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Boiler Water Management Guidelines For Black Liquor Recovery Boilers

First Posted Draft

The following document is an initial posted draft of a new BLRBAC document addressing boiler water management for BLRBs. As noted in the Table of Contents, four sections of the document have been included. Additional sections are under development and will be added as they are ready for posting. The Executive Committee has agreed to posting the draft for BLRBAC Membership review and comment, but a date has not been established for when this guideline is expected to be presented to the membership for vote. Any comments and/or questions about either the technical content or the format sent/given to the chairman of the Water Treatment Subcommittee prior to or at the Spring 2013 meeting will be discussed by the subcommittee at that time.

Tom Madersky, Chairman – Water Treatment Subcommittee Power Specialists Assoc. Inc. 531 Main Street Somers, CT 06071 Tel: 860-763-3241 [email protected]

BOILER WATER MANAGEMENT GUIDELINES FOR

BLACK LIQUOR RECOVERY BOILERS

THE BLACK LIQUOR RECOVERY BOILER ADVISORY COMMITTEE

October 2012 - Draft

Notice and Disclaimer of Liability Concerning Recommended Guidelines and Procedures BLRBAC brings together volunteers from operating companies, manufacturers and insurance companies representing varied viewpoints and interests to achieve consensus on Guidelines and Recommended Practices for the safe operation of recovery boilers. While BLRBAC facilitates this process, it does not independently test, evaluate or verify the accuracy of any information or the soundness of any judgments contained in its Recommended Guidelines and Procedures. BLRBAC disclaims liability for any personal injury, property or other damages of any nature whatsoever, whether special, indirect, consequential or compensatory, directly or indirectly resulting from the publication, use of, or reliance on BLRBAC Guidelines and Recommended Practices. BLRBAC also makes no guaranty or warranty as to the accuracy or completeness of any information published herein. In issuing and making this document available, BLRBAC is not undertaking to render professional or other services of or on behalf of any person or entity. Nor is BLRBAC undertaking to perform any duty owed by any person or entity to someone else. Anyone using BLRBAC Guidelines and Recommended Practices should rely on his or her own independent judgment or, as appropriate, seek the advice of a competent professional in determining the exercise of reasonable care in any given circumstance. Users of BLRBAC Guidelines and Recommended Practices should consult applicable federal, state and local laws and regulations relating to the safe manufacture and operation of recovery boilers. BLRBAC does not, by the publication of its Guidelines and Recommended Practices intend to urge action that is not in compliance with applicable laws, and its publications may not be construed as doing so.

Recovery Boiler Water Management Guidelines (black italicized text = to be developed, green text = completed, blue text = in progress 2011)

I. Clarification/Filtration Systems

II. Feedwater Support Systems

III. Boiler Auxiliary Support Systems

A. System Overview B. System Components

B1. Deaerator Systems B2. FW Pump Systems

1. Design & Operational Considerations

• System Overview • Basic System Flow Path • Basic System Component Design • Basic System Control Technology

a. Guideline(s) or Monitoring Tool(s) (seal water systems) b. Guideline(s) or Monitoring Tool(s) (minimum flow recirc) c. Guideline(s) or Monitoring Tool(s) (other)

2. Chemical Treatment & Control Considerations

• Water/Steam Quality Impact Assessment • Chemical Control Variables

a. Guideline(s) or Monitoring Tool(s) (oxygen/dissolved solids ingress monitoring/troubleshooting)

b. Guideline(s) or Monitoring Tool(s) (other)

3. Key Maintenance Practices & Protocols

• System Reliability Impact Assessment • Inspection Techniques • Inspection Frequency

a. Guideline(s) or Monitoring Tool(s) (strainers) b. Guideline(s) or Monitoring Tool(s) (pump seals) c. Guideline(s) or Monitoring Tool(s) (corrosion/erosion of

piping (NDE)) d. Guideline(s) or Monitoring Tool(s) (other)

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B3. FW Steam Attemporation Systems



a. Guideline(s) or Monitoring Tool(s) (attemperator

valve/sleeve) b. Guideline(s) or Monitoring Tool(s) (sweetwater condenser

metallurgy) c. Guideline(s) or Monitoring Tool(s) (effect of fireside

deposition) d. Guideline(s) or Monitoring Tool(s) (other)



a. Guideline(s) or Monitoring Tool(s) (monitoring or troubleshooting sweetwater condenser leakage)

b. Guideline(s) or Monitoring Tool(s) (monitoring or troubleshooting FW (for attemporation) water quality)

c. Guideline(s) or Monitoring Tool(s) (alternative (backup supply) sources of high quality attemporation water)

d. Guideline(s) or Monitoring Tool(s) (other)



a. Guideline(s) or Monitoring Tool(s) (attemperator valve and sleeve integrity)

b. Guideline(s) or Monitoring Tool(s) (sweetwater condenser integrity)

c. Guideline(s) or Monitoring Tool(s) (other)

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B4. Blowdown Heat Recovery Systems



a. Guideline(s) or Monitoring Tool(s) (flash steam & steam

distribution) b. Guideline(s) or Monitoring Tool(s) (level control) c. Guideline(s) or Monitoring Tool(s) (other)



a. Guideline(s) or Monitoring Tool(s) (boiler blowdown impurities - steam)

b. Guideline(s) or Monitoring Tool(s) (boiler blowdown impurities - makeup water)

c. Guideline(s) or Monitoring Tool(s) (other)



a. Guideline(s) or Monitoring Tool(s) (installation of CBD flow meters)

b. Guideline(s) or Monitoring Tool(s) (installation of CBD conductivity probes)

c. Guideline(s) or Monitoring Tool(s) (inspection of level control system)


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IV. Recovery Boiler

A. System Overview B. System Components

B1. Economizer



a. Guideline(s) or Monitoring Tool(s) (changes in furnace

heat input and distribution) b. Guideline(s) or Monitoring Tool(s) (changes in FW supply

temperature) c. Guideline(s) or Monitoring Tool(s) (other)



a. Guideline(s) or Monitoring Tool(s) (oxygen) b. Guideline(s) or Monitoring Tool(s) (iron/copper) c. Guideline(s) or Monitoring Tool(s) (chemical feed points) d. Guideline(s) or Monitoring Tool(s) (other)



a. Guideline(s) or Monitoring Tool(s) (metallurgical integrity assessment)

b. Guideline(s) or Monitoring Tool(s) (visual structural integrity assessment)

c. Guideline(s) or Monitoring Tool(s) (waterside visual condition assessment)


