generation best practice guidelines v2 05dec10 aes

A E S G E NE RA TI NG PL A NT

- Best Practice Guidelines -

AES Asset Management Framework Global Engineering Group

Document Status Version 2.0 Document Identifier AMF-AGPOG-0001

Revision Date 05 December 2010

Distribution Internal Use Only – Confidential and Proprietary Document of the AES Corporation

A E S G E N E R A T I N G P L A N T B E S T P R A C T I C E G U I D E L I N E S

Proprietary & Confidential 2

Table of Contents

DOCUMENT CHANGE CONTROL LOG ........................................................................................................ 4

1.0 INTRODUCTION ............................................................................................................................................ 5

2.0 OPERATIONS ................................................................................................................................................. 6

2.1 Control Room Conduct ...................................................................................................................................... 6 2.2 Metrics and Unit Expectations ........................................................................................................................... 7 2.3 Standard Operating Procedures .......................................................................................................................... 8 2.4 Temporary Operating Procedures (TOPs) ......................................................................................................... 9 2.5 Emergency Operating Procedures – Place holder ............................................................................................ 10 2.6 Equipment Inspection Guidelines (EIGs) ........................................................................................................ 11 2.7 DCS Alarm Management ................................................................................................................................. 12 2.8 Three-way Communication Process ................................................................................................................ 14 2.9 Operator Training and Qualifications .............................................................................................................. 15 2.10 Shift Reports, Logs and Operator Rounds ..................................................................................................... 16 2.11 Water Chemistry ............................................................................................................................................ 18 2.12 Solid Fuel Handling ....................................................................................................................................... 19 2.13 Heat Rate Program ......................................................................................................................................... 20 2.14 Protective Device Testing .............................................................................................................................. 21 2.15 Lubrication and Oil Condition Monitoring .................................................................................................... 22 2.16 Auxiliary Equipment – Vibration Monitoring ............................................................................................... 23 2.17 Operation of Transformers ............................................................................................................................. 24

3.0 MAINTENANCE ........................................................................................................................................... 27

3.1 Key Elements of Maintenance ......................................................................................................................... 27 3.2 Predictive Maintenance .................................................................................................................................... 29 3.3 Preventive Maintenance ................................................................................................................................... 30 3.4 Computerized Maintenance Management System ........................................................................................... 31 3.5 Backlog Management ...................................................................................................................................... 33 3.6 Key Performance Indicators & Scorekeeping .................................................................................................. 34 3.7 Event Reporting & Root Cause Analysis ......................................................................................................... 35 3.8 Management of Change ................................................................................................................................... 36 3.9 Boiler Mapping ................................................................................................................................................ 38 3.10 Management of Weld Quality ........................................................................................................................ 39 3.11 Welding Requirements for Repair and Maintenance Contracts ..................................................................... 40 3.12 Non-Destructive Testing – CMV Weld Inspections ...................................................................................... 42 3.13 Care and Replacement of Threaded Fasteners ............................................................................................... 43 3.14 Injection Leak Sealing ................................................................................................................................... 45 3.15 Care & Maintenance of Induced Daft Fans ................................................................................................... 46 3.16 Care & Maintenance of Electric Motors ........................................................................................................ 47 3.17 Maintenance of Station Batteries ................................................................................................................... 49 3.18 Handling Electrostatically Sensitive Devices ................................................................................................ 52



3.19 Portable Electric Measuring Equipment ........................................................................................................ 53 3.20 Performing Electrical Testing on Live Apparatus ......................................................................................... 54 3.21 Insulated Hand Tools for Live Work (to 650V) ............................................................................................ 55 3.22 Asbestos-based Components in Air Break Switchgear .................................................................................. 56

4.0 LOSS PREVENTION BEST PRACTICES ................................................................................................ 57

4.1 Boilers and Heat Recovery Steam Generators ................................................................................................. 57 4.2 Steam Turbines ................................................................................................................................................ 58 4.3 Gas Turbines .................................................................................................................................................... 60 4.4 Hydro Turbines ................................................................................................................................................ 62 4.5 Wind Turbines – Suspended and under review ............................................................................................... 64 4.6 Internal Combustion Engines ........................................................................................................................... 65 4.7 Generators ........................................................................................................................................................ 67 4.8 High Energy Steam Piping ............................................................................................................................... 69 4.9 Pressure Vessels ............................................................................................................................................... 70 4.10 Boiler Feed Pumps ......................................................................................................................................... 71 4.11 Safety Valves ................................................................................................................................................. 72 4.12 Transformers .................................................................................................................................................. 74 4.13 Miscellaneous Electrical Equipment .............................................................................................................. 77 4.14 Fire Protection ................................................................................................................................................ 79



Document Change Control Log Effective Date Version NO. Nature of Revision

August 15, 2010 1 Initial Draft.

Oct 13, 2010 1.1 Released to: Regional Performance Directors, Corporate Legal, AGIC and other subject matter experts for review, corrections and comments.

Dec 05, 2010 2.0 Includes changes by Corporate Legal – Words such as: requirements, standards, must, shall, replaced with: expectations, will, need.

Wind Turbines – Suspended and under review

Additional text added to the section on ‘Station Batteries’

Added Section 4.14 – Fire Protection

Added place holder for a section on Emergency Operating Procedures

Section updates include: DCS Alarm Management; Shift Reports, Logs and Operator Rounds; Management of Change; Maintenance - Key elements, Predictive, Preventive; Pressure Vessels; Gas Turbines; Protective Device Testing.

Updated section numbering



1.0 INTRODUCTION

What is an AES “Best” Practice?

“AES has always been about diversity and the unencumbered pursuit of business excellence. Our generating plants operate in many different business environments. How can one set of practices be considered “best” given so many different and unique situations?”

he determination of what is “best” is, of course, a subjective evaluation and will vary with the situation. At AES, the local management of each generating facility will always bear ultimate responsibility for the selection and implementation of practices, that best suit the unique business environment, for any given plant. To assist plant management with this responsibility, this manual presents a collection of Operations and Maintenance (O&M) practices that have been evaluated as

industry best practice for generating facilities. The practices have been recognized as having significant positive impact on the safe, economical and reliable operating performance of generating plants. The Operation and Maintenance (O&M) practices have therefore been defined as guidelines to be applied to the extent reasonably possible at each AES generation businesses.

The O&M Guidelines in this manual have been divided into three sections:

• Operations - focus on the conduct of operations and some of the key management processes and techniques used to operate AES generating facilities.

• Maintenance - address some of the key elements and processes used by high performing maintenance organizations in support of operations.

• Loss Prevention Standards - focus primarily on physical assets such as facilities, systems and equipment and provide specific actions that will lower the risk of major failures or property damage.

Each guideline in this manual is also divided into three sections. The first section, Objective, provides insight into “Why” a guideline is defined for the topic. The second section, Minimum Expectations, describe “What” is expected from generating businesses in a concise bulleted list format. The last section of each guideline is a hyperlink to additional information in a folder on Docushare. The information in the folder has been assembled to assist businesses with further information on “How” the practice might be implemented or has been applied at other businesses.

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2.0 OPERATIONS

2.1 Control Room Conduct

OBJECTIVE

To maintain a professional work environment in control rooms that is conducive to safe, economic and reliable operation of generating units.

MINIMUM EXPECTATIONS • Control rooms are well lighted, clean, and have background sound levels below OSHA limits required for

continuous occupation.

• Access to control rooms is controlled and limited to authorized personnel and all control room activities are conducted in a professional business manner.

• Activities affecting the status of plant systems and equipment are authorized by appropriate operating personnel on each shift

• Instrumentation and controls in the control room are maintained in good working order

• Hard hats, safety glasses, flashlights, loose tools or other possessions are removed or secured before approaching switches, panels, computers or keyboards

• Well-maintained logs and operating procedures are readily available to operating personnel

• Communication equipment, both internal and external, is easily accessible and maintained in working order.

• Policies addressing non-work related reading material, background music, meal locations, personal use of computers and other potential distractions are established by local leadership, communicated and followed.

• Piping and Instrumentation Drawings (P&IDs), logic diagrams, and other control system configuration documents are kept updated and available to operators and other personnel who need them. Access to original documents is controlled.

• Emergency and safe shutdown policies and procedures are readily available

REFERENCE DOCUMENTATION AND EXAMPLES: Hyperlink to Reference Material When Available



2.2 Metrics and Unit Expectations OBJECTIVE To provide focus on, and measurement of, operating performance. A set of leading and lagging operational indicators that are adopted, owned and under the control of the Operations teams helps to guide and drive continuous performance improvement. These indicators should be directly linked to plant, and ultimately AES Corporate key performance indicators (KPIs).

The KPIs help align performance improvements in people, processes and systems with the business’ targets and objectives.

MINIMUM EXPECTATIONS

Each Operations team will develop performance metrics for their area that consider impacts to Availability, Efficiency, Cost, Effectiveness, Quality, Utilization or Safety as applicable to the team. Typical Operating teams include:

• Control Room

• Power Block

• Water Treatment

• Material Handling

• Environmental (FGD, SCR, ESP, etc…)




2.3 Standard Operating Procedures OBJECTIVE

To provide consistency in unit operating practices and to provide a platform for improving procedures and incorporating best practices. Operation procedures and documents will be clear and technically accurate, provide appropriate direction, and be used to support the safe, economical and reliable operation of the facility.

MINIMUM EXPECTATIONS • Procedures are defined, implemented and followed for critical operational activities including, but not limited

to:

o Unit start-ups/ shut-downs - including turbines, boilers, & HRSGs [address cold, warm and hot start scenarios as appropriate] Include black-start procedures, if unit is designed for black start.

o Major System start-ups and shut-downs [e.g. FGD, cooling water system, control air system, water treatment system, fuel system, etc.]

o Emergency shutdown procedures for Operator actions during fire or explosion

o Any operation that requires documentation (environmental, legal, insurance, etc)

o Procedures for the Lock-out/Tag-out process

o Procedures for monitoring and maintaining housekeeping

• Operational activities are monitored to ensure compliance with procedures and good operating practices. Where issues are identified, there is a process in place to ensure the issue is corrected.

• Procedures are current to the actual methods being employed to accomplish the tasks and are comprehensive enough to ensure reliable generation.

• Operating personnel have easy access to procedures and maintain awareness of recent procedure changes and plant modifications affecting procedures.




2.4 Temporary Operating Procedures (TOPs)

OBJECTIVE

To identify, document and communicate operating procedures that are temporary in nature due to unusual conditions of plant, systems or equipment. Examples might include special procedures needed due to the temporary loss of redundant equipment, capacity constraints on equipment awaiting repair, equipment out-of-service for temporary periods, etc.

MINIMUM EXPECTATIONS • Whenever standard operating procedures or methods will be changed to accommodate temporary

equipment conditions, the change in procedures is documented and communicated to other operating personnel responsible for operating the equipment. The requirements contained in the facility’s Management of Change process should be followed when making these changes.

• The standard method for communicating Temporary Operating Procedures is understood by operating personnel and consistently followed.

• TOPs are maintained current, readily available for review and kept separate from daily operating notes or logs. (Exceptions are allowed if electronic logs are used and the logs carry forward special operating instructions automatically until they are manually removed).

• Temporary posting of notices or operating instructions on or near equipment does not, on its own, constitute compliance with this standard.

• When the condition or constraint causing the unusual operation has been cleared the return to normal operations is communicated.

• Fire Protection Impairment Procedures are developed and utilized.

REFERENCE DOCUMENTATION AND EXAMPLES:

Hyperlink to Reference Material When Available



2.5 Emergency Operating Procedures – Place holder

OBJECTIVE

MINIMUM EXPECTATIONS REFERENCE DOCUMENTATION AND EXAMPLES:




2.6 Equipment Inspection Guidelines (EIGs) OBJECTIVE

To provide for the periodic inspection of plant equipment according to OEM recommended minimum frequencies by operating personnel. This standard recognizes the importance of qualified operators routinely performing physical inspections as a necessary supplement to control system monitoring of plant equipment.

