GE Mechanical Fluid Systems

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gGE Power Systems

3. Mechanical/Fluid Systems

Volume IPage

3. Mechanical/Fluid Systems 13.1 Piping Design/Materials/Freeze Protection/Insulation.....................3

3.2 Boiler Drains/Blowdown System....................................................19

3.3 Steam Piping Drains and Vents.....................................................33

3.4 Fuel Gas (FG) System...................................................................47

3.5 Fuel Oil (FO) System.....................................................................693.6 Gas Turbine Piping Systems..........................................................74

3.7 Compressed/Service/Instrument Air (SA/IA) System.....................79

3.8 Nitrogen Blanketing (N2) System...................................................83

3.9 Hydrogen (H2) System...................................................................86

3.10 Carbon Dioxide (CO2) System.....................................................88

3.11 HVAC............................................................................................89

3.12 Fire Protection..............................................................................92

3.13 Auxiliary Cooling Water System................................................102

3.14 Feedwater System......................................................................111

3.15 Condensate System...................................................................115

3.16 Pipe Cleaning/Pressure Testing................................................125

3.17 Systems First Fills......................................................................128

3.18 Access Platforms and Stairways for Power Island Equipment..129

3.19 Steam Water Sampling and Monitoring System........................132

3.20 Gas Turbine Air Processing Unit (APU) Design Considerations

............................................................................................................1343.21 Condenser Circulating Water System.......................................136

3.22 Revision Table...........................................................................141

GE PROPRIETARY INFORMATION Mechanical/Fluid Systems

Volume I ERB DBD (09 March 2004



Volume II

CHEMISTRY GUIDELINES FOR GE STAG 207FACOMBINED CYCLE PLANTS





3.1 Piping Design/Materials/Freeze Protection/Insulation

3.1.1 General

The plant is designed for operating modes ranging from peaking service (dailystarting and stopping) to base load (continuous) service. The plant is designedfor operation on natural gas and fuel oil. Natural gas is the primary fuel withdistillate serving as backup fuel.

The condenser hot well and steam turbine lube oil tank are at ground floorelevation and not in a pit.

•General Components025A/025B Piping

025F Pipe Hangers

0025G Specialty Items

026/027 Standard and Specialty Valves

028 Thermal Insulation and Lagging

056A Temperature Sensors

056C Processor Transmitters

056E Local Gauges

078 Oils and Greases

•See applicable section for Codes and Standards

3.1.2 Piping Design

Drain Piping will have a minimum internal diameter of 25 mm (1 in.) to allowcleaning of the pipe.

Thermowells will be threaded boss-type. Instrument connections will be DN20 (3/4”).

Pipe wall thickness is determined in accordance with ASME B31.1, for powerpipng or B31.3 for process piping. A minimum corrosion/erosion allowance of1.5 mm (1/16 in.) is included for all chrome moly and carbon steel piping. Forflashing, erosive service P5 chrome moly is used with 2.5 mm (0.10 in.)erosion allowance.

For oil or fuel piping no corrosion protection is required.





ASTM A106, Grade B piping DN 50 (2”) and smaller is a minimum Schedule80 wall thickness. ASTM A312, Grade TP304 piping DN 50 (2”) and smaller

is a minimum Schedule 40 wall thickness. Stainless steel piping to be aminimum of Schedule 40S wall thickness.

Permissible use of flanges for all welded systems is restricted to connections toequipment and/or to frequent maintenance items. Threaded pipe connectionswill not be permitted except in specific cases.

All main cycle piping is open butt welded with root pass using gas tungsten arcwelding (GTAW) process. Backing rings will not be permitted.

Pipe and valve sizes DN 90 (3-1/2”) and DN 125 (5”) will not be used.

Design of piping to include provision for installation of temporary jumpers orbypasses to accomplish an effective cleaning of the system after installation.

The ASTM A335 Grade P (T) 91 piping/tubing material, when used, requiresspecial attention during procurement, fabrication and welding. Therecommendations of EPRI 1006590 – “Guideline for Welding P (T) 91” shalbe followed when using this material.

3.1.3 Piping Material Specifications

GE Spec. No.(Ref. Only)

Service GE SystemDesignation

ANSIClass

Pipe Material(See GE Spec. for

Valve, Flange, ThreadedConnections etc.Materials)

M101 General Purpose [T = 204oC (400oF)max.]

Wastewater (Pumped Drains)Condensate

GP1

WSTCD1

125 Carbon SteelASTM A106 Gr. B or A53Gr. B

M102 Service Air

Potable Water

SA1

PW1

125 Use M146

M103 General Purpose [T = >204oC(400oF)] Saturated SteamCondensate

GP2SS1CD2

150 ASTM A53-BASTM A106-B

M104 General Purpose [T = 204oC (400oF)

max.]Raw Water

Oil Tank Vent/Gen. VentsExhaust Frame Cooling AirGenerator H2 SupplyAir Processing

GP3

RWMVFC

H2AP

150 Carbon Steel

ASTM A106 Gr. B orA53 Gr. B







ANSIClass


Valve, Flange, ThreadedConnections etc.

Materials)

M105 General Purpose [T = 204oC (400oF)Max.]Feedwater

GP4FW1

300 ASTM A53-BASTM A106-B

M106 General Purpose [T = >204oC(400oF)]

Compressed/Service Air

GP5

SA3

300 Carbon Steel

ASTM A106 Gr. B or A53Gr. B

M107 General Purpose

Feedwater

GP6

FW2

400 ASTM A106-B


Saturated Steam

GP7

SS3

600 ASTM A106-B


Saturated Steam

GP8

SS4

600 ASTM A106-B

M110 Feedwater FW3 600 Use M108

M111 Steam – Main/Hot Reheat

Auxiliary Steam

MS2/HR1

AS

600 Alloy Steel (1.25% Cr –0.5% Mo)

ASTM A335-P11

M112 General Purpose GP10 900 Carbon Steel

ASTM A106 Gr. B


M114 Steam – Main/Hot Reheat MS3/HR2 900 Alloy Steel

ASTM A335-P11M115 General Purpose

Steam – Main

GP11

MS4

1500 Carbon Steel

ASTM A106 Gr. B


M117 1500 Alloy Steel (1.25% Cr –0.5% Mo)

ASTM A335-P11

M118 Fuel Gas

Fuel Oil [T = 204oC (400oF) max.]

FG1

FO1

150 Carbon Steel

ASTM A106 Gr. B ASTMA53 Gr.or B, ASTMA312-TP304L

M119 Fuel GasFuel Oil [T = 204oC (400oF) max.]

FG2FO2

300 Carbon SteelASTM A106 Gr. B A53Gr. B or ASTM A312-TP304L

M121 Lube Oil LO 150 Use M103 or ASTMA312-TP304L

M123 Fuel Oil

Fuel Oil

FO3

FG4

600 Use M108

M125 Low Pressure Carbon Dioxide CO2 300 Carbon Steel Galvanized







ANSIClass



Materials)

ASTM A106 Gr. B,threaded connections upto 3 “ bore pipes.

M126 Sanitary/Site Drains SD None Carbon Steel GalvanizedASTM A106 Gr. B

M128 Cooling Water

Air Removal

CW

AR

125 Carbon Steel


M129 Fire Protection (Above Grade) FP1 125 Carbon Steel


M130 Chemical Feed (Injection) CF1 600 Stainless SteelASTM A312-TP304

M131 Demineralized Water DW1 125 Stainless Steel

ASTM A312-TP304 or TP316L

M133 Gas Turbine/Base/Skid Drains GTD 125 Carbon Steel


M134 Fire Protection FP2 150 Use M104

M135 Demineralized Water DW2 125 Carbon Steel, SaranLined, Dow Chemical orASTM A312-TP316L

M136 Cooling Water CW2 150 Use M103

M137 Condensate CD3 150 Use M104

M138 Fire Protection (Under Grade) FP4 125 Carbon Steel Galvanized,ASTM A106 Gr. B

Ductile Iron, ANSI A21.51

M139 Fire Protection (Under Grade) FP5 125 Carbon Steel Galvanized,ASTM A106 Gr. B


M141 Hydrogen H2 150 Use M103

M144 Boiler Blowdown and Drains BD 600 Use M108?

M146 Instrument Air

Potable Water

IA

PW2

125 Copper, ASTM B88,

galvanized carbon steelor ASTM A312-TP304L.

M147 Fuel Gas FG3 300 Stainless Steel

ASTM A312-TP304

M148 Drain Oil D 150 Use M103

M149 Chemical Feed (Injection)

Sampling and Analysis

CF2

SMP

1500 Stainless Steel

ASTM A312-TP304

M150 General Purpose GP12 150 Stainless Steel







ANSIClass



Materials)

Water Wash WW ASTM A312-TP304


Water Injection Inlet Air Heating

GP13

WI

600 Stainless Steel

ASTM A312-TP304

M152 Fuel Gas FG4 600 Use M108

M153 Circulating/Auxiliary/Closed CoolingWater

CCW1 125 Carbon Steel


M154 Circulating/Auxiliary/Closed CoolingWater

CCW2 125 Red Brass, ASTM B43


M155 General Purpose [T = 204oC (400oF)max.]

Hydraulic Oil Return

GP14

HOR

300 Stainless Steel

ASTM A312-TP304

M160 Fuel Oil Underground

Note:

Use of this material must have chiefEngineer approval. Notrecommended if the contractor is nottrained.

FO4 TBD Rigid Bondstrand CX-3000A fiberglass doublecontainment pipe.Underground serviceonly. –29oC (-20 oF) to+99oC (+210 oF) or ASTMA312-TP316L

M161 Underground piping for the following:Fire Protection

Raw Water

Potable Water

Service Water

Demineralized Water

Sanitary Drains

Water Wash (supply to skid)

Waste Water (where temperature is

less than 60o C (140oF))

FP

RW

PW

SW

DW

SD

WW

WST

160 working

presstest

240psi

HDPE pipe material PE-3408 Rating DR 11, orASTM A312-TP316L

Heat fusion connectionsat HDPE joints andFlange connections withdissimilar materials

Ductile Iron joints mayuse MJ adapters

M175 Oil Feed to Bearing (Bearing Oil)

Oil Drain from Bearing (Drain Oil)

Vent Connection on Oil TankAir Vent Trap

Oil to Coupling Cooling Line

Oil Guard Line

OFB

ODB

AVSAVST

OCB

OGL

150 Use M104

Or ASTM A312-TP304L

M176 Steam Seal Line to Packings

Steam Exhaust from Packings

Steam Seal Regulator Exhaust

Steam Shaft Packing Re-entry

SSP

SSE

SRE

SSPR

150 Use M103







ANSIClass



Materials)

M177 Valve Stem Leak-off (Inner)

Valve Stem Leak-off (Outer)

SVLI

SVLO

600 Use M108 ?

M178 Shell Drain SSD 1500 Use M117 ?

M179 Steam Seal Line to Packings

Steam Exhaust from Packings

SSP

SSE

150 Use M104

M180 Steam MS1 300 Alloy Steel (125% Cr –0.5% Mo)

ASTM A335-P11

M181 Oil Feed to Bearing (Bearing Oil)

Oil Drain from Bearing (Drain Oil)

OFB

ODB

150 Use M103, or

ASTM A312-TP304L

M182 Vacuum Breaker VAB 125 Use M101

M200 Main Steam MS5 2500 Alloy Steel (2.25% Cr –1.0% Mo)

ASTM A335-P22

M202 Main Steam MS6 2500 Alloy Steel (9 Cr-1 Mo-V)ASTM A335 Gr. P91

M203 Hot Reheat MS7 900 Alloy Steel (9 Cr-1 Mo-V)ASTM A335 Gr. P91

Notes

• GE piping material specifications can be used for reference only. (Replace with piping materialspecifications for specific power plant project.)

• For secondary piping containment requirements, refer to section 8, Environmental Engineering.

• Use of Electric Resistance Welded (ERW) pipe is acceptable if the design and procurement adheres toASTM specification application limits along with GE Engineering concurrence for each system.

3.1.3.1 Critical Valves

The valves for critical piping systems shall meet special NDT requirements.

The special NDT requirements apply to the following valves:

A. Standard or Special Class cast valves 4in. NPS or larger designed to ANSIB16.34 in critical piping system as defined below.

B. Standard or Special Class forged valves 4in. NPS or larger in critical pipingsystem as defined below.

C. The critical piping systems are defined as:

— Main Steam, Cold Reheat, Hot Reheat, Intermediate PressureSteam, Low Pressure Steam Systems

— HP, IP and LP Steam Bypass systems

— Boiler Feedwater (HP and IP FW pump discharge)





D. Valves under the jurisdiction of ASME Boiler and Pressure Vessel Codeshall meet the requirement of the Code.

3.1.3.1.1 NDT Requirement:

Cast Carbon Steel and Alloy Valves (ASTM A216/A217)

• Hydrostatic Testing per ANSI B16.34

• Radiographic Examination – body/ bonnet/cover per ANSI B16.34

• Surface Examination – all exterior and accessible interior parts of

body/bonnet/cover shall be examined by a liquid penetrant examination or amagnetic particle examination per ANSI B16.34.

• Test reports for all tests performed are required

Welding Considerations

GE Steam Turbine Product Department requires special weldingconsiderations to the piping attached to the steam turbine casing. The A/E shalreference these GE procedures on the piping arrangement drawings as well asthe Project construction/erection specifications given to the installationcontractor.

Forged Carbon Steel and Alloy Valves (ASTM A105/A182)

• Hydrostatic Testing per ANSI B16.34

• Ultrasonic or Radiographic Examination - body/ bonnet/ cover per

ANSI B16.34.

• Surface Examination – all exterior and accessible interior parts of

body/ bonnet/ cover shall be examined by a liquid penetrant examination ora magnetic particle examination per ANSI B16.34.

• Test reports for all tests performed are required.

3.1.4 Allowable Fluid Velocities (***) Akışkan HızlarıSERVICE VELOCITY

Steam

Superheated steam 35 to 76 m/s (7,000 to 15,000 feet/min)

Saturated steam 20 to 50 m/s (4,000 to 10,000 feet/min)

Subatmospheric steam 76 to 152 m/s (15,000 to 30,000 feet/min)

Intermittent steam bypass 36 to 127 m/s (7,000 to 25,000 feet/min)





SERVICE VELOCITY

Two phase flow (liquid/gas) < 23 m/s (75 feet/second)

Water

Circulating water

< DN 1800 (72 “) Pipe 1.8 to 2.4 m/s (6 to 8 feet/second)

> DN 1800 (72 “) Pipe 2.7 to 3 m/s (9 to 10 feet/second)

Boiler feedwater

Suction 1.8 to 2.4 m/s (6 to 8 feet/second)

Discharge 1.8 to 3.7 (6 to 12 feet/second)

Condensate

Suction 0.3 to .9m/s (1 to 3 feet/second)

Discharge 1.8 to 3 m/s (6 to 10 feet/second)

General Service

Suction .9 to 2.1 m/s (3 to 7 feet/second)

Discharge 1.8 to 3.7 m/s (6 to 12 feet/second)

Gravity 0.9 to 1.5 m/s (3 to 5 feet/second)

Gases

Compressed air 4.6 m/s to 22.9 (900 to 4,500 feet/min)

Fuel Gas

Piping 15.2 to 27.9 m/s (3,000 to 5,500 feet/min)

Compressor (suction and discharge) < 18.3 m/s (60 feet/second)

Oils

Lube oil

Supply < 2.1 m/s (7 feet/second)Drain < 0.6 m/s (2 feet/second)

Fuel oils

Tank fill lines < 0.9 m/s (3 feet/second)

Distillate and crude

Suction .6 to 1.2 m/s (2 to 4 feet/second)


Residual

Suction 0.15 to .3 m/s (0.5 to 1 feet/second)


3.1.5 Pipe Stress Analysis and Flexibility

All steam and elevated temperature and pressure water piping systems are tobe analyzed to verify compliance with applicable design codes. Such analysisshall be performed to include all operating cases consistent with 3.1.6.1.6Piping which normally operates in a cold state, but which is expected tooperate occasionally at elevated temperature is included in the aboverequirements.





3.1.5.1 Piping Analysis

The loading conditions used in piping system analysis shall be in accordance

with the above requirement and ASME B31.1, or ASME B31.3 . except whenPED codes are applicable or customer contract requirements. Piping supportstructures and associated support elements shall be designed per AISC Manualof Steel Construction, or similar superseding code, derated for temperatureeffects when applicable.

Component drifts due to wind and seismic loads are to be a piping designconsideration. In addition to the design code requirements applicable to thepipe runs when motion limits (displacements and rotations) are defined for acomponent, such as the HRSG, the pipe and its supports must be designed tonot exceed those permissible motion limits.

3.1.5.1.1 Deadweight

The effects of the pipe, fluid and insulation weights shall be considered asapplicable. In addition, riser clamps, trapeze style support steel and pipeclamps shall be included in the piping analysis to include significant hardwareweights in excess of one linear foot of the piping to be supported.

3.1.5.1.2 Thermal Expansion

The thermal operational modes of the piping system shall be identified where

applicable.

3.1.5.1.3 Seismic Conditions

The effect of earthquakes shall be based on seismic design as specified.

3.1.5.1.4 Wind Conditions

All piping exterior to the powerhouse building or other enclosed structuresshall be subject to wind loading including piping on structural bridges. Windpressure will be applied to the exposed piping in the lateral directions. Wind

forces will be calculated in accordance with Contract requirements.

3.1.5.1.5 Steam Hammer Conditions

Perform a dynamic stress analysis to evaluate the impact of steam hammer onthe applicable piping systems utilizing the Ceaser II stress analysis program orequivalent.





3.1.5.1.6 Operating Conditions

Various operating modes for the subject piping systems (pressure and

temperature distribution) shall be analyzed to insure piping stress andequipment nozzle reactions are within acceptable design parameters during allphases of system operation including startup, part load, base load, shutdownand any combination of units running and shut down. Refer to the HP sectionof Tab 2, Main Steam System, for typical operating scenarios to be considered.

3.1.5.1.7 Special Piping Components

Valves with large and heavy operators shall be modeled with the weight of thevalve and the weight of the operator.

The effects of thermal expansion, deadweight, other sustained loads andoccasional loads must meet the following limits as defined in ASME B31.1 orASME B31.3. (Refer to ASME B31.1 or ASME B31.3 for description ofnomenclature.)

Equipment nozzle loads and displacements shall be evaluated as follows:

1. Valve and pipe flange nozzle loads shall be considered acceptable if theadjacent pipe weld or flange (as applicable) stresses are within Codeallowables.

2. Turbine casing nozzle reactions shall meet the requirements provided byGE. Turbine-supplied valves, piping leads and thermal nozzle

displacements must be provided, where applicable, for input to pipingflexibility analyses. Analysis shall be run to the turbine casing.

3. Analysis is required for the following remaining Balance of Plant pipingsystems:

— Steam turbine drains

— HRSG drains

— Fuel gas (heated for performance enhancement or subject tosolar radiation)

— Fuel oil (subject to solar radiation)

— Any remaining systems with temperatures above 149°C (300oF)

— For those systems operating below 149°C (300oF), the design

should reflect good engineering practice with respect to thermalgrowth, flexibility, pipe support, locations and terminal point loadings.





3.1.6 Pipe Drainage

All superheated steam lines shall be sloped 8 mm per 1000mm (1” in. per 10

ft.) of pipe run in the cold position and 4 mm per 1000 mm (½” in. per10 ft.)of pipe run in the hot position.

All saturated steam lines shall be sloped 8 mm per 1000 mm (1 in. per10 ft.) ofpipe run in the cold position and 4 mm per 1000mm (1/2 in. per 10 ft.) of piperun in the hot position.

3.1.7 Freeze Protection

The following provide general guidelines in determining the extent of freezeprotection for power plant systems and components. Final design criteria will

be based on site-specific conditions and applicable local codes.

• Degree of treatment is highly dependent on duration of sub-freezing

temperature.

• Minimum areas requiring insulation and heat tracing are:

— Sensors/transducers and associated sensing lines

— Low points of instrument and compressed air systems

— Above ground water lines 4” (100mm) and smaller down to thefirst below grade elbow for systems such as

—

Raw Water — Demineralized water





— Emergency outdoor eye wash and shower stations

– Circulating water pump bearing flush lines

– Miscellaneous system drains with normally closed drain valves.

• More extensive protection may include:

— Heating of fuel oil

— Enclosure of the HRSG

— Heating of water tanks

— Addition of circulating pump house building

— Addition of turbine-generator building

— Large > 4” (100 mm) water lines

• Extended shutdown may require:

— HRSG draining

— Draining above grade cooling tower header(s)

— Draining of all above grade non-heat traced water piping andequipment (condensate, boiler feedwater, demineralized water,auxiliary cooling water, gas turbine water injection, etc.)

3.1.8 Insulation

Outdoor piping is heat traced when the minimum site ambient is below 0oC(32oF). Freeze protection is included.

3.1.8.1 General

All piping, tanks, pressure vessels and equipment shall be insulated, that:

• Transmit heat, resulting in an economic loss, and have a surface

temperature of at least 60oC (140oF) during normal operation, or

• Will form external condensation, or

• Will endanger station personnel, or

• Must be protected from freezing.

The site design conditions shall be as listed in the Site Data Specification.

For insulation material in French Standards NF P 52-306-1 & NF P 52306-2,in US GE MIL I-24244 or local applicable codes.





All outdoor piping and equipment shall be suitably insulated with the materialsspecified, and unless otherwise stated, to a thickness such that with ambient airat 25oC (77oF) and 4.5 m/s (10 mph) wind speed, and screened from solar gain,

the surface temperature of the insulating material or jacketing shall not exceed60oC (140oF), unless specifically noted otherwise. All indoor piping andequipment shall be suitably insulated with the materials specified, and unlessotherwise stated, to a thickness such that with ambient air at 30 oC (86oF) and a0.60 m/s fps (1.0 mph) local air velocity, the surface temperature of theinsulating material or jacketing shall not exceed 60oC (140oF), unlessspecifically noted otherwise. Multiple layers shall be used where total thicknessexceeds 75 mm (3 in.). No individual layer shall exceed 75 mm (3 in.) inthickness.