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B2. Drum, Tube & Header Circuitry



a. Guideline(s) or Monitoring Tool(s) (changes in furnace

heat input and distribution) b. Guideline(s) or Monitoring Tool(s) (changes in FW supply

temperature) c. Guideline(s) or Monitoring Tool(s) (other)



a. Guideline(s) or Monitoring Tool(s) (corrosion and corrosion by-products)

b. Guideline(s) or Monitoring Tool(s) (deposition and particulate matter)

c. Guideline(s) or Monitoring Tool(s) (chemical feed and sampling points)




a. Guideline(s) or Monitoring Tool(s) (metallurgical integrity assessment)

b. Guideline(s) or Monitoring Tool(s) (visual structural integrity assessment)

c. Guideline(s) or Monitoring Tool(s) (waterside visual condition assessment)


V. Condensate Systems A. System Overview B. System Components

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VI. Chemical Cleaning

• Determine what factors should be considered and why • Provide the end user with some tools to decide how often.

* 1st Develop a list all factors to be considered. * 2nd Classify as either a quantifiable or a subjective consideration. * 3rd Assign an initial value (1 - 10) relative to importance (reach consensus on an

initial value). * 4th Provide the concise written rationale for the value assigned (represents 1 of 3

perspectives). * 5th Share findings with the other two WTSC teams (review findings in that same

order).

• Determine which boiler circuits pose the greatest chemical cleaning concern from a design perspective and why.

• Provide the end user with some design information that focuses upon what to

look at and/or take into consideration and why.

* 1st Provide a list of most troublesome circuits to clean and why. * 2nd Describe fill (if applicable) drain and flush options for those circuits. * 3rd Assign an initial value (1 - 10) relative to importance (reach consensus on an

initial value). * 4th Provide the concise written rationale for the value assigned (difficult to clean,

difficult to flush, etc.) (represents 1 of 3 perspectives). * 5th Share findings with the other two WTSC teams (review findings in that same

order). • Elaborate from a water management perspective on the “factors” presented by

the Maintenance Team (more specifically the subjective considerations). • Elaborate from a water management perspective on the “troublesome circuits”

presented by the D&O Team (i.e., briefly describe where/how the deposits form and why (roof tubes, etc.).

VII. Sampling & Testing Protocols

Feedwater Pump Systems

III (B2): FW Pump Systems


System Overview

Feedwater (FW) pump systems are designed to provide:

Stable drum water level control under all firing conditions A spare pump in the event of main pump failure Provisions to rapid drain the economizer.

A conventional FW pumping system is capable of handling somewhat greater than the maximum FW demand of the boilers the system supplies.

Basic System Flow Path

The following illustration represents basic deaerator/feedwater circuitry. The boundaries for this system are from the deaerator (DA) storage tank outlet penetration(s) to the inlet of the economizer. Recovery boiler operating systems may vary with respect to component and circuit design. Any variation may impact how the guidelines and monitoring tools are employed.


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Basic System Component Design

A basic FW pump system is comprised of:

Droplegs or piping runs from one or more DA storage tank to a FW pump inlet header A FW pump suction header (suction side of the pump(s)) Pump suction strainers A FW discharge header (discharge side of the pump(s)) Full capacity pump(s) as well as a full capacity backup pump(s) FW pump(s) can be steam- or electric-driven. Preferably the main operating pump would be

steam-driven with an electric backup on standby. Where only electric-driven pumps are employed, there should be a secondary source of electrical power supply to the pumps

Minimum flow recirculation lines (typically routed back to the DA) A pump shaft seal system (either mechanical seals or packing glands with/without seal water) Regulating control valve system, an isolation valve, a non-return valve, a drain valve and a

rapid drain valve Chemical injection quills of proper design and materials of construction A continuous oxygen analyzer (with trend capabilities) is recommended. The sampling

system should have sample extraction capabilities on both the suction and discharge side of the FW pump(s)

Conductivity element with alarm capabilities (located in the dropleg below the DA storage tank)

Cation conductivity where FW is utilized for attemperation pH element with alarm capabilities (recommended) ORP measurement (optional).

Basic System Control Technology

The FW regulating valve is controlled by a steam drum level control system. The rapid drain valve and FW stop valve are controlled by the rapid drain system.

Guideline(s) or Monitoring Tool(s)

Guideline #1: FAC - The original FW piping should be designed to reduce the effect of flow-assisted corrosion. Any changes in operation such as an increase in FW flow rate, change in pH, dramatic change in dissolved oxygen levels, or a change in FW system chemistry should take the potential for flow-assisted corrosion into consideration (refer to maintenance inspection guidelines).


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Guideline #2: Mechanical Seals or Packing Glands - Depending upon pump design, leakage in and around shaft seal systems can impact FW quality. It is a best practice to reinject cooled FW where packing gland systems are utilized. The selection of a cooling water source for the sample heat exchanger will be system dependent. It is also a best practice to utilize high purity water for mechanical seal cooling. In those systems that do not have DI utilization and recapture capabilities, it is recommended that you meet the minimum seal water quality standard as specified by the pump manufacturer.

Guideline #3: Oxygen Testing & Sampling - There should be a properly designed and constructed high pressure sample cooling system in place (temporary or permanent installation) to accommodate testing for dissolved oxygen on both the suction and discharge sides of a FW pumping system. For more information on installation points, sample flow requirements and temperature limitations, contact/refer to one or more of the following:

Your water treatment chemicals supplier Equipment manufacturing specifications (OEM) TAPPI TIPs #0416-03 (water quality and monitoring requirements for high purity water) and

#0416-16 (water quality and monitoring requirements for softened water).