These guidelines also seek to promote consistency and adequate thoroughness in these inspections. Routine inspections carried out by plant personnel help to ensure all critical parameters and plant areas are being appropriately monitored, equipment is operating normally and routine maintenance is being properly carried out.

MINIMUM EXPECTATIONS • EIGs exist for each major area of the plant and all major pieces of equipment or systems within a job area

requiring periodic monitoring are listed on an EIG

• A logical inspection route(s) is developed as guidance for walkdowns. The inspection frequency and criteria is based on equipment type and criticality

• The EIG describes minimum expectations for physical inspection of equipment and fire protection systems in the area including the frequency of inspection, the major pieces of equipment to be inspected and the inspection method.

• Where beneficial, normal operating conditions are listed on the EIG for comparison with actual conditions. Significant deviations from normal are addressed appropriately (e.g. by correcting the problem, reporting to the control room operator, generating a work request, or taking other appropriate action.)

• Checksheets are completed during rounds to document observations and any critical readings.

• Performance data for key equipment and systems important to reliability and efficiency is monitored, collected, trended and analyzed.

• Instrumentation used for monitoring is routinely calibrated and has adequate sensitivity and accuracy to provide reliable results.





2.7 DCS Alarm Management OBJECTIVE To maintain functionality of operator warning alarms and to provide guidance on the proper response to critical alarms or alarms that can lead to high impact incidents.

MINIMUM EXPECTATIONS • Alterations of the control logic and/or alarms require risk analysis and approval from the person responsible

for the plant. Management of Change procedures are followed prior to implementation.

• For plants with Digital Control Systems (DCS), plant staff includes qualified and competent controls personnel.

• Corrective actions in response to alarms are taken based on the significance and impact of the problem on safety, environment and operations.

• Equipment is not normally allowed to continuously run in alarm condition. Exceptions will be authorized and documented.

• Defective instruments, alarms and controls get identified and corrective measures are taken promptly.

• False alarms and unnecessary alarming frequency are minimized through the use of dead bands, delays and smart alarm groupings.

• Maintenance notifications by the DCS should be directed straight to the CMMS via rules or to a separate maintenance notification system.

• Regularly use alarm summaries to review and report nuisance alarms to control systems personnel.

• Single-page Alarm Response Procedures that provide bullet summaries of the following topics are available to assist with proper response to critical alarms:

o Alarm Title, Initiating Device, and Set-point

o Possible Causes of the Alarm

o Possible Consequences of the Alarm

o Immediate Operator Responses

o Follow-up Operator Responses

• Alarm Response Procedures include proper step sequencing to ensure optimum effectiveness. In addition to minimizing and/or mitigating damage from unusual events, the development and periodic review of Alarm Response Procedures is a proactive method to train and prepare operating personnel to deal with potentially catastrophic events.



• Alarm Response Procedures will be controlled documents, readily available and periodically reviewed.

• Procedure to response to various emergencies, fire alarms, or verbal reports of emergencies.

• Alarms, set-points and priorities are reviewed at least every three years.




2.8 Three-way Communication Process OBJECTIVE

To improve safety and reduce operating errors caused by miscommunication of instructions among operating personnel. This standard applies when using radio, phone, personnel address systems and other similar communication technologies used to transmit verbal operating instructions.

MINIMUM EXPECTATIONS • Whenever instructions are provided to operate field equipment remotely (e.g. open valves, start motors, etc)

a three-way communication process is used to communicate the name of the equipment/system and actions to be taken. The three steps in the process are:

o Step 1 – Instructions stated by the operator including name of equipment and action to be taken.

o Step 2 – Instructions repeated by the person performing the operation

o Step 3 – Acknowledgement as correct by the operator who provided instructions

• Whenever alphabetic characters are used in the labeling of equipment and provided as part of the instruction, and character names sound similar, a phonetic alphabet appropriate for the language, region or country is used. (e.g. for English, “B” = Bravo, “D” = Delta, etc).

• Numeric values are stated one digit at a time. For example: Circuit 380 is stated as Circuit three-eight-zero.

• Time is stated using a 24-hour clock. For example: 4:00 PM is expressed as 1600 hours.




2.9 Operator Training and Qualifications OBJECTIVE

To help ensure operating personnel have an understanding of the expectations associated with their roles, have the skills and knowledge necessary to perform their roles, and have access to resources to help assess and continuously improve their skills and knowledge.

MINIMUM EXPECTATIONS • The expectations for craft knowledge and skills are defined and documented for each operating position

within the plant. In general, these expectations will be defined around:

o Technical subjects and applied science

o Energy plant basics

o Plant systems & components

o Operation and resetting of fire protection systems

o Plant operating procedures & practices

o Plant emergencies and emergency response

• Each operator is assessed by his/her leadership for knowledge and skills against expected levels. Assessments are conducted at least every three years.

• Developmental plans exist to cover any shortcomings in current positions

• People accept responsibility for their own development.

• Leadership provides training materials and resources, including refresher training, to facilitate improvement and maintenance of operator skills and knowledge.





2.10 Shift Reports, Logs and Operator Rounds OBJECTIVE

To provide records of key events and operator observations occurring on shift. Operating logs are essential for facilitating good communications between operators and also maintenance personnel. They provide vital information to supplement data recorded by control and monitoring systems within the plant.

MINIMUM EXPECTATIONS • Shift reports, logs and operator rounds are electronically recorded.

• Each major operating area within the plant needs to maintain an operating log

• Log entries are divided by shifts and the person responsible for making an entry is clearly identified.

• Entries are clear and concise and have adequate detail to facilitate shift change and to allow operators returning from long absences to understand the history and current state of unit(s).

• A summary of unit/area status is the first entry in the log. Additional entries include:

o Major equipment/system start & stop times

o Significant milestones related to unit startup or shutdown, such as:

§ Fans On/Off

§ Pumps On/Off

§ Turning Gear On/Off

§ Fire in Boiler In/Out

§ Turbine Rolling

§ Turbine On/Off Turning Gear

§ Turbine at Sync Speed

§ Generator on/off line

§ Boiler at Rated Pressure

§ Fire protection impairments or system outages

o Any de-ratings/curtailments with description of the problem, magnitude and time of the event

o Unit and major equipment malfunctions with description of the problem. Examples might include loss of a feeder, pump trips/failures, precipitator problems, etc.

o Detailed information concerning outside government or regulatory agencies that contact the control room or supervisor.



o Communications with dispatch or customers including complaints or switching requests

o Equipment testing performed on shift such as turbine valve testing, DC oil pump tests, emergency generator starts, etc.

• Operator rounds use electronic handheld devices to record information, including collecting offline data used for equipment condition monitoring.

• Records of operating reports and logs are kept for durations in compliance with AES Record Retention Guidelines, contractual obligations, or as dictated by regulatory requirements.




2.11 Water Chemistry OBJECTIVE

To increase unit reliability by establishing minimum standards for boiler chemistry monitoring. Water chemistry is closely linked to reliability and maintenance costs. Consequently, a disciplined approach to water chemistry, including plant-specific measures and practices, is needed.

MINIMUM EXPECTATIONS • Each generating station equipped with a boiler will have a chemistry monitoring program. The program, at a

minimum, will include:

o Monitoring of control equipment – softeners, demineralizer, chemical pumps & controls, injection points. Key monitoring points should be included in the Equipment Inspection Guideline (EIG) for the area.

o Monitoring, trending and reporting of key parameters including the clear specification of limits and action levels

• Procedures for water chemistry are documented, including:

o Unit start-up and shut-down, including system lay-up

o Sample collection, preparation, analysis and reporting procedures

• Training and qualification programs exist for water chemistry that include:

o Annual training conducted by vendors

o Management expectations and standards

o Theory training

o Practical job factors

o Qualifications




2.12 Solid Fuel Handling OBJECTIVE To improve plant economics and reliability of generating plants by proper management of Solid Fuels MINIMUM EXPECTATIONS • AES Sourcing is consulted on all contracts for the purchase and transport of fuel

• Total cost of fuel transportation is actively managed considering production needs, handling costs and overtime, demurrage, transportation expenses, etc.

• Fuel storage procedures exist to provide guidance on the proper shape and management of coal storage piles to reduce conditions favorable to spontaneous combustion and to minimize run-off of rainwater.

• Coal pile run-off is routed to settling pond(s) and settled coal periodically is removed and placed back on the storage pile for use.

• Dust control procedures, such as the periodic wetting of roads in coal yards, are used to minimize fugitive dust.

• Weighing and sampling procedures are implemented to ensure the quality and quantity of fuel meets contractual agreements.

• Coal conveyors, chutes, hoppers and other handling equipment are maintained in good working condition. Protective devices such as conveyor trip wires and fire detection systems are kept operational and tested periodically.

• Skirts and other spill control equipment are adjusted periodically to maintain cleanliness. Spilled coal is washed down daily.

• Coal sizing requirements/limits for proper combustion is defined by operating personnel. Sizing of coal delivered to unit bunkers is monitored and adjusted as necessary by coal handling personnel.

• To help prevent stagnant pockets of coal that could spontaneously ignite, storage bunkers are emptied prior to major outages or extended shutdowns.

• Management of Change procedures are followed for changes in types of coal burned.





2.13 Heat Rate Program OBJECTIVE To ensure optimum efficiency, reduce fuel cost and reduce the environmental impacts of combustion. Fuel costs are generally one of the largest cost factors at AES facilities. A disciplined heat rate program monitors component efficiency and identifies deviations from best achievable heat rate. MINIMUM EXPECTATIONS • Heat rate performance is monitored at the unit and major component level (e.g. boiler/HRSG, turbine,

condenser, feedwater heaters, cooling tower, etc.).

• Reports identify component losses and trends. Plants use this report to prioritize opportunities to improve the Heat Rate. Heat rate deviation should be calculated in both engineering units (e.g. BTU/kWh, kJ/kg, etc.) and commercial impact (e.g. $, £, €, etc.).

• A Heat Rate Awareness program provides periodic training on topics such as theory, controllable losses and corrective actions, plant-specific monitoring, and the commercial impact of heat rate. This training is included as part of the qualification program for appropriate staff.

• Periodic system walkdowns ( ‘Cycle Isolations’) are conducted to identify sources of efficiency loss – e.g. leaking valves, faulty steam traps, poor insulation, etc.

• Formal heat rate tests are conducted before and after major outages.

• Steam path audits are conducted during steam turbine overhaul.

• A formal calibration program is implemented for source instrumentation for heat rate measurement.




2.14 Protective Device Testing OBJECTIVE To demonstrate proper functionality of protective systems and equipment at each generating facility. Protective devices are often the last line of defense against catastrophic failures and exist for the protection of both people and equipment. MINIMUM EXPECTATIONS • A list is maintained of critical protective equipment and systems that require testing on a regular basis. At a

minimum, this list will include, as applicable:

o Fire protection systems, e.g., water based, foam based and gaseous based systems including alarm detection and systems operations in accordance with corresponding NFPA codes.

o Spillways, sluice gates, and other emergency gates and valves at hydro stations

o Turbine valves and extraction non-return valves

o DC back-up equipment such as DC turbine oil pumps and DC seal oil pumps

o Diesel generators and other black start equipment

o Turbine overspeed trips

o Turbine Water Induction Protection (TWIP) system

o Uninterruptible Power Supply (UPS)

o Emergency lighting

• Testing procedures are in place prior to testing. Procedures specify documentation requirements where appropriate.

• Testing is only performed by qualified personnel.

• Functional testing of protective devices is performed following major overhauls, repairs and/or replacement of protective systems and equipment.