Piping and equipment to be insulated for personnel protection shall be insulated

to a height of 2.4 m (8 ft) above floors and platforms and within 1 m (3 ft)horizontally of all platforms and walkways.

Valves, flanges and similar in-line items shall be insulated, except as otherwisespecified. All insulated surfaces of equipment, ductwork, piping and valvesshall be jacketed.

All outdoor insulation shall be weatherproofed as specified herein. Outdoorpiping shall be defined as piping not interior to building walls, not inside theexterior column lines of open type canopied buildings.

Thermal insulation and jacketing shall be applied to:

A. The entire drip leg of steam piping, and connected drain valving, trap andstrainer. Beyond the downstream isolation valve and bypass valve, thecondensate piping shall be insulated for personnel protection only for atemperature equal to steam pressure saturation temperature at upstream.

B. From pipeline header to and including root valve, or both valves whendouble valved, of all instrumentation/isolation valves and normally closedpipeline drains and vents when pipeline is insulated.

C. From pipeline header to and including the inlet flange and lower body halfof safety and safety/relief valves.

3.1.8.2 Insulation Materials

Material furnished under this Specification shall be asbestos free, standardcatalogued products, new and commercially available, suitable for servicerequiring high performance and reliability with low maintenance, and free of aldefects. The use of pre-fabricated standard products shall be maximized.





3.1.8.2.1 General Requirements

A. Insulation materials shall be inhibited and of low halogen content so that

the insulation meets the requirements of MIL I-24244, Amendment 3regarding stress corrosion cracking of austenitic stainless steel.

B. All materials and integrated insulation assemblies furnished shall have flamespread ratings of not over 25 (fire resistive) and a smoke developed ratingof not over 50, as established by tests conducted in accordance with ASTME84, NFPA 255 and UL 723. The treatment of jackets or facings to impactflame and smoke safety must be permanent. (The use of water-solubletreatment is prohibited.)

C. Adhesives, coatings and vapor barrier materials shall be asbestos free andof types with approved compatibility as recommended for use by theinsulation manufacturer. Contractor shall be able to submit a certified

statement attesting to its approval. The following adhesives and coatings,as manufactured by Foster Division, H.B. Fuller Co. or Childers ProductsCo. are representative of approved products that meet the aboverequirements. (Other manufacturers who demonstrate to the Owner thattheir products are equivalent are acceptable.)

Lagging adhesive 30-04, CP50Vapor barrier coating 30-35, CP30Vapor seal adhesive 85-75, CP82 or Armstrong 520Duct adhesive 85-20, CP82Sealing compound adhesive 30-45, CP70Weatherproof mastic 35-01, CP10-1 or Manville “Insulkote”

3.1.8.2.2 Material Specifications

Mineral or Glass Fiber Preformed Pipe Insulation, ASTM C547, Class 1Nominal density – 160 kg/m3 (10 lb/ft3), semi-rigid“K” value – 0.046 W/m-K at 93oC (199oF) mean temperatureFor operating temperatures up to 230oC (446oF)Approved product – Certainteed Snap*on

Mineral or Glass Fiber Preformed Pipe Insulation, ASTM C547, Class 2Nominal density – 192 kg/m3 (12 lb/ft3), semi-rigid“K” value – 0.057 W/m-K at 93oC (199oF) mean temperatureFor operating temperatures up to 398oC (748oF)

Mineral or Glass Fiber Blanket Insulation, Metal Mesh Covered, ASTMC592, Class II, for equipment where removal is necessary for maintenance

Nominal density – 192 kg/m3 (12 lb/ft3), minimum“K” value – 0.061 W/m-K at 93oC (199oF) mean temperatureWoven wire mesh, both sidesFor operating temperatures as rated by manufacturer

Calcium Silicate Block and Preformed Pipe Insulation, ASTM C533, Type I





for Piping, Equipment and DuctworkNominal density – 240 kg/m3 (15 lb/ft3)“K” value – 0.102 W/m-K at 371oC (700oF) mean temperatureFor operating temperatures above 340oC (644oF)

Mineral Fiber Block Semi-Rigid Insulation, ASTM C512, Class 3 for Equip-ment and Ductwork

Nominal density – 192 kg/m3 (12 lb/ft3)“K” value – 0.040 W/m-K at 93oC (199oF) mean temperatureFor operating temperatures above 454oC (849oF)

Flexible Elastomeric Cellular Insulation, Antisweat & Anti-noise, ASTMC534

Nominal density – 48 kg/m3 (3 lb/ft3) to 136 kg/m3 (8 lb/ft3)“K” value – 0.433 W/m-K at 24oC (75oF) mean temperature

For operating temperatures 18o

C (64o

F) to +49o

C (120o

F)Approved product – Armstrong “Armaflex”Use calcium silicate where strength is required at supports

Mineral Fiber Finishing Cement shall be asbestos free, meet the requirementsof ASTM C449, and be suitable for a temperature up to 538 oC (1000oF). Itshall be a fast drying cement and provide a smooth surface after drying.

Mineral Fiber Thermal Insulating Cement shall be asbestos free, meet therequirements of ASTM C195, and be suitable for a temperature up to 870 oC(1600oF).

All outdoor insulated piping or equipment shall have weatherproof, aluminum-zinc coated steel jacketing with factory applied.. Designation for coatingthickness shall be no less than AZ180 per ASTM A-792M. Thickness oflagging shall be a minimum of 0.40 mm (16 mil) for all piping and equipmentBands shall be Type 316 stainless steel, minimum of 12 mm (1/2 in.) wide. Thepainted and galvanized metal jacketing shall be the equal of Insul-mate AZ-60as manufactured by RPR Products, Inc. The Contractor shall state theminimum quantity of any combination of lagging thickness, size and color toprovide for economical order lots.

Reusable Fabric Wrap Insulating Jackets shall be pre-engineered Teflon coated

fiberglass fabric rated to 260

o

C (500

o

F). Secure with lacing and lacing hooksover valving, etc. requiring maintenance.

Weatherproof Mastic shall be Childers CP-10/11 or approved equal. Sealingmaterial shall be Childers CP-70 or other compatible sealant suitable for theapplication.

Vapor Barrier Mastic shall be Childers CP-30 or approved equal. A compatible joint sealant such as Childers CP-76 shall be used.





Adhesives, coatings and sealants shall be compatible with insulation.

3.1.8.3 Insulation Thickness (***) İzolasyon Kalınlıkları

The following table is representative of typical insulation thicknessrequirements. Project specific requirements shall apply.

MINIMUM INSULATION THICKNESS, mm (in.)

FLUID TEMPERATURE RANGE 399oC

(750oF)

454oC

(850oF)

510oC

(950oF)

Pipe Size -18oC

(-0.4oF) to

49oC

(120oF)

50oC

(122oF)

to 120oC

(249oF)

121oC

(250oF)

to 176oC

(349oF)

177oC

(351oF) to

232oC

(450oF)

233oC

(451oF)

to 287oC

(549oF)

288oC

(550oF) to

343oC

(649oF)

344oC

(651oF) to

398oC

(748oF)

399oC

(750oF) to

454oC

(849oF)

455oC

(851oF)

to 510oC

(950oF)

> 510oC

(950oF)

DN 40(1-1/2”.)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

50mm(2 in.)

50mm(2 in.)

50mm(2 in.)

63mm(2.5 in.)

63mm(2.5 in.)

75mm(3 in.)

DN 50(2 “)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

50mm(2 in.)

63mm(2.5 in.)

63mm(2.5 in.)

63mm(2.5 in.)

75mm(3 in.)

88mm(3.5 in.)

DN 65(2.5 “)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

38mm(1.5 in.)

50mm(2 in.)

50mm(2 in.)

63mm(2.5 in.)

88mm(3.5 in.)

88mm(3.5 in.)

DN 80(3 “)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

50mm(2 in.)

63mm(2.5 in.)

63mm(2.5 in.)

75mm(3 in.)

88mm(3.5 in.)

100mm(4 in.)

DN 100(4 “)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

50mm(2 in.)

63mm(2.5 in.)

63mm(2.5 in.)

75mm(3 in.)

88mm(3.5 in.)

100mm(4 in.)

DN 125(5 “)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

63mm(2.5 in.)

75mm(3 in.)

75mm(3 in.)

88mm(3.5 in.)

100mm(4 in.)

113mm(4.5 in.)

DN 200(8 “)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

75mm(3 in.)

88mm(3.5 in.)

75mm(3 in.)

88mm(3.5 in.)

100mm(4 in.)

113mm(4.5 in.)

DN 250(10 “)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

75mm(3 in.)

88mm(3.5 in.)

75mm(3 in.)

88mm(3.5 in.)

100mm(4 in.)

125mm(5 in.)

DN 300(12 “)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

63mm(2.5 in.)

75mm(3 in.)

88mm(3.5 in.)

100mm(4 in.)

113mm(4.5 in.)

125mm(5 in.)

DN 350(14 “)

25mm(1 in.)

25mm(1 in.)

25mm(1 in.)

50mm(2 in.)

63mm(2.5 in.)

88mm(3.5 in.)

88mm(3.5 in.)

100mm(4 in.)

113mm(4.5 in.)

138mm(5.4 in.)

DN 400(16 “) & Up

25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

50mm(2 in.)

75mm(3 in.)

88mm(3.5 in.)

88mm(3.5 in.)

100mm(4 in.)

125mm(5 in.)

138mm(5.4 in.)

Equipment 25mm(1 in.)

25mm(1 in.)

38mm(1.5 in.)

50mm(2 in.)

75mm(3 in.)

88mm(3.5 in.)

100mm(4 in.)

113mm(4.5 in.)

125mm(5 in.)

150mm(6 in.)

ASTMMaterial

C534 C547 C2 C547 C3/C533 T1 C533 T1

For applicable insulation classes and operating temperatures, see the Piping Line List. The last field of the piping designation is the insulation class.N No insulation required, i.e. bare pipe.H Insulation is required for the conservation of heat energy.F Pipeline must be protected against freezing by the application of electric heat tracing and insulation.A Pipeline must be insulated and vapor sealed to prevent condensation forming on the piping exterior surface because of lower than ambient

wet bulb temperature of fluid. In-door piping only.P Insulation is required only in areas where not (> 55oC (131oF)) piping surfaces could be touched by plant personnel during normal work

duties.

Where freeze protection cable is to be installed on piping which is otherwise insulated for heat conservation or personnel protection, the total thickness ofinsulation before the application of the cable shall be per the table above for the applicable temperature and pipe size, less DN 15 (1/2 in.). The freezeprotection cable will be installed beneath an additional outer insulation layer of 13 mm (1/2 in.) thickness of the same type of material as that specified for theoriginal insulation.





3.2 Boiler Drains/Blowdown System

3.2.1 System Description

The boiler vents and drains (BD) system performs the following functions:

• Conveys the startup blowdown of the HP, IP and LP steam drums to the

blowdown tank. Startup blowdown is used to assist in controlling waterlevel in the steam drums during startup.

• Boiler Drains and Blowdown system is used to control the cycle water

chemistry by varying chemical concentration in the cycle water.

• Conveys the intermittent blowdown of the HP, IP and LP steam drums to

the blowdown tank. Intermittent blowdown is used to reduce solids thatcollect in the steam drums and/or lower headers during normal operation.It is operated intermittently, usually shortly after the HRSG is shut downand still pressurized.

• Conveys the continuous blowdown of the HP, IP and LP steam drums used

during normal operation to the blowdown tank. Continuous blowdown isused in conjunction with the chemical feed system to control the steamdrum water chemistry.

•Provides water/steam drains from the HP, IP and LP economizers to theblowdown tank.

• Provides water/steam drains from the HP, IP and LP superheaters, steam

piping and bypasses to the blowdown tank.

• Provides water/steam drains from the HP, IP and LP drum gauge glasses

and water column to the blowdown tank.

• Provides piping from water relief valves, (IP economizer and LP

economizer) to the blowdown tank.

•Provides drain piping from steam drum and steam pipe safety valves andsilencer drains to the blowdown tank.

• Provides drain piping from the HRSG reheater to the blowdown tank.





During operation, water is blown down into the blowdown tank as awater/steam flashing mixture. In the tank, the steam is vented to atmosphere

through an open vent pipe on the top of the tank while the water is dischargedfrom the tank to the plant drains system. The discharge from the tank isthrough a riser pipe within the tank that maintains a minimum level in the tank.The blowdown tank is equipped with an overflow line that TEES off of thevent line at the top of the tank and ties into the wastewater drain line.

The blowdown tank drains should be located in an area clear of anyelectrical/control cable as well as any other structure which may be damageddue to drain side steaming.

One (1) blowdown tank including piping and valves is provided per HRSG toreceive blowdown and water/steam drains.

3.2.2 Major Components

007BA Blowdown Tank Qty-2

GT Frame Size Tank Diameter Straight Shell Height

7F/7H 6 ft (1.8m) 10 ft (3m)

9F/9H 8 ft (2.5m) 12 ft (3.7m)

The blowdown tank is a vertical atmospheric tank designed, fabricated andstamped in accordance with the ASME Boiler and Pressure Vessel Code,Section VIII, Division 1.

The blowdown tank is constructed of carbon steel, SA-570, Grade 70 with adesign pressure of 3.5 kg/cm2,g (50 psig) and a maximum operating pressureof 0.35 kg/cm2,g (5 psig). A corrosion allowance of 1.6 mm (0.06 in.) orhigher, if required per the applicable code, is included. The tank diameter andshell height dimensions will be checked during the design cycle to assure thatthe tank has adequate space for blowdown separation and condensate levelsurge during startup or abnormal operation. The tank should be located in a pit(below ground) adjacent to the HRSG to facilitate gravity draining of thesystem. If the blowdown tank is located above grade and gravity draining ofthe entire system is not possible then precautions need to be made to prevent

drains systems “cold legs” from freezing during extended shutdowns in areaswith cold climates. In addition the above ground tank must allow for enoughslope to insure that there is no standing water in the tubes and headers locatedin the gas path of the HRSG. We want to avoid thermal shocking these pipingsystems with cold and hot gas.

Also provisions must be made (low point drain valves) to allow for totasystem drainage.





The tank is a vertical, cylindrical type tank in which blowdown enterstangentially. The high velocity steam/water blowdown mixture hits acircumferential wear plate mounted on the shell of the tank. Condensate

separates from the steam and drops to the water collected in the lower portionof the tank. Steam is vented to atmosphere through a vent pipe attached to thetop of the tank. The vent pipe diameter will be checked during the design cycleto assure that the tank is adequately vented to maintain a maximum of 5 psigpressure during maximum flow, i.e., meets the ASME Boiler and PressureVessel Code.

The tank should be designed at 5% of HRSG guarantee flow rate. However,the vent and drain of the tank and the quench water line should be sized at15% of the HRSG guarantee flow rate to handle the maximum flow to theblowdown tank during intermittent blowoff. The tank shall be sized such that

the flash steam velocity through the tank annular area will be 0.8 m/s (2.5ft/sec) or less. The flash steam vent shall extend one (1) meter (3 feet) into thetank.

At a minimum, the tank will have the following connections and instruments:

Inlet Continuous and intermittent blowdown headers from IP/LP circuit

Inlet Continuous and intermittent blowdown header from HP circuit

Inlet Startup blowdown header from HP/IP/LP circuit

Inlet Economizer relief valve drains and HRSG maintenance drains header

Outlet Steam vent pipe to atmosphere

Outlet Water discharge pipe to blowdown sumpInspection openings

Pressure gauge

Thermometer well

Gauge glass

3.2.3 Design Criteria/Limits

3.2.3.1 Mechanical Criteria

A. The tank shall be one (1) FOR EACH HRSG

B. The vent size shall be 24 in. minimum and equipped with silencer. Ventpipe sized for 1psi pressure drop max. plus 1psi silencer pressure drop

C. Tank porcupines shall be individual, one for each pressure level

D. The porcupine cross sectional area shall be 10 x sum of all drains area, 2spare connections shall be provided on each porcupine. The porcupineshall be schedule 80 pipe, the HP porcupine material shall be chrome molysteel P11.





E. All drains piping shall be designed for 2 phase flow.

F. Manual maintenance drains shall be provided at all drains allowingcomplete draining of the HRSG (blowdown tank above groundinstallations).

G. The IP/LP Econ. Relief valves (as applicable) shall be routed to the BDtank separate from the porcupines.

H. The HP/IP startup blowdowns shall be routed to the BD tank separately.

I. The HP, SH and RH startup drains valves shall be motor operated. TheHP, SH valves shall have intermediate position (valve goes to theintermediate position if pressure is> 125psig).

J. The CR/IP/LP startup drain valves shall be pneumatically actuated (FOfailure mode).

K. The BD tank shall have a quenching water supplied to the shell of the tank

to limit the outlet water temp. to 140 °F max. The quenching water systemshall include a TCV valve with the manual bypass and a TE located in tankoutlet piping.

3.2.3.2 Process Criteria

The design pressure of the startup and intermittent blowdown piping from thesteam drums up to and including the blowdown valves shall be equal to themaximum allowable working pressure of the HRSG plus 25%.

The design pressure of the continuous blowdown piping in the piping from the

steam drum up to and including the blowdown valves shall not be less than thelowest set pressure of any safety valve on the drum.

The design pressure of the maintenance drain piping from the HRSG drainconnections including the required valve(s) shall be equal to the pressure of thedrain connection. Static head and choked flow conditions shall be considered.

The design pressure of the HRSG relief valve drain piping will be thedetermined from the design pressure of the highest HRSG relief valvedischarge connection or the design pressure of the HRSG maintenance drainpiping connected to the relief valve header, whichever is higher.

The design pressure of the steam drum and steam pipe safety valves drains andthe silencer drains will be the same as the design pressure of the highest safetyvalve discharge connection.

The design temperature of the startup and intermittent blowdown piping fromthe steam drums up to and including the blowdown valves shall be equal to thetemperature of saturated steam at the maximum allowable working pressure ofthe HRSG, rounded to the next highest 5oC (10oF) increment.





The design temperature of the continuous blowdown piping from the steamdrums up to and including the blowdown valves shall be equal to thetemperature of saturated steam at the maximum allowable working pressure of

the HRSG, rounded to the next highest 5oC (10oF) increment.

The design temperature of the drain piping from the HRSG drain connectionsincluding the required valve(s) shall be equal to the temperature of the drainconnection, rounded to the next highest 5oC (10oF) increment and will not beless than 110oC (230oF).

The design temperature of the HRSG relief valve drain piping will bedetermined from the design temperature of the highest HRSG relief valvedischarge connection or the design temperature of the HRSG maintenancedrain piping connected to the relief valve header, whichever is higher.

The design temperature of the steam drum and steam pipe safety valves drainsand the silencer drains will be 105oC (220oF).

The design temperature of the piping from the blowdown tank to theblowdown sump is 110oC (220oF).

The design flow for the boiler vents and drains system piping is based on themaximum operating flow. These flow rates shall continue for a period ofapproximately 30 minutes during combined-cycle startup.





Pipeline Maximum Operating Flow

Continuous blowdown piping from HPsteam drum

5% of flow entering the steam drumfrom the rating point case heat balance.

Continuous blowdown piping from IPsteam drum

5% of flow entering the steam drumfrom the minimum ambient temperaturecase heat balance.

Continuous blowdown piping from LPsteam drum

5% of flow entering the steam drumfrom the minimum ambient temperaturecase heat balance.

Intermittent blowdown piping from HPsteam drum

10% of flow entering the steam drum,from the rating point case heat balance.

Intermittent blowdown piping from IPsteam drum


Intermittent blowdown piping from LPsteam drum


Startup blowdown piping from HP steamdrum

15% of flow generated @ 200 psig as aminimum

Startup blowdown piping from IP steamdrum

15% of flow generated @ 200 psig as aminimum

Startup blowdown piping from LP steamdrum

15% of flow generated @ 200 psig as amimimum

HP/IP/LP startup blowdown header Maximum simultaneous startupblowdown from HP, IP and LP steamdrums.

IP economizer relief valve discharge

piping

Maximum flow from IP economizer relief

valves.LP economizer relief valve dischargepiping

Maximum flow from LP economizerrelief valves.

3.2.4 Piping Design

See Section 5.1.3 for recommended piping materials and Section 5.1.4 forallowable fluid velocities.

The boiler vents and drains system piping will be designed to the requirementsof ASME Code Section I, Power Boilers and ANSI/ASME B31.1, PowerPiping.

As a minimum, the size of the blowdown piping will be the same size as theconnection on the HRSG.





The blowdown piping between the high pressure drop blowdown valves andthe blowdown tank where the pressure is reduced approximately to

atmospheric pressure and cannot be increased by closing a valve shall bedesigned for saturated steam at the appropriate pressure and temperature inaccordance with Table 122.2 of ANSI B31.1. The blowdown piping betweenthe high pressure drop blowdown valves and the blowdown tank will be thesame material and wall schedule and will be one pipe size larger than theblowdown piping upstream of the blowdown valves.

All blowdown lines will have two valves between the steam drum and theblowdown tank. A motor-operated block valve will be located near the steamdrum for the continuous blowdown line. A high pressure drop type blowdownvalve will be located as close as possible to the blowdown tank . This needs tobe discussed with HRSG

Water relief valves are routed to a corresponding pressure header, which isrouted to the blowdown tank.

HRSG startup drains from the HRSG shall be routed to the correspondingpressure header. HRSG drain piping will be the same size as the drain from theHRSG.

Headers routed to the blowdown tank shall be sized such that the area of theheader equals the sum of the areas of the branches feeding the header.

For schedule pipe, the minimum wall thickness, tm, for the boiler vents anddrains system piping is determined in accordance with ANSI/ASME B31.1,Section 104.1. Pressure design of components – straight pipe, where tm equals87.5% of the nominal wall thickness for schedule pipe due to manufacturingtolerances. The actual wall thickness, ta, shall be determined based on schedulepipe tolerances. The schedule of pipe with a wall thickness equal to or greaterthan ta, will be selected. The actual wall thickness, ta, includes the toleranceadded for machining of the “C” dimension required for the weld end detail,minimum.

Piping stress analysis shall be performed for all large bore pipe and for smallbore pipe subject to operating temperatures greater than 150oC (300oF) to

determine the pipe stresses and terminal reactions at equipment interfaces. Thestresses shall comply with limits allowable by code. Pipe supports shall bedesigned in accordance with the requirements of ASME Section I and ANSIB31.1 or ANSI B31.3, depending upon code in effect.