Guideline #4: Chemical Feed - Chemical feed point locations, use of injection quills and methods of chemical delivery should, from a chemical compatibility perspective, be reviewed in detail when selecting a point of chemical addition that will be upstream of a FW pump or a FW control valve. Chemical injection quills should be of proper design and materials of construction. For more information on installation points, sample flow requirements and temperature limitations, contact/refer to one or more of the following:

Your water treatment chemicals supplier Equipment manufacturing specifications (OEM) TAPPI TIPs #0416-03 (water quality and monitoring requirements for high purity water) and

#0416-16 (water quality and monitoring requirements for softened water).


Water/Steam Quality Impact Assessment

Impurities that enter through the FW circuit between the DA storage outlet flange and the economizer inlet flange can result in potential damage to the boiler circuit. The source of these impurities can be the deaeration system or the FW pump(s). Contamination levels, if significant, can result in a water chemistry problem.


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Key Chemical Control Variables

American Society of Mechanical Engineers (ASME) guidelines should be consulted for a full discussion of chemical control variables, including dissolved oxygen, pH, conductivity, iron, copper, and hardness (ASME guidelines are contained in the Appendix section). Mills shall maintain emergency standard operating procedures (ESOPs) for reacting to out-of-range FW parameters. At a minimum, these shall include oxygen, iron, pH, hardness, and conductivity. When contamination is suspected, operators should validate their test results and, once validated, follow the ESOPs that are in place to troubleshoot the problem. The validation step is to ensure that the sample conditioning station is not the source of the apparent contamination.


Guideline #1: ESOP - Dissolved Oxygen Contamination - ESOPs shall be in place to address oxygen contamination of FW. Possible sources for oxygen in the FW include the DA, FW pump seals, and the automatic FW recirculation (minimum flow) line. Condensate can be the source of dissolved oxygen, particularly where the return condensate stream enters the DA heater below the spray nozzle section. The sample extraction points for dissolved oxygen testing are as follows:

Ahead of the economizer inlet (recommended - refer to illustration) FW pump suction/discharge (single O2 analyzer and two sample sources).

It is recommended that a continuous dissolved oxygen analyzer be deployed, backed up with a periodic sampling/analysis protocol to ensure accurate measurement and validation of test results.

Guideline #2: ESOP - pH - ESOPs shall be in place to address both high and low FW pH conditions. The ESOPs should address the following for both low and high pH conditions.

Test validation and verification prerequisites for either condition (pH meter validation, etc.) Decision tree to specify at what pH level fire should be removed from the boiler.

Guideline #3: ESOP - Conductivity - ESOPs shall be in place to address high FW conductivity. Boiler FW pump seal water systems and heat exchangers can be the source of conductivity. BLRBAC requires that recovery boiler FW systems have continuous conductivity monitoring capabilities. There should be alarm and high alarm conductivity setpoints with the appropriate action steps to be taken by the operators. Continuous cation conductivity monitoring should be employed in FW systems that utilize FW for superheated steam attemperation to provide a means of differentiating between amine contribution and other conductive species. (For more information on attemporating systems refer to the FW attemporation section of the BLRBAC Water Treatment Guidelines.)


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Guideline #4: SOP - Iron Levels - SOPs shall be in place that address ASME guidelines for iron levels in the boiler feedwater. Oxygen intrusion and process intrusion can both contribute to high iron levels in the FW. Low pH can also contribute to high iron levels. There are a variety of tests that measure iron in its different oxidation states. These tests can run on samples taken from various points within the FW circuitry. The type of iron test, sample extraction points, and sampling protocols will be a function of system design, chemistry employed, and conditions encountered. The objective of the testing is to identify particulate iron and/or iron corrosion by-products that contaminate the FW. The deaeration system and the FW piping between the DA outlet flange and the economizer inlet flange can be a source of iron contamination. For additional information regarding iron monitoring, testing, and control (downstream of the economizer inlet) refer to the economizer and boiler circuitry sections of the BLRBAC Water Treatment Guidelines. Consult your water treatment experts to determine the best testing protocols to meet your mill's needs.

Guideline #5: SOP - Copper Levels - Identify the alloys deployed in the recovery boiler water system heat exchangers to confirm if there are any potential sources of copper. Some of the more common sources of copper are:

Copper alloy heat exchangers Copper alloy steam coil air heaters Copper alloy sweetwater condensers Heating systems (may be seasonal and intermittent).

Due to the low levels of copper typically encountered and field test limitations in the measurement of any increase in those levels of copper, testing for copper is not practical. If copper ingress is suspected, then samples extracted from the pertinent streams should be sent out to the lab for high purity analysis. An action plan should be developed; predicated upon the lab findings. Consult your water treatment experts to determine the best ways to deal with copper issues.

Guideline #6: ESOP - Hardness Levels - ESOPs shall be in place that address hardness levels above ASME guidelines for boiler FW. Possible hardness sources include:

FW pump seal water Process water hardness-related ingress that may occur in systems upstream of the feed

pumps. Consult your water treatment experts to determine the best ways to deal with hardness issues.


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Monitoring Tool #1: Feedwater Conductivity Element - As stated earlier, recovery boiler FW systems with continuous conductivity monitoring capabilities is a BLRBAC requirement. There should be alarm and high alarm conductivity setpoints with the appropriate action steps to be taken by the operators when the system is in alarm mode or conductivity levels in the FW suddenly trend upwards.

Monitoring Tool #2: Feedwater Cation Conductivity - It is recommended that continuous cation conductivity monitoring be employed in FW systems that utilize FW for superheated steam attemperation. There should be alarm and high alarm conductivity setpoints with the appropriate action steps to be taken by the operators when the system is in alarm mode or cation conductivity levels in the FW suddenly trend upwards. To monitor cation conductivity you will need to install a sample cooler and small cation exchange column upstream of the conductivity probe. In systems where the conductivity probe is located directly in the FW line, the probe will need to be relocated and made an integral part of the sampling system.

Monitoring Tool #3: Feedwater pH - To monitor and identify FW ingress contaminants that may be slightly conductive yet acidic in nature (organic acids) or redundant indication when experiencing alkaline ingress (black liquor, etc.), it is advisable to have pH measurement as a supplemental monitoring tool. The pH probe should be located upstream of any non-volatile alkaline chemical feed points. Consideration should be given to the influence of amines upon the pH monitoring and alarm and control setpoints employed (if applicable). The primary focus should be a step change in the pH reading under normal operating and chemical material balance conditions.

