elemental Analysis of the Black Tarry Deposit which Formed after Unsuccessful
Chemical Cleaning
 Figure 3
Flow-Accelerated Corrosion of Carbon Steel Channel Separators in the LP Drum

Figure 4
Massive Stress Corrosion Cracking L-1 LP Turbine Disk caused by High Concentration of
NaOH in Steam
 Figure 5
Corroded Waterwall Tube from a High Pressure Drum Boiler after One Year Operation at MCR

Figure 6
Chloride Concentration in Steam Generator Water
throughout Several Fuel Cycles of a PWR Unit