The blowdown and drain piping and the blowdown tank will be insulated forpersonnel protection.





The boiler vents and drains system piping will be designed to slope downwardto the low point drains. Slope will be at least 8 mm per 1000 mm (1 in. per10 ft.) of pipe run in the cold position and 4 mm per 1000 mm (½ in. per 10 ft.)

of pipe run in the hot position. All drains shall terminate no lower than 0.5 m(1-1/2 ft) above grade.

Drain headers/porcupines which collect various low temperature (< 399°C

(750oF)) cycle drains prior to entering blowdown tanks, receivers andcondenser shall be made of ASTM A106-B carbon steel. Material thicknessshall consider effects of erosion due to flashing steam and shall be a minimumwall thickness of Schedule 80.

Similarly, high temperature drains (>399°C (750oF)) shall use appropriate alloy

steel for the expected temperature rating.

3.2.5 Piping Layout

The piping arrangements shown on the following drawings represent a“typical” routing of HRSG drains to the blow down tank. The intent is todemonstrate one approach to the routing of the piping adjacent to the HRSGwith no interferences with other plant equipment or compromises to plant andHRSG accessibility. Job specific requirements will dictate actual drainlocations, terminal points, and blow down tank location. Accessibility tovalves, platforms, ladders, and walkways must be developed on a case by casebasis.

The drain piping layout shall conform to the HRSG drain design standarddrawings (P&Ids 2196-M214, Sheets 1 through 4, Plan Drawing M414Sheet1 and HRSG Drain and Piping Elevation Drawing M414, Sheet 2) whichare included at the end of this section. This standard is based upon a 3-pressureHRSG with HP, IP, LP water and steam circuits. Different HRSG designs willaffect the drain requirements and layout, but the principles of the standardshould be followed and the key issues addressed.





The key issues to be addressed in laying out the HRSG drains are:

•Safety – The drain lines should be located away from walkways andpositioned to reduce tripping hazards and the risk of head banging.

• Operability – The plant operators must be able to quickly and safely

access all of the drain line valves. Valves should be placed in optimumlocations for access either from grade (preferred) or from access platforms.

• Accessibility – Space the drain lines to allow ease of installation as

well as to allow adequate access space for maintenance of drain lines andvalves. As the drain line installation progresses, newly installed linesshould not block access to the drain line valves previously installed. Thedrain lines must also not block access to other plant equipment that the

operators monitor and operate.

• Optimize Routing – The drain lines should be manifolded where

possible to minimize the number of lines running from the bottom of theHRSG to the blowdown tank. The lines should be laid out in parallel asmuch as possible to make drain line identification easier and to make thedrain layout aesthetically pleasing.

The blowdown tank should be located off to the side of the HRSG in such aposition that there is adequate space between the HRSG and the blowdowntank for all of the drain lines to be neatly arranged. None of the drain lines tothe blowdown tank should extend beyond the outer edge of the blowdown

tank. The base of the blowdown tank will be located at grade or within a pitWhere a pit is used, the preferred arrangement is to have the blowdown tank’sinlet headers (HP, IP, and LP) above pit level to minimize the depth of the pit.

Figures 1 and 2 show a plant where the drain piping is neatly arranged withinthe HRSG – blowdown tank envelop. The walkways are clear and the drainvalves accessible.





Figure 1 – Example of Proper Drain Piping Layout – Above GroundBlowdown Tank

Figure 2 – Example of Proper Drain Piping Layout – Above GroundBlowdown Tank





Figures 3, 4, and 5 show a plant during construction with a poor drain layoutFigure 3 shows drain lines within a walkway area that present a trippinghazard. Figure 4 shows the drain piping layout is inconsistent and presents a

cluttered, awkward appearance. Maintenance workers will have problemsgetting repair equipment near the bottom of the HRSG where most of the drainvalves are located, as shown in Figure 5. Likewise, the plant operators will notbe able to get to the valves quickly because of the limited access.

Figure 3 – Example of Improper Drain Piping Layout (Safety Hazard)





Figure 4 – Example of Improper Drain Piping Layout





Figure 5 – Example of Improper Drain Piping Layout (Access Limited)

Drawing M214, Sheets 1 through 4 are P&Ids showing the drain lines that arerequired for a three-pressure HRSG (HP, IP, LP) and the line connections tothe blowdown tank. Sheet 1 is the P&ID showing the high pressure HRSGdrains’ origination points. Sheets 2 and 3 show the intermediate and lowpressure HRSG drains’ origination points, respectively. Sheet 4 shows all of

the drain lines connecting to the blowdown tank. As shown on Sheet 4, thehigh pressure drains, intermediate pressure drains, and low pressure drainsenter the blowdown tank through individual corresponding HP, IP and LPtangential inlet connections. Drain lines must only be connected to headers ofthe same pressure. Each individual HP, IP or LP drain line must only connectto the appropriate HP, IP or LP drain line header as shown on Sheet 4.





Drawing M414, Sheet 1 is a plan view and Drawing M414, Sheet 2 is anelevation drawing that show the general layout of the drain lines. The drawingshave been designated A for Option 1 and B for Option 2 which show variations

in expansion loop designs. The drain lines’ positions and arrangement may bealtered to fit the specific plant requirements, but the basic layout philosophy asdiscussed in the key issues above, should be followed.

P&ID M214, Sheet 1

P&ID M214, Sheet 2

P&ID M214, Sheet 3

P&ID M214, Sheet 4

HRSG Drain and Piping Plan View M414, Sheet 1

HRSG Drain and Piping Elevation Drawing M414, Sheet 2

HRSG Blowdown Drain Destination

The HRSG blowdown drain system shall be directed to a collector sump. Thepumps shall be sized so that the two operating sump pumps (3 x 50% total)will be capable of handling the maximum HRSG blowdown rate of 15% of themaximum guaranteed feedwater flow rate plus the quantity of quench waternecessary to reduce the blowdown water to 140°F. The blowdown sump shal

be sized so that a single 50% capacity sump pump can draw the sump leveldown from its high level set point to its low level set point in one hour with ablowdown influent of 1% of the guaranteed feedwater flow plus quench waterflow.

The sump level switches shall be set so as to stagger the start of the individualsump pumps in order to minimize their operation. In addition, the sump pumpmotors shall be designed to accommodate the maximum frequency ofoperation utilizing a standard motors.

The discharge piping from the sump pumps shall terminate at the pumpdischarge. The waste distribution system is supplied by others.

For those systems requiring recycling the boiler blowdown the discharge pipingfrom the blowdown sump shall be routed above grade via the pipe rack to thecondenser outlet circulating water piping.

In order to conserve on plant water consumption, the HRSG blowdown drainsystem shall be directed to a collector sump. The pumps shall be sized so thatthe two operating sump pumps (3 x 50% total) will be capable of handling the





maximum HRSG blowdown rate of 15% of the maximum guaranteedfeedwater flow rate plus the quantity of quench water necessary to reduce theblowdown water to 140°F. The blowdown sump shall be sized so that a single

50% capacity sump pump can draw the sump level down from its high level setpoint to its low level set point in one hour with a blowdown influent of 1% ofthe guaranteed feedwater flow plus quench water flow.

The sump level switches shall be set so as to stagger the start of the individualsump pumps in order to minimize their operation. In addition, the sump pumpmotors shall be designed to accommodate the maximum frequency ofoperation utilizing a standard motors.

The discharge piping from the sump pumps shall terminate at the pumpdischarge to a waste collection distribution system supplied by others.

For those systems requiring recycling the boiler blowdown the discharge pipingfrom the blowdown sump shall be routed above grade via the pipe rack to thecondenser outlet circulating water piping.

3.3 Steam Piping Drains and Vents

3.3.1 Steam Systems

Power Plant Engineering design philosophy for steam system drains for alplants involving steam turbine generators is based upon, as a minimum, fullcompliance with the ASME Recommended Practices for the Prevention ofWater Damage to Steam Turbines used for Electric Power GenerationStandard No. TDP-1-1998 Part 1- Fossil Fueled Plants.

It is the intent of this design basis to highlight the important aspects of plantdrains design and disposal. Details concerning equipment design and specificconfigurations are referred back to the above-mentioned standard.

This design basis for steam system drains will cover the following areas:

• Turbine and Cycle Piping Drains System Design Philosophy

• Main Steam

• Hot Reheat





• Cold Reheat

•

LP Steam

3.3.2 Turbine and Cycle Piping Drains Systems

Drains systems can be summarized into high pressure drains andintermediate/low pressure drains.

High pressure drains consists of the high energy drains contained primarily inthe HP steam system.

These drains should be connected to a condensate receiver drains tank which isvented to atmosphere with the accumulated drains either vacuum dragged or

pumped to the condenser hotwell.

This drains tank serves the following purpose.

• Collects water from high energy drains within the plant

• Prevent overheating condenser shell connections.

• Reduces the number at penetrations in the condenser shell.

• Reduces the pressure and temperature of the high energy drains, thereby

reducing the amount of liquid which will flash steam to the condenser.

• Provides a central location to run heavy wall small bore drain lines thereby

minimizing overall piping runs to the condenser.

• Supports schedule activities by minimizing coordination and rework efforts

by condenser manufacturer.

The tank is located at grade or basement level in the turbine hall and primarilycollects those drains associated with the steam piping within the steam turbinebuilding. The elevation of this tank must be such that all low point drains willflow by gravity to this tank when it is operating at maximum pressure whichwould be between 0.2 –0.35 kg/ cm2, g (3 – 5 psig) for most applications.

Typical drains which should be run to the condensate receiver are

• HP steam header low point drains

• Intermediate and low pressure drains in the vicinity of the steam turbine.





3.3.2.1 Major Components007BE Condensate Receiver Qty-1

The condensate receiver is an atmospheric tank designed, fabricated andstamped in accordance with the ASME Boiler and Pressure Vessel Code,Section VIII, Division 1.

The purpose of the condensate receiver is to collect pressurized steam systemdrains in the vicinity of the steam turbine and forward them to the steamsurface condenser via a vacuum drag system or by pumping depending onsystem calculations. The receiver is vented to atmosphere.

The condensate receiver allows the plant designer to keep pressurized drainsseparate from drains that can be under vacuum during startup or normaoperation. This design practice eliminates the possibility of inhibiting drain flowin vacuum drains, which if not carefully considered can lead to steam turbinewater induction.

Another benefit of the condensate receiver is the elimination of numerous highenergy drain penetrations in the condenser shell. The condensate receiver alsoallows room for additional drains in the field if need be without compromisingthe integrity of the condenser shell and tube bundle.

The tank is constructed of carbon steel, SA-570, Grade 70 with a designpressure of 3.5 kg/ cm2, g (50 psig) and a maximum operating pressure of 0.35kg/ cm2,g (5 psig). The tank dimensions will be checked during the designcycle to assure that the tank has adequate space for water/gas separation andcondensate level surge during startup or abnormal operation.

The tank is a vertical, cylindrical type tank in which water/steam enterstangentially. The high velocity steam/water blowdown mixture hits a wearplate mounted on the shell of the tank. Condensate separates from the steamand drops to the water in the lower portion of the tank. Steam and gas isvented to atmosphere through a vent pipe attached to the top of the tank. Thevent pipe diameter will be checked during the design cycle to assure that the

tank is adequately vented to maintain a maximum of 0.14 kg/ cm2,g (2 psig)pressure during maximum flow, i.e., meets the ASME Boiler and PressureVessel Code.

Intermediate/low pressure drains comprise of the HRH, IP and LP steamsystems.





The condensed steam is vacuum dragged through a level control valve ( failclosed ) to the condenser. Overflow drains are controlled via an on-off levelcontrol valve ( fail open ) taking its signal from the tank high level switch

These drains are also routed to the condenser. A manual drain valve should beprovided for maintenance.

3.3.2.2 Design Criteria/Limits

The design pressure of the steam drains up to and including the drain valvesshall not be less than the set pressure of HRSG superheater outlet safetyvalves. Static head and choked flow conditions shall be considered.

The design pressure of the fuel gas heater water outlet piping shall not be lessthan the water side safety relief valve setting on the fuel gas heater.

The design temperature of the steam drain piping from the steam lines up toand including the valves shall be equal to the design temperature of theassociated steam line.

The design temperature of the fuel gas heater water outlet piping should beequal to the design water side temperature of the HRSG IP economizer.

The design temperature of the piping from the condensate receiver tank to thecondenser hotwell is 110oC (230oF).

The design flow for the drains system piping is based on the maximum

operating flow.

3.3.2.3 Piping Design

Piping Materials are to be per Section 3.1.3 and allowable piping velocities perSection 3.1.4.

The drains system piping will be designed to the requirements of ASME CodeSection I, Power Boilers and ANSI/ASME B31.1, Power Piping.

The drain piping between the high pressure drop drain valves and the

condensate tank where the pressure is reduced approximately to atmosphericpressure and cannot be increased by closing a valve shall be designed forsaturated steam at the appropriate pressure and temperature in accordancewith Table 122.2 of ANSI B31.1 or ANSI B 31.3. The drain piping betweenthe high pressure drop drain valves and the condensate receiver will be thesame material and wall schedule and will be one pipe size larger than the drainpiping upstream of the drain valves.





All drain lines will have two valves between the steam line and the condensatereceiver. A high pressure drop type valve will be located as close as possible tothe condensate receiver.

For schedule pipe, the minimum wall thickness, t m, for the vents and drainssystem piping is determined in accordance with ANSI/ASME B31.1, Section104.1. Pressure design of components – straight pipe, where t m equals 87.5%of the nominal wall thickness for schedule pipe due to manufacturingtolerances. The actual wall thickness, ta, shall be determined based on schedulepipe tolerances. The schedule of pipe with a wall thickness equal to or greaterthan ta, will be selected. The actual wall thickness, ta, includes the toleranceadded for machining of the “C” dimension required for the weld end detail,minimum.

Piping stress analysis shall be performed for all large bore pipe and for smallbore pipe subject to operating temperatures greater than 150oC (300oF) todetermine the pipe stresses and terminal reactions at equipment interfaces. Thestresses shall comply with limits allowable by code. Pipe supports shall bedesigned in accordance with the requirements of ASME Section I and ANSIB31.1.

The drain piping and the condensate receiver will be insulated for personnelprotection.

The drains system piping will be designed to slope downward to the low pointdrains. Slope shall be at least 8 mm per 1000 mm (1 in. per 10 ft.) of pipe run

in the cold position and 4 mm per1000 mm (½ in. per10 ft.)of pipe run in thehot position. All drains shall terminate no lower than 0.5 m (1-1/2 ft) abovegrade.

Drain headers/porcupines which collect various low temperature (< 399°C

(750oF)) cycle drains prior to entering blowdown tanks, receivers andcondenser shall be made of ASTM A106-B carbon steel. Material thicknessshall consider effects of erosion due to flashing steam and shall be a minimumwall thickness of Schedule 80.

Similarly, high temperature drains (> 399°C (750oF)) shall use the appropriate

alloy steel for the expected temperature rating.

ANSI B31.3 may be used in place of ANSI B31.1 depending upon code ineffect for the project.





3.3.3 Main Steam

This procedure is required to prevent the accumulation of water in the mainsteam piping between the steam generator and the steam turbine. It pertainsmainly to the piping located in close proximity to the steam turbineRecommendations for drains located in the area of the HRSG can be foundunder Section 3.2 of this document titled “Boiler Drains/Blowdown System.”

A drain should be installed at each low point in the main steam piping from theboiler outlet to the connection on the turbine stop valve(s).

The position of the piping in both the cold and hot positions should be slopingdownward in the direction of steam flow from the steam generator to the

turbine.

In all cases, a drain pot shall be located just upstream of the main steam stopvalve(s).

3.3.3.1 Main Steam Stop/Control Valves

Implementation of these guidelines will ensure that all drains piping connectedto the MSCV will be designed so that there will be no cool condensate trappedin the piping which can backflow into the hot valves.

3.3.3.1.1 Steam Turbine Department Drawings

Obtain copies of the latest revisions of the following steam turbine drawings:

• Combined stop/control valve outline. This drawing shows the valve

outline and identifies all the piping connections off the valve.

• Steam drains drawing for the MSCV. This drawing provides each

connection designation and shows the Steam Turbine Department (STD)recommended destinations for the various piping connections off thevalves.

•Interface point table for the MSCV. This drawing provides the

design conditions for all the piping connections off the valves.

Review the above ST drawings in detail. Look for the following information:

• Type of drain connections

• Verify correct labeling of each drain connection





• Number of drain connections

• Quantity of each type of drain connections

• Size of each drain connection

• STD recommended destination for each drain connection

• Design conditions for each drain connection

• Direction and distance each drain connection moves from the cold

to the hot position

• Review all of the requirements for drains in the Station Designers

Manual.

3.3.3.1.2 Plant Drawings

• P&Ids

— Show all the MSCVs.

— Show and label all drain lines off the MSCVs. Valve labelingshall agree with the ST drawings.

— Specify the sizes of pipes based on the ST drawing drainconnection sizes and design conditions.

— Add a note that requires each drain to be shown on an isometric

drawing. — Add sufficient notes that require each drain line to be sloped.

— Show the destinations of each drain connection off theMSCV(s).

• Isometric Drawings

— Provide an isometric drawing for each drain line and warm-upline off the MSCV, as shown on the P&Ids.

— The length of each drain piping shall be kept as short as possiblefrom the source to the destination.

— The drain pipes shall be sloped continuously from their sourceto their destinations.

— The piping must be sloped a minimum of 2mm per 1000 mm(1/4 inch per foot) of length.

— The isometrics must clearly identify the connections on theMSCVs and their destinations. The connections must be clearly andaccurately labeled on the drawings so that the piping will be installed in





the field correctly. Each drain destination must agree with those shownin the P&ID.

— The thermal movement of the MSCVs must be taken intoconsideration from the cold to hot positions so that the piping is alwayssloped properly and in the correct direction.

3.3.3.1.3 Analyses

A thermal analysis must be performed for each MSCV drains pipe to ensurethat they will not be overstressed when going from a cold to hot position.

3.3.3.1.4 Hangers/Supports

• Hangers/supports must be located and designed based on the stress

analysis so that no piping is overstressed. The hangers/supports must bedesigned to ensure that the drains piping will be sloped continuously fromthe source to their destinations. All hanger/support locations must beshown and clearly labeled on the isometrics.

• Detailed shop sheets must be provided for all hot small bore drains

piping. The shop sheets must show the hanger number, location, thermalmovements (if required), bill of materials and all auxiliary steel, if required.

3.3.3.1.5 Condenser Drain Manifolds

The drain manifolds at the condenser must have a drain hole at the bottom(inside condenser) to ensure that they are completely empty of water so thatwater can never backflow up into the MSCVs through any drain line connectedto it.

3.3.3.1.6 Drain Pipe Routing

All MSCV drains shall be routed as indicated in the following table:

Description Destination Conn.Size

(Note1)

Conn. Location Routing

Before SeatDrain

CondensateReceiver

DN 25(1 “)

At Porcupine Each drain line shall be routed separately andnot combined with any another drain line. Noconnection to porcupine internal baffles areacceptable in the condenser.

ControlValve StemLeakoff

AtmosphericFunnel

DN 40(1-1/2

“)

Route to SafeArea at Grade

Each drain line shall be routed separatelyand not combined with any another drain line.This piping shall be located in a restrictedarea agreed to by the Customer.





Description Destination Conn.Size

(Note1)


ValveActuatorLeakoff(WWO)

AtmosphericFunnel

DN 40(1-1/2

“)

Run to Safe AreaAt Grade

Each drain line shall be routed separately andnot combined with any other drain line. Thispiping shall be located in a restricted areaagreed to by the Customer.

After SeatDrain

Condenser DN 25(1 “)

Above Water Line

Direct Connectionto Condenser

Each drain line shall be routed separately andnot combined with any another drain line. Noconnection to porcupine. Internal baffles areacceptable in the condenser.

Stop ValveStemLeakoff

Gland SealSystemPiping

DN 50(2 “)

Above Low Pointin Gland SealSystem piping.

These lines can be combined, into a commonline, if necessary.

Note (1): Line sizes shown are suggested minimum and should be verified based on the valve drain

connection sizes and design conditions shown on the steam turbine department drawings.All HRH valve drains shall be routed as indicated in the following table:

Description(Note 2)

Destination Conn.Size

(Note 1)


Before SeatDrain

RH PipeImmediately Upstreamof RH Valve

DN 25(1 “)

Pipe Tap Each drain line shall be routed separately andnot combined with any another drain line.Continuous drain with no valves, traps ororifices.

RH ValveStem SealLeakoff

Atmospheric Funnel

DN 40(1-1/2 “)



ValveActuatorLeakoff(WWO-1)

Atmospheric Funnel

DN 15(1/2 “)



After SeatDrain

Condenser DN 25(1 “)

Above Water LineDirect Connectionto Condenser

Each drain line shall be routed separately andnot combined with any other drain line. Eachline shall contain a power-operated drainvalve.

Note (1) See attached sketch for location of each drain connection on the body of the RH valve.

Note (2) Line sizes shown are suggested minimum and should be verified based on the valvedrain connection sizes and design conditions shown on the Steam Turbine Departmentdrawings.





The power-operated drain valve is controlled by the steam drains controsystem found in the plant DCS. In addition, position indication should beprovided in the control room to permit the operator to determine the position

of each of the power-operated drain valves. Operator control of valve positionshould also be included.

Hot reheat drains should be piped directly to the condenser for single shaftcombined cycle plants or to the condensate receiver for multi-shaft combinedcycle plants.

3.3.5 Cold Reheat

The cold reheat system extends from the high pressure turbine exhaust to thereheater inlet. Power-operated drains are required at all low points similar to

the main steam system. Drain pots are required.

Each pot should be provided with a drain line of nominal 51 mm (2 in.)minimum size and a full size full ported automatic power operated drain valve.

Each drain pot should be provided with a minimum of two level sensingdevices. The first level shall actuate to fully open the drain valve and shalinitiate an alarm in the control room indicating that the valve has opened. Thesecond level shall initiate a high-high level alarm in the control room.