Monitoring Tool #4: In-Line Dissolved Oxygen Monitors - The sample extraction points for dissolved oxygen testing are as follows:

Economizer inlet (recommended) FW pump suction/discharge (single O2 analyzer and two sample sources).

The sample conditioning requirements, sample line location, length of sample line run, and sample flow should be taken into consideration when installing a dissolved oxygen sampling system. The location of the chemical feed point relative to the sample extraction point can influence test results.


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System Reliability Impact Assessment

FW pumps and pumping systems can be a source of O2 ingress and subsequent erosion/corrosion of the downstream integral piping system.

Inspection Techniques

Inspect pump seal water systems and review seal water quality for adequacy (seal water quality should be equivalent to that of the FW). Identify high risk areas in the FW piping system (such as bends, elbows, and any injection quill locations) and employ NDE methods to inspect for FAC. Inspect and calibrate the system O2 analyzer and visually inspect all associated sample piping and valves. Monitor or periodically inspect for the presence of any sample flow restrictions. If raw or mill water is used on the sample cooler/heat exchanger the heat exchanger should be periodically inspected and cleaned.

Inspection Frequency

Strainers - There are instances when strainers foul with materials like fiber and resin. The source of these materials can be water system-related and may have impacted other water support systems and sample monitoring devices. It is recommended that you inspect the FW pump strainers in accordance with planned FW pump maintenance schedules. In addition, it is advisable to routinely monitor pressure drop across the strainers to ensure that the strainers are not accumulating materials that may restrict feedwater flow. Seal Water Systems - Inspect and review water quality as mill experience dictates. FW Piping Systems - The mill should develop a protocol that delineates the inspection frequency for FAC in high risk areas (typically very 3 - 5 years, but could be more or less frequent depending on mill experience/history). O2 Analyzers - Units should be inspected and calibrated in accordance with the OEM guidelines. Associated sample piping systems, valves, and sample coolers should be inspected as mill experience dictates.


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Guideline #1: SOP - Maintenance & Inspection - A seal water system SOP shall be in place that delineates standard operational and maintenance practices and established inspection frequencies.

Guideline #2: SOP - Inspection - Facilities shall have an SOP in place governing the inspection of FW piping systems for the presence of FAC.

Guideline #3: SOP - Oxygen Analyzers - Facilities shall have an SOP in place that governs the operation, maintenance, and inspection of O2 analyzers and their associated sample piping, valves, and sample coolers.

FW Steam Attemporation Systems

III (B3): FW Steam Attemporation Systems


System Overview

Attemporation, sometimes referred to as desuperheating, is the process whereby the boiler superheated steam is cooled with water to obtain a constant steam temperature. Since the water utilized in the attemporation process is introduced upstream of a steam turbine, and/or in many cases introduced within the superheater circuitry, it must be extracted from a reliable source that is relatively pure (trace levels of dissolved and/or suspended solids). There are several sources of high purity water within the recovery boiler water support system that can be utilized for attemporation water:

Sweetwater condenser (condensed steam from a dedicated heat exchanger) is the water source of highest purity. If properly designed and integrated into the feedwater system, a sweetwater condenser is also the most reliably consistent source of attemporation water.

Recovery boiler feedwater (FW) is another attemporation water source that is commonly

utilized. In some applications FW is a backup supply to a sweetwater condenser. The level of impurities in this water source can vary as water quality from the various support systems (ion exchange systems, condensate systems, etc.) fluctuates. Water treatment chemistry upstream of the attemporation water extraction point can also influence water quality.

Turbine condensate is the third most common source of attemporator supply water and, in

some applications, is a backup supply to the two aforementioned water supply systems. The level of impurities in this water source can vary as a function of the purity of the steam supply to the turbine condenser, oxygen, and other contaminants that may be present in the condensed steam.

Polished condensate can be an attemporation water source; however, reliability and

consistency factors tend to place this water source in the emergency backup category. Demineralized water in very limited applications is utilized as either a lead or backup

attemporator water supply source. Since, in all likelihood, this water is not deaerated, its use as an attemporator supply water source is strongly discouraged. A detailed corrosion study of all downstream circuitry and steam/water system components is recommended.

In this BLRBAC guideline, the focus will be upon the sweetwater condenser and boiler feedwater attemporating water systems. Other water sources will be considered as either special applications and/or backup attemporator water supply sources.

FW Steam Attemporator Systems

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The following illustrations represent conventional FW steam attemporation system circuitry. Recovery boiler operating systems may vary with respect to component and circuit design. Any variation may impact how the guidelines and monitoring tools are employed.


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Attemporation with feedwater (upper illustration).

Attemporator sleeve Double valve (block and flow control valves) with bypass Cation conductivity measurement.

Attemporation with a sweetwater condenser (lower illustration).

Attemporator sleeve Sweetwater condenser Sweetwater condenser metallurgical considerations Double valve (block and flow control valves) with bypass Sweetwater condenser sample line (for grab sample) Steam temperature indication before and after attemporation.


The attemporator water flow is controlled to sustain the desired superheated steam outlet temperature.


Guideline #1: Metallurgy - Due to their good corrosion resistance properties, Monel (nickel (~69%)/copper) and stainless steel are the most common materials utilized in the fabrication of sweetwater condenser tubes. Where any copper bearing metallurgy is utilized (by design or retrofit), there is the potential, under certain conditions, for copper to corrode and for the copper corrosion by-product to enter the boiler circuitry (please refer to the chemical treatment and control section for more specific information on copper corrosion). Where carbon steel bearing metallurgy is utilized (by design or retrofit), there is the potential, under certain conditions, for carbon steel to corrode and for iron corrosion by-product to enter the boiler circuitry (please refer to the chemical treatment and control section for more specific information on carbon steel corrosion).

Monitoring Tool #1: Sampling - To have the capability to test the condensed steam within the sweetwater condenser shell section for contamination, there should be a sample extraction point at the condenser shell side outlet.