2.15 Lubrication and Oil Condition Monitoring OBJECTIVE To provide guidance for the management and practices of oil condition monitoring and establish procedures to detect oil degradation and abnormal operation of machines MINIMUM EXPECTATIONS • Sample should be taken from a free flowing line or well mixed tank. Samples from a tank should be drawn

from the middle to the bottom. • System should be in steady state operation or should be sampled within 30 minutes of shutdown. • Samples should be taken before filters • Sample containers should be clean (if possible the bottle should be flushed with the oil) and should be

resistant to the oil sample. • Samples for analysis by external laboratories should be labeled with customer and site name, unit and

equipment ID, date of sample, oil type (if known) and details of oil addition. • New oil should be tested to establish a “baseline” sample of the oil. • Data should be kept for a minimum of 26 samples or 5 years, whichever is longer. • Analysis of in service oil should be carried out on intervals specified in the following table:

Application Parameter Pumps/

Compressors Gearbox Engine

Oils Critical Hydraulic

Other Hydraulic

Con

trol

Par

amet

ers

Appearance 6 monthly 6 monthly 6 monthly 3 monthly 6 monthly Moisture 6 monthly 6 monthly 6 monthly 3 monthly 6 monthly Viscosity 6 monthly 6 monthly 6 monthly 3 monthly 6 monthly Total Acidity Number (TAN)

6 monthly 6 monthly 3 monthly 6 monthly

Total Base Number (TBN)

6 monthly

Flashpoint New Oil Only New Oil Only

New Oil Only

Oxidation Stability Annually Annually Annually 3 monthly Annually Demulsification Number (sec)

Annually Annually Annually 3 monthly Annually

Fuel Oil Contamination & Particulates

6 monthly




2.16 Auxiliary Equipment – Vibration Monitoring OBJECTIVE To establish guidelines for performing periodic vibration monitoring on the equipment selected by a plant’s maintenance strategy. MINIMUM EXPECTATIONS • For equipment included in the scope of periodic vibration monitoring, there should be two alarm

levels of vibration established that define abnormal operation.

o Warning alarm level should designate a level at which investigation should be started. o Critical alarm level should designate a level at which action should be taken.

• Data should be collected on an interval determined by the ability to predict failure modes. For

example, if the time between detecting high vibration and failure of a bearing is typically 6 weeks then the frequency of vibration should be no greater than 6 weeks – preferably shorter. When these failure times are difficult to predict, the following general guidelines should apply

o Data should be collected monthly on most machines. o For critical machines, data should be collected weekly or monitored continuously.

• Data should be kept for a minimum of 26 samples or 3 years, whichever is longer. • When a machine undergoes maintenance and is returned to service, the next reading should be put in

the vibration database as the baseline reading, except when a machine with rolling element bearings is maintained and the rolling element bearings are not touched; in that case, the original readings should be kept as the baseline.




2.17 Operation of Transformers OBJECTIVE To provide guidance on the operation of transformers within the voltage range of 3.3kV and 400kV. MINIMUM EXPECTATIONS AES has developed an Engineering Standard for the Life-cycle Management of Power Transformers (see reference below). This document should be reviewed for more complete guidance on operation of critical transformers. As a partial summary of the requirements listed in this document: • Operating procedures should avoid conditions in which overfluxing of the generator step-up (GSU)

transformer can occur. The GSU will be overfluxed if:

o a higher than normal voltage is applied to either the HV or LV winding at nominal frequency when the generator is at speed and carrying load.

o the generator excitation is in service at nominal volts and the generator is spinning at less than operating speed.

o the generator is running at synchronous speed without load with terminal voltage higher than

normal– such as during testing. • Since automatic tripping of the generator circuit breaker normally trips the generator field switch, the sudden

disconnection of the load is not considered to be a serious cause of overfluxing. However, if Automatic Voltage regulation is in the manual position excitation will be immediately reduced.

• Overfluxing protection should not be in-service when the unit is synchronized and on load, as this

protection can initiate a reduction in generator excitation which could lead to instability. Overfluxing protection should only be operative when the HV circuit breaker is open.

• As a general rule during unit shutdown, the Automatic Voltage Regulator (AVR) and excitation system

should be switched out of service after the voltage has been adjusted to nominal following the opening of the HV circuit breaker, while the unit is between 95% and 100% rated speed. Operators should not rely on the overfluxing relay to trip excitation during rundown.

• If overspeed tests are performed with the rotor winding excited then precautions should be taken to ensure

that the rated nominal voltage is not exceeded. • On-load tap-changers (OLTC) should be routinely exercised to remove pyrolytic carbon growth on switch

contacts causing overheating due to high resistance. The OLTC should be operated over the entire range if possible. If the unit is on-line and carrying load, changes should be coordination with the grid operator.

• On-load tap-changer should only be operated from a remote control room when transformer is energized.



• Overloading of any transformer above nominal capacity is generally not advisable. However, if overloading

is required, the level of overload should not exceed the design limits of the transformer and all operational and safety precautions will be taken into consideration. Operational and Maintenance leadership should have the knowledge of operation of the transformer outside of nominal ratings.

• Critical transformers should be visually inspected daily by operators. All record sheets should be maintained

for future reference. The following should be considered when preparing inspection procedures:

o Conservator: Oil level at sight glass and topping up if necessary o Paintwork: Signs of deterioration and corrosion o Leaks: Paying particular attention to: Joints/gaskets, bushing, main tank, tap-changer

cable boxes, thermometer pockets and passing relief valves o Drainage: bases of transformer ensuring that there are no blockage o Temperature: Windings and oil and record the load o Desiccant/Breather/refrigerant: Inspect for any abnormality

• Thermographic surveys should be conducted every six (6) months for essential and every three (3) months

for critical transformers. Areas covered during these surveys should include:

o Cooling system to check for hotspots i.e. blockage in cooling system o Air bushing connections o IPB bus-ducts o Transformer tank, especially gasket areas on LV side of the transformer.

All results will be maintained electronically and historical trend will be reviewed by well qualified persons. For any question or clarification consult Electrical Knowledge Community.

• The following maintenance and testing activities should be implemented when the transformer is in service:

o Insulating oil should be routinely sampled and tested to monitor the condition of oil o Visual inspections should be carried out at least every month on generator, unit and station

transformers and at least every 3 months on other transformers • When the transformer is off-line, routine maintenance should be carried out depending on the planned

outage frequency, available outages, OEM recommendations and plant history. • For generator, unit and station transformers, the interval between checks on protection devices should not

exceed four years. • Locations should keep adequate records of their transformers including:

o A register of assets o Network diagrams o Maintenance records o Modification details o Manufacturers factory test certificate



• Maintenance records should include:

o The date maintenance was carried out o Details of maintenance performed o Condition of the environment that the transformer is situated in o Results of maintenance o Oil replacement and condition after replacement o Due date of next maintenance




3.0 MAINTENANCE

3.1 Key Elements of Maintenance OBJECTIVE To ensure that the overall approach for plant maintenance is based on reliability principles including: equipment criticality, failure modes, effects and the condition of assets. This approach establishes the proper balance of predictive, preventive and corrective maintenance activities. Good maintenance programs strive to perform the correct maintenance type at the most opportune time. Reliability Centered Maintenance (RCM) is the recommended approach to selecting the appropriate maintenance tasks to be performed on critical assets. MINIMUM EXPECTATIONS The following key elements exist as a part of each facility’s maintenance program. • Maintenance Strategy - A mix of preventive/predictive maintenance (PM) and corrective maintenance

(CM) practices is used based on the criticality of equipment and components to achieve business objectives.

• Criticality determination is based on various combinations of failure modes and effects. Typical reasons for classifying equipment as critical are that the plant effects results in a unit trip or shutdown, significant (costly) damage, reduction in power output, personal hazard, or violation of some regulation (e.g. environmental).

• Condition Monitoring Data – The information collected via instrumentation either online or offline, including data from operator rounds is electronically trended and actioned according to predetermined rules.

• Work Management - A process exists to identify and select highest priority work in support of operations. Work is planned, scheduled, controlled, and supported with resources for safe, timely, and effective completion.

• Conduct of Maintenance - Plant maintenance people conduct their activities in a manner that achieves safe, reliable and economical operations consistent with good operating practices and the AES values.

• Maintenance Training – Structured to addresses people’s needs to achieve the plant’s business objectives, use of outside resources, growth opportunities, and expected turnover.

• Outage Management - A process exists for overall outage planning to optimize plant run time while ensuring the successful completion of the identified work scope in a safe, productive and cost effective manner.

• Capital Expense Planning – A planning program is in place that achieves the long term objectives of the business. The capital investments process is managed to ensure that capital investments are identified, analyzed, implemented and reviewed with a thorough understanding of opportunities and risks

• Performance Measures – Key Performance Indicators (KPIs) are identified and tracked to measure maintenance program effectiveness.



3.2 Predictive Maintenance OBJECTIVE To lower maintenance cost by replacing timed maintenance tasks with maintenance that is scheduled only when warranted by equipment condition. Predictive maintenance (PdM) uses primarily non-intrusive testing techniques, visual inspection, and performance data to assess machinery condition. PdM and other types of maintenance (Preventive and Corrective) have their own advantages and disadvantages, and each one of them should be selected depending on asset criticality, failure modes and the ability to monitor operational condition. MINIMUM EXPECTATIONS • Plants maintain a list of plant assets and have defined criticality for each asset.

• For critical assets, the needed functionality and potential failure modes are defined. Failure modes are analyzed and PdM tasks applied for those assets where predictive technologies are justified as a means to prevent failures. For a PdM task to be considered applicable and effective, the following considerations will be made:

o There will be a measurable parameter that can detect the deterioration in the asset condition.

o The period of time between detection of a problem and failure of equipment (P-F interval) will be fairly predictable and allow adequate time to take corrective action

o The PdM task will be carried out at an interval that reduces the probability of failure to an acceptable risk level.

o The cost of undertaking a PdM task over a period of time should be less than the total cost of the consequences of failure.

• An asset condition reporting process is in place to communicate issues identified by PdM tasks including the urgency.

• PdM tasks and resources are managed by the work management process.

• Test equipment used for predictive monitoring of equipment is included in the plant’s calibration program.

• Thermography and UT Programs…

• Qualification and training programs are in place to assure people using PdM technologies maintain competency in the use of equipment and analysis of data.





3.3 Preventive Maintenance OBJECTIVE To effectively reduce the frequency and seriousness of unplanned machine failures. Preventive Maintenance (PM) is the inspection, adjustment, cleaning, lubrication, parts replacement, calibration, and repair of components and equipment performed at pre-defined intervals (time, operating hours, or cycles). PM is also referred to as time-driven or interval-based maintenance and performed without regard to equipment condition. PM and other types of maintenance (Predictive and Corrective) have their own advantages and disadvantages, and each one of them should be selected depending on asset criticality, failure modes and the ability to monitor operational condition. MINIMUM EXPECTATIONS • Preventive Maintenance tasks are applied only if Predictive Maintenance methods are first considered and

deemed not feasible. In addition, PM tasks are only performed when they are economically justified (i.e., the cost of performing PMs should not exceed the cost of repairing or replacing equipment).

• To establish the Preventive Maintenance program, the businesses has:

o Selected the variables that will be used for scheduling preventive maintenance for assets included in the PM program (e.g. months, operating hours, equivalent operating hours, etc.) Normally, the Original Equipment Manufacturer (OEM) provides this information but this should be optimized based on actual equipment history or the application of RCM, RCA or other continuous improvement tools.

o Developed the task list that will be performed according to the defined intervals. The tasks may come from OEM or other information sources and may be improved with the utilization of any of the above tools.

o Determined the resources needed for each maintenance scope: spare parts, manpower, time, tools, special services, etc.