Each valve should have a remote indicator in the control room to monitorvalve position as well as provide remote/manual operation by the operator.

3.3.6 LP Steam System

The LP (Low Pressure) steam system shall follow the same general guidelinesas the hot reheat system.

Drains which are routed to either the condenser or the condensate receivermust be segregated by energy level. HP and LP drains must not beinterconnected. The drains to manifolds should be grouped in approximatelythe same operating ranges. The drain lines should be arranged in a descendingorder of pressure, with the drain from the highest pressure source farthest fromthe manifold opening at the condenser or condensate receiver.

3.3.7 Drain Pot Design Philosophy

The drain details below are appropriate on steam headers of combined cycleplants with high levels of superheat and have continuous flow duringoperation. These lines only have condensation during startup, so no norma





operation drains are needed. Dead-end branched such as bypasses etc. coulduse a trap or orifice for normal drainage with the power-operated valve usedfor system startup. Another area that needs careful consideration is header

drainage for multiple HRSG systems with one or more HRSGs out of service.

3.3.7.1 Drip Leg Sizing

Typically, minimum drip pot size would be line size for lines DN 100 (4”) andsmaller, DN 100 (4”) for DN 150 (6”) lines, DN 150 (6”) for DN 200 (8”),DN 200 (8”) pots for DN 250 (10”) lines and DN 250 (10”) pots for DN 250(10”) lines and larger. Pots used with temperature controlled drains should be150 mm (6”) minimum, with the thermowell insertion ~ 100 mm (4”) into thepot. The distance from the thermowell and the drain should be no greater thanDN 100 (4”). If the drain is a side connection, it should be within 100 mm (4”)of the bottom of the pot to minimize water volume. The drip pot should alsobe provided with a cleanout connection (not shown). Drip pot cleanouts shouldbe DN 20 (3/4”) or DN 25 (1”), located at the bottom of the drip pot.Cleanouts should be double valved with a welded pipe cap end for highpressure lines. Single valved capped cleanouts can be used for intermediate andlow pressure systems. Drip pot piping should have a wall thickness allowancefor erosion due to flashing.

3.3.8 Drip Leg Level Control Valve Actuators

Motorized operators are used on valves installed in systems with designpressures of 42 kg/cm2, g (600 psig) and greater because they can develop thepower to tightly close the valves, and open tightly shut valves. Diaphragmactuators are used on valves installed on systems with design pressures of lessthan 42 kg/cm2, g (600 psig).

Typically, motor-operated drains are used for hot reheat service.

Another consideration when choosing actuator type is the required fail-positionfor the valve. MOVs are fail-as-is. Diaphragm actuators can be fail-open, fail-close or fail-as-is. Reheat drain valves with diaphragm air operated actuators,

which operate in vacuum service, are required to be fail close.

The control valve should be located as close to the drain connection aspractical. This minimizes both freeze protection concerns and the potential forwater hammer in the drain piping due to water accumulation in the upstreampiping.





3.3.8.1 Instrumentation

Two different instrumentation methods can be used to detect water in the drip

leg.

One method is to instrument the drip leg with two external sealed-cage, float-type level switches, one switch installed higher than the other. The water levelin the drip leg rises until the lower level switch is actuated, signaling to thecontroller to open the drip leg level control valve. When the level in the dripleg falls, the level switch changes state and signals to the controller to close thevalve. The higher level switch is used to alarm high water level in the drip legin the event of lower level switch or valve failure.





The second method is to install a thermocouple in the drip leg. When thetemperature of the steam temperature inside the drip leg becomes less than

28°C (50

°F) above saturation, the controller commands the drip leg leve

control valve to open. When the temperature of the steam goes 28 °C (50°F)

above saturation the valve is commanded closed. Note that this methodrequires a pressure measurement to calculate the saturation temperature. Fiftydegrees above saturation is used because at saturation temperature, the level ofthe water in the drip leg cannot be determined; at saturation, water and steamcan coexist. In automatic, the valve is opened until 15 seconds after the propersuperheat level is reached and an alarm is provided if the valve remains open60 seconds after proper superheat levels have been established. A valve alarmis also provided if the valve does not open as required when the thermocoupleindicates the contents of the drain pot are still within saturation limits. A

locked open drain valve should be located upstream of the power actuatedvalve.

The third method would be to open the drain valve at the lowest point of theHP piping, either when the HP temperature >3000 C (5700F), or the ST load is> 15%.

During plant startup (SU) and shutdown (SD), the plant SU/SD sequencinglogic over-rides the instrument-based drip leg level control logic.

3.3.8.2 Limitations On The Different Instrumentation Methods

The limitations on each method are as follows:

Thermocouples can be used only where the process steam entering the piping

is expected to have at least 28°C (50°F) degrees superheat during all operation

modes.

Level switches are limited to systems where the design temperature is not

expected to exceed 399°C (750°F). Level switches are usually used in cold

reheat and LP systems. Thermocouples are usually used in the HP, IP andHRH systems.

3.3.9 Instrumentation

Aside from the physical limitations of each method, there are those that preferthe thermocouple method because a thermocouple is believed to be morereliable than a level switch.





3.4 Fuel Gas (FG) System


It is imperative that the design engineer obtains an accurate sample of theproject specific fuel gas analysis prior to performing the detailed engineering ofthis system. Gas line temperatures must be maintained above the hydrocarbonand water dew points prior to initial gas turbine light off.

This analysis should be obtained from the gas company providing the productgas. The gas should be analyzed down to C14 since it is the heavierhydrocarbons that have the greatest affect on dew point temperaturesAlternatively a dew point analysis can be done which also identifies dew point

limits.

Note that the electric startup heater provided on combined cycle plants isdesigned to heat the incoming gas to the proper temperature. It does not,however have any heating capability of the gas contained in the pipelinebetween the heater and the gas turbine FG1 connection. So for those caseswhere the dewpoint is high and the ambient temperature is low, additionalheating must be provided between the heater and FG1. It is recommended thatprocess heat tracing be applied to this pipe run designed to maintain the propersuperheat in the fuel gas contained in this “cold leg “.

The same concern applies to simple cycle plants with water bath heaters. The

heater should be located as close to the unit as possible to minimize the coldleg between the heater and the FG1 connection. Process heat tracing may berequired in this pipe run if the ambient temperatures fall below the requiredsuperheat temperature of the fuel gas.

The fuel gas (FG) system performs the following functions:

• Delivers natural gas from the power station property boundary to

the gas conditioning equipment located within the station propertyboundary. This is accomplished through gas compression, gas pressurereduction or conveying gas at the proper Customer terminal point pressure

established by meeting the gas turbine FG1 requirements with allowancefor pressure loss through the gas delivery system.

• Removes liquid droplets and contaminates by filtration/centrifugal

separation

• Heats the natural gas going to the gas turbine (GT) to provide fuel

gas at the proper superheat conditions as well as for performanceenhancement if required





• Conveys natural gas to the HRSG duct burner or auxiliary boiler if

applicable

• Provides connections for sampling incoming fuel gas

The fuel gas system treats and delivers gas to the turbines at the properconditions. A filter/separator removes liquids and solids from the incoming gassteam. A pressure reducing station reduces the gas pressure to a level that isacceptable to the gas turbines and the fuel gas heater raises the gas temperatureto that required by the gas turbines. The filter/separator and pressure reducingstation are provided on a station basis while the heaters and scrubbers areprovided on a unit basis. A scrubber is supplied downstream of the fuel gasheater to remove both particulate matter and liquids thereby providing a cleangas to the gas turbine. The gas scrubber comes complete with a liquid levelcontrol system to automatically maintain a safe level of accumulated liquid inthe scrubber. A scrubber drain tank receives mixed drains from the scrubbersand safely separates and vents fuel gas from the waste drain stream.

Gas booster compressors may be required if the gas supply pressure at the fuelgas terminal point is determined to be inadequate for turbine operation.

A metering tube is provided for each gas turbine to measure and record fuelgas consumption to the gas turbine.

The fuel gas shall comply with the latest revision of GEI-41040 found in theReference Specifications/Documents Tab.

Fuel gas is provided at the terminal point at a pressure and flow ratesupporting plant performance requirements. To account for fuel gasconditioning equipment and piping losses from the terminal point to the gasturbine fuel valve, the minimum supply pressure is at least 3.87 kg/cm2

(55 psi) higher than the GEI requirements for the specific gas turbine modelwith DLN combustors.

The sulfur content of the fuel gas is assumed to be 0 ppm unless otherwisespecified by the Owner.






Fuel Gas Performance HeaterFuel gas Duplex Coalescing Filter

010BA Fuel Gas Filter Separator

010BB Fuel Gas Dewpoint Heater

010BC Fuel Gas Scrubber

010BE Fuel Gas Pressure Reducing Station

007CD Gas Drains Tank

Gas Booster Compressors

The objective of this guideline is to identify basic considerations for the designand installation of a gas turbine power plant fuel gas supply system that willmeet the GE fuel gas specification, and support safe and reliable operation ofthe plant.

3.4.3 Scope

The scope of this guideline is the gas turbine power plant gas fuel supplysystem from the site boundary up to the FG1 connection on the GT fuel gasmodule. Interface with the gas supply system in the scope of the gas supplieris also covered. The guideline assumes that gas is received from a gastransmission pipeline, either directly, or from a local distribution companyThe design considerations included in the guideline also apply to gas receivedfrom LNG facilities.

3.4.4 References

The guideline refers to the latest revision of the following existing GEstandards, and does not repeat requirements and recommendations given inthese documents pertaining to GE fuel gas experience, equipmenconfigurations and GT fuel gas specification requirements:

1. GEI-41040

2. GER-3942

3. GEK-41745 Cleaning of Main Steam Piping

3.4.5 Definitions

Custody Transfer – The legal and commercial transfer of a commodity such asnatural gas from one party to another.

Hydrate – A solid, ice-like material resulting from the combination of a gaswith water under pressure. Of natural gas constituents – methane, ethane





propane, 50iamese50e, normal butane and also hydrogen sulfide and carbondioxide will form hydrates. The greater the pressure in the equipment, thehigher the temperature at which the hydrate will form, usually well above

freezing. Hydrates can cause restriction and stoppage of flow, and can becontrolled by alcohol injection or by dehydration of the gas.

Local Distribution Company – A company which obtains the major portion ofits gas operating revenues from the operation of a retail gas distributionsystem, and which operates no transmission system other than incidentaconnections within its own system or to the system of another company.

Monitoring Regulator (Monitor) – A pressure regulator set in series with acontrol pressure regulator for the purpose of automatically taking over thecontrol of pressure downstream in case that pressure tends to exceed a set

maximum.

Pressure Cut (Pressure Regulating Station) – Equipment installed for thepurpose of automatically reducing and regulating the pressure in thedownstream pipeline or main to which it is connected.

Rangeability – The ratio of a valve’s maximum to minimum controllable flowrates.

Turndown – The ratio of maximum to minimum capacity of a system.

3.4.6 Industry Codes and Standards





3.4.6.1 Applicable Codes and Standards

ANSI/ASME B31.1 – Power PipingPower plant fuel gas supply piping up to the gas turbine equipment interface isdesigned, fabricated, inspected and tested per ANSI/ASME B31.1 requirements.This includes design per the industry codes and standards referenced by B31.1.

ANSI/ASME B31.3 – Process Piping

Power plant fuel gas supply piping up to the gas turbine equipment interface isdesigned, fabricated, inspected and tested per ANSI/ASME B31.3 requirements.This includes design per the industry codes and standards referenced by B31.3.

ASME Section VIII

Pressure vessels for fuel gas conditioning equipment (separators, scrubbersfilters, drain tanks) are designed, fabricated, inspected and tested per ASME

Section VIII requirements.API 12K

Water bath heaters used in power plant gas service are designed, fabricatedinspected and tested per API 12K.

API 520

The design, sizing and installation of pressure relieving devices that are used inpower plant fuel gas piping systems is per API 520.

ASME Code Jurisdiction

The design and installation of gas transmission piping is in the scope oANSI/ASME B31.8. The design of gas turbine power plant fuel gas piping up tothe gas turbine fuel module inlet connection is in the scope of ANSI/ASMEB31.1. If the revenue meter (custody transfer meter) is located on the powerplant property, the code break between B31.8 and B31.1 jurisdiction is at theoutlet of the revenue meter. This break in code jurisdiction is important to notesince the design rules outlined in these two codes for pipe sizing, materialselection, over pressure protection, etc. are different.





3.4.7 Fuel Gas Supply

Natural gas is delivered to the power plant from a tap-in point on one or moreinterstate gas transmission pipelines. The gas supply can be directly from thepipeline operator or via a local distribution company.

The gas supply is conditioned by the gas supplier or local distribution companyto meet the gas supply contract requirements regarding liquid and particulatelevels, temperature and pressure.

Gas is metered by the gas supplier for custody transfer to the Customer.

The gas pressure is reduced from pipeline pressure to the pressure at which itis delivered to the power plant in one or more pressure cuts, either by theoperator of the gas transmission pipeline, by the local distribution company, orby the power plant fuel gas supply system. The final pressure cut is frequentlymade either adjacent to the power plant property, or on the power plantpremises. The location and ownership of the final pressure cut affects theapplicable piping design code.

It is important for the power plant engineer to review the design of the gassuppliers equipment installation to both confirm the adequacy of the gassuppliers design and installation for the application and to avoid duplication ofgas conditioning equipment, where possible.

3.4.7.1 Gas Conditioning

In the absence of specific direction that fuel conditioning will be provided byothers or specific components are not required, we will assume that the basecase for fuel gas conditioning will include moisture separation, pressureregulation, gas filtering, dew point heating and final scrubbing. The type ofconditioning equipment that is used is a function of the composition of theincoming gas, including anticipated liquid and particulate levels, the turndownrequirement of the application, and the sparing philosophy for the design.

If coalescing filters or filter-separators are used in this applications, redundant

equipment may be required depending on the expected quality of the gascoming to the pressure cut from the pipeline; and on the mode of operation ofthe units. Gas separators have a maximum turndown ratio of approximately2:1; gas scrubbers have a maximum turndown ratio of approximately 5:1. Theturndown capabilities of separators and scrubbers are exceeded by the realisticfuel turndown capability of multiple gas turbine power plant installation, whichlimits their use to single unit application.





Another consideration is to determine if the unit(s) will operate base loaded orin a peaking application. For base loaded systems filter separators must bedesigned in a 2 x 100% station configuration to allow removal of spent filters

while the unit is still in operation.

Unit scrubbers do not require this redundancy due to the “dry” type ofscrubbing action being performed with no filtration required. At this point inthe system the primary concern is the carry over of particulate matter from theupstream carbon steel piping system. Downstream of this scrubber the pipingto the unit should be run as stainless steel.

The practice of installing a bypass around fuel gas filtration equipment for on-line maintenance is not recommended by GE, due to the potential impact ondownstream equipment, including the gas turbine, of particulates and liquid

slugs bypassing the filter elements.

3.4.7.2 Metering

The gas is metered for custody transfer. Gas metering runs normally comprisea strainer, flow straightener, and meter flow element and instrumentationTurbine, Vortex meters or orifice plates are typically used in gas pipelinecustody transfer applications. Gas suppliers normally locate the meter flowelement upstream of the pressure regulators, to reduce the size of the meter.The gas meter can also be located downstream of the pressure regulators if thepipeline pressure fluctuates.

3.4.7.3 Heating

For pressure cuts from transmission pipeline pressures, the gas is heatedupstream of the pressure control valves or regulators to prevent the formationof liquids and hydrates in the flow stream due to the gas temperature dropresulting from the Joule-Thompson throttling effect. Removal of liquids isrequired prior to heating the gas, since fuel gas heaters are designed to heatsaturated or superheated gas, and do not evaporate entrained liquids. The heatinput required is a function of the incoming gas temperature and the gascomposition and water content, which set the water and hydrocarbondewpoints and the hydrate formation temperature. As a rule of thumb toestimate the heating requirement, -3.5oC (7oF) of Joule-Thompson coolingresults from every 7 kg/cm2,g (100 psi) of pressure reduction.





Indirect fired water bath heaters designed to API 12K are commonly used inthe U.S. for heating gas at pressure cuts on gas pipelines. The simplest waterbath heaters use pneumatic bath and process controllers and pressureregulators, with natural draft burners. Water bath heaters can also be equippedwith forced draft firing systems to improve the heater response time andturndown capabilities; and with low Nox burners, depending on the air qualityrequirements of the application.

The main advantage of the water bath heater is the simplicity of the design.

The main disadvantages of water bath heaters are the physical size of the unitsand the emissions of the burner system, which may be impacted by the site air

permit. The heating capability of water bath heaters is also limited by theatmospheric boiling point of the water-glycol bath solution.

Large pressure reduction applications may require this type of heatingupstream of the pressure reduction station in addition to the dew point heatingsystem downstream of the station. In these applications it is very important toget the final gas analysis down to the C14 level along with other gascomponents (i.e. water content) during the bidding process. This will have adirect impact on the design and cost for such a system and cannot be delayeduntil after the order has been placed. If no analysis is available at the time ofthe bid, then the wording in the Design Assumptions must be carefully writtento mitigate scope/cost impacts later.

3.4.7.4 Pressure Control

3.4.7.4.1 Type of Valve

Both control valves and pilot-operated regulators are commonly used on gaspipeline pressure cuts. It should be noted that the types of gas pressureregulators and pneumatically-controlled pressure control valves that arecommonly used on gas transmission pipelines and for gas distribution systemsmay not have a speed of response that is sufficient for accurate pressure

control of gas turbine fuel gas supply systems.

Contact Gas Turbine Product Department Engineering for allowable steady-state and transient fuel gas supply conditions at the gas turbine FG1Purchaser’s connection.





3.4.7.4.2 Valve Configuration

The configuration of the pressure control valve/regulator installation has to

provide sufficient rangeability to cover the fuel turndown capability of the gasturbine installation plus the variation in the fuel gas supply pressure. Onmultiple unit sites, it is common to have parallel trains of regulators set atdifferent control points, in order to provide the required pressure controrangeability.

3.4.7.4.3 Control Pressure

The setpoint for pressure control has to be established by working backwardsfrom the GT fuel gas module inlet connection, adding the piping andequipment design pressure drops back to the location of the pressure control

sensing point. For installations where the final pressure cut is made by the gassupplier, establishing the pressure control points needs to be coordinatedbetween the gas supplier and the plant designer.

3.4.7.4.4 Overpressure Protection

ANSI/ASME B31.8, ANSI/ASME B31.1 and ANSI/ASME B31.3 containspecific design requirements for the protection of piping systems andequipment from overpressure. However, the B31.8 design requirements foroverpressure are different than for B31.1.

•ANSI/ASME B31.8 ANSI B31.8 allows the following forms ofoverpressure protection:

— Monitor –regulator arrangement of pressure regulators

— Pressure cutoff valves

— Safety relief valves

— Certain combinations of the above equipment

In addition to overpressure protection, gas pipeline pressure cut installationsare usually equipped with pressure blowoff valves set to relieve pressure due toregulator leakage, to prevent actuation of the main overpressure protection.

• ANSI/ASME B31.1 — ANSI/ASME B31.1 requires that if pressure reducing valvesare installed in B31.1 piping, the piping and equipment downstream ofthe pressure reducing valves must be protected from over pressure,either by designing to the upstream conditions or by the installation ofsafety relief valves.

• SRV Installations





— The relief valves must be sized to prevent overpressure of theprotected piping and equipment due to wide-open failure of theupstream pressure control valves or regulators. For plants with parallel

trains of fuel gas pressure control valves/regulators, multiple safetyrelief valves with staggered set pressures may be required to meet theoverpressure protection design requirements. Safety relief valvesshould be sized, located and installed per API 520. The SRVmanufacturer’s recommendations should also be followed to ensurethat the configuration of the adjacent inlet and discharge pipingsupports proper functioning of the valve.

— Consideration should be given to installation of a pressureblowoff valve in the plant fuel gas supply piping to relieve pressure dueto leakage of the gas supplier’s regulators, to prevent actuation of themain overpressure protection.

• Coordination with the Gas Supplier

— The setpoint of the overpressure protection needs to becoordinated between the engineer designing the last pressure cut andthe engineer designing the gas turbine power plant fuel gas supplypiping. The setpoint of the overpressure protection needs to be highenough to prevent actuation of the overpressure protection duringnormal operation of the fuel gas supply system. For safety relief valveinstallations, the setpoint of the SRV should be set sufficiently abovethe control pressure to prevent simmering.

3.4.7.5 Isolation Valves

Plug valves and metal-seated ball valves for gas service are equipped withsealant injection ports for emergency sealing of valve leaks.

In the U.S, state regulations govern the location of shutoff valves at aboveground gas pipeline installations. The required distance from the shutoff valveto the equipment varies from state to state, but the common intent of suchregulations is to make the isolation valve accessible for operation during anemergency.

For gas application soft seated valve are also acceptable.

However, in some countries local regulations that will take presidencies over,the type of isolation valve that will be acceptable.





3.4.7.6 Security

Pipeline pressure cuts may be fenced off for security. Valves can be aboveground or in vaults. Valves and equipment can also be installed in enclosures,for both security, weather protection and for noise attenuation. ANSI/ASMEB31.8 requires that above ground gas piping installations near public accessroads be protected from vehicle damage.

3.4.7.7 Future Provisions

Provisions for future expansion of the pressure cut due to planned future

expansion of the power plant needs to be considered in the design andarrangement of the initial installation.

3.4.7.8 Noise Attenuation

The valve noise and piping breakout noise emanating from gas pressurereducing stations can exceed 100 dBA, depending on the pressure dropinvolved. For this reason, in-line diffusers, acoustic treatment of the piping andacoustic enclosures may be included in the installation, for noise attenuation.Attenuation requirements should be determined on a case by case basis.”

3.4.8 Gas Turbine Power Plant Fuel Gas Supply System

Typical arrangements for fuel gas conditioning systems can be found in therespective Reference Plant Documents for the various power plantconfigurations.

3.4.8.1 System Configuration

The configuration of the gas turbine power plant fuel gas supply system variesas a function of the following:

3.4.8.1.1 Gas Supply Pressure

The range of pressure at which gas will be delivered to the power plant by thegas supplier affect the design and configuration of the plant fuel gas system.