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Since the water utilized in the attemporation process is introduced upstream of a steam turbine and/or in many cases introduced within the superheater circuitry, it must be extracted from a reliable source that is relatively pure (trace levels of dissolved and/or suspended solids). The impurities present in that attemporating water source can deleteriously impact the reliability of recovery boiler superheater circuitry (if interstage desuperheating is employed) and other key support system operating components (turbines) located downstream of the attemporation water injection point. Note: Other related water support systems can become contaminated and alter the purity of the attemporation water supply source. Where attemporation systems other than a sweetwater steam condenser are utilized, the water quality of those water support systems should be monitored. Attemporation water purity can vary on either a continuous or intermittent basis. Therefore sampling, monitoring, and operator notification protocols should be in place that focus upon identifying changes or variations in the attemporation water supply.


The key control variable in monitoring attemporator water purity is conductivity. Other variables such as pH and sodium provide meaningful information; however, it is not essential for either to be monitored on a continuous basis. An increase in conductivity in the attemporator water supply can be caused by an increase in cation/anion loading (non-volatile contaminants) and/or an increase in amine/ammonia loading (volatiles typically associated with water treatment). The non-volatile contaminants can deposit in steam/water components located downstream of the attemporation introduction point. There are two commonly employed methods of monitoring/measuring conductivity:

Specific Conductance - Measures how a water source containing both volatile and non-volatile water contaminants (cations, anions, amines, and ammonia) conducts an electrical current.

Cation Conductivity - Sensitizes the specific conductance measurement and focuses upon

only the non-volatile anion water components in the water source intentionally eliminating amines and ammonia.

Cation conductivity is recommended because the presence of amines and ammonia in the attemporation water source make it difficult to tell the difference between volatile and non-volatile contributors to the conductivity of an attemporating water source. Non-volatile solids can deposit in superheaters and turbines.


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To test for the non-volatile components, a cooled-continuous flowing attemporator water sample stream is processed through a small cation exchange column located upstream of a conductivity probe yielding a cation conductivity measurement. The resultant cation conductivity measurement provides a more accurate measurement of the cation/anion loading within the attemporator water supply. Incremental step changes in variables monitored on a continuous or intermittent basis would require an investigation as to probable cause. In such cases, the water treatment supplier should be contacted immediately. You can also refer to the feedwater pump section for additional information regarding cation conductivity and related information regarding other feedwater system chemical control variables.


Guideline #1: Drawings - Maintain an up-to-date drawing of the attemporation water system. Include all backup water sources, sample locations, and chemical feed points (if applicable). An annual review of the system drawings and the backup system utilization strategy is recommended.

Guideline #2: Conductivity - Attemporator water supply sources that exceed 12 µS/cm conductivity should be scrutinized for suitability of use by your water treatment supplier.

Guideline #3: SOP - Water Quality - An SOP shall be in place that addresses attemporation water quality. This SOP should provide guidance if the water quality is determined to be:

Outside the prescribed operating boundaries for the parameters being monitored Undergoing a parameter step change Experiencing a discernable trend change in one or more parameters being monitored.

Samples of any suspect attemporation water source should be extracted and saved for future examination during any period of time when one or more of the aforementioned conditions are encountered.

Guideline #4: Non-Volatile Chemicals - The addition of non-volatile chemicals upstream of any attemporation water source is strictly prohibited.

Guideline #5: ESOP - Change in Water Source - An ESOP should be in place that addresses what action should be taken if there is a change in attemporating water source. Procedures should include action steps to confirm that the attemporating water is suitable for use as defined by your water treatment supplier.


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Guideline #6: ESOP - Steam Purity - An ESOP should be in place that addresses what action should be taken if a sustained or intermittent change in the purity of steam is experienced. This ESOP should specifically focus upon contamination of attemporation water sources (turbine condensate, sweetwater condenser condensate, etc.).

Monitoring Tool #1: FW Conductivity - It is recommended that conductivity be continuously monitored in all recovery boiler feedwater systems. Refer to BLRBAC Instrumentation Checklist and Classification Guide for Instruments and Control Systems Used in the Operation of Black Liquor Recovery Boilers, Appendix A, Item 6.

Monitoring Tool #2: FW Cation Conductivity - Where FW is utilized as the primary source of steam attemporation, continuous monitoring of cation conductivity of the FW is recommended.

Monitoring Tool #3: Attemporating Water Grab Sampling - Grab samples should be routinely extracted and then tested for conductivity from attemporation water sources that may be subject to contamination and are not otherwise continuously monitored. Frequency should be determined by mill management personnel working in concert with their water treatment supplier.

Monitoring Tool #4: pH - Monitoring of attemporation water pH is optional, yet particularly helpful in identifying the presence of organic-acid compounds that are not highly conductive but have the ability to suppress attemporation water pH.

Monitoring Tool #5: Sodium - Monitoring sodium is a valuable troubleshooting tool. In many boiler water support systems, sodium is either profiled (by grab sample) or continuously analyzed to measure trace levels in:

Demineralized water ion exchange systems Condensate return systems Saturated/superheated steam.

A sweetwater condenser can serve as a saturated steam sampling point and is well suited for sodium analysis. If the attemporation water is feedwater, the measurement of sodium can be helpful when assessing suitability for use and/or troubleshooting attemporation water quality problems.


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The consequences of poor quality water or improper attemporator water dispersion could include:

Deposit formation within the attemporator (flow restriction) Deposition on downstream components (superheater tubes and turbine blades) Thermal cycling of components Flooding of superheater pendants General mechanical integrity issues Superheater tube failure.


Attemporator sleeves should be equipped with a properly designed inspection port so it can be visually inspected with a boroscope. The visual inspection should include, but not necessarily be limited to:

Spray nozzle assembly (diaphragm, nozzle welds, backing plate, spray head) Liner (if applicable) Attemporator body (look for erosion or cracks).

If a sweetwater condenser is utilized, it should be inspected for general structural integrity. Metallurgy of the heat exchanger tubes should be verified. If a condensed steam sample line exists, it should be free of obstructions. Temperature control valves should be monitored and maintained to prevent excessive leak-by.


The frequency of inspection for the attemporator sleeves or the sweetwater condenser system is mill location specific, but typically coordinated/aligned with turbine outages.