• The scheduling, task list and resources are maintained in a Computerized Maintenance Management System (CMMS) and are auto-generated.

• PM tasks are periodically reviewed for scope and timing changes based on changes in OEM operating and maintenance notices, operating requirements, equipment condition, age and other factors.




3.4 Computerized Maintenance Management System OBJECTIVE To help in the management, capture and tracking of work at various stages of the maintenance process. Computerized Maintenance Management Systems (CMMS) is used for scheduling, collection of data, reports preparation, cost analysis, and inventory control. MINIMUM EXPECTATIONS • The plant utilizes a Computerized Maintenance Management System (CMMS) for evaluating, planning and

processing maintenance activity.

• The CMMS has the following capabilities;

o A security system that restricts access based on user profiles.

o The ability to classify preventive and corrective maintenance.

o Includes or links to an inventory control system.

o Integrates with the procurement process

o Facilitates prioritizing and classifying work orders with the ability to capture key information about the work such as manpower required, work performed, resources used, etc.

o Stores useful equipment record data such as manufacturer, model number, equipment class and attributes.

o Contains pre-defined tables of failure catalogs to simplify use and reporting.

• The CMMS is used for;

o generating maintenance reports

o automatically generating predictive and preventive work orders

o screening and approving work requests based on criticality and alignment with the businesses work priority process.

o tracking requested work activities. The status of all work orders is maintained and readily accessible. Pending work activities are periodically reviewed for continued need.

o recording equipment and maintenance history, including modifications that occur per the Management of Change Procedure

o Tracking and trending of insurer loss control recommendations



• An administrator is assigned over the CMMS program to control system changes by following procedures identified for making modifications.

• The work management system is periodically audited to verify the work management process is followed, appropriate data is being captured, and the work backlog is managed.





3.5 Backlog Management OBJECTIVE To assure work with the highest priority gets performed, duplicate work orders are eliminated, and requested work is not lost. MINIMUM EXPECTATIONS

• People who initiate work requests will review pending requests in order to avoid duplicate work requests.

• Work Order backlog is monitored and trended in order to determine need for complete backlog review

• Periodic meetings are held with a multi-disciplinary team to review, coordinate and prioritize the backlog. Duplicates and work that will not be performed is removed.

• Work in the backlog that represents significant change is subjected to the plant’s “Management of Change” process.

• Operation personnel attend maintenance planning meetings and have input to work scheduling and priority.

• Part requirements for backlogged work is managed through strategic spares, inventory or procurement

• Required maintenance procedures, tools, labor or other resources needed to perform work is available before performing backlogged work.





3.6 Key Performance Indicators & Scorekeeping OBJECTIVE To align performance improvements in people, processes and systems with the business targets and objectives. A set of leading and lagging maintenance indicators are adopted, owned and under the control of the Maintenance teams to guide and drive continuous performance improvement, and are directly linked to plant and ultimately AES Corporate key performance indicators (KPIs). MINIMUM EXPECTATIONS Each Maintenance team has, at a minimum, performance metrics for each of the following categories: • Planning and Scheduling

• Proactive vs. Corrective Maintenance

• Maintenance Cost (including inventory)

• Safety

Teams may develop other metrics that provide leading or lagging indication of maintenance productivity or performance. REFERENCE DOCUMENTATION AND EXAMPLES:




3.7 Event Reporting & Root Cause Analysis OBJECTIVE To promote a systematic, formal analysis of failures or other triggering events through completing Event Reporting and Root Cause Analysis (RCA). These reviews ensure problems are identified and resolved and the lessons learned are shared with other AES plants in a timely manner. Event reporting/RCA is a critical component in achieving world-class performance in plant operating efficiency, reliability and safety. MINIMUM EXPECTATIONS • Each facility should define, in writing, the type and significance of events that “trigger” a RCA analysis or

event report. The triggering events may be one-time significant events or chronic, recurring, failures that have high impact. Examples include unit trips, equipment failures, repeat bearing or seal failures, safety and environmental incidents, etc.

• When trigger events occur, the plant should have a formal process established for investigating these events to determine root causes, financial impact and necessary corrective actions.

• Analyses should be lead by people trained in RCA or APEX facilitation.

• For complex RCAs, the recommended approach is to use the enterprise version of PROACT software for analysis.

• Key learnings from RCAs that are of potential value to other AES facilities should be shared.





3.8 Management of Change OBJECTIVE To ensure all significant process or design changes are properly evaluated, approved, implemented and documented. A disciplined program and process that defines the requirements for managing permanent and temporary process changes to equipment, technology, facilities, procedures, control logic, materials, etc. The Management of Change (MOC) process ensures that the health and safety, as well as the operational risks arising from the proposed changes, are managed correctly. MINIMUM EXPECTATIONS • A Management of Change process exists that clearly defines:

o Procedures that control all emergency, temporary, or permanent process modifications, operating conditions and/or design changes, which may significantly affect plant or business operations; this includes elements such as:

§ The intended change

§ The documented findings of the MOC review

§ Change approval

§ Close-out

o Requirements for the removal of plant protective systems and operating without protective systems functioning normally or bypassed.

o Safety/Protective/Lock out operating controls bypass if required for plant operation will have a HAZOP study and approved only by related managers and approved for only a determined amount of time if otherwise a permanent design change will be in order.

o If any Safety/Protective/Lock out control is bypassed operators will sign a log book (electronic or written) and tight safe operation controls will be in place and clearly written.

o Lock out logbook will be established and controlled to ensure open items are closed in due time.

o Assurances that all relevant stakeholders are notified of the change subject to any confidentiality agreements that may exist and any applicable approvals are obtained with regards to warranties and/or service agreements.

o A process for maintaining MOC records and documents.

o A MOC training program that adequately covers all relevant sections of the facilities MOC policy including examples of what would trigger an MOC.

o Submittal of fire protection changes or major facility changes to Property Insurer.



• Definitions of “permanent” and “temporary” changes exist, are known and are followed.

• A complete list of temporary MOC is maintained and reviewed at least monthly.

• Where applicable, the program meets the requirements of OSHA 29 CFR 1910.119 (I) Management of Change

• Training material related to any system, equipment or process that is changed is reviewed and modified to reflect the change.





3.9 Boiler Mapping OBJECTIVE To help optimize the integrity and availability of the steam generator and allow for near and long term maintenance planning. Boiler water wall tube failures are the most frequent cause of fossil-fired boiler unscheduled outages and are the largest cause of unavailability for the conventional fired boiler fleet. MINIMUM EXPECTATIONS Facilities with steam generation equipment have an integrated steam generator integrity program that includes the following activities; • Tube mapping for wastage and other degradation mechanisms that identifies remaining tube thickness,

internal and external pitting, hydrogen damage, and caustic gouging.

• Trending tube wastage rates and predicting time to replacement.

• Identifying areas prone to accelerated wastage and implementing more frequent tube mapping program in these areas.

• Understanding changes in operation such as cycling, fuel blends, temperature and pressure changes and adjusting the inspection frequency and scope as required

• Tube sampling and metallurgical analysis (at a limited scale) as part of the boiler mapping program. These programs can assist in understanding the amount and characterization of any tube deposits. Tube samples should be taken from the highest heat input areas.

• Documenting boiler tube failures in a comprehensive format describing the specific boiler and tube location, failure mechanism, repair, weld procedure and solution applied.

• Storing, trending and analyzing mapping and failure data.





3.10 Management of Weld Quality OBJECTIVE To achieve control of welding quality. Weld quality is critical in maintaining a safe, reliable and economic plant. MINIMUM EXPECTATIONS

• Welding should be done by qualified welders, unless the parts being welded are not load-bearing or pressure-containing. Welders in these cases will still be provided with appropriate training and guidance to ensure that they are competent in the maintenance and operation of the welding equipment to be used.

• Whenever window welds are used for emergency repairs to boiler tubing:

o Records will be kept of all window weld procedures and the areas affected. o All window weld repairs should be replaced with conventional inserts at next outage or next

suitable opportunity • Cold weld repairs on CrMoV and 2CrMo components may be considered whenever:

o The conditions required by conventional repair cannot be met (e.g. Proper control of heat

treatment cannot be met) o Conventional repair will result in unacceptable extension of planned outage. o Repairs are required as a result of breakdown and system requirements are paramount. o Cold weld repairs should be inspected regularly on a time interval specified by an approved

welding engineer and all cold welds found to be cracked on inspection should be re-repaired.




3.11 Welding Requirements for Repair and Maintenance

Contracts OBJECTIVE To reduce potential major safety hazards or commercial threats resulting from the failure of welds performed by contractors. MINIMUM EXPECTATIONS

• Procedures for pressure welds that to be used by contractors should be reviewed and approved for

repair and maintenance contracts:

o Welding procedures should be identifiable and traceable to the specific welds that they will be used for.

o Nomination and approval of welders should be done by name and/or mark and documented appropriately by the contractor.

o Approval of the procedure and welder will be obtained before any welding.

• Additional needs include:

Needs Details

Documentation

o A weld schedule should be produced for planned work, referencing drawings, weld procedures and other special process procedures.

o The contractor should submit the schedule, drawings, weld procedures, and heat treatment procedures at least one month before the start of the outage.

Materials o New materials should be certified in terms of mechanical properties and/or chemical analysis.

Welding Preparation

o Backing rings should not be used for welds in high integrity pipe work, unless they are to be machined out subsequently.

Method of Preparation

o Machining of weld preparation is preferred on all sizes over 50mm OD – rotary abrasive wheels or discs, rotary burrs, abrasive caps and manual filing are all acceptable on smaller sizes, provided they can be shown to achieve the specified preparation geometry.

Inspection of Preparation

o Ensure that welds containing unfused lands are cleaned of residues which may impair weld integrity or interfere with the welding process.

Pre-heat

o Preheat by electrical resistance heating elements controlled by thermocouples when possible.

o Gas pre-heat is only permitted on butt welds in plates up to 12.5mm thick and pipes up to 12.5mm in wall thickness and 127mm outside diameter. Gas pre-heat is not permitted for: § Ferric steels containing more than 6% alloy content. § Ferric steels containing greater than 3% chromium content. § Any element that exceed 12.5mm of thickness.

o Pre-heat should be maintained throughout the welding period over a heated band width of 3x the parent material thickness or 75mm, whichever is smaller.



Consumables o All welding consumable should have traceable batch or individual analysis certificates

Post-weld Heat Treatment

o Temperature measurement should be done using capacitance discharge welded thermocouple only.

o Calibrated recorders and controllers are used to monitor post-weld heat treatment.

Acceptable Standard

o Local excavation of the defect is allowable if defect is within the top 50% of a weld and the repair excavation does not exceed one third of the circumferential surface length of the weld.

o Local excavation of the defect is allowable if defect is within the bottom 50% of a weld and the repair excavation does not exceed one sixth of the circumferential surface length of the weld.

o Defects within top 10% of the weld should be removed by grinding where possible; provided any excavation is blended smoothly into the weld surface profile and weld thickness is sufficient for design purpose.

Boiler Tubes

o All tubes should be cut square and cleaned o Exposed tubes, pipes, headers, etc. will be capped to prevent entry of

extraneous material. o Tube attachments:

§ No welding of attachments should be done while tubes contain water. § Tube attachments, which have been calorized during heat treatment,

should be ground at the welding positions to remove all traces of the calorized layer before welding on tube attachments.

o When welding a new insert into an existing tube, the wall of the existing tube should be lightly ground for a length of at least two inches below the weld preparation to avoid contamination of the weld metal by the corrosion deposits.