3.4.8.1.2 Gas Supply Temperature

The range of temperature at which gas will be delivered to the power plant

affects the design and configuration of the plant fuel gas system. The gassupplier’s contract with the power plant Customer may contain temperatureguarantees at the outlet of the gas supplier’s custody transfer point. However,between this point and the power plant the gas supply pipeline is usually buriedso that the gas will approach the ground temperature depending on both thelocation of the custody transfer point relative to the power plant and theambient ground temperature. For this reason, the design of the plant fuel gassystem has to consider the temperature range of the gas as it is received at theplant boundary, not per the gas supplier’s contract with the Customer.

3.4.8.1.3 Gas Analysis and Quality

The gas analysis provided by the Customer in the contract can normally beused for gas turbine performance calculations and for the identification oflevels of concentration of contaminants such as sulfur that can cause corrosionproblems in the gas turbine fuel gas system and HRSG LP economizer. Adiscussion of the impact of fuel gas contaminants on the gas turbine is providedin Reference 2. It is GE’s experience that for the design of the fuel gas system,the contract gas analysis does not contain sufficient information regarding thegas concentrations of heavy hydrocarbons and moisture that have a significantimpact on the water and hydrocarbon dew points and the hydrate formationtemperatures of the gas delivered to the plant. Also, it is GE’s experience thecomposition of the natural gas delivered to the power plant can vary bothseasonally and whenever gas is purchased from a different supplier.

Outside of dewpoint testing, the most reliable source for determining the gasdew points and hydrate formation temperatures that are used in the plant fuelgas system design basis is the records and experience of the customer’s gassupplier. For this reason, GE recommends that either during the proposaphase of the project or at the start of the project, a meeting be held with thecustomer and the Customer’s gas supplier to identify the information that isrequired from the gas supplier for the design of the plant fuel gas system. Thismeeting should also include a review of the gas supplier’s proposed design.





3.4.8.1.4 Type of Plant (Simple-Cycle, Combined-Cycle)

The type of plant affects to design and configuration of the gas supply system.For example, some combined cycle units will require design of separate gassupply systems off the main header for the gas turbines, and potentially for theHRSG duct burner and the auxiliary boiler, if included in the project scope.

3.4.8.1.5 Number of Units

The number of units affects the sizing and configuration of the pressure controlequipment as well as the configuration and type of the gas conditioning

equipment that is used.

3.4.8.1.6 Mode of Operation (Peaking, Cycling Duty, Base Load)

The mode of operation of the plant affects the sparing philosophy for gasconditioning equipment. For example, a single gas coalescing filter is sufficienfor a simple cycle gas turbine installed for peaking duty. However, for a baseloaded simple cycle gas turbine in base load operations, redundant capacitywould be required if coalescing filters are used for gas conditioning.

3.4.8.1.7 Future provisions

The initial design of the power plant fuel gas system can include provisions forthe addition of future units that are part of the Customer’s generation plan forthe site.

3.4.8.2 Design basis

3.4.8.2.1 Design Pressure

For power plant fuel gas systems with no pressure control valves or regulators,the design pressure should be established based on consideration of both the

set pressure of the gas supplier’s overpressure protection; and on the limitingdesign pressure of the GE and BOP equipment supplied for the project. Thefact that the gas supplier’s over pressure protection affects the design pressureof the power plant fuel gas system is one of the reasons why coordinationbetween the gas supplier and the plant engineer is required.

For power plant fuel gas systems with pressure control valves, the systemdesign pressure should be established based on the limiting design pressure ofthe GE and BOP equipment supplied for the system.





3.4.8.2.2 Design Temperature

The piping design temperature should be established based on a review of the

maximum and minimum process conditions as well as on the ambientconditions.

3.4.8.3 Equipment

3.4.8.3.1 Conditioning Equipment

It is Critical that the fuel gas is properly conditioned prior to being utilized asgas turbine fuel. This conditioning can be performed by a variety of methodsThese include, but not limited to: media filtration, inertial separationcoalescing and fuel hating. Gas fuel contaminant acceptable levels are given in

table 2b of reference 1 (paragraph 3.4.4).

It is critical that the fuel gas conditioning equipment be designed and sized sothat these limits are not exceeded.

For gas turbine power plants with multiple units and fuel gas heating, single orredundant filter separators, depending upon the plant operating mode, areinstalled in the fuel supply header upstream of the heaters. A dry scrubber isinstalled for each gas turbine unit.

3.4.8.3.2 Gas Heating Equipment

• Simple-Cycle

— Simple-cycle fuel gas heaters are used to meet the 28oC (50oF)super heat requirement of Reference 1. Water bath heaters or electricheater are used in this application. Steam can also be used to heat gas,but is not recommended when either water bath or electric heaters canbe used, as discussed below.





• Water Bath Heaters

— Water bath heaters as described under FUEL GAS SUPPLY

can be used. Design considerations for this type of heater include thespace required; the turndown and temperature control accuracyrequirements; the burner system emissions vs. the air permit; the heaterstack height requirement vs. the site air permit; and the impact on theplant heat rate for the fuel gas consumed by the heater. Water bathheaters have a practical rating limit of approximately 2,520,000 kcal/hr(10,000,000 Btu/hr) in a single shell.

• Electric Heaters – (Later)

• Steam Heaters

— In power plant applications where a large pressure cut is takenin the plant fuel gas system, fuel gas can be heated by condensing low-pressure steam in a shell and tube condensing-type heat exchanger.Due to the drawbacks involved, GE recommends that this approachonly be considered if water bath heaters or electric heaters cannot beused.

— The main advantages of using steam for heating natural gas isthe availability of plant steam and the smaller size of the heat exchangeequipment. Higher gas outlet temperatures can also be achieved byheating with steam, than with water bath heaters.

— The main drawbacks to heating high pressure gas with plant

steam include the need for a vacuum venting system on the shell of theheater to remove non-condensable gases; and the design provisionsrequired to prevent and detect entry of fuel gas into the steam systemand the condensate return system due to a heater tube leak.

3.4.8.3.3 Venting System

In steam condensing applications, the steam side of the heat exchanger requirescontinuous venting to prevent accumulation of non-condensable gases, whichwill cause the heater to stop condensing. Steam condensers typically operate ata vacuum, either at part loads or over the entire operating range, depending onthe heater design. Therefore, in order to continuously vent the steam side of

the heater, a vacuum source is required. The heater venting system should beseparate from the main condenser, to prevent entry of gas into the maincondenser due to a heater tube leak.

3.4.8.3.4 Design for Leakage

In power plant applications using steam for fuel gas heating, both the plantsteam supply and the heater condensing pressure are typically significantly





lower than the fuel gas pressure. Under these conditions, the direction of aheater tube leak will be from the gas system into the heater shell. Therefore,adequate design provisions are required to prevent both over pressurization of

the heater shell by gas system pressure and leakage of gas into other plantsystems.

3.4.8.3.5 Combined-Cycle Performance Heater

These heaters are of the shell and tube type with the gas on the shell side andthe water on the tube side. The heating is done with a hot water line comingfrom the HRSG IP economizer. The only type of heater recommended is asingle pass heater with two shells in series.

3.4.8.3.6 Pressure Control

Pressure control valves or pressure regulators can be used, as described aboveunder FUEL GAS SUPPLY.

3.4.8.3.7 Over Pressure Protection

If pressure control valves are used in the power plant fuel gas system, safetyrelief valves are required by code. Safety relief valve should be installed asdescribed in FUEL GAS SUPPLY. For safety relief valve installations, thepiping design has to consider the thrust loads due to SRV discharge. Also, apressure blow off valve should be installed to relieve pressure accumulation in

the fuel gas system due to control valve/regulator leakage, to prevent the SRVfrom lifting.

3.4.8.3.8 Metering

The gas turbine meter tube, including the meter instrumentation, is supplied byGE Gas Turbine and is installed in the fuel gas system piping between theshutoff valve and vent valve skid and the fuel gas module inlet connection.

3.4.8.4 Piping

3.4.8.4.1 Material

From the site terminal point with the gas supplier to the inlet of the fuel gasscrubber at the unit, seamless carbon steel piping is used. From the outlet ofthe GT unit gas scrubber to the inlet of the gas turbine fuel gas module, 304Lstainless steel is required by the GE Fuel Gas Specification, Reference 1.





3.4.8.4.2 Connections

Power plant fuel gas piping connections are welded. Connections at equipment

or valves are ANSI flanges. On some equipment, e.g. meter tubes, flange orbutt weld connections can be used.

3.4.8.4.3 Pipe Sizing

Fuel gas piping is sized based on pressure drop considerations. The gas supplycontrol pressure set point and over pressure set point(s) at the last pressure cutcannot be established until the maximum operating condition fuel gas pipingand equipment pressure drops have been calculated. The pressure dropcalculations must consider any low supply pressure operating conditions thatare included in the plant design basis as well as the impact of future planned

expansion of the plant on the pressure drop in the common supply headers tofuture multiple units.

The use of smaller pipe diameters and reduced-port isolation valves to reducethe installed cost of the plant fuel gas system must be weighed against theimpact of such cost reduction measures on the operability of the system underlow supply pressure conditions due to factors such as seasonal gas demand andfuture demands from other users on the gas supply pipeline.

3.4.8.4.4 Design for Pressure

The pressure design of power plant fuel gas supply piping is per ANSI/ASMEB31.1. For buried piping, a corrosion allowance of 1.6 mm (1/16-”) should beused. It should be noted that when using schedule piping, the excess wallabove tm that results from the B31.1 (or B31.3) minimum wall thicknesscalculation with A=0 may be greater than 1.6 mm (1/16-”), so that noadditional allowance for corrosion s required in the code calculation.

3.4.8.4.5 Design for Flexibility

For combined-cycle units with fuel gas performance heaters, a stress analysis isrequired for the fuel gas piping between the fuel gas heater and the gas turbinefuel gas module connection. For extended runs of above-grade fuel gas piping

exposed to direct sunlight, a stress analysis of the piping should be considered.

3.4.8.4.6 Piping Arrangement

Power plant fuel gas piping could be either buried or above grade at theconnections to the fuel gas equipment.

Above grade piping is bottom-supported.





3.4.8.4.7 Corrosion Protection

Un-insulated, above ground, carbon steel fuel gas piping should be painted

with a coating system that is suitable for the environmental conditions.

The power plant fuel gas piping should be electrically isolated from the gassupply supplier’s piping with dielectric isolating flanges.

As a minimum, buried onsite fuel gas piping should be coated and wrapped forcorrosion protection. However, cathodic protection of the buried fuel gaspiping may be required, depending on the chemical analysis, conductivity andcorrosivity of the surrounding soil. The design of the corrosion protectionshould be based on a review of the site soils report data.

For long runs of gas piping between the dew point heater and the unitconsideration should be given to having to heat trace/insulate the lines iextended shutdown periods are anticipated. An example of this scenario wouldbe having the primary fuel as distillate with fuel gas as the backup fuel or apeaking situation where the unit is down on a daily basis. This downtime couldlead to liquid formation in the gas line between the heater and the unit andcould cause liquid slugs to enter the unit at startup. Other mitigatingapproaches would be to vent the gas before starting through the vent valve andthen raise the minimal starting temperature. Install an absolute filter in place ofa unit scrubber to insure 100% liquid removal during startup.

3.4.8.5 Isolation Valves

Plug valves and metal-seated ball valves equipped with sealant injection ports,soft seated ball valves should be used for fuel gas isolation. Both flanged andbutt-weld valve connections can be used.

The power plant fuel gas system should be equipped with at least oneemergency shutoff valve. The emergency shutoff valve should be located farenough away from above ground, gas equipment to provide safe access formanual operation during a fire. The location of the emergency shutoff valveshould be shown on the plant arrangement drawing.

3.4.8.6 Filling, Venting and Purging Provisions

Sufficient purge and vent connections are to be provided such that each sectionof the fuel gas system can be isolated, depressurized and purged independently.





3.4.9 Installation

Buried fuel gas piping should be bedded and back filled with screened material

to protect the pipe coating and wrapping from damage from coarse debris.

To minimize the amount of debris, dirt and water that accumulates in thepiping during construction, sections of buried gas piping should be weldedabove grade, and then lowered into the pipe trench for final welding. Pipesections should be capped during construction, also to minimize the amount ofdebris, dirt and water that accumulates in the piping during construction.

3.4.10 Inspection and Testing

Power plant fuel gas piping is inspected and tested per the requirements of

ANSI/ASME B31.1. or ANSI/ASME B31.3





3.4.11 Cleaning

Water, dirt and construction debris will accumulate in the fuel gas pipingduring construction. This is especially true of pipe sections that sit in opentrenches for extended periods of time prior to final closure welds. Both thefuel gas supply pipeline to the power plant and the power plant gas distributionpiping to the units must be thoroughly cleaned to prevent equipment damagedue to debris, dirt and water that accumulates in the pipe during constructionand operation problems due to

3.4.11.1 Pneumatic Cleaning

Fuel gas piping can be pneumatically cleaned by air or natural gas blow. The

flow rate required for cleaning is established by the flow momentum (cleaningratio) approach as outlined in Reference 4 for cleaning of steam piping. Theapproach for design of the temporary piping is the same as for steam.

Initial, low velocity blows are recommended to remove large objects and thebulk of water, dirt and construction debris, prior to full pressure blows at thecalculated conditions.

When blowing from the upstream pipeline to the plant, the pipeline should becleaned separately prior to blowing through the plant pipeline. Cleaning theupstream piping first minimizes the debris that will be carried from the pipelineinto the plant piping, where it could cause severe damage to vessels left in-lineand plug drain piping.

3.4.11.1.1 Future Considerations

For gas-fired power plants with planned future expansion, the design of thetemporary piping and the procedures for pneumatic cleaning should considerthe maximum gas flow conditions with all units in operation.

In-line devices and equipment should be removed or protected duringpneumatic cleaning, as outlined below.





3.4.11.1.2 Control Valves

Control valves and diffusers should be removed to prevent damage to the valvetrim. Control valve diffusers should be removed to prevent both damage andlodging of debris in the diffuser passageways, which is difficult to removeSacrificial strainers and/or blowoff covers can be purchased with control valvesto protect them during pneumatic cleaning with the valves in place. However,it is GE’s experience that it is more cost effective to plan for removing controlvalves and diffusers from the piping during pneumatic cleaning.

3.4.11.1.3 Pressure Regulators

Pressure regulators should be removed from the piping, since they are typically

not designed for the conditions that will occur during pneumatic cleaning.

3.4.11.1.4 Metering equipment

Metering equipment, including the flow element, meter tube, strainers and flowstraighteners should be removed from the piping.

3.4.11.1.5 Instrumentation

Instrument should be valved out or removed, as applicable, from the piping.

3.4.11.1.6 Relief Valves

Relief valves, including safety relief valves and blowoff valves should beremoved from the piping.

3.4.11.1.7 Separation Equipment

Blowing through knockout drums, gas separators or scrubbers is acceptable ifthe upstream has been cleaned first; and if the required cleaning ratio can beachieved with this equipment in the flow path.

Otherwise, it is recommended that this equipment be bypassed with temporarypiping during pneumatic cleaning.

3.4.11.1.8 Filtration Equipment

Blowing through particulate or coalescing filters acceptable if the upstream hasbeen cleaned first; if the filter elements have been removed; and if the requiredcleaning ratio can be achieved with this equipment in the flow path





Otherwise, it is recommended that this equipment be bypassed with temporarypiping during pneumatic cleaning.

3.4.12 Preparation and Planning

3.4.12.1 Safety

When doing pneumatic cleaning with natural gas, precautions are requiredduring filling and blowing to prevent ignition. The temporary piping should bearranged for safe discharge of the gas, e.g. away from potential ignitionsources, nearby structures or occupancies. The piping should be groundedagain to eliminate a potential ignition source.

3.4.12.2 Noise

The noise emanating from the piping during pneumatic cleaning will have to beaddressed in the design of the temporary piping and considered in thedevelopment of the cleaning procedure.

3.4.12.3 Equipment and Services

Motor-operated valves should be used for on/off control of the gas blow.Valves for this service should be specified to open against full shutoff pressure.Compressors will be required for air or nitrogen blows. Activities to specify

and procure the required equipment and services for pneumatic cleaning haveto be done sufficiently in advance to support the project construction andstartup schedule.

3.4.12.4 Coordination with Gas Supplier

Natural gas blows, where performed, have to be coordinated with the gassupplier to confirm that there is adequate pressure and pack in the pipeline tosupport sustained gas blows to complete the cleaning of the plant gas supplypiping without interruption of service to others users on the pipeline.

Targets can also be used to confirm piping cleanliness.

3.4.12.5 Cleanliness During Construction

Weld pipe sections above grade and cap piping at the end of each workday tominimize debris and water accumulation in the pipe sections. Work aboveground to minimize open piping sections sitting in trenches prior to closurewelds. Use in TIG root passes welds for final closure welds.





3.4.12.6 Pigging

The use of pipe size changes along headers supplying multiple units to reduce

piping cost is not recommended if the piping will be cleaned with pigs.

3.5 Fuel Oil (FO) System

3.5.1 Overview

Liquid hydrocarbon fuels that have been burned in gas turbines are shownbelow. Distillate is the most common liquid fuel, and except for a fewinstallations where natural gas is not available, it is used primarily as a backupand alternate startup fuel. Crude oils are common as primary fuels in many oil-

producing countries because of their availability.

All fuels must conform or be made to conform to the Gas Turbine Liquid FueSpecification, Reference GEI-41047.

Both crudes and residuals will require treatment for sodium salts and vanadiumcontamination. Further fuel preparation for use in the gas turbine may includefiltering and heating to maintain proper viscosity for atomization at the fuenozzles.

• Conventional Liquid Fuels

— Distillate — Crude Oils

— Residuals

• Less Conventional Liquid Fuels

— Jet Fuels

— Kerosene





• Unconventional Liquid Fuels

— Naphtha

— Natural Gas Liquids

— Natural Gasolines

• Process Residuals

• Methanol

Jet fuels and kerosene have occasionally been used as backup fuels whereavailability and economic considerations have made these fuels a moredesirable choice than the distillates. The basic problem with these lighterfractions is that their lubricity is lower than the distillates and heavier fuels. Aminimum level of fuel lubricity is desirable to provide reasonable life of themechanical fuel system components such as the main fuel pump and flowdivider. However, since these fuels have been selected primarily as backupfuels, with limited operation expected, the current approach to their lowlubricity is to accept the somewhat shorter parts lives.

Naphtha, natural gas liquids and natural gasolines have an even lower level oflubricity and, in addition, also have flash points that are low enough to requirespecial handling from a safety point of view. The lack of lubricity is ofsufficient magnitude that additives are not an economically viable solutionespecially since most current applications of these fuels are for essentiallycontinuous duty. As a result, a different concept of fuel control and flow

division has been developed for those applications utilizing these fuels. Thisnew approach is referred to as the “pressure compensated flow division liquidfuel system”.

The pressure compensated flow division system eliminates those componentsthat require a minimum level of fuel lubricity through use of a motor-driven,high-head centrifugal pump and flow division via carefully matched orificesoperating with a very high pressure drop. The PCFD skid meets the hazardousarea requirements of Class 1, Group D, Division 2.


Most gas turbine systems being purchased today with the liquid fuel option arebeing specified using distillate oil.





The following describes system design considerations for units using distillateoil as the primary fuel supply. Some changes to these design considerations are

appropriate when distillate oil is used as a backup fuel supply to the primaryfuel source.

3.5.3 System Components

The following components comprise the typical distillate oil delivery/storagesystem:

• Fuel oil unloading station

• Fuel oil storage facility

• Fuel oil forwarding

• Interconnecting piping and valves

3.5.3.1 Fuel Oil Unloading Station

The fuel oil unloading station is typically comprised of several unloadingpumps designed for low suction head conditions. The feed to these pumps maybe tied to a header or individual suction lines. In either case, the terminal pointof the unloading station must be designed to connect the tank truck connectionto the supply line. These connections are quick disconnect type which provide

for each mate up with the tanker. Suction lines to pumps must include a coarsestrainer. Sizing of the pumps is generally based on being able to unload atanker in about twenty minutes. These tankers each can hold approximately30,000 liters (8000 gallons) of fuel oil. Fuel is then pumped to the fuel oilstorage tank(s) via a local control which should be interlocked with the tanklevel control loop. Typical pump loading capacity 80 – 90 m3/hr. (20 – 25GPM).

Flow metering should be provided as the fuel oil is being pumped to thestorage tanks. The number of fuel storage tanks and their size should besufficient to provide a flow of fuel to the turbine(s) without interruption. Thiscriteria will also be key in sizing the area required for the fuel oil unloadingstation. Areas of concern in sizing the unloading station are the number oftrucks required to unload on a daily basis, their size, the area required to drivein and drive out while being unimpeded by other tankers in the unloading areaas well as the entry and exit points to and from the plant.





3.5.3.2 Fuel Oil Storage

A minimum of two storage tanks is required. Each tank is to be of sufficientsize so as to provide an uninterrupted supply of fuel for that period of timenecessary to fill the second tank and allow a twenty-four hour settling periodafter filling. This is a minimum requirement. Total fuel consumption and thenumber of tankers required to fill the storage tank is another importanconsideration in tank sizing. The larger the tank, the more flexibility there isbetween delivery cycles.

An exception to this rule can be made when distillate oil is used as a backupfuel source. In this instance, a single tank may be used assuming that thesettlement criteria above, is met prior to draining fuel oil from the storage tank.Tank size and frequency of use will also influence the number of storage tanksrequired.

If the fuel is to be washed or otherwise treated, the use of a smallercertification tank is recommended. The treated fuel would go into this tankfirst and then pumped into the larger tank when positive verification of fueltreatment is acknowledged. Unsatisfactory fuel would be recycled for furthertreatment thereby preventing contamination of the larger storage tank.

Inlet piping to the storage tank should be eighteen inches minimum above thebottom of the tank. Baffling at the point of fuel entry is desirable. Theincoming stream of fuel should not be directed toward the bottom of the tank

or done in such a way as to stir up any material settled on the bottom of thetank. A velocity diffuser can be used to minimize the jet effect of incomingfuel.