Guideline #1: Inspection - Since these systems require very little maintenance, they typically get overlooked in the inspection process. Facilities should develop and maintain their own formalized written maintenance protocol governing the inspection of attemporator system components.


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Monitoring Tool #1: Checklist - As stated earlier, the quantity and the purity of the attemporation supply water can deleteriously impact downstream system components. Poor steam temperature control can exacerbate other problems and further complicate any potential deposition-related concerns. The temperature control valve position and superheater steam outlet steam temperature conditions should be routinely reviewed/scrutinized by the boiler operator and incorporated into a checklist.

Blowdown Heat Recovery Systems

III (B4). Blowdown Heat Recovery Systems


System Overview

Blowdown heat recovery systems are designed to recover some of the latent heat energy within the boiler blowdown water through the process of flashing steam from a tank at a lower operating pressure. The continuous blowdown (CBD) system controls the concentration of dissolved and suspended solids in the recovery boiler water, whereby a portion of the most concentrated boiler water is continuously extracted from the boiler steam drum. A small percentage of boiler water (typically 1% - 3% of the feedwater flow) exits the steam drum via a small diameter blowdown line. It should be noted that the location of the blowdown line within the steam drum and the orientation, sizing, and spacing of the orifices can impact how effectively the solids are extracted from the boiler water. The flow of boiler blowdown water can be controlled manually or automatically. Where flow meters are to be employed, the location of a CBD flow meter requires careful consideration with respect to static head and its positioning relative to the blowdown flow control valve. Boiler water from the internal blowdown line is routed to a singular blowdown collection tank (flash tank) or, in some applications, a series of cascading pressure blowdown collection tanks. In some heat recovery systems a heat exchanger is also utilized to recover some of the sensible heat energy in the residual blowdown water as it is discharged from the flash tank. In some blowdown heat recovery systems, a properly engineered heat exchanger can take the place of the flash tank. A malfunctioning blowdown heat recovery system can become a source of steam contamination to the recovery boiler water system. If the flashed steam becomes contaminated with boiler water, recovery boiler deaeration systems and other low pressure steam users can be impacted; ultimately affecting the quality of the boiler feedwater.


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The following illustration represents basic continuous blowdown system circuitry. The boundaries for the system are from the boiler steam drum CBD line to the two locations where the blowdown water flashes and the remaining liquid discharges to sewer. Recovery boiler operating systems may vary with respect to component and circuit design. Any variation may impact how the guidelines and monitoring tools are employed.


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A conventional blowdown heat recovery system is comprised of:

A blowdown line (typically 1" - 1 ½" diameter) located inside the steam drum An external blowdown line (typically 1" - 1½" diameter)

o Two external manual isolation valves (typically located in close proximity to the steam drum)

o Manual blowdown valve (with valve position indications) o Flow meter (optional) o Automatic flow control system (optional)

A flash tank (with or without internal baffles) o Blowdown line penetration(s) into the flash tank steam space o Water level sight glass o A manual or automatic level control system o Steam piping for tying into a low pressure steam distribution system o Safety valve

Additional flash tanks (in series - optional) A heat exchanger (typical but optional) supplied with cool RO and/or ion exchanged

processed water where a transfer of heat from the boiler blowdown water to the processed water takes place. Note: In most CBD (continuous blowdown) heat exchanger applications that processed water is utilized as recovery boiler makeup water.


A basic blowdown heat recovery system should have a level control system to maintain boiler blowdown water level within the flash tank.


Guideline #1: Level Control - If feedwater conductivity increases and steam purity is suspect, operators should confirm that the flash tank is being maintained at the appropriate water level, as high level could create a carryover condition whereby blowdown water containing high dissolved and suspended solids becomes entrained in the steam being flashed to interconnected steam headers.

Guideline #2: Heat Exchanger - If a heat exchanger is part of the heat recovery system, first, note the pressure relationships of the two fluids entering/exiting the heat exchanger. If the blowdown water can contaminate the process water, instrumentation should be in place to detect and alarm to that condition. If a blowdown heat exchanger is suspect of leaking, isolate the exchanger and observe the impact upon water chemistry at points downstream of the suspect exchanger.


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Guideline #3: Level Control - Since the boiler blowdown contains dissolved and suspended solids, it is critical that the blowdown water in the flash tank be mechanically controlled at a level that minimizes the potential for contamination of the flashed steam. Note: Operating the flash tank outside the design specifications (high load conditions, start-up, etc.) can result in boiler water contamination of the flashed steam.



Boiler water impurities in the flashed steam can distribute throughout the mill's steam distribution system, and can eventually contaminate the low pressure steam supply. Recovery boiler deaeration systems utilize low pressure steam. Other end users utilize low pressure steam that, when condensed, can return as condensate to the recovery boiler feedwater system. Flash steam contamination in a blowdown heat recovery system can cause an undesirable increase in recovery boiler feedwater conductivity which, in turn, will result in an elevation of solids levels within the recovery boiler circuitry and, where applicable, in feedwater superheater attemporation systems. The level of contamination, if significant, has the potential to alter the recovery boiler system chemistry, impact steam purity, and contribute to the formation of waterside deposits and/or contribute to corrosion mechanisms. Note: Under certain circumstances, contamination of the boiler makeup water supply via a faulty blowdown heat recovery heat exchanger can result in contamination of the water being supplied as makeup to a recovery boiler.


Recovery boiler blowdown water can contain a variety of impurities. The composition and concentration of the impurities is impacted by feedwater quality, chemical program selection (as a function of boiler operating pressure), extraneous contaminate ingress sources, and blowdown control. When either feedwater or steam is suspected of being contaminated, operators should validate their feedwater test results and, once validated, follow the emergency standard operating procedures (ESOPs) that are in place to troubleshoot the problem and identify the source of contamination. If the source of contamination is boiler blowdown water, then the composition or profile of the contaminants, albeit diluted, will typically reflect boiler water chemistry.


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Guideline #1: ESOP - Steam Contamination - It is a best practice to have ESOPs in place that address contamination of the steam. The continuous blowdown tank can be one of many potential sources of steam contamination. If the blowdown tank (flash tank) is suspect, there will be an elevation in feedwater conductivity with no elevation in makeup water conductivity.