3.12 Non-Destructive Testing – CMV Weld Inspections OBJECTIVE To ensure the safety and integrity of pipework systems by providing a strategy for reviewing and responding to new findings and failure mechanisms in high pressure, high temperature steam pipework systems manufactured from chromium-molybdenum-vanadium (CMV) materials. MINIMUM EXPECTATIONS

• Establish and maintain an updated inventory of CMV pipework and welds within the system

• Define and carry out a specific inspection strategy for CMV pipework. This strategy should include:

o Inspection schedules and procedures § Keep detailed records of all inspections and defects found. § Compile and maintain a complete inventory of welds in each pipework system including a

unique identifier for each weld that is labeled on updated drawings as well as on the pipework itself

§ Define the period of inspections § Establish a procedure to detect leaks from pipework welds § Carry out inspection in accordance with approved inspection procedures.

o Assessment of defects in welds

§ Inspections should be assessed by a specialist metallurgist with experience in investigating weld

defects. § When a defect is found, take into account possible similar defects in parallel lines, adjacent

welds, and sister units. § Carry out follow-up inspections § Weld repairs and repairs to Type IV damage § Weld repairs and new welds should be made in accordance with approved weld procedures.

o Corrective actions whenever a leak is detected

§ Take unit off load and de-pressurize system § Make further detailed inspections of leaking area § Take samples § Implement weld repair § Monitor area after repair




3.13 Care and Replacement of Threaded Fasteners OBJECTIVE To establish appropriate procedures for the care and replacement of threaded fasteners operating at temperatures exceeding 370ºC (700 degF). Fasteners used at these high temperatures more subject to creep and deformation. MINIMUM EXPECTATIONS • Fasteners used for pressure vessels, valves, flanges and fittings for high-temperature service should

meet the requirements of ASME SA-193.

• Selection of an appropriate grade of fastener will depend upon design, service conditions, mechanical properties and high-temperature characteristics.

Type Grade Description Ferritic Steel B5 5 % Chromium Ferritic Steel B6, B6X 12 % Chromium, AISI Type 410 Ferritic Steel B7, B7M Chromium-Molybdenum Ferritic Steel B16 Chromium-Molybdenum-Vanadium Austenitic Steel B8, B8A AISI Type 304 Austenitic Steel B8C, B8CA AISI Type 347 Austenitic Steel B8M, B8MA, B8M2, B8M3 AISI Type 316 Austenitic Steel B8P, B8PA AISI Type 305 with restricted Carbon Austenitic Steel B8N, B8NA AISI Type 304N Austenitic Steel B8MN, B8MNA AISI Type 316N

Austenitic Steel B8MLCuN, B8MLCuNA Unstabilized, 20 Chromium, 18 Nickel, 6 Molybdenum with restricted Carbon

Austenitic Steel B8T, B8TA AISI Type 321 Austenitic Steel B8R, B8RA 22 Chromium-13 Nickel-5 Manganese Austenitic Steel B8S, B8SA 28 Chromium-8 Nickel-4 Silicon + Nitrogen Austenitic Steel B8LN, B8LNA AISI Type 304N with restricted Carbon Austenitic Steel B8MLN, B8MLNA AISI Type 316N with restricted Carbon

• Legislation across the European Union requires that all applicable items of pressure equipment placed

on the market by May 2002 will be fully compliant with the PED 97 / 23 / EC. Fasteners have to be made from steel listed in EN 10269 or they have to be approved in a “Particular Material Appraisal”. Manufacturer has to give certificate according to EN 10204-3.1.B, stating that the products are approved in accordance with PED 97 / 23 / EC. For more information on the directive, please visit web site of Enterprise and Industry, European Commission - http://ec.europa.eu/enterprise/pressure_equipment/ped



• As failure of fasteners may cause serious injury or death, for critical applications it is advisable to

procure fasteners from reputed manufacturers only. • Re-use of bolts is not recommended unless testing or calculations reveal the fasteners have sufficient

life remaining to reach the next planned outage. Calculation of remaining life, if performed, should consider mechanical properties, operating temperatures, and effective operating hours.

• Plants should maintain database records of current status of fasteners, with updates following all

retightening and replacement actions, in order to maintain a basis for future assessment and comparison.




3.14 Injection Leak Sealing OBJECTIVE To ensure that plant safety and integrity are maintained in the injection leak sealing process by site specific care and maintenance strategies. Injection sealing is permissible for routine and emergency on-stream, on-line, leak repair in water, air, process and steam applications ranging from cryogenic to 1700°F, and pressures from vacuum to 6000 psig. MINIMUM EXPECTATIONS • Identify and confirm a list of approved and assessed contractors to carry out the sealing process. • Examine and review records of previous repairs on the leaking component, and determine any

limitations.

o Determine cause and assess effects of component failure. o Perform a technical assessment to ensure that proposed process is suitable for the repair of

component being considered. o Ensure that sealing material used is compatible with the fluids and substances in the pipework

system as well as the materials of the plant components. • Maintain updated records for each repair carried out and assess when permanent repair is appropriate. • Check repaired component at next outage. REFERENCE DOCUMENTATION AND EXAMPLES: Hyperlink to Reference Material When Available



3.15 Care & Maintenance of Induced Daft Fans OBJECTIVE To ensure the continued safe operation of induced draft (ID) fans given the risk of fatigue crack growth and brittle fracture. Operation and inspection strategies will provide guidance in classification, inspection intervals, and identification and categorization methods to assess risk of failure. MINIMUM EXPECTATIONS • Under normal operating conditions, readings of horizontal and vertical vibration levels of fan and

motor bearings should be recorded and trended at least quarterly although monthly is recommended.

• Because of the risk of cracking and brittle fractures of fans operating as induced draft fans, periodic inspections are needed. Any defects identified should be recorded and assessed by a specialist or knowledgeable person prior to returning the fan to service. The recommended inspections and frequency include:

o Visual Inspection by experienced personnel every overhaul. o Magnetic Particle Inspection (MPI) should be performed at least every four years. o Ultrasonic Inspection only needed in special cases using specialized procedures. o A Material Composition Inspection should be performed to determine material grade of each

section of center sheets, cone sheets and blades. • If inspection reveals defects, the defect should be recorded and categorized by defect type, for

example: o cracking from region of the weld root, o cracking from the region of the weld toe, o cracking approximately normal to the surface

• Plants should maintain records of original design specifications, number of running hours and fan starts for each fan. The record should also include details of any defects, grinding work or other repairs performed.




3.16 Care & Maintenance of Electric Motors OBJECTIVE To help prevent the failure of electric motors during normal operation by establishing careful operation practices, applying suitable monitoring equipment and adopting detailed test and inspection procedures. MINIMUM EXPECTATIONS • In the absence of standards set by local legislation, the adoption of the following standards should be

considered good practice: o Work activities, including operation, use and maintenance of an electric motor system, should be

conducted in a way as to avoid danger. o No work activity should be carried out near any live conductor. o Only people with technical knowledge or experience should engage in activities where technical

knowledge and experience are necessary to prevent danger.

• Maintenance, fault diagnosis, and monitoring of stators on critical electric motors o During normal operation

§ Clean and inspect regularly – frequency of cleaning depends on operating environment and

type of motor. Cleaning every 5 years is common. § Monitor stator winding temperature, effects of load cycling, and vibration levels. § Perform on-line partial discharge analysis for the most critical motors

o During outages

§ Undertake routine tests on strategic motors such as fans, feed pumps, pulverizers, etc.

Insulation resistance and polarization index tests should be conducted at least annually and results trended.

§ Conduct detailed inspection of the following areas: • End windings and end winding supports, slot wedges, stator core, HV windings, stator

internals, and stator frame.

§ When necessary, carry out the following tests to assess integrity of stator core and windings • Rated Core Flux Test, EL-CID Test, Tan Delta Test, Partial Discharge Test

§ Carry out any remedial work based on inspections and tests

• Clean/Dry Out of Windings, re-wedge, re-brace, core repairs, and Varnish & Stove stator windings



• Maintenance, fault diagnosis, and monitoring of rotors on critical electric motors

o Identify and adhere to any constraints on starting cage rotor induction motors.

§ For example, most motors should be capable of two successive starts followed by a 30 minute cooling period, or three starts equally spaced throughout one hour during normal operation.

§ Typical restrictions might include limiting starts to no more than three starts in one hour.

o Monitor induction motor for conductor defects.

o Carry out the following recommended condition monitoring while motor is running: § Monitor temperature rise in bearings – excessive temperature rise may mean abnormal

condition. § Monitor temperature rise in coolant – exit temperature should not exceed limits set by

manufacturer. § Monitor shaft eccentricity – maximum eccentricity should not exceed manufacturers stated

limit

o Carry out detailed inspections and tests during major outages § With rotor in place, the following inspections should be used:

• Air-gap check – measure air-gap at four mutually perpendicular positions around the rotor at each end.

• Axial position check – ensure that the axial position of the rotor within the stator lies on the magnetic center. Accuracy in accordance with manufacturer’s tolerance.

• Fan, seal and baffle clearances. § Typical tests include:

• Winding resistance of wound rotors – should be measured using a high current type milli-ohm meter and set to the standard temperature.

• Insulation Resistance of Wound Rotor Windings – insulation resistance and polarization index should be measured to ensure the safe condition of winding for high voltage testing. Low resistance indicates further investigation is needed and a possible “dry out” will be needed prior to high voltage AC testing.

• Cleaning/Drying out of Windings – if values of insulation resistance and polarization index are below acceptable limits, procedure for drying/cleaning windings should be used.




3.17 Maintenance of Station Batteries OBJECTIVE To ensure that batteries, chargers and inverters remain in good condition so they are able to perform necessary functions when called upon. Station batteries are critical components to the safe operations of generating facilities by acting as back up power to operate protective relays in a lost power event. A proactive station battery monitoring program is necessary to ensure safe operations and optimized asset utilization. MINIMUM EXPECTATIONS • Document current battery type & technology requirements and limitations. • In order to limit maximum voltage that operators could be subjected to during maintenance, inter-cell

connectors should be clearly marked to identify position and function. • Sites that have both lead-acid and nickel-cadmium batteries should keep separate sets of tools and

equipment for the two types. • Lead-acid type cells should be installed in a dedicated battery room with ventilation and restricted

access. • The room ventilator fans operation should be alarmed to control room in case of failure. • Maintenance of the Lead Acid batteries will be in accordance with IEEE 450 - Recommended Practice

for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications and IEEE 1188-1996 - Recommended Practice for Maintenance, Testing, and Replacement of Valve- Regulated Lead-Acid (VRLA) Batteries for Stationary Applications

• Install a permanently mounted battery monitor system, capable of continuously making all of the

voltage, current, temperature, and resistance measurements called for by the IEEE Standards. • Respond to any out-of-tolerance conditions and take the corrective action recommended by the IEEE

or battery manufacturers. • Trend monthly data from internal cell resistance measurements and take action as follows:

o If any resistance reading exceeds the baseline value for that model cell by 50% or more, then replace the cell without any further testing.

o If the resistance value is between 20 to 50% greater than baseline, then perform a capacity test to verify its state of health. If capacity is 80% or less, then replace the cell as soon as possible. If greater than 80%, then continue to watch for further increases in resistance. If capacity testing is not an economically viable option, then replace the cell. Keep in mind that capacity testing can be performed on the entire string offline or can be performed on a single suspect cell online.



o Perform capacity testing in accordance with the IEEE recommendations. This should only require the rental of a load bank, since the monitor will log data during the discharge test. Of all the capacity tests recommended, the acceptance test performed right after installation is the most important one and will be performed.

o Analyze data from the monitor at least once monthly, and perform an annual sanity check on the monitor itself to verify that it is properly calibrated and working correctly (Someone will need to be monitoring this).