A floating suction line within the tank should be used so that the fuel beingdrawn off to the turbines is near the top of the fuel oil level. The travel of thefloating suction should be limited so that the inlet is never less than eighteeninches off the bottom.

Any recirculation of fuel back to the storage tank must be done in a mannerthat will cause minimum agitation of fuel in the tank. The return line shoulddeliver the fuel at a location removed from the floating suction in a way thatwill not stir up any material settled at the bottom of the tank.





After filling a tank or adding additional fuel to it, allow twenty-four hours for asettling period before taking fuel from the tank. Under no circumstances

should fuel be pumped into a tank at the same time that it is being pumped out.Storage tank bottoms should slope to an area from which water and othersettled material can be removed.

For fuels that are highly volatile and have a low flash point, it may be desirableto use a floating roof on the tank. This reduces the fire hazard and minimizedloss by evaporation. A fixed roof over the floating roof is desirable so thatthere will be minimum entrance of rain and condensation.

3.5.3.3 Fuel Oil Forwarding

Fuel oil forwarding skids, transfer oil from the storage tanks to the turbine fueldelivery and combustion system. Design practices and considerations are thesame as those used for the balance of systems described here”

3.5.4 Process/Operating Factors

Piping materials are to be per Section 4.1.3 and piping velocities per Section4.1.4.

The minimum wall thickness, tm, for piping is determined in accordance withANSI/ASME B31.1, Section 104.1, Pressure Design of Components –Straight Pipe. The minimum wall thickness will equal 87.5% of the nominal

wall thickness for schedule pipe due to manufacturing tolerances. The actualwall thickness, ta, includes the tolerance added for machining of the “C”dimension required for the weld end detail.

For containment philosophy, please refer to Section 8, Environmental andSafety Systems.

Buried piping systems need to address the needs of cathodic protection toprevent pipe corrosion. Depending on soil conditions, pipe may be directburied with no external protection, coated and wrapped in areas which bordercorrosive conditions or in aggressive environments, use sacrificial anodes or

impressed current systems of protection.

For above ground runs of piping, thermal expansion due to solar radiationmust be considered when designing the pipe runs.





3.6 Gas Turbine Piping Systems

3.6.1 Gas Turbine Plant Equipment Drains Systems

The gas turbine plant equipment drains system consists of drains from thefollowing individual systems:

• Liquid fuel and lube oil drains from the gas turbine to the gas turbine drains

tank

• Water and liquid hydrocarbon drains from the fuel gas heaters, scrubbers,

filter separators, etc. to the gas drains tank.

• Compressor wash water effluent for off-line turbine wash cycles to the

water wash drains tank.


007CC Gas Turbine Drains Tank (per GT unit) Qty-1

007CD Fuel Gas Drains Tank Qty-1

007CI Water Wash Drains Tank (per GT unit) Qty-1

Note: Unit quantities may change based on site-specific arrangements.

3.6.3 Piping Design

Piping materials are to be per Section 3.1.3.


The gas turbine false start and water wash drains tank shall have a rectangularcross-section. The tank shall be single-walled and located in a covered, belowground vault. The tank shall be divided into two compartments by a double-walled partition with leak detection connection.

The gas turbine drains system includes discharge flows from the unit should a

false start occur. The false start drain valve is thus normally closed and underpressure during normal operation. There may be an occurrence when the valvecould fail in the open position thereby discharging compressed air to theenvironment.





Because the gas turbine drains system is a gravity drains system pressurizingthe line during a drain valve failure will pressurize the drain line and can

potentially cause vapors to backflow through the purchasers connectionmanifold and branch connections. For this reason it is recommended that thefalse start drain connections discharge into an open funnel which is then pipedto the header. This design not only maintains the piping system at atmosphericpressure, but it also provides an audible recognition of a failed open false startdrain valve.

Under no circumstances should this system be tied into relief valve dischargesof any fuel oil or fuel gas equipment.

These requirements are detailed in GEK 110885, “Gas Turbine Drain DesignRequirements.” This document provides some system recommendations and is

based on the results of GE Product Safety Reviews.

The water wash drains and liquid fuel/oil drains are atmospheric gravity drainsand should be designed accordingly.

The fuel gas drains tank should be designed to accommodate simultaneousopening of all drains piped to the drains tank. Vent should be adequately sizedto prevent over pressurization of the drains tank.

Gas turbine drain piping should be routed outside enclosure into drain headerto preclude potential drain backflow.

The tanks shall be made of ASTM A285, Grade C carbon steel with platethickness not less than 9 mm (3/16 inch) thick or equal.

3.6.5 Tank Sizing

Frame Size Gas Turbine Drains Tank

Liters (Gallons)

Wash Water Drains Tank

Liters (Gallons)

6B/F 950 Liters (250 Gallons) 9500 Liters (2500 Gallons)7EA 950 Liters (250 Gallons) 9500 Liters (2500 Gallons)9E 950 Liters (250 Gallons) 11400 Liters (3000 Gallons)

7FA/FB 1900 Liters (500 Gallons) 9500 Liters (2500 Gallons)9FA 1900 Liters (500 Gallons) 13300

Liters (3500 Gallons)

Note: Capacities calculated between bottom of tank and bottom of inleconnection 1524 mm (5 ft.).





3.6.6 Combined False Start and Water Wash Drains Tank

Note: Plan view height represented in table below.

Frame Size X1 mm (ft) Y1 mm (ft) X2 mm (ft) Y2 mm (ft) Height mm

(ft)

6B/F 2743 mm(9 ft.)

2743 mm(9 ft.)

1219 mm(4 ft.)

1067 mm(3.5 ft.)

1676 mm(5.5 ft.)

7EA 2743 mm(9 ft.) 2743 mm(9 ft.) 1219 mm(4 ft.) 1067 mm(3.5 ft.) 1676 mm(5.5 ft.)9E 3048 mm

(10 ft.)2743 mm

(9 ft.)1219 mm

(4 ft.)1067 mm(3.5 ft.)

1676 mm(5.5 ft.)

7FA / FB 3048 mm(10 ft.)

2743 mm(9 ft.)

1676 mm(5.5 ft.)

1524 mm(5 ft.)

1676 mm(5.5 ft.)

9FA 3200 mm(10.5 ft.)

3200 mm(10.5 ft.)

1676 mm(5.5 ft.)

1524 mm(5 ft.)

1676 mm(5.5 ft.)



Y1

X1

X2

Y2

WATER WASH



3.6.7 Gas Turbine Water Injection System Piping

All interconnecting piping, flanges valving etc. both to and from the waterinjection skid must be stainless steel (ANSI 304L or 316L). The water storagefacility should be stainless or suitably coated.

The process conditions at the skid inlet must be properly maintained within thelimits specified on the respective GE Product Department piping schematicpertaining to MLI 0462.

Pressures higher or lower than those specified at the skid inlet can result in aplant trip due to over or under injection of water respectively.

3.7 Compressed/Service/Instrument Air (SA/IA) System

3.7.1 System Description – Simple-Cycle Power Plants

Instrument air is supplied, on a station basis, by two (2) 100% capacity oil-free, motor-driven compressors.

Instrument air is required for the various air-operated valves and instruments inthe power plant including initial setting of the DLN control valves prior to unit

startup. Instrument air, is dried by an air dryer such that it has a dew point of –40oC (-40oF). The dryer comes with redundant pre-filters and after-filters. Anair receiver is located just upstream of the air dryer. The system comes pre-packaged and is skid-mounted.

3.7.2 System Description – Combined-Cycle PowerPlants

The compressed air compressor system is composed of the instrument airsystem and the service air system. Instrument air is required for the various air-operated valves and instruments in the power plant, while service air is used

for such services as power tools. Instrument air, is dried by an air dryer suchthat it has a dew point of –40°C (-40°F).

Instrument and service air, is supplied by two (2), 100% capacity oil-flooded,screw type, motor-driven compressors.

Discharged air is piped to a common air receiver.





A pressure control valve located on the service air distribution system does notallow air to flow into the service air system unless the pressure in the commonportion of the compressed air system is high enough to satisfy the instrument

air system. This ensures that the instrument air system requirements are alwayssatisfied prior to allowing for the service air requirements.

Downstream of the common air receiver, the instrument air is dried via two100% capacity dual tower desiccant air dryers. The dryer skid comes completewith redundant pre-filters and after filters to insure good quality air for theinstrument air system.


011BA Air Compressor Qty-2

Air Receiver Qty-1Pressure Swing, Heatless (Desiccant) AirDryer (Dual Tower)

Qty-2


Design pressure of the system shall be 8.8 kg/cm2,g (125 psig).

The design capacity for the compressed air equipment will be based on themaximum instrument air demands and/or service air demands (as applicable)for the plant.

Drains shall be installed at all low points.

Quick disconnect hose connections with shutoff valves shall be located at aconvenient location for maintenance purposes.

Hose connections shall be located so that no more than a 15 m (50 ft) air hosewill be required to reach any maintenance located in the plant. This includesthe circulating water pump-house, fuel area, roofs and ventilation filters.

The design temperature of the compressed air systems is determined inaccordance with ANSI/ASME B31.1, Section 101.2.2, Internal Design

Pressure. This section states the internal design pressure shall be not less thanthe maximum sustained operating pressure within the piping system. A safetyvalve on the air receiver will be utilized to protect the system from overpressurization. The air compressors will also have a safety valve for protection.

The design temperature of the compressed air systems is determined inaccordance with ANSI/ASME B31.1, Section 101.3.2, Design TemperatureThis section states that design temperature shall be based on the expectedmaximum sustained operating temperature (MSOT).





This maximum compressed air temperature will be related to the maximumtemperature of cooling medium for the compressor’s after-cooler. Water-cooled air compressors will be used and supplied from the auxiliary cooling

water system. The MSOT will be the maximum auxiliary cooling watertemperature plus the air compressor after-cooler TTD rounded up to thenearest 5oC (10oF) increment.

3.7.4.1 Air Compressors

The oil free flooded screw-type air compressor will be equipped with an inletair filter, which will be sized to handle at least 150% of the air compressorcapacity.

The air compressor inlet air filter will be equipped with an air intake blowoff

silencer muffler which will be sized for the unloading cycle to allow 85 dBAmaximum discharge air noise, measured three feet from the muffler endopening and side wall.

Additionally, local regulations or client noise limit requirements may applyTherefore, acceptable noise levels for each project shall be evaluatedindividually.

The air compressor will be located as near the air receiver as possible. Pipingshould be as short and as direct as possible with a minimum number of elbowsand fittings. The discharge line from the air compressor will not be reduced.

3.7.4.2 Air Receiver

The air receiver will confirm to the Section VIII, ASME Code requirementsfor unfired pressure vessels and will be sized to dampen out pressurefluctuations and provide surge time to take care of sudden heavy air demands.

The air receiver will be made of ASTM 285, Grade C carbon steel.





3.7.4.3 Sizing Criteria Required For Compressor and Receiver?

3.7.4.4 Instrument Air Dryers

Two (2) dual tower, pressure swing, heatless desiccant air dryers will be usedThe instrument air dryer will conform to the Section VIII, ASME Coderequirements for unfired pressure vessels and will be sized to provide dry air (-40oF dewpoint) for a volumetric flow capacity equal to 125% of the totalcombined calculated instrument air demand at a line pressure of 8.1 kg/cm2,g(115 psig). The pre-filter on the instrument air dryers will be 2 x 100%coalescing type filters designed to remove all particles 3 microns and larger.The after-filter will be 2 x 100% coalescing type filters designed to remove allparticles 0.6 microns and larger.

3.7.5 Piping Design


The following criteria will also be used during the compressed air systemallowable pressure drop calculations:

• Pressure drop across the instrument air dryer to be used in calculations is

0.7 kg/cm2, g (10 psi).

•Maximum allowable pressure drop from the after-filter on the instrumentair dryer to the end user of the instrument air system is 10% of theinstrument air system design pressure.

• Maximum allowable pressure drop from the air receiver to the end user of

the service air system is 10% of the service air system design pressure.

• Maximum pressure drop in the main system headers is 0.21 kg/cm2, g (3

psi).

• Maximum pressure drop in the main system branches is 0.21 kg/cm2, g (3

psi).

• Maximum pressure drop in the individual air lines from the main system

branches to the users is 0.28 kg/cm2, g (4 psi).

• Maximum allowable pressure drop in the air compressor inlet air filter is

0.035 kg/cm2, g (0.5 psi).





3.7.6 Standards

The standards and codes listed below are for design and construction of the

compressed air system:

3.7.6.1 American National Standards Institute (ANSI)

ANSI/ASME B31.1 Power Piping

ANSI B16.8 Cast Bronze Solder-Joints Pressure Fittings

ANSI B16.10 Face-to-Face and End-to-End Dimensions of Valves

ANSI B16.22 Wrought Copper & Bronze Solder-Joints Pressure Fittings

ANSI B16.24 Bronze Flanges and Fittings

ANSI B16.34 Valves – Flanged, Threaded and Welding End

ANSI B36.10 Welded and Seamless Wrought Steel Pipe

3.7.6.2 American Society of Mechanical Engineers (ASME)

Unfired Pressure Vessel Code

3.7.6.3 American Society for Testing Materials (ASTM)

ASTM A105 Forged Carbon Steel

ASTM A106 Carbon Steel for High Temperatures

ASTM A126 Cast Iron

ASTM A182 Forged Austenitic Alloy Steel

ASTM A216 Cast Carbon Steel

ASTM A312 304 Stainless Steel

ASTM B43 Seamless Red Brass Pipe

ASTM B88 Seamless Copper Water Tube

3.7.6.4 Instrument Society of America (ISA)

ISA S7.3 Quality Standard for Instrument Air

3.8 Nitrogen Blanketing (N2) System


A nitrogen blanketing system is used during short unit shutdowns to protectthe internal surfaces of the HRSG from corrosion. When extended unitshutdown are anticipated, the system should be drained, dried and blanketed





The nitrogen blanketing system consists of standard pressurized nitrogencylinders connected to a station manifold. The system is designed to maintainnitrogen in each HRSG drum during short shutdowns. Nitrogen is supplied by

separate lines to the high, intermediate and low pressure drums of the HRSG.


010CB Nitrogen Storage Rack (each HRSG) Qty-1

Manifold (each HRSG) Qty-1

Pressure Regulator (each HRSG) Qty-1

Bottle rack and manifold designs may change based on site specificarrangement.

The nitrogen system will consist of a storage rack and the piping and valvesrequired to transport nitrogen to the various pieces of equipment that requireblanketing during outages and unit shutdowns.

Nitrogen will be delivered to the site in gas cylinders, which will be manifoldedtogether.


The system is manually activated with automatic pressure control afteractivation to provide a continuous and uninterrupted supply of gas.

3.8.4 Piping Design


Nitrogen will be piped from the gas storage cylinders to the HRSG steamdrums for blanketing during outages and unit shutdowns.

The nitrogen system piping will be designed to the requirements ofANSI/ASME B31.1, Power Piping.

The system piping will match the size of the outlet connection on the cylinder

bottle manifold.

A pressure regulating valve will be located downstream of the nitrogencylinder manifold to maintain a nitrogen blanket pressure of 0.35 kg/cm2, g(5 psig).

A drain or bleed-off with shutoff valve will be located downstream of thepressure regulating valve.





A check valve will be located downstream of the drain or bleed-off, followedby a shutoff valve.

Each branch to a piece of equipment will have an isolation valve rated atequipment pressure.

The design pressure of the nitrogen system piping will be 0.35 kg/cm2, g (50psig).

The rapid expansion of nitrogen gas when it expands from the high pressurenitrogen cylinder into the low pressure nitrogen piping system results in anextreme chilling effect. This should be considered in determining the lowestexpected service temperature relative to the brittle fracture of the materiaselected.

For schedule pipe, the minimum wall thickness, tm, for the nitrogen systempiping is determined in accordance with ANSI/ASME B31.1, Section 104.1,Pressure Design of Components – Straight Pipe, where t m equals 87.5% of thenominal wall thickness for schedule pipe due to manufacturing tolerances. Theactual wall thickness, ta, shall be determined based on schedule pipe tolerancesThe schedule of pipe with a wall thickness equal to or greater than t a will beselected. The actual wall thickness, ta, includes the tolerance added formachining of the “C” dimension required for the weld end detail.





3.9 Hydrogen (H2) System


Hydrogen system is provided for hydrogen-cooled generators. The systemconsists of standard pressurized storage cylinders connected to a generatormanifold supplied with the generator.


010CD Hydrogen Storage Qty-1The bulk hydrogen gas bottle manifold should have the following features:

A. Pigtails: One for each hydrogen gas bottle. There is a check valve on themanifold end fitting of each pigtail.

B. Globe Valve: One for each hydrogen bottle.

C. Pressure Regulator Valve: This valve drops the pressure from the high-pressure bottle manifold pressure down to approximately 8.8 kg/cm2,g(125 psig) as required by the downstream flow regulation restrictionGauges are provided on the regulator valve.

D. Pressure Regulator Bypass Valve: The bypass valve should be opened or

closed completely and not put into a partially opened position.

3.9.3 Piping Design

Refer to Section 3.1.1.


Hydrogen is used in place of air as the cooling agent for generators principallybecause of its low density and its superior cooling properties. Due to theextreme lightness of hydrogen – its density being only 1/14 th the density of air –

hydrogen cooling reduces the windage friction losses of a rotating machine to asmall fraction of their value with air cooling.





Other advantages of hydrogen cooling are: less windage noise than with aircooling; the windings and ventilating passages remain cleaner because the

generator is completely enclosed; corona effect on the winding is minimizedand the fire hazard in the generator casing is eliminated because pure hydrogenwill not support combustion.

Pure hydrogen is nonflammable; however, a mixture of hydrogen and aircontaining between four and 75% hydrogen by volume may be ignited if it iscomes in contact with a spark or open flame.

Explosive hydrogen mixtures in the casing of the hydrogen-cooled generatorare avoided by maintaining the hydrogen purity in the casing at approximately97% in normal operation, and by the introduction of an inert gas, such ascarbon dioxide, into the casing when changing from air to hydrogen and

hydrogen to air.

The hydrogen equipment of the generator is so arranged that ample ventilationis provided for the parts from which hydrogen leakage to atmosphere mightoccur. Care should be taken, however, to insure that any hydrogen dischargedfrom the various valves open to atmosphere is not allowed to collect inenclosed spaces; also, bringing an open flame into a region in which hydrogenmay be discharged should be avoided.

3.9.5 Control Philosophy

The gas control system includes a control panel, hydrogen manifold, carbondioxide manifold, gas dryer, pressure regulators and necessary gauges tosupervise the following principal functions:

A. To maintain the hydrogen purity and pressure in the generator at therequired value in normal operation.

B. To provide means for safely interchanging hydrogen and air in thegenerator casing, using carbon dioxide as the purging agent.

C. To maintain a dry atmosphere in the generator at all times by removing thesmall amount of moisture that may enter the generator casing with the oilfrom the shaft seals.

D. To indicate the pressure, purity and temperature of the hydrogen in thegenerator and to detect the presence of oil or water in the casing.

An alarm signal system provides audible and visual indications of abnormaconditions in the gas control or shaft-sealing system.





3.10 Carbon Dioxide (CO2) System


A carbon dioxide system is provided to purge the hydrogen from thegenerators. The carbon dioxide system consists of standard pressurized carbondioxide storage cylinders connected to a manifold supplied with the generator.


077 Chemicals and Gases Qty-1


The CO2 gas bottle manifold should have the following features:

A. Pigtails: One for each carbon dioxide gas bottle. There is a check valve onthe manifold end fitting of each pigtail.

B. Globe Valve: One for each carbon dioxide bottle.

C. Pressure Regulator Valve: This valve drops the pressure from the high-pressure bottle manifold pressure down to approximately 8.8 kg/cm2,g (125psig) as required by the downstream flow regulation restriction. Gauges areprovided on the regulator valve.

D. Pressure Regulator Bypass Valve: The bypass valve should be opened or

closed completely and not put into a partially opened position.

3.10.4 Piping Design

The CO2 piping upstream of the gas control valves should have a flowregulation orifice to control flow rate during the purge step which admits COinto the generator. Downstream of this orifice there should be a section oflarge diameter pipe where solid CO2 precipitation can accumulate. Refer toSection 3.1.3 for piping material specifications.






An inert gas, carbon dioxide, is used as an intermediate gas so that air andhydrogen do not mix inside the generator. The purging procedure for thegenerator has carbon dioxide introduced to displace the air, then hydrogenintroduced to displace the carbon dioxide. The generator is then pressurizedwith hydrogen and the pressure is maintained automatically with a controlvalve. The generator may remain pressurized with hydrogen during shortoutages even if the shaft is not on turning gear. Prior to opening the generatorfor maintenance, the hydrogen is depressurized and then carbon dioxide isintroduced to displace the hydrogen. Air is then introduced to displace thecarbon dioxide and the end shields can be opened. During an emergency it isimportant to at least purge the generator of hydrogen by introducing carbon

dioxide.

Gas control during the purge operations will be automated or can beperformed manually at the gas control valve station.

3.10.6 Ambient Design Factors

The minimum supply temperature of CO2 to the generators is 10oC (50oF). Forplants where the storage environment of the CO2 cylinders may go below 10oC(50oF) (outdoor applications) the cylinders should be housed in a heatedenclosure that is sized and designed to prevent walk-in possibility.

The reason for maintaining a 10oC (50oF) ambient is to insure that solids do notplug up the supply line during the expansion process, which would inhibit thepurge cycle during an incident.

3.11 HVAC

3.11.1 Introduction

3.11.1.1 General

This Section outlines the basic heating, ventilating and air conditioningrequirements for the following areas:

• Turbine Hall

• Electrical equipment Areas





• Control Room

3.11.2 Design Criteria The following needs to be established when estimating or designing the plantHVAC system:

• Maximum ambient temperature/relative humidity

• Minimum ambient temperature/relative humidity

• Indoor design temperature, ventilated systems, summer/winter

• Indoor design temperature, air conditioned spaces, summer/winter

For indoor design conditions, offices, control room and locker rooms shouldbe based on winter temperatures of 20oC (68oF) and a summer temperature of22oC (72oF). Ventilated areas are based on a –10oC (14oF) rise above ambient.