Guideline #2: ESOP - Processed Water Contamination - If RO or ion exchange processed water is supplied to the blowdown flash tank heat exchanger and that processed water is utilized as makeup to the recovery boiler feedwater system, it is a best practice to have ESOPs in place that address process water contamination. The blowdown tank heat exchanger can be one of many potential sources of makeup water contamination. In those cases where the blowdown water pressure at the heat exchanger exceeds the processed water pressure and the heat exchanger becomes suspect, there may be an elevation in conductivity in the water being supplied to the feedwater system. The extent of contamination will be a function of the conductivity levels being maintained in the recovery boiler blowdown water and the extent and nature of the heat exchanger leak.

Monitoring Tool #1: Feedwater Conductivity Element - For out-of-compliance results (alarm condition), determine if any changes in feedwater conductivity levels can be attributed to the makeup water supply; the condensate supply or the steam supply to the deaerator. Review your troubleshooting guidelines (ESOP) that address recovery boiler feedwater contamination. Check your alarm and control setpoints.

Monitoring Tool #2: Condensate Conductivity Element - For out-of-compliance results (alarm condition), review your troubleshooting guidelines (ESOP) that address recovery boiler condensate system contamination. Check your alarm and control setpoints.

Monitoring Tool #3: Grab Sample - If a CBD heat exchanger is suspect, manually test the processed water downstream of the heat exchanger and look for an increase in the conductivity of the processed water supply.


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If the purity of the steam exiting the continuous blowdown flash tank, or the purity of the feedwater makeup exiting the heat exchanger (if used) is ever compromised, it can usually be attributed to one or more of the following:

Poor mechanical separation Poor level control Heat exchanger integrity Excessive blowdown flows.


Flash Tank:

If there are baffles in the vessel, check for proper alignment. Inspect the level control shell penetrations for obstructions. Inspect the blowdown level sensing lines if present.

Heat Exchanger:

Verify proper operation of any level sensing device. Perform hydrostatic test of the heat exchanger.


A periodic visual inspection schedule should be established. There may also be code requirements which should be considered. Inspection SOPs should be developed and implemented.


Guideline #1: Inspection - The blowdown flash tank(s) level should be checked visually on a routine basis as part of the operator's walkdown.

Guideline #2: Inspection - There should be a periodic inspection of blowdown piping for thinning due to corrosion. Adhere to jurisdictional inspection requirements.

Economizer Systems

IV (B1): Economizer Systems


System Overview

The economizer is the last feedwater preheating step before the feedwater enters the steam drum. The economizer recovers heat from the flue gas, elevating feedwater temperature. Most recovery boiler economizers are integral to the boiler. Typically, they are once through flow bottom-to-top with or without headers to distribute flow at very low velocity to the steam drum. The water pressure must exceed steam drum pressure and, although economizers are located in relatively low temperature portions of the boiler, elevated approach temperatures can result in premature boiling within the upper portion of the economizer. Premature boiling can impact circulation within the boiler circuits and can deleteriously impact boiler start-up. The economizer system may incorporate a feedwater air heater (heat exchanger). The economizer may also consist of one or more sections. The economizer is subject to the same contaminant concerns as the feedwater piping, but the heat input in this portion of the water circuit, coupled with the low velocities, makes the economizer the first place that contaminants may manifest themselves. The low feedwater velocities can create a number of problems specific to particulate iron buildup within the lower extremities of the economizer circuitry. If coupled with oxygen and/or non-compliant water parameters or chemistries, concerns regarding corrosion heighten. In many systems the key problem, particulate iron, can transport into the boiler drum, tube and header circuitry.

Economizer Systems

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The following illustration represents basic economizer circuitry. Recovery boiler operating systems may vary with respect to component and circuit design. Any variation may impact how the guidelines and monitoring tools are employed. The boundaries for this system are from the point where the feedwater piping enters the economizer inlet header to the steam drum inlet penetration.

Economizer Systems

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A conventional economizer system is comprised of:

Sample point at the outlet of the economizer Sample point at the inlet of the economizer Heat exchangers (flue gas/FW and air/FW are optional and not illustrated) Boiler water treatment chemical injection quills (optional and not illustrated).

Economizer outlet temperature should be monitored and below the saturation temperature per alarm setpoint. Refer to OEM recommendation.


A basic economizer system does not have any system controls, with the exception of economizer ESP rapid drain valve(s).


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From a chemical treatment perspective, the integrity of the economizer must be sustained over time without benefit of routine inspection of the various circuits and headers. Corrosion or deposition within circuitry may result in premature component failure and/or affect the components and circuits located downstream of the economizer. If the location of the failure is above a baffle, water may enter the furnace, resulting in a critical exposure. Therefore, the prescribed guidelines and monitoring tools utilized to assess tube surface conditions and metallurgical integrity should be routinely reviewed and updated as required.


American Society of Mechanical Engineers (ASME) guidelines should be consulted for a full discussion of chemical control variables, including dissolved oxygen, pH, conductivity, iron, copper, and hardness (ASME guidelines are contained in the Appendix section). Mills should maintain emergency standard operating procedures (ESOPs) for reacting to out-of-bound FW parameters. At a minimum, these procedures should address oxygen, iron, pH, hardness, and conductivity.

Economizer Systems

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When contamination is suspected, operators should validate their test results and, once validated, follow the ESOPs that are in place to troubleshoot the problem. Ensure that the sample conditioning station is not the source of the apparent contamination.


Guideline #1: ESOP - Dissolved Oxygen Contamination - ESOPs shall be in place to address oxygen contamination of FW. Excessive levels of oxygen will result in localized corrosion within the economizer.

Guideline #2: ESOP - pH - ESOPs shall be in place to address both high and low FW pH conditions. The ESOPs should include test validation and verification guidelines for either condition (pH meter validation, etc.). It is recommended that an ESOP specifies at what feedwater pH level fuel should be removed from the boiler. Refer to TAPPI TIP #0416-05 (response to contamination of high purity FW).

Guideline #3: Conductivity - ESOPs shall be in place that address high FW conductivity. The potential sources of elevated conductivity in the economizer may include one or more of the following:

Condensate - Surface condenser - Evaporator - Pulp mill - Paper machine - Stock prep - Liquor heaters.