• Weekly inspections should be performed to include:

o Float voltage o General appearance and cleanliness o Charger output current and voltage o Electrolyte level o Cell cracks or leaks o Evidence of general or terminal corrosion

• Quarterly testing and inspections should include:

o Voltage of each cell and total bank voltage o Specific gravity of each cell, as applicable o Representative sampling of electrolyte temperature, as applicable o Log and top up electrolyte levels o Visually inspect each cell for electrolyte level, plate color, and condition o Visually inspect positive connection of pillars for signs of pillar corrosion, lid cracking and

crack propagation into container o Check all terminals and intercell connections for tightness and degradation o Log overall battery voltage, current, associated load current and charger current

• Annual inspections should be conducted to condition of each cell and the condition and integrity of the

battery rack. In addition, cell-to-cell terminal resistance should be checked each year. • The following additional inspections should be undertaken when performing routine battery

maintenance:

o Ensure that all identification, safety and warning notices are present and legible o Verify that fire protection systems are functional and on-line o Make sure that room ventilation is operating and clear o Ensure that room is clear of any combustible trash and is not being used as storage. o Make sure tools are available in convenient locations (stands/racks/cupboards)

• Keep records of the durations and boost charge voltages of boost charging. • Performance/capacity checks should be performed 2 years after commissioning new batteries and then

every 5 years thereafter. If battery performance degrades or reaches 85% of service life, testing frequency should be increased to annual testing.



• Valve-regulated lead-acid (VLRA) batteries, or gel batteries, are not maintenance free. The following checks should be performed on VRLA batteries:

o Internal ohmic value measured every 3 months o Temperature measured on each negative terminal every 3 months o AC Ripple current measured on an annual basis o Performance/capacity tests should be conducted annually. If degradation has occurred, the

checks should be done every six months

• Maintain records of discharge tests to verify operational capacity. • Assess records and logs accumulated from monitoring. Key indicators of a problem cell are:

o Cell voltage is out of step with the rest of the battery o High water usage o High debris accumulation in “mud space” below plates o Corrosion

• When a battery is to be removed:

o Disposal of redundant cells should be undertaken by specialist contractors – battery manufacturers

usually offer this service o Extent of personal protection needs to be increased – eyewash bottles, first aid equipment and a

supply of running water will be available REFERENCE DOCUMENTATION AND EXAMPLES: Hyperlink to Reference Material When Available



3.18 Handling Electrostatically Sensitive Devices OBJECTIVE To provide guidance on the proper precautions that should be taken while handling components sensitive to electrostatic discharges. MINIMUM EXPECTATIONS • The following procedures should be undertaken when removing a module containing electrostatic

sensitive devices:

o Before removing module, the person removing it should be at the same electrostatic potential as the module by touching the equipment case

o Handle module by its front-plate, frame or edges of the printed circuit board

o Do not pass module to any person without first ensuring that he/she is at the same electrostatic potential – this can be achieved by simply shaking hands

o Place the module on an antistatic surface or on an anti-conducting surface which is at the same electrostatic potential

o Store or transport module in a conductive bag

o Any person making measurements on internal circuitry of an amplifier in service should be earthed to the case with a conductive wrist band. Wrist bands should have a resistance to ground between 500k ohms and 10M ohms. If wrist band is not available contact should be maintained with the case to prevent buildup of static.




3.19 Portable Electric Measuring Equipment OBJECTIVE To ensure safety by minimizing the risk of electric shock in the procurement, use and maintenance of portable electrical tools, instrumentation and test equipment. MINIMUM EXPECTATIONS • Risk of electric shock when using portable electric tools can be minimized by:

o Earthing all exposed metal parts.

o Maintaining an all-insulated outer enclosure.

o Maintaining double insulation to isolate exposed unearthed metal parts.

o Utilizing a reduced voltage to supply the apparatus.

o Providing sensitive earth-leakage protection to limit duration of the shock.

• Portable electric tools, instruments and test equipment should be stored in a place free of oil, dirt, moisture, excessively high or low temperatures and away from sunlight.

• All portable electrical tools should be inspected on an interval of no more than 6 months. Records should be kept that detail the nature of any problems found and when testing was performed.

• An effective calibration policy and documented program for calibrating critical measuring equipment should be established including, if applicable, any required regulatory requirements.




3.20 Performing Electrical Testing on Live Apparatus OBJECTIVE To provide guidance on making electrical measurements on a live apparatus. MINIMUM EXPECTATIONS • In order to reduce the risk of accidents involving test leads and equipment, the following options exist

to be used singly or in combination:

o Fused probes and test leads. These should be inspected before use for mechanical damage that could impair performance

o Multimeters without Current Ranges

o Contactless Current Measurements

o High Impedance Probes

o Isolation Probes

o Low and Limited Energy Systems

o Installation of view ports for Thermography inspections.

• Equipment should be selected to minimize the risk of accident in the event of an operational error. When selecting the tool to be used for a task, the following guidelines should be taken into account:

o Don’t work on live machines unless absolutely necessary

o Minimize extent of live metal exposed during installation and operation

o Make firm connections to prevent leads from becoming detached

o Install fuses and resistance limiters as near to the point of connection as possible.

o When making connection to a live apparatus, the lower voltage connection should be made first.

o The standard general purpose test instrument should consist of a multimeter with no current ranges, supplied with a pair of fused probes and all contained in a carrying case that provides protection for the meter and probes.

o Oscilloscope probes should be a x10 or x100 with the attenuator built into the probe tip.

o Fuse probes and fused input current meters should not be used in CT secondaries.

o All equipment should be regularly checked, inspected and calibrated.

• Properly rated gloves and arc flash personal protective equipment will be used.




3.21 Insulated Hand Tools for Live Work (to 650V) OBJECTIVE To provide guidance on the control and inspection of insulated hand tools for working on or around live systems with voltages of up to 650V. MINIMUM EXPECTATIONS • In order to prevent confusion between insulated hand tools and general engineering hand tools with

handles made of insulating materials, insulated hand tools should be easily distinguishable (ex. Use only one color for the insulated hand tools at a site).

• All insulated hand tools should be inspected before use for evidence of any mechanical damage or

deterioration which may affect electrical performance • If tool is to be used in a dirty environment, the user should inspect it during the task regularly to

ensure that the tool remains clean and suitable for the task • Tools should be inspected at least every 6 months. If tools are being used in an environment that may

lead to rapid deterioration, then the interval between inspections should be reduced. • The inspection process for insulated hand tools should include the following:

o Check for mechanical cuts and abrasion to the insulation. o Check for burns or solvent attack. o Check for cracks. o Check that the bonding between the insulation and the metal parts is intact. o Check that insulation is clean and free of oil, grease and dirt. o The tool should be disposed of if the insulation is found to be damaged.




3.22 Asbestos-based Components in Air Break Switchgear OBJECTIVE To assist in the maintenance and management of air-break switchgear apparatus containing asbestos-based components. MINIMUM EXPECTATIONS • An asset register should be maintained at each plant listing the location of asbestos-containing

components. The following data should be included: o Location and type of each asbestos-containing component o Material condition of the component o Date of last air sampling survey or details of other sampling evidence for the location

• Safety and advisory signs should be placed at each location. • When working on or near asbestos-based components, the Job Safety Assessment should address

asbestos handling provisions to minimize risk of inadvertent damage during work. Personnel should be trained on the site procedures for handling asbestos.

• When cleaning is necessary, a vacuum cleaner approved for the collection of asbestos should be used. • All work should be suspended in the event that damage is incurred, identified or suspected. • Minor repair of asbestos-containing components should be permitted, but significantly damaged

components should be removed from service. The following guidelines should be used in order to determine whether a component should be considered for repair or not: o Structural fault, such as cracking, fracturing, erosion or significant burning, would be considered

significant damage o Surface scratching or light discoloration, peripheral scuffing, feathering of edges or corners, which

would be able to be contained by the application of a sealing agent, would be considered repairable.

• Grinding, sanding or other working of material that may potentially give rise to fiber release should not

be permitted. REFERENCE DOCUMENTATION AND EXAMPLES: Hyperlink to Reference Material When Available



4.0 LOSS PREVENTION BEST PRACTICES

4.1 Boilers and Heat Recovery Steam Generators OBJECTIVE To define guidelines for safe operation of large power boilers and heat recovery steam generators. MINIMUM EXPECTATIONS • Direct drum level imaging should be provided to the control room operator through the use of mirrors,

cameras or fiber-optics. Properly installed and maintained newer generation capacitance or inductance monitoring systems such as Yarway, Aquarian or Hydrastep are acceptable substitutes.

• Boiler internal inspection frequency should be based on applicable state or jurisdictional requirements.

• During major outages, boiler tube samples should be taken and analyzed for deposit loading in order to assess the potential need for chemical cleaning and provide feedback on the plant’s water chemistry program effectiveness.

• Nozzles and liners of attemperators and desuperheaters should be inspected at least every five years. More frequent inspections may be required depending on operating conditions.

• Calibration and testing of control schedules, alarm levels and trip set points for burner and boiler controls should be performed annually. The following critical alarms and trips will be in service for operation:

o Power failure trip o Low deaerator level trip o Low furnace draft trip o Loss of flame alarm and trip o High and low furnace pressure alarm and trip o Feedwater and steam flow alarm and trip o High and low drum level alarm and trip o High tube metal temperature alarm o High steam temperature alarm o Manual operator push button trip o Low air flow trip o Generator and turbine trip o Low oxygen trip o Loss of all ID & IFD Fans or air heater trip





4.2 Steam Turbines OBJECTIVE A proactive steam turbine maintenance program is necessary to ensure safe operations and optimized asset utilization. MINIMUM EXPECTATIONS Each facility with Steam Turbines will develop and implement an integrated Steam turbine integrity program that includes the following activities:

• Perform daily checks of the steam turbine to include:

o Visual inspection of inlet and exhaust piping; stop and control valves; front standard; hydraulic and lube oil drains, piping and systems; and oil tanks

o Turning gear, generator and auxiliary systems

• Perform weekly tests. Ideally these tests are performed on a regular regime - such as the same shift each week. These tests should include:

o Test auxiliary and emergency lube oil pumps o Test lube oil system low pressure and low level alarms o Simulated overspeed and thrust bearing wear detector trips o Cycle/exercise turbine main stop and throttle/control valves, combine reheat stop and intercept

valves o Cycle test extraction non-return valves

• Once per month, lubricating and hydraulic oil should be sampled and analyzed.

• Annually, the following tests and inspections should be performed:

o Visually inspect and functional test stop, throttle, control, extraction non-return and other

critical valves. o Visually inspect mechanical and electrical controls and calibrate instrumentation (alarms, trips,

backup systems and emergency oil pumps) o Test mechanical overspeed and vacuum trip devices. A mechanical overspeed test can be

performed every two years if the primary overspeed trip system is electronic. o Visual inspection of turning gear teeth for wear or damage

• Every two years, the following tasks should be performed:

o Visual inspection or borescope of turbine nozzle inlet and exhaust stages and other stages if

access is available. o Internal and alignment inspection of turning gear o Internal inspection of main stop, throttle, control, extraction and non-return valves checking for

wear, seat leakage, or other indications of damage.