These values are suggested starting points. Customer RFQ and/or contractrequirements shall take precedence over these suggested values. Site specificsituations such as extreme tropical environments should be dealt with on a caseby case basis.

3.11.3 Turbine Hall Ventilation Design Criteria Basis

Temperature rise within the building.

3.11.3.1 Ventilation Fan Sizing Criteria

Air flow based on the above two relevant criteria.

3.11.3.2 Heat Loads

Building heat loads shall consider heat generated inside the building due toboth mechanical and electrical equipment as well as the effects of solar

radiation.

The following heat loads shall be considered:

• Gas turbine compartment ventilation ductwork radiant and

convective heat rejection

• Steam turbine, condenser, steam cycle piping





• HRSG radiant and convective heat loads

• Electrical equipment

• Solar radiation

For the 7FA/7FB gas turbine models, care should be given in determining if theunit(s) come with an exhaust diffuser enclosure. This enclosure comes withcom0artment ventilation, which should normally be ducted outdoors. If theunit is not equipped with an exhaust diffuser enclosure or if the enclosure isvented into the building, an additional 252,000 kcal/hr (1,000,000 Btu/hr) mustbe added to the overall heat duty per unit. Larger heat duty should beanticipated for the 9FA/9FB units.

The Engineer should reference the heating and ventilation information found

under ML 0412 (part of the gas turbine documentation package) for jobspecific cases.

3.11.3.3 Building Louver

Building louver are depends on the amount of air required to meet the buildingtemperature rise design criteria in addition to the total air required forcompartment ventilation for the gas turbine(s).

Acoustic requirements for plant noise abatement will have a considerable affecton the final louver face area specified.

3.11.3.4 Gas Turbine Compartment Ventilation

Gas turbine compartment ventilation air should be ducted outside the buildingdue to the high exhaust temperature. Remaining ventilation openings should bereviewed on a case-by-case basis to determine if the various compartmentvents can be left to vent indoors. If such is the case the system designer shallconsider this in the overall turbine hall heat load.

Ventilation ductwork should be sized to within the maximum allowablepressure losses as defined by the gas turbine ventilation system drawings.

Units with off-base gas compartments will require the extension of skid-mounted bleed and vent lines to a safe location. These vent lines can containfuel gas.





3.11.3.5 Turbine Hall Heating

Forced air convective type heaters, roof-mounted hot air recirculation fans or a

combination of both are the preferred methods of building heating.

3.11.4 Electrical Equipment Areas

Electrical equipment subject to ambient temperatures greater than 40oC(104oF) may require deaerating.

3.11.5 Control Equipment

The DCS and it’s supporting equipment (i.e. I/O racks) should be installed in atemperature controlled environment.

3.11.6 Battery Rooms

Induced draft ventilation to the outdoors.

3.12 Fire Protection

3.12.1 Introduction

The purpose of this guideline is to provide recommendations and referencematerials to be considered when defining fire suppression methods for powerplant protection systems. This guideline includes and goes beyond the basedesign elements found in the reference plant. Final system design should beconsistent with the Design Criteria and Assumptions Section of the TechnicalProposal. Finally, the proposed design must have approval of the authorityhaving jurisdiction.

3.12.2 General

These guidelines provide recommendations (not requirements) for the fire

protection systems for power plants based on NFPA 850 – RecommendedPractice for Fire Protection for Electric Generating Plants and HVDCConverter Stations.

It should be recognized that many of the specific recommendations providedherein, may require modification after due consideration of all local and projectspecific requirements involved.





Examples of local factors are local fire codes, fire water supply limitations, andproximity of the plant to adjacent structures.

Examples of project-specific requirements include contract requirementscustomer’s insurance company requirements, and the location of plant firehazards in relation to other plant structures and equipment.

3.12.3 Base Case Reference Designs

3.12.3.1 Simple-Cycle Design Basis

The following design basis pertains to simple-cycle reference plant designs:

The fire protection system is supplied from the city water distribution system at

adequate flow and pressure.

A fire main with hydrants is provided around the power plant site withsectionalizing valves properly located for ring header isolation. Every otheryard hydrant should include a hose house containing hose, wrench and fire axe.

Fire walls are installed to provide fire barriers between adjacent transformersand between transformers and adjacent structures. Deluge fire suppressionsystems are not included for oil-filled main step-up and large station servicetransformers.

The gas turbines are protected by a low pressure CO2 fire protection systemRefer to the Gas Turbine and Accessories Tab for a description of the CO 2 fireprotection system.

3.12.3.2 Combined-Cycle Design Basis

The following design basis pertains to combined-cycle reference plant designs:

The fire protection system is supplied from the city water distribution system atadequate flow and pressure.

A fire main with hydrants is provided around the power plant buildings and

site. A standpipe system is provided for the turbine building with sectionalizingvalves properly located for ring header isolation. Every other yard hydrantshould include a hose house containing hose, wrench and fire axe.

Firewalls are installed to provide fire barriers between adjacent transformersand between transformers and adjacent buildings. Deluge fire suppressionsystems are not included for oil-filled generator step-up transformers and largestation service transformers.





Areas and equipment protected by fire suppression systems are defined below:

• Yard hydrants, hose stations and portable fire extinguishers

• Hose stations for building protection

• Automatic dry pipe or foam-water sprinkler protection for steam

turbine lube oil tank

• Automatic or manual dry pipe sprinklers for office areas, locker

rooms and restrooms in the turbine building

• Wall-mounted handheld extinguishers for control room area

• Automatic water spray system for cooling tower of combustible

construction

• Fuel oil tanks

3.12.4 Design Guidelines

The default designs for both simple and combined-cycle plants are as describedin Section 3.12.3. Variations to the default design may occur due to projectspecific requirements.

The following summarizes general requirements and design guidelines for

optional fire suppression systems:

3.12.4.1 Water Supply

The water supply for the permanent fire protection installation should be basedon providing a 2-hour supply for the following:

• The largest fixed fire suppression system (or any fixed fire

suppression systems that could reasonably be expected to operatesimultaneously during a single fire)

• Plus the hose stream demand of not less than 113.6 m3/hr (500

gpm)

The water supply may originate at an existing fire main or appropriate citywater supply line.

For on-site storage, a reliable water supply must be available (-to refill-), one(1) firewater storage tank should be provided, with the capacity calculated to





meet the fire water flow demands for two (2) hours. The fire water supplyshould be capable of refilling the 2-hour demand in 8-hour period.

The firewater storage tank and accessories should satisfy the requirements ofNFPA 22.

The tank can be a dual-purpose use as long as the piping arrangement reservesthe required capacity for fire protection use only.

A fresh water source is recommended for use in the fire protection systemOther water sources, like seawater, demineralized water or water containingmaterials deleterious to the fire protection system should be avoided.

The fire water storage tank may require heating and/or insulating so that thewater temperature in the tank is maintained above 6oC (42oF).

3.12.4.2 Fire Pumps

For systems requiring fire pumps, two (2) main fire pumps should be provided,one with electric motor drive and one with diesel engine drive, both completewith controllers. The fire pumps and accessories should meet the requirementsof NFPA 20 and should be Underwriters’ Laboratories (UL) listed.

Rated capacity of each of the main fire pumps should be sufficient to meet thefire flow requirements (see Section 3.12.3).

The rated head of the main fire pumps should be typically 70 m (230 ft) 7kg/cm2 (100 psi) so that at least 4.6 kg/cm2,g (65 psig) is available at thefarthest user (hydrant, standpipe, deluge system, foam chamber, etc.)

For the double-suction impeller pumps, the pump suction piping should beinstalled in accordance with recommendations of the Hydraulic InstituteStandards.

The suction piping should not be installed so that there is an elbow close to thesuction nozzle of the pump except when the elbow is in the plane at right angleto the pump shaft. The improper installation of the elbow close to the pumpsuction nozzle causes uneven flow distribution and could lead to prematurewear and impeller damage.

One (1) UL listed pressure maintenance pump (jockey) should be provided tomaintain the desired system pressure. Typical rated capacity/head of thepressure maintenance pump should be 6.8 m3/hr (30 gpm) @ 77 m (254 ft) 7.7kg/cm2 (110 psi). An additional hydropneumatic tank should be provided onlarge power plants with extensive fire mains.





Fire pumps should be located separately from adjacent power plant areas,either in an attached or detached structure. The ambient temperature in thepump room should be maintained above 4oC(40oF).

Rooms housing diesel-driven fire pumps should be protected by automaticdry-pipe sprinkler system designed per NFPA 13.

The fuel oil tank for the diesel-driven fire pump should be located indoors inlocations where site minimum ambient temperature is below 0oC (32oF). Thetank should be curbed to provide full containment.

3.12.4.3 Yard Mains/Hydrants/Standpipes

The fire water mains and the outdoors fire hydrants should meet the

requirements of the NFPA 24.A. The fire water mains should be looped around the main power block and

should be of sufficient size to supply the design flow rate to any point inthe yard loop considering the most direct path to be out of service. Theyard loop should be routed either below grade or above grade. Whenistalled below grade the depth of cover over the pipe should be one 300mm (1ft.) below the frost line, with a minimum cover 750 mm (2-1/2 ft.).

B. Indicating manual control valves should be installed in the yard loop toprovide adequate sectional control of the fire mains to minimize plantprotection impairments.

C. The fire protection loop inside the turbine building should be provided withtwo (2) valved connections to the yard main and with appropriate sectionalmanual control valves on the interior loop.

D. Fire hydrants should be spaced approximately 76 m (250 ft) apart. Eachhydrant should have a DN 150 (6 “) diameter underground isolation valvewith a valve box.

E. Hose houses with equipment should be provided strategically placed(provided for every other hydrant).

F. A 96iamese type connection should be provided to allow a fire departmentpumper to discharge into the system. This connection should be locatedoutside of the fire pumphouse.

G. Class II standpipe and hose connections per NFPA 14 should be providedfor all buildings. Each hose station should be equipped with a hose rackand with a maximum 300 m (100 ft) long, 38 mm (1-1/2 in.) fire hose. Thenumber of hose stations should be such that all portions of each story ofthe building are within 9 m (30 ft.) of a nozzle when attached to not morethan 300 m (100 ft.) of hose.

H. Portable fire extinguishers should be provided throughout the power plantThe portable extinguishers should meet the requirements of NFPA 10.





3.12.4.4 Transformers

If plant specific requirements call for a deluge water spray system, the

following oil-filled transformers should be provided with suppression systemsin accordance with NFPA 15:

• Main step-up transformer

• Station service transformer

• Station startup transformer

Transformer protection should cover all exterior surfaces except underneathsurfaces, which may be protected by horizontal projection. The water shouldbe applied at a rate not less than .61 (m3/hr)/m2 (0.25 gpm/ft2). Of projected

area of rectangular prism envelope for the transformer and its appurtenancesand not less than .37 (m3/hr)/m2 (0.15 gpm/ft2). On the expected groundsurface area of exposure.

Oil insulated transformers containing 1893 liters (500 gallons) or more of oilshould be separated from adjacent structures and from each other by a 2-hourrated fire wall or by spatial separation in accordance with the following:

Transformer Oil Capacity Minimum Line Of Sight Separation WithoutFire Wall

1900-19000 liters (500-5000 gallons) 7620 mm (25 ft)

Over 19000 liters (5000 gallons) 15240 mm (50 ft)

Oil insulated transformers of greater than 379 liters (100 gallons) capacityshould not be installed indoors. Any transformers of greater than 379 liters(100 gallons) oil capacity installed indoors should be separated from adjacentareas by fire barriers of 3-hour fire resistance. Transformers having a ratinggreater than 35 kV, that are insulated with a less flammable liquid or non-flammable liquid and installed indoors should be separated from adjacent areasby fire barriers of 3-hour fire resistance.

Where a firewall is provided between structures and transformer, it shouldextend vertically and horizontally as indicated in Figure 3-2.9.3 (NFPA 850).With respect to structures such as the gas turbine inlet air filter compartmentline of site shall be considered from the top of the transformer conservator tankto the top of the steel structure supporting the inlet compartment.

Containment should be provided for outdoor oil-insulated transformers toprevent oil spills. Refer to Section 8 of this document for drain and spilcontainment design criteria.





It is recommended that the transformer containment be sized as required abovewithout connection to the site drainage system.

3.12.4.5 Substation/Switchyards

Substations and switchyards located within the power plant should beprotected by the yard fire hydrant system.

3.12.4.6 Steam Turbine/Generator

GE reference plant designs do not provide any fire protection for the steamturbine-generator, because, potentially catastrophic results of mis-operatingwater sprays on hot casing and bearing.. However, some projects do require(Customer mandated) specific forms of fire protection in the following areas:

3.12.4.6.1 Below Operating Floor

In cases where the steam turbine-generator requires protection, the areabeneath the turbine-generator operating floor that is subject to oil flow or oilaccumulation should be protected by an automatic, dry-pipe sprinkler system.This coverage typically includes all areas beneath the operating floor in theturbine building. The sprinkler system should be designed to a density of .73(m3/hr)/m2 (0.3 gpm/ft2) over a minimum application of 465 m2 (5,000 squarefeet) and be designed per NFPA 13. A foam-water sprinkler system designedper NFPA 16A is an acceptable alternate to the water sprinkler system.





3.12.4.6.2 Bearings

The turbine-generator bearing should be protected with a manually operatedpreaction spray system. The system should utilize fixed temperature closedhead spray nozzles. The nozzles should be directional type and shielding shouldbe provided where necessary so that heated metal surfaces do not sustaindamage from direct water impingement. The bearing protection system shouldbe designed for a density of 0.61 (m3/hr)/m2 (0.25 gpm/ft2). And be designedper NFPA 13. The preaction system should utilize fixed temperature heatdetectors provided with alarm set points at approximately 10oC (50oF) abovethe ambient temperature at each bearing location.

The turbine-generator bearing may also be protected by a low or high pressureCO2 fire protection system.

The GE reference plant provides protection for the lubricating oil reservoir andhandling equipment with an automatic, dry-pipe sprinkler system per NFPA 13A foam-water sprinkler system designed per NFPA 16A is an acceptablealternate to the water sprinkler system.

The lubricating oil reservoir should be provided with containment designed inaccordance with Section 8 of this document.

The lubricating oil storage area (clean or dirty oil storage), if located in theturbine building, should be protected with fixed, automatic, dry-pipe sprinkler

system per NFPA 13 and should have curbing designed to accommodate oilspills. A foam-water sprinkler system designed per NFPA 16A is an acceptablealternate to the water sprinkler system.

The hydraulic control system should use a listed fire-resistant fluid. If a fire-resistant fluid is not used, hydraulic control equipment should be protectedwith automatic sprinkler system per NFPA 13. A foam-water sprinkler systemdesigned per NFPA 16A is an acceptable alternate to the water sprinklersystem.

3.12.4.7 Gas Turbine-Generator

The following compartments should be provided with enclosures and protectedwith gaseous total flooding carbon dioxide system. This also applies toreference designs.

• Turbine compartment

• Accessory compartment





The fuel oil tank fire detection system design criteria should be as follows:

•Heat detectors should be selected according to design, with tiptemperature of at least 100°F above highest expected temperature inside

the tank. These detectors should be mounted on flanges for better accessduring routine maintenance.

• For unmanned station where local codes require automatic

operation of fire suppression system in case of fire, the detection logicshould be based on a cross-zoned design. This means two (02) independentsignals of fire are require to automatically activate the system..

• Fire protection system control module boxes should be

appropriately design for ambient temperature and conditions and should

never be located under direct sunlight.

3.12.4.9 Heat Recovery Steam Generator (HRSG)

The HRSGs using supplemental firing with liquid hydrocarbons should beprotected with an automatic, dry-type sprinkler system covering the burnerfront fire hazard.

The sprinkler system should be designed per NFPA 13 with a density of0.25 gpm/square ft over the protected area.

The burner design should be in accordance with the NFPA 8506.

3.12.4.10 Cooling Towers

The cooling towers of combustible construction should be protected with anautomatic water spray system designed in accordance with NFPA 214 with adensity of 1.2 (m3/hr)/m2 (0.5 gpm/ft2). Over the fill plan area. The systemshould be open head deluge system designed on per cell basis to lower the firewater demand. Fire partitions rated for a minimum of 20 minutes should beprovided between all cells.

3.12.4.11 Auxiliary Equipment/Structures

Oil-fueled auxiliary boilers installed within main plant structures should beprotected by automatic, dry-pipe sprinkler system per NFPA 13 designed for adensity of .61 (m3/hr)/m2 (0.25 gpm/ ft2).

Emergency diesel generators installed within main plant structures should beprotected by automatic, dry-pipe sprinkler system per NFPA 13 designed for adensity of .61 (m3/hr)/m2 (0.25 gpm/ ft2).





The following areas of the power plant should be provided with automaticdry-pipe sprinkler systems designed per NFPA 13:

• Administration building/offices

• Storage rooms

• Warehouses

• Machine shops/maintenance building

• Locker rooms/rest rooms

3.12.4.12 Electrical Equipment

Control and computer rooms should be provided with ionization smokedetection system throughout the rooms, including walk-in-type consolesabove suspended ceilings and below raised floors. The detection system designshould be per NFPA 72.

Control/computer rooms that have raised floors containing cables should beprovided with a total flooding, fire extinguishing system for the areas beneaththe raised floors.

The system should be designed in accordance with NFPA 2001. The cleanagent should be of the type allowed for use in normally occupied areas

Recommended clean agent is HFC-227ea (known as FM-200).

Switchgear, relay and battery rooms should be provided with ionization typesmoke detection system designed per NFPA 72. This applies also to the GTauxiliaries, like Packaged Electrical Control Compartment (PECC).

Cable spreading rooms and cable tunnels should be provided with automaticsprinkler system designed per NFPA 13.

3.13 Auxiliary Cooling Water System

3.13.1 Ethylene Glycol vs. Propylene Glycol

Neither the 7FA nor 7EA gas turbine product line is extremely sensitive tousing propylene glycol in their cooling systems when using, for comparisonpurposes, ethylene glycol which has been the standard medium for freezeprotection.





If propylene glycol is intended to be used the respective gas turbine requisitionengineer should be notified to confirm that the heat exchanger equipment isdesigned properly. Either the A/O design will be sufficient or suitable

modifications will be made to the design to allow the system to operate asintended.

The time at which this information should be communicated is at the ODM.This will mitigate any rework/extra cost, which may occur if the information isreceived on an already released unit.

The situation for steam turbine is much the same as gas turbine. The system isnot that sensitive to using propylene glycol in place of ethylene glycol.

Both gas and steam turbine also include a three-way temperature control valvewhich monitor the outgoing lube oil temperature from the coolers. Duringstartup this valve will remain closed until the lube oil temperatures reach 54oC(130oF) and 49oC (120oF) respectively. Therefore the system has a chance towarm up should cooling water temperatures be at lower levels.

With respect to generator, their hydrogen-cooled system has far less flexibilitybecause of the nature of the design of the hydrogen coolers. Aside from beingable to modify fin shape/density there is not much left that is practical for thegenerator designer to consider. For these reasons, generator puts a limit on theminimum ambient cooling water temperature to the coolers when usingpropylene glycol at 2oC (35oF). At lower temperatures the viscosity ofpropylene glycol begins to increase appreciably making it a poorer conductor

of heat than ethylene glycol. The same is true for TEWAC generators.

As an example, a 50% mixture of ethylene glycol at –18 oC (0oF) has a viscosityof 19.3 cps. A comparable mixture of propylene glycol at –18oC (0oF) has aviscosity of 61.3 cps.





There is also another consideration that must be addressed by the generatorengineer and that is the performance of the machine at high ambient conditions

There is the potential for not being able to meet expected performance if thecooling system does not perform adequately. Again, as in the cases for gas andsteam turbine, the time to communicate the makeup of the cooling watersupply is at the ODM.

With respect to the off-base fin-fan coolers, which are commonly used insimple cycle plants and some combined cycle plants, using propylene glycolwill require a change to the cooling water pumps and possibly the fansTherefore if the plan is to use propylene glycol then this requirement needs tobe identified in PEGASUS during the ITO phase before the project is awarded.

In certain scenarios, propylene glycol may be used in environments and low as

–29oC (–20oF). Namely, the majority of run of cooling water pipe must beunderground, below frost depth (our standard for below ground pipingsystems). The piping should start below ground at the off-base cooler andcontinue below ground with above grade runs as required at the respectivecomponent coolers.

Heat tracing and insulation will be required on the above ground portion of thecooling water supply piping to the generator coolers to insure 2oC (35oF)cooling water during startup. For this short run, mineral wool with jacketing isrecommended for the insulation system.

During startup, it will take about 10 minutes for the unit to get to FSNL froman initiation to start command. The criteria are to insure a minimum of 2oC(35oF) cooling water to the generator coolers prior to loading the unit fromFSNL to base load. Calculations show that during this 10 minute period therewill be a temperature rise of about –9oC (16oF) (using specific heat informationfrom Dow), which means that we cannot start the system with a coolingmixture temperature of less than –7oC (19oF). However, a couple of otherthings work to mitigate this limitation.

First, prior to initial fire, the unit’s lube oil systems and seal oil systems mustbe operational. This will add some additional heat to the cooling water circuitbecause the oil systems have to establish (through calrod heaters) a minimum

temperature as a permissive to start.





Secondly, the great majority of the cooling water supply piping to and from thefin fan cooler will be underground. The standard is to bury the pipe below frost

depth, which in turn will keep the bulk fluid temperature around 7

o

C (45

o

F).

Depending on the amount of above grade pipe exposed to ambient heat tracingand insulating the generator cooler supply, piping may or may not benecessary.

If the total volume of fluid contained in the above ground cooling water supplypiping is less than 190 liters (50 gallons), heat tracing and insulation is notnecessary.

The off-base cooling water module does contain a bypass valve around theforced air heat exchanger so the cooling water will not receive any external

cooling during this time period. This same bypass valve will also insure theliquid temperature does not drop below the 2oC (35oF) limit when the unit is inoperation.

This design is an alternate to using ethylene glycol double-walled buried pipingsystem. Following these guidelines will allow use of propylene glycol down to –29oC (–20oF). Lower temperatures increase liquid viscosity beyond thepumping capability of the off-base cooling water module.