Ion Exchange Systems - Regeneration practices - Bed exhaustion - Ingress.

Deaerator Steam Contamination Condensate Polishers

Alarm and/or dump protocols should be established and reviewed on an annual basis.

Economizer Systems

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Guideline #4: SOP - Iron Levels & Testing - Oxygen, process contaminants, and certain process chemical treatments can contribute to high iron levels in the FW. Low pH can also contribute to high iron levels. The measurement of iron in the FW on either side of the economizer is a useful surveillance methodology that will help determine if iron is being generated, accumulating, or transported through the economizer. To determine iron transport, a post-economizer sample point is required. There are a variety of tests that measure iron in its different oxidation states. These tests can include colorimetric, spectrophotometric, and filtration and can be run on samples taken across the economizer. The objective of the testing is to identify particulate iron and/or iron corrosion by-products that may contaminate the feedwater supply. The economizer itself can be a source of, or repository for, iron contamination. For more information on iron sampling and testing, contact/refer to one or more of the following:

Your water treatment chemicals supplier Equipment manufacturing specifications (OEM) TAPPI TIP #0416-05 (response to contamination of high purity FW).

SOPs shall be in place that address ASME guidelines for iron levels in the boiler feedwater. Refer to the ASME guidelines contained in the Appendix section.

Guideline #5: Copper Levels - Identify the alloys utilized in the recovery boiler water support system heat exchangers to determine if there are any potential sources of copper. Some of the more common sources of copper are:

Copper alloy heat exchangers Copper alloy steam coil air heaters Copper alloy sweetwater condensers Heating systems (may be seasonal and intermittent).

Ammonia and certain amines can exacerbate copper corrosion. If copper corrosion and ingress are suspected, samples extracted from the pertinent streams should be sent out to a lab for high purity analysis. Due to the low levels of copper typically encountered and field test limitations in the measurement of any increase in those levels of copper, field testing for copper is not practical. An action plan should be developed; predicated upon lab findings. Consult with water treatment experts to determine the best ways to deal with copper issues. Refer to the ASME guidelines contained in the Appendix section.

Economizer Systems

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Guideline #6: ESOP - Hardness Levels - ESOPs shall be in place that address hardness levels above ASME guidelines for boiler FW. Possible hardness sources will be upstream of the economizer, but the inverse solubility of calcium results in the economizer being one of the first places that it will deposit. Refer to the ASME guidelines contained in the Appendix section. Consult with water treatment experts to determine the best ways to deal with hardness issues.

Guideline #7: Chemical Feed - When feedwater is chosen as a feed point location, a stainless steel chemical injection quill is recommended to ensure that the chemicals are well mixed and properly diluted before contacting any of the boiler water circuitry. Chemical feed point locations, use of injection quills, and methods of chemical delivery should, from a chemical compatibility perspective, be reviewed in detail when selecting a point of chemical addition. Feed of any internal boiler water treatment chemicals (i.e., phosphates, dispersants, etc.) ahead of an economizer is not an advisable practice and the need to do so should be scrutinized. If boiler water treatment chemicals are added upstream of the economizer, the compatibility of these chemicals must be reviewed to determine what potential effects they may have on the economizer. As stated earlier, a sample point downstream of the economizer is recommended. Appropriate sample flows must be maintained to ensure that the sample is representative of the water in the process. Sample temperature and time lag must be taken into account when designing these sample points. High pressure sample coolers are required on post-economizer sampling systems. Chemical injection quills should be of proper design and materials of construction. Refer to TAPPI TIPs #0416-03 and #0416-14.

Guideline #8: SOP - Water Testing - A properly designed and constructed high pressure sample cooling system shall be in place to accommodate testing of water across the economizer. Utilization of pre- and post-economizer sample points will provide an indication of whether iron is being removed or deposited in the economizer. An SOP shall be in place to monitor iron in and out of the economizer.

Guideline #9: SOP - Sample Line Purging - At a minimum, sampling protocols shall be in place that specify flow rates and, if the flow is intermittent, line purge requirements. If a sample line experiences some restriction in flow (over time), an SOP shall be in place to address line purge and re-stabilization practices. Refer to TAPPI TIPs #0416-03 and #0416-14.

Guideline #10: Economizer Tube Sampling - An economizer tube sample should be taken and inspected at regular intervals. The frequency of sampling and inspection depends on company policy, water consultant guidelines, and as history of economizer tube samples analysis dictates. The composition of the tubes must be analyzed for the presence of contaminants other than iron. The tubes must also be inspected for pitting.

Economizer Systems

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From a maintenance perspective, the integrity of the economizer must be sustained over time without benefit of routine inspection of the various circuits and headers. Corrosion or deposition within circuitry may result in premature component failure and/or affect the components and circuits located downstream of the economizer. If the location of the failure is above a baffle, water may enter the furnace, resulting in a critical exposure. Therefore, the prescribed guidelines and monitoring tools utilized to assess tube surface conditions and metallurgical integrity should be routinely reviewed and updated as required.


It is best practice to periodically remove the handhole caps in the economizer headers and conduct boroscope inspection, nondestructive testing, and/or periodic tube sampling of the economizer. In both cases the purpose is to monitor for any evidence of deposits or O2 pitting. Consideration should also be given for periodic iron studies across the economizer. Facilities should consult their water treatment experts to determine need, frequency, and methodology.


The need to inspect the economizer and the frequency of inspection are driven by a number of factors: economizer operating history and feedwater quality being two key factors. It is recommended that a timeline that best fits your operating circumstances be established.


Guideline #1: Inspection - Facilities should establish written protocols that determine the scope and frequency of economizer inspections and tube sampling.

Guideline #2: Inspection - If there is scheduled economizer repair work, it is best practice to inspect, via camera, the exposed circuit.

Guideline #3: Root Cause Analysis - If there is a tube failure, root cause analysis should be conducted.

Documents

Boiler Water Management Guidelines For Black Liquor ...blrbac.org/sites/default/files/Boiler Water Management Guidelines... · Recovery Boiler Water Management Guidelines ... Deaerator