• The recommended period between overhauls for steam turbines depends on several factors including

the operating characteristics, number and severity of starts, condition of turbines, operating and maintenance history, performance expectations, etc, As a general rule, outages should be performed at intervals not exceeding 100,000 hours if a risk analysis has been performed (such as Hartford Steam Boiler’s STRAP assessment) at 5-7 years into operation

• Stay current with OEM technical advisories (information letters, recall notices & service information

bulletins)

• Follow outlined process for increasing outage intervals to include AGIC notification if extending more than one year from previous interval

• Include vibration monitoring and trending with multi-staged alarms (high & hi-high)

• The following physical protection for steam turbines is recommended:

o Water induction protection installed and maintained to local and international standards. o Continuous vibration monitoring and trending to include:

§ High and high-high level alarms in the control room, § Pedestal-mounted seismic vibration probes, or § Turbine shaft vibration sensors or proximity probes

o Emergency lube oil pumps should have battery or steam backup power supply with no over-

current protection on the motor

o Critical alarms and trips for steam turbines include: § High boiler drum level trip § High feedwater heater level trip § High exhaust hood temperature trip § Generator trip § Boiler trip § Loss of hydraulic pressure or mechanical turbine trip § Electronic and mechanical overspeed trip § Low lube oil pressure and level trip § High lube oil temperature alarm § High bearing metal temperature alarms § High vibration alarms and trips § Loss of vacuum alarm and trip





4.3 Gas Turbines OBJECTIVE A proactive gas turbine maintenance program is necessary to ensure safe operations and optimized asset utilization. MINIMUM EXPECTATIONS Each facility with Gas Turbines will develop and implement an integrated Gas turbine integrity program that includes the following activities:

• Daily visual inspection of turbine, gearbox, generator, inlets, exhaust and auxiliary systems

• Weekly tests should include:

o Testing of auxiliary and emergency lube oil pumps o Testing of lube oil system low pressure and low level alarms o Simulated overspeed test

• Monthly sampling and analysis should be performed on lubricating and hydraulic oil systems

• Every 3 months, the following checks should be made:

o Visual inspection of turbine exhaust system for oil and/or fuel leakage o Inspection of turbine inlet and outlet thermocouples for proper operation

• Annually, inspections and tests should include:

o Inspection of seals, bearings and related assemblies (without disassembly) o Visual inspection of mechanical and electrical controls and calibration of instruments and

controls (alarms, trips, backup systems, emergency oil pumps) o Overspeed trips should be tested annually. Mechanical trips can be tested every two years if the

primary overspeed detection system is electronic.

• OEM guidelines should generally be followed for timing of inspections and overhauls. Typically this guidance considers the number of starts, firing conditions, fuel types and other factors. Typical timing of inspections are:

o Combustion inspections at 8,000 to 12,000 equivalent operating hours o Hot gas path inspection at 16,000 to 24,000 equivalent operating hours o Major inspection at 32,000 to 48,000 operating hours

• Stay current with OEM technical advisories (information letters, recall notices & service information

bulletins)



• Implement OEM advisories in the CMMS for cases where parts needs to be changed or inspected to ensure OEM advisories are tracked and complied.

• Maintain a record of inspection / maintenance activities and test results.

• Vibration monitoring and trending should be continuous and include:

o High and high-high level alarms in the control room o Pedestal-mounted seismic vibration probes, or o Turbine shaft vibration sensors or proximity probes

• Emergency lube oil pumps should have battery or steam backup power supply with no over-current

protection on the motor

• The minimum critical alarms needed for gas turbine operation include:

o Electronic and mechanical overspeed trip o Low lube oil pressure and level trip o High lube oil temperature alarm o High bearing metal temperature alarms o High vibration alarms and trips o Dynamic monitoring (specific to turbine model)





4.4 Hydro Turbines OBJECTIVE A proactive hydro turbine maintenance program is necessary to ensure safe operations and optimized asset utilization. MINIMUM EXPECTATIONS Each facility with Hydro Turbines will develop and implement an integrated hydro turbine integrity program that includes the following activities: • Daily visual inspection of thrust bearings, trash racks, tail races, turbine, gearbox, generator and auxiliary

system • Weekly tests and inspections to include:

o Testing of auxiliary and emergency lube oil and water pumps o Testing of low lube oil pressure and low lube oil level alarms o Simulation of overspeed trip o Inspection of filters and water purity on lubricating water systems o Vibration readings on runner, gearbox, generator and wicket gates

• Monthly sampling and analysis of lubricating and hydraulic oils • Annually, the following tests and inspections should be performed:

o Dewater inspections o Inspect shaft seals, bearings and seal oil and lubricating oil systems o Visually inspect mechanical and electrical controls and calibrate instrumentation (alarms, trips,

backup systems, emergency oil pumps) o Test overspeed trips. Mechanical overspeed trips can be tested every two years if the primary system

is electronic o Inspect gates and mechanisms for damage, closing clearances, wear, etc. o Check operation of isolation valves o Visually inspect gearbox

• Every two years, the following should be performed:

o Wicket gate and runner blade variable geometry (open and inspect bearings and bushings) o Inspect penstocks and surge tanks o Open, inspect and check alignment of gearbox o Borescope inspection of blades (if accessible)

• Overhaul frequency for hydro turbines are a function of many factors including turbine design, head, water

purity, operating times, etc. As general guidance overhauls should be conducted on 5-year cycles.



• Maintain records of inspection/maintenance activities and test results. • Vibration monitoring and trending should be continuous and include:


• Emergency lube oil pumps should have battery or steam backup power supply with no over-current

protection on the motor • The minimum critical alarms needed for hydro turbine operation include:

o Electronic and mechanical overspeed trip (non-recycling) o Low lube oil pressure and trip o High lube oil temperature alarm o High thrust and shaft bearing metal temperature alarms and trip o High vibration alarms and trips o Fail-safe governor drive mechanism to stop water flow to turbine in the event of drive failure





4.5 Wind Turbines – Suspended and under review OBJECTIVE A proactive wind turbine maintenance program is necessary to ensure safe operations and optimized asset utilization. MINIMUM EXPECTATIONS Each facility with Wind Turbines will develop and implement an integrated Wind turbine integrity program that includes the following activities: • Daily inspection of units for abnormal operation, increase in noise level, damaged blades, improper

positioning, leaks vibration, etc. • Quarterly visual inspections should be performed on blades, gearbox, generator brakes, bearings, pitch and

yaw control, general controls, protection systems and nacelle and nacelle auxiliaries • Annual tests and inspections include sampling and analysis of gearbox lube oil and tests to simulate system

controls and interlocks (wind cut-in and cut-out speeds, vibration, wind temperatures, etc.) • Every 18 months, visual inspections should be performed on gearbox internals and generators along with

insulation resistance testing of the rotor and stator • Overhauls schedules will vary with type of machine and OEM. The OEM and industry experience should

be considered when establishing the overhaul frequency. • Maintain a record of inspection / maintenance activities and test results. • Instruments and controls installed should include:

o System speed – turbine and generator o Generator voltage, amperage, output, power and reactive power o Gearbox oil and bearing temperatures o Generator coolant and oil temperatures o Nacelle ambient temperature and detection warning systems o Rotor and nacelle vibration o Wind speed, shear, direction and temperature o Hydraulic system pressure and temperature sensors o Critical alarms should exist for key identified information tags (turbine and generator over speed,

gearbox temp, generator temperature, rotor and nacelle vibration etc.). REFERENCE DOCUMENTATION AND EXAMPLES:




4.6 Internal Combustion Engines OBJECTIVE A proactive maintenance program is necessary to ensure safe operations and optimized asset utilization of internal combustion engines. MINIMUM EXPECTATIONS Each facility with internal combustion engines will develop and implement an integrated integrity program that includes the following activities: • Daily visual inspections of the unit’s inlet and exhaust connections, engine, generator and auxiliary systems

for damage, leaks, plugged filters and abnormal operation. o If operating, verify cylinder pressures and exhaust temperatures are normal o Check all control linkages for signs of binding and general condition

• Weekly inspections and tests to be performed include:

o Taking vibration readings from engine and generator if unit does not have permanent vibration

monitoring equipment installed o Testing of emergency backup lube oil pump for proper operation o Testing of emergency backup cooling water pump for proper operation o Testing the low lube oil level and low lube oil pressure alarms o Testing of the simulated overspeed trip, where applicable, or verify shutdown alarm operation.

• Monthly testing and inspections to be performed include:

o Sampling and analysis of lube oil, fuel oil and cooling water quality o For emergency diesel engines – start, run and load the generator set until the engine temperatures have

stabilized for at least 30 minutes o Check ignition timing, inspect the crankcase, take valve lash readings, inspect the governor drive and

inspect cams, push rods and rockers • Visual inspections of the cylinders and valves should be conducted as specified by the manufacturer for the

particular model, duty cycle, type of combustion system and/or fuel type. In the absence of these recommendations, annual inspections are recommended.

• Annual inspections and testing should include:

o Inspection of seals, bearings, seal oil and lubrication systems, turbocharger bearings and fuel system piping and components for wear, leaks, vibration damage, plugged filters and other kinds of thermal and mechanical stress

o Visual, mechanical and electrical inspection of instrumentation, protection and control systems, including checking alarms, trips, filters, backup lubrication and water systems



o Mechanical overspeed trip testing. Test frequency can be lengthened to two years for mechanical overspeed trips if the primary trip is an electronic system.

o Take hot crankcase web deflection readings. o Counter weights, if used, need to be torque and checked per OEM recommendations. o Turbochargers should be disassembled and inspected per OEM recommendations o Valve clearances and other critical measurements should be taken per OEM recommendations

• Complete overhauls should be conducted as specified by the manufacturer for the particular model, duty

cycle, type of combustion system and/or fuel type. In the absence of these recommendations, overhauls every 5 years are recommended.

• Stay current with OEM technical advisories (information letters, recall notices & service information bulletins)

• Maintain a record of inspection / maintenance activities and test results.

• Coolant temperatures should be continuously monitored with high and high-high alarms in the control room

• Lube oil pressures should be continuously monitored with high and high-high alarms in the control room • Engines should have both electronic and mechanical overspeed trips

• The minimum critical alarms needed for internal combustion engine operation include:

o High bearing temperature alarms and trips o Low coolant pressure alarms and trips o Vibration alarms and trip o High oil filter differential pressure alarm o Low lube oil sump level alarm o Manifold air temperature alarm o Engine exhaust temperature alarm





4.7 Generators OBJECTIVE A proactive generator maintenance program is necessary to ensure safe operations and reliable performance. MINIMUM EXPECTATIONS Each facility with generators will develop and implement an integrated generator integrity program that includes the following activities: • Stay current with OEM technical advisories (technical information letters, recall notices & service

information bulletins) • For sites with GE Model 6A3 and other small frame generators understand the typical problems

encountered - loose wedges, corona, pole jumpers & tape migration • Understand special inspection requirements associated with 18-5 Mn-Cr retaining rings due to stress

corrosion cracking when exposed to water and humidity contamination. • Daily inspections of generators should include visual examination of generator and auxiliary systems

including the condition of frame and bed plate, seals, bearings etc. • During overhauls, the following inspection and testing should be performed

o Winding copper resistance test o Insulation resistance test and polarization index o Power factor test o Corona probe test or partial discharge analysis o Shorted terminal (RSO), wedge tightness and end turn tightness should be checked

• Every 3 years, iso-phase busses should be visually inspected • Vibration monitoring and trending should be continuous and include:


• For hydrogen seal oil systems, the return detraining tank should be vented to outside atmosphere to avoid

the potential build up of hydrogen inside the plant • The following relays, instrumentation and control devices should exist for each generator installation:

o Voltage and frequency o Distance relay o Reverse power relay (anti-motoring)



o Loss of field o Stator unbalance o Stator thermal protection o Instantaneous overcurrent applying to breaker circuitry o Timed overcurrent o Voltage controlled timed overcurrent relay o Overvoltage protection o Zero sequencing voltage relay o Primary ground fault relay o Voltage balance o Timed overcurrent relay o Fault pressure relay o Primary rotor ground fault voltage relay o Transformer oil or gas level relay o Loss of synchronization protection o Over and under frequency relays o Lockout auxiliary relay o Bus protection differential relay o Differential relay for generator protection o Differential relay for transformer protection





4.8 High Energy Steam Piping OBJECTIVE To address catastrophic failures that have happened in the industry with seamed high energy piping. High energy piping is a concern under these conditions:

• Temperatures greater or equal then 950 degrees F • Pressure greater or equal to 200 psig • Chromium-Molybdenum piping material that is ASTM A 155 class 1 or 2, ASTM A 691 class 11, 12 or

22, and ASTM A 387 Grade B Class 12, Grade C class 11, or Grade D class 22 • Longitudinally welded piping • Piping with greater than 80,000 operating hours

MINIMUM EXPECTATIONS

• It is strongly recommended that piping meeting the adjacent criteria be replaced. Until replacement can be

completed, the following examination will be conducted:

o Acid etch testing should be used to identify sections of piping that are seamed o Complete full piping evaluation that can identify sections under highest stress and loading and

highest traffic areas o Collect metallographic analysis of plug samples collected during next outage in high stress and high

traffic areas identified in (2) above OR

o Insulation will be removed from all seamed high energy piping and full ultrasonic inspection using

time-of-flight defraction and focused phase array techniques will be completed • Inspections and testing of high energy piping and headers should only be performed by qualified firms.

Ultrasonic testing (time-of-flight and focused phased array) are commonly employed. REFERENCE DOCUMENTATION AND EXAMPLES:




4.9 Pressure Vessels OBJECTIVE To define the routine maintenance and inspection requirements associated with pressure vessels. MINIMUM EXPECTATIONS Pressure vessels such as tanks, feedwater heaters, deareators, etc. often have inspection scopes and frequencies dictated by local jurisdiction. Where jurisdictional requirements do not exist, or where the requirements are less stringent than the requirements below, the recommended approach is: • Deaerator flash and storage tanks should be inspected within 12 to 24 months after initial installation.

Inspection should include wet magnetic fluorescent particle testing of a percentage of each tank’s weld seams and heads. Reinspection frequency will depend on inspection results:

o 3 to 5 years if there is no crack found and no repairs are necessary

o 1 to 2 years if minor cracking is observed but no cracks requiring weld repair

o 12 months or less if cracks are found that require weld repair

• The waterbox of feedwater heaters should be inspected at each boiler overhaul

• Air tanks will be inspected in interval in accordance to NBIC and internally inspected by NDE because an internal visual inspection by the port hole will yield no significant information.





4.10 Boiler Feed Pumps OBJECTIVE To define the routine maintenance and inspection requirements for boiler feed pumps. MINIMUM EXPECTATIONS • Overhaul frequency for boiler feed pumps should be determined by pump performance testing and past

history. Industry-wide, typical overhaul frequency is every 5 to 15 years.

• Suction, Discharge and minimum flow valves should be inspected every 5 to 6 years for larger units (>1,000 horsepower) and every 2 to 3 years for units smaller than 1,000 horsepower.

• Units should have at least two pumps provided. At a minimum, each pump will be capable of supplying adequate capacity needed to continue feeding water to the boiler until all residual heat is safely removed following a full load master fuel trip.

o If both pumps are motor-driven, their power supplies will come from separate and independent sources





4.11 Safety Valves OBJECTIVE Properly applied, installed, and maintained pressure relieving devices are essential to the safety of personnel and the protection of equipment. A proactive inspection and maintenance program of pressure relieving devices will ensure that they are capable of providing the required protection. MINIMUM EXPECTATIONS Each facility with pressure vessel equipment (boilers, tanks, piping etc.) will develop and implement an integrated pressure relieving device integrity program that includes: • Maintaining records for all pressure relieving devices including pressure loop diagrams, specifications &

drawings, records of any isolating valves in the pressure loop and inspection and maintenance history of devices.

• Understanding operating pressures for each pressure vessel and the appropriate safety & relief valve settings.

• Testing and inspection criteria based on regulatory compliance, system use, maintenance experience and tolerance limits.

• Replacement & return to service inspection & testing before resuming operations

• Operational considerations – e.g. capacity check method and steam calculations.

• Periodic inspection, testing and maintenance consistent with ASME Boiler and Pressure Vessel Code Sections VII.

o Boiler safety valves should be hydroset tested at least every 2 years.

o Boiler safety valves should be overhauled at least every 5 years unless operational history, local regulations or codes requires more frequent testing.

• For Balance-of Plant safety/relief devices, the following maximum inspection intervals is recommended. Inspection history and local regulations or Codes may require more frequent and thorough inspection requirements. Conversely, if there are no existing mandatory requirements and the inspection history finds specific safety devices to have exceptional service histories, the re-inspection intervals may be further increased by applying a performance based analysis for testing and maintenance.



• ASME tolerance requirements that define the limits for acceptable and defective safety valves.

• Specified annual on-line inspections to be conducted and recorded





4.12 Transformers OBJECTIVE To define the testing and routine maintenance requirements of critical and essential power transformers. By performing the proper routine maintenance that includes insulating oil testing and transformer electrical tests, and by operating the unit within its design operating parameters, a transformer could reasonably be expected to last in excess of 30 years. MINIMUM EXPECTATIONS Each facility with transformers will develop and implement an inspection and maintenance program that includes the following activities. Each facility is expected to adjust the recommended frequencies based on factors such as outage frequency (planned and unplanned), OEM recommendations, plant history, etc.

• For dry transformers, annual inspections and testing should be performed to include:

o Measurement of coil and ambient temperatures with an infrared device o Visual examination of coils for dust, debris or rodent infiltration o Examination of vents for air passage obstruction o Insulation resistance testing

• Daily inspections should be performed by operating personnel to include checks of:

o Conservator oil level o Paint integrity, evidence of corrosion o Oil leakage o Drainage at base of transformer (check for blockage) o Temperatures of windings and oil o Desiccant, breather, refrigerant

• Weekly inspections should be performed on critical transformers by qualified electricians or operating

personnel and include checks for:

o Unusual noises o Restricted airflow across the radiators o Cracked or damaged bushings or arresters o Excessive operating temperatures o Oil leakage or other undesirable conditions

• Monthly inspections of liquid filled transformers should include checks of:

o Load current o Oil, winding and ambient temperatures o Peak indicators recorded and reset o Oil levels for transformers, oil-circuit breakers, tap changers and bushings o Tank pressures on transformers and circuit breakers where applicable o Nitrogen pressures on transformers if applicable



o Operation of fans and circulating pumps o Radiator cleanliness o Condition of controls, relays and wiring o Protective devices o Counter readings from tap changers, circuit breakers, reclosers and disconnects o Visual inspection for cracked or dirty bushings, oil leaks, evidence of overheating or corrosion

• Quarterly inspection and testing should include:

o Transformer dissolved gas analysis (DGA) and dielectric fluid (oil) analysis on critical

transformers o Pressure relief valve inspection o Examination of all major ground connections o Thermographic surveys of critical transformers including cooling systems, air bushing

connections, isophase buss ducts, and transformer tank

• Every 6 months, inspections and testing that should be conducted includes:

o Examination of surge arrestors for cracks, corrosion, and integrity of ground connections o Testing of load tap changers for proper operation o Dielectric strength testing of oil in oil circuit breakers o Transformer dissolved gas analysis (DGA) and dielectric fluid (oil) analysis on essential

transformers o Infrared inspection of transformers and substations

• Annually, the following tests and inspections should be conducted:

o Standard screen testing of insulating oil for dielectric breakdown, interfacial tension, moisture, acidity, color, specific gravity and power factor

o Operational and trip checks of air circuit breakers o Switchgear blade and contact surface check for arcing and general deterioration and operational

checks if condition permits o Calibration and testing of all protective relays, controls and metering devices o Polarization Index (PI) insulation resistance test

• Every 3 years, the following tests should be performed:

o Ground resistance test o Transformer power factor test [Note in the U.S. and U.K Doble testing should be conducted

each year for the first three years and then every three years]

• Every 5 years:

o A remaining life assessment should be performed on each critical transformer o All critical and essential transformers oils will be tested for corrosive sulfur per the latest

available industry standard



• For the latest recommendation on transformer off-line testing, including fault and DGA initiated testing, please refer to the AES Engineering Standard on Transformer Life-Cycle Management





4.13 Miscellaneous Electrical Equipment OBJECTIVE To define the maintenance and inspection requirements of miscellaneous electrical maintenance equipment including circuit breakers, switchgear, disconnect switches, cables & buses, and aluminum conductors. MINIMUM EXPECTATIONS

• For air circuit breakers, annual maintenance and inspections should include:

o Clean insulating material and inspect for signs of corona, tracking, arcing, thermal or physical damage

o Confirm spring pressures as appropriate o Clean arc interrupters as needed, observe for breakage and confirm cleanliness of arc shoots o Inspect operating mechanism for looseness, breakage and excess wear, confirm proper actuation

timing and lubricate as necessary o Inspect auxiliary devices for proper operation and overall condition. Relays and trip devices

should be tested to confirm proper operation

• For vacuum circuit breakers, annual maintenance and inspections should include:

o Perform maintenance as outlined for air circuit breakers o Test vacuum chamber per OEM specifications

• For switchgear, annual maintenance and inspections should include:

o Inspect insulators, supports and connectors for signs of cracking or physical damage o Vacuum cleaned of all dust and debris o Vents and fan grills cleaned o Examine filters and replace as necessary o Confirm proper operation of fan and clean blades as needed

• Air disconnect switches annual maintenance and inspections should include:

o Maintenance as outlined for ACBs o Confirm proper operation of arc blades, linkages and operating rods o Confirm operation using multiple manual cycles o Resistance test all contacts

• Oil circuit breakers annual maintenance and inspections should include:

o External inspection of enclosure for signs of leakage o Clean external components and inspect for signs of deterioration, tracking, loose or broken

parts and check oil level o Conduct screen test of insulating oil o Resistance test all contacts o Open breaker and visually examine if necessary



• Molded case circuit breakers annual maintenance and inspections should include:

o Clean as necessary for proper ventilation

• Cables and busses annual maintenance and inspections should include:

o Perform Polarization Index testing as necessary to track any negative trending o Observe manhole cables for gas accumulation and inspect for sharp bends, physical damage,

proper tension, oil leaks, cable movement, poor ground connections, etc. Inspect concrete for spalling, excessive moisture, etc.

o Inspect aerial cable supports for excessive wear and inspect cable for wear at support points o Inspect raceways for proper support o Inspect cable insulation for damage o Inspect joints for cleanliness and integrity o Perform thermographic survey of bus ducts under maximum load if possible

• When aluminum conductors are used, these should be inspected within six months after installation and

annually thereafter. REFERENCE DOCUMENTATION AND EXAMPLES:




4.14 Fire Protection OBJECTIVE To define maintenance, inspection, modification and impairment requirements for fire protection systems. MINIMUM EXPECTATIONS • Requirements for inspection, test, and maintenance of fire protection systems/equipment are based on

NFPA Standards. Inspection, test, and maintenance activities at AES Facilities along with the frequency and appropriate NFPA reference can be found in the AES Global Insurance Company (AGIC) Fire Protection System Maintenance and Testing Guideline. Some frequencies may differ from those listed in NFPA documents, but in no case is the frequency more restrictive than the NFPA requirement. This was done after careful engineering analysis and in recognition of the unique nature of power facilities and the impracticality of performing some inspection, testing, and maintenance at the prescribed NFPA frequency. It is further recognized that unique situations may arise at some facilities, and those will be considered on an individual case by case basis.

• Fire Protection Valves:

o Inspection fire protection valves monthly to ensure that they remain in their normal position, locked (or sealed), operable and accessible condition in accordance with the AES Fire Protection System Valve Testing Guideline.

o Stroke all fire protection valves to ensure they are operated through their normal stroke at lease annually in accordance with the AES Fire Protection System Valve Cycling Guideline.

• Fire Protection Water Storage Tanks:

o NFPA 25, Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection

Systems, Section 6-2.4 states that the interior of a water storage tank will be inspected every 5 years or every 3 years for steel tanks without corrosion protection. Due to the relativity vague nature of the above referenced NFPA document, test tanks in accordance with the AES Global Insurance Company Fire Protection System Water Storage Tank Guideline.


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