For power plants using air-cooled generators, propylene glycol can be used forthe gas turbine component cooling systems as long as the minimum ambientdoes not go below –29oC (–20oF) and the supply/return piping is run belowgrade.

3.13.2 ACW Head Tank Vent Design

In a plant with a hydrogen cooled generator, hydrogen gas may leak into theauxiliary cooling water system if the hydrogen pressure for the generator isdesigned higher than the auxiliary cooling water system operating pressure. Toprevent hydrogen from venting in the turbine building, the auxiliary coolingwater heat tank should be vented outside the building.





3.13.3 Corrosion Inhibitors

At no time should the cooling system be operated without corrosion inhibitorsin the coolant solution. Most commercial antifreeze contains corrosioninhibitors. It is strongly recommended that a commercial antifreeze productthat contains appropriate inhibitors be used rather than those withoutinhibitors. The inhibitor in one type of coolant (antifreeze or water) may not becompatible with another type of coolant and can form gums, as well as destroythe effectiveness of an inhibitor. It is very important not to add an inhibitor to asystem containing a commercial antifreeze which has its own inhibitor packagewithout ensuring the two are compatible.

If the coolant is a mixture of pure glycol and demineralized water, or just

demineralized water alone, it is necessary to add a suitable corrosion inhibitorSpecific corrosion inhibitors cannot be recommended as the selection dependson economic factors, availability, and the environmental impact, which mayvary from locale to locale. However, there are generally two corrosioninhibitors for mild steel, which are commonly used in closed cooling systems –molybdate and nitrite. The most commonly used corrosion inhibitor for copperand copper alloy is tolyltriazole but other azoles are sometimes used.

For corrosion inhibitor compatibility with various material for closed coolingwater system for Combustion gas turbine follow GEI 41004H, “CoolingWater Recommendations”

The following table gives the desired dosage for the most commonly usedcorrosion inhibitors:

INHIBITOR RESIDUAL DOSAGES

Tolyltriazole (PPM as TTA) 100

Molybdate (PPM as Mo) 250

Nitrite (PPM as NO2) 1000

When the system is filled initially, some of the inhibitors will be used up rapidlyin the production of films on the metal surfaces and thus an adjustment ofconcentration may be necessary to bring the inhibitor residual up to the desiredlevel.





3.13.4 Auxiliary Cooling Water Pumps

For the double-suction impeller pumps, the pump suction piping should be

installed in accordance with recommendations of the Hydraulic InstituteStandards.


3.13.5 Combined Cycle Lube Oil Cooling During Loss ofService Power

3.13.5.1 Background

There are several items to be considered when addressing lube oil temperatureduring the loss of service power when rapid restart capability is required. Thegenerator(s) seal oil needs to be cooled to maintain seal integrity and the steamand gas turbines lube oil must be cooled to allow running on turning gear.Cooling water needs to be provided to the auxiliary cooling water heatexchangers to provide oil-cooling capability to the lube oil coolers. Combinedcycle single shaft systems use a common lube oil cooler that supportsgenerator, gas turbine and steam turbine lube oil cooling. The limiting

temperature is the steam turbine requirement of 90o F maximum oil temp priorto starting turning gear operation for either multiple or single shaft systems(see GEK 110214).

3.13.5.2 Discussion

During a unit trip and loss of service power, the unit’s cooling system will gooff line along with the open loop cooling system. An alternate method ofcooling the closed loop (auxiliary) cooling water system is needed to maintainthe oil temperatures within the required limits for turning gear operation. TheAC lube oil pump will also need to be powered via a backup AC source as well

as the hydraulic pumps, the bearing lift oil pumps, and the turning gear. Theestimated power requirement for this equipment, for a single-shaft 109FA isapproximately 400 kW. The auxiliary cooling water pumps, if required, wouldneed an additional 200–300 kW to enable, depending upon the unit size andconfiguration. The emergency DC oil pump cannot be used for cooling sincethat pump bypasses the lube oil cooler and, therefore, will not provide therequired oil cooling for rapid restart. The system solutions listed below wileach require less than 200 kW in addition to the requirement for the lube oil





3.14 Feedwater System


The function of the feedwater system (FW) is to:

• Supply HP feedwater from the feedwater pumps to the HRSG HP

steam system.

• Supply IP feedwater from the feedwater pumps to the HRSG IP

steam system.

• Supply feedwater through the IP economizer for fuel gas heating.

• Supply HP water from the feedwater pumps for HP superheater

steam attemperation.

• Supply IP feedwater from the feedwater pumps for reheater steam

attemperation.

The feedwater system delivers feedwater from the LP drum to the HP and IPsystems via the boiler feedwater pumps. The standard feedwater pumparrangement consists of 2 x 100% combined HP/IP feedwater pumps. Thesystem can also be designed with separate HP and IP feedwater pumps.

The required minimum flow through the boiler feed pumps is automaticallyprovided using a flow measuring device with transmitter which automaticallymodulates a flow control valve to recirculate feedwater back to the LP drum.

3.14.2 Piping Recommendations

The boiler feed pump suction design is critical to stable feed pump operationunder any and all operating conditions. Through experience, it has beendetermined that the feed pump suction line should be designed for velocity of6-8 feet per second. This velocity should be calculated using the pump ratingpoint values put forth in the equipment specification.





The next item for consideration is the margin to be used in calculating availableboiler feed pump NPSH. It is recommended that the calculated available NPSH

value includes a margin of 100% above the NPSH required by the feedwaterpump. This calculation should use a flow rate number consistent with the boilerfeed pump rating point as defined in the pump specification. The NPSHcalculation should include allowance for the pump suction strainer.

The suction of each feedwater pump shall be equipped with a permanentsimplex basket strainer. Recommended basket mesh size is mesh 40. Thebasket strainer shall be located for ease of accessibility and maintenanceallowing the basket removal without disturbing any of the adjacent pipingFinal mesh size and the layout shall be part of design reviews prior to issuingdrawings for construction. Each basket strainer assembly shall be providedwith the differential pressure transmitter to alarm the strainer clogging

remotely in the control room.

In considering the boiler feed pump NPSH, the design engineer needs to payparticular attention to the physical layout of the suction piping from the LPdrum to the pump inlet flange. This piping, ideally, should run verticallydownward with a minimum of fittings to accommodate changes in direction.Horizontal runs of pipe should occur only when branching off the main suctionheader to individual pump inlet connections near grade level (assumingmultiple pump installations). These horizontal runs should be sloped in thedirection of flow to preclude air pocket formation. A 15-degree slopeminimum is recommended.

For the double-suction impeller pumps, the pump suction piping should beinstalled in accordance with recommendations of the Hydraulic InstituteStandards.


Elbows in suction piping should be of the long radius type and eccentric

reducers with straight side up should be used when installed in the horizontalpiping.

3.14.3 Pump Protection

The following recommendations have been developed to apply to all GEcombined-cycle power plants.





To protect the boiler feed pump, the following pump stop/trip protectionshould be implemented:

a. Low feedwater flowb. High feedwater flow

c. High temp. of motor winding or motor bearing

d. High temp. of pump bearing

e. Low LP drum level

f. Low lube oil pressure

g. High rate of pressure decay of LP drum

3.14.4 Control Considerations

With the 2 x 100% feedwater pump arrangement, the pumps should bedesigned to operate in a lead/lag/standby mode. The failure of the lead pumpwill automatically initiate the start of the lag/standby pump.

The boiler feed pump recirculation control valve opening and closing stroketime shall be five seconds or less and must be faster than the HP drum levecontrol valve. This allows the recirculation valve to react in responses to drumlevel transients to keep the pump in operation. This also allows the valve toreact quickly to assure minimum flow when a boiler feed pump is started.

The boiler feed pump recirculation valve is operated open when the boiler feedpump is shut down and thus a flow path for the minimum flow is available

when the pump starts.

3.14.5 Boiler Feed Pump Sizing Criteria

The Design flow value is based on the sum of the following:

1. Maximum Continuous operating Flow value

2. Maximum Steam Turbine Bypass Attemperation Flow (if Applicable)

3. Drum Blowdown (1% of applicable rating point steam flow)

4. Others as required on a project specific basis

5. Pump marginFor cases with supplemental firing the Maximum continuous flow with firing isconsidered without adding the maximum steam turbine bypass attemperationflow item 2.

The pump margin is normally specified as 11% of the total flow summation ofitems 1 through 4 above. The margin includes 5% for pump wear deteriorationand 6% for non-steady state transient operation.





The Design Point pump discharge pressure is based on the following:

1. Normal Maximum Receiving drum operating pressure

2. Pipe friction pressure drop (estimated as 30 psid including flow elements)3. Applicable Economizer Pressure drops

4. Feedwater Level Control Valve pressure drop (estimated 75 psid at fullflow for parallel split range and variable speed pump operation, 125 psidfor series split range control)

5. Elevation head to Receiving drum from Pump

6. Feedwater Pressure Control Valve (series split range control only) 125 psid

7. Other as applicable for the specific project

The pump head curve is required to be continuously rising with a shutoff headat least 110% of the rated pump head and a maximum limit of 130% of rated

pump head. The pump shutoff head should not exceed the applicableeconomizer design pressure less 100 psi excluding Hydraulic Institute (HI)tolerances.

The pump head is required to supply a minimum of 50% or the maximumnormal flow to the Receiving Drum with the lowest pressure setting of DrumRelief Valves.

The pump runout flow is required to be greater than 120% of the rating pointflow.

The Intermediate Pressure Design Point pressure is verified against the fuel gasheater pressure requirements, if applicable. The fuel gas performance heaterpressure is the maximum fuel gas pressure at the performance heater includingfuel gas pressure drop, economizer water pressure drop, water piping frictionpressure drop, plus a margin of 25 psid of water pressure above the fuel gaspressure. If this value is greater than the design point discharge pressurewhich is calculated above, this value is used as the design point pressure.

The calculated available NPSH value shall include a margin of 100% above theNPSH required by the feedwater pump.

The performance guarantee points are verified to be within the performance of

the specified pump design conditions. The guarantee point performanceindicates the flow and discharge pressure required to meet the performancerequirements and uses assumptions for pressure drops and elevations at theperformance flow. The assumed values are required to be verified by the plantdesigner. The pump and driver must not exceed the allotted powerconsumption at the plant rating point, not the pump design point.





The pump driver is designed for not less than 100% of the Brake Horsepower(BHP) required by the pump at all operating points including the HydraulicInstitute (HI) tolerances for pump capacity and head.

3.15 Condensate System

3.15.1 Condenser Design Considerations

These recommendations have been developed due to the increasing occurrenceof condenser tube failures in combined cycle plants designed for full load steamturbine bypass.

We have experienced several such failures in the recent past and have come up

with some common denominators for all failures.

First, the majority of condensers contained Titanium tubes. This material wasselected because of sea water applications and/or brackish cooling waterconditions.

Second, most all failures occurred during full load steam bypass. One failure ina fossil fired plant occurred during a part load rejection test, however it ishypothesized that the condenser experienced a full load rejection for the time ittook for the power boiler to run back it’s control firing to 40% of full load.

Third, all failures occurred during startup/commissioning/demonstrating testingwhen the system is in the continuous bypass mode.

Therefore while the bypass system is designed to startup and shutdown theplant (part load bypass) and handle steam turbine trips (full load bypassfollowed by gas turbine runback), the system can experience full load bypassconditions for extended periods of time during a project’s commissioning andtesting activities.

The tube failures in question were classical in nature exhibiting vertical splittingof the tubes between tube support plates.

The tube bundle area most frequently exhibiting these failures is the upper tubebundle periphery, which is located below the bypass dump header.

Resultant damage not only occurred in the condenser proper, but also cascadedto the condensate, feedwater and steam systems and equipment due tocondensate contamination with high sodium levels.

As a result of the above incidences, a number of precautions have been takento try and preclude these events from reoccurring in the future.





3.15.1.1 Steam Bypass System Operation

Special attention shall be paid to the flow rate of steam dumped into the

condenser by the bypass systems during plant startup, shutdown and rejectionof load. In addition, the condenser design shall take into consideration theoperation of the bypass during plant commissioning (continuous operation) andstartup with low circulating water temperatures where water impingement andtube vibration phenomena may occur.

The steam dump header for the steam bypass connections shall be providedwith adequate sparging and drain holes to prevent damage to the condensertubes and steam turbine LP hoods. The dimensioning and size of the steamdump holes shall assure homogeneous and even distribution of the water/steammixture on the condenser. Drain provisions shall consider the length of pipe

between the condenser connection and the bypass valve as a condensateforming “cold leg “. The drain holes shall include impingement protection forthe tubes during normal bypass operation.

The design and location of the steam dump header and the orientation of thespray holes shall prevent water drops from impinging the condenser tubes, andprevent high energy steam flows into the steam turbine LP hood. An exhausthood spray system shall be provided between the dump lines and the LP hoodto limit the temperature of the dump steam emigrating into the turbine to 70ºC(158ºF) – 80ºC (176ºF). The spray nozzles shall not be directed toward thedump tube, the condenser tubes or the LP section of the steam turbine.





The dump headers shall be made of stainless steel or other wear resistancematerial to preclude erosion. Support sections for the dump header and

impingement baffles (if required) shall be also made of erosion-resistantmaterial if subject to steam impingement. Impingement baffles shall be locatedso as to prevent water due to wet steam impingement from running directlyover the condenser tubes. The mounting of the bypass dump tubes shall allowfor thermal growth of the bypass dump header. The dump header tubes shalbe located furthest from the condenser tube bundle within the confines of theturbine exhaust chamber, to reduce impingement impact. A minimum of 1.8 m(6 ft.) shall be considered from the bottom of the dump tube header to the topof the tube bundle for the high pressure dump.

The dump headers shall be provided with an adequately dimensioned drain todrain the steam condensed in it and in the pipes between the bypass valves and

the condenser. Vendor shall base drain capacity using 22860 mm (75ft.) ofinterconnecting bypass pipe as the volume for condensed steam.

A drain before the Bypass valve at the lowest point shall be provided to ensurethat line is liquid free. However, if the pipe slope is opposite to the flowdirection drain will not be necessary. A warm up line to avoid thermal shockshould be considered. These considerations are important for the bypass valveto properly function.

3.15.1.2 Flow-Induced Vibration

The Condenser Supplier shall design the condenser to ensure reliable operationwithout tube damage during plant commissioning and all operating conditions,in different functional modes such as bypass, low loads, one tube bundle out ofservice, low circulating water temperature, etc. The most recent experience oncondenser tube failures during these operating modes shows that conventionalmethods (i.e. HEI) to calculate these vibrations do not adequately addressflow-induced vibration and water impingement phenomena for CombinedCycle Power Plants, therefore not acceptable.

A more conservative vibration analysis than the aforementioned calculationsshall be used for tube and tube bundle vibrations. The vibration analysis shaltake into account vortex shedding, fluid elastic instability and other vibration-induced phenomena that may lead to tube damage. Tube bundle operatingfrequencies shall be calculated using Connors’ method, HTRI or otherestablished industry standards.





The Condenser Supplier shall study condenser behaviour and provide avibration analysis for all condenser operating modes throughout the full range

of the steam turbine loads. In addition to the normal operating modes, thefollowing critical operating modes shall also be considered as a minimum:

• Maximum base load operation without bypass at minimum cooling

water temperature

• Maximum bypass operation duty (maximum flow full load bypass)

at minimum cooling water temperature

• One water box (ie.: one tube bundle) out of service and dry and the

other water box (ie.: the other tube bundle) under guarantee thermal loadat minimum water temperature.

− HP Bypass Steam _______kg/h @ _______kJ/kg

− IP Bypass Steam _______kg/h @ _______kJ/kg

− LP Bypass Steam _______kg/h @ _______kJ/kg

− Cooling water inlettemperature

___ºC

• One water box (ie.: one tube bundle) out of service and dry and the

other water box (ie.: the other tube bundle) under maximum bypassconditions at minimum cooling water temperature

3.15.1.2.1 Vibration Analysis

The Condenser Supplier shall perform and submit a complete vibration analysisreport for the proposed, condenser design specific for the project. The reportshall analyze and provide specific information on vortex shedding, TurbulentBuffeting, Fluid Elastic Whirling, Acoustic Vibration, fluid elastic coupling,tube gap speeds, tube natural frequencies, tube material characteristics, shapeof the tube bundle, steam distribution around tube bundle periphery, waterimpingement and other aspects that, in accordance with the present experience,may affect the tubes.

Current design rules aimed at preventing tube damage due flow-inducedvibration are as follows:

• Fluid Elastic instability, the ratio between actual steam & water mixture

velocity through the tube gaps and Critical (sonic) velocity (Vr/Vcr) shalnot exceed 0.5.





• At tube frequencies below 100 Hz the RMS amplitudes due to Random

Flow Turbulence shall not exceed 2% of the tube diameter. At tubefrequencies greater than 100 Hz. The RMS response shall not exceed 2%of the tube diameter x 100/tube bundle natural frequency in Hz.

• Maximum tube support spacing shall not exceed 750 mm (30 “)

3.15.1.3 Tube Material Selection and Tube Wall Thickness

Requirements for condenser tube material, diameter and minimum walthickness are defined in the Condenser Specification.

Tube wall thickness shall not be less than 22 BWG for at least the first tworows of the periphery of the tube bundle for Titanium tubed condensers. If

stainless steel is used then tube wall thickness shall be 22 BWG throughout, asa minimum. However, if vendor wishes to use tube material and thicknessother than specified, vendor must satisfactorily justify the suitability of thealternative material and provide evidence via reference plants where suchmaterial has been in use for at least ten years without any undue damage. Toprotect the tubes from impingement impact damage thicker wall tubes, i.e. 20BWG should be used. See section 3.15.1.5 for further details on impingementprotection.

3.15.1.4 Tubesheet Material Selection

Tube sheet material shall be selected on the basis of the cooling medium. Whenseawater is used as coolant the tubesheet shall either be solid titanium orCarbon steel overlaid with titanium. Overlay shall be applied to the water boxside. The entire overlaid surface shall be ultrasonically inspected to ensureproper fusion between the base metal and the overlay.

3.15.1.5 Steam Impingement Tube Protection

Experience has shown that the tube bundle periphery is more susceptible tomechanical damage in the following locations:

• Under the low pressure turbine exhaust

• In the vicinity of the turbine bypass line

• In the vicinity of the high energy baffled drains





To avoid tube damage, two (2) rows of thicker gage tubes, same diameter andpitch as the tubes, shall be provided at the top and bottom of the tube bundle

all along the line of sight. Deflector baffles or plates with similar function maybe offered as an alternate in addition. A grating placed on top of the tubebundles to protect the tubes shall also be considered. Condenser manufacturershall propose any other design to mitigate impingement, which will bereviewed for acceptance.

3.15.1.6 Tube to Tube Sheet Joints

The tubesheet shall be prepared by drilling of holes in a pitch chosen by theconstructor, that the constructor has used to design the heat exchanger for thespecified duty conditions. Hole dimensions shall be in accordance with the HEIStandards. The holes shall be grooved (fig. 2) for the first two rows. Thegrooves will provide axial rigidity and help to withstand stresses that will occurduring differential expansion between the tubes and the shell, specially duringstartup and shutdown and turbine trips. There are various methods of weldingtubes to the tube sheet. The following are examples of a few typical jointwelding preparations (fig. 1).

Tube sheet Weld

Tube

Figure 1

Following expansion of the tubes inside the tubesheet holes the tube shall bewelded to the tubesheet. Normally welding shall be use TIG (GTAW) methodWelding either is manual or by programmable fully mechanized TIG equipmentespecially designed for T/TS-welding. This latter method is frequently used.





Grooves Weld 0.4mm

10mm

40 mm 3mm

Approx. 6mm

40 mm 3mm

Typical Grooving of Tubesheet

Tube

3.15.1.6 Optional use of Anti-vibration Stakes

In order to reduce the risk of tube vibration to the minimum achievable levelthe Supplier may consider as a possible solution, the provision of anti-vibrationstakes. Staking of tubes will provide additional stiffness to the tube bundle andpreclude possible vibration effects. The stakes shall be stainless steel with

indentations at the tube locations. The stakes shall lock tubes into a singlevibration-free unit and shall be designed not to shift over the life of the plant.

3.15.1.7 Expansion Joint Liners

We have experienced expansion joint liner failures during plant commissioningand operating activities. The liner plates, which protects the expansion jointfrom direct impingement from the bypass steam water mixture during start-up,steam turbine trip, and shut down, separated from the shell body and fell on topof the tube bundle. The liners were made of thin stainless plates, and thecondenser shell was of carbon steel. The liners were welded using continuousgroove weld to the inside wall of the condenser shell. The cause of the failureswas determined to be due to differential expansion between the condenser shelland the stainless steel liner. In another instance the leak sprang in the corner ofan expansion joint. The failure was attributable to a burn through weld.



TUBESHEET



In order to mitigate such failures the design of the expansion joints shalconsider that during steam bypass operation a rapid increase of temperature in

the LP turbine exhaust hood section of the condenser will incease up to 360degree F for a short period. Where dissimilar material is welded together suchas stainless liner plate welded to carbon steel the differential growth rate anddifferent coefficient of expansion shall be considered in the design of the welded joints. To mitigate this problem several options are available. The liner couldbe in sections with gaps to take up the differential expansion. Gaps shall beprotected with an overlay pieceto prevent direct steam impingement on theexpansion joint. The welds can be intermittent (stitch-weld) or combination ofboth types of design. The liner pieces shall be a minimum of ¼” thick.

The orientation of the dump tube nozzles shall be away from the expansion jointarea to prevent direct impingement of the jets steam on to the liners. The

expansion joint corners shall be rounded to a minimum of one foot radiusWhere possible all expansion joint welds shall be performed in the shop, wherequality of the welds can be better controlled, rather than in the field. Duringtransportation the expansion joints shall be protected against any damage byeasily removable locking bolts.

3.15.1.8 Installation Considerations

To facilitate the installation of the condenser between the turbine pedestasupport columns, the condenser shell nozzle connections shall not extend morethan 6 inches (150mm) beyond the shell surface. The dimension from the shel

surface to the foundation wall shall be a minimum of 12 inches (300mm).

3.15.2 Corrosion Protection

In order to minimize the potential for galvanic corrosion, an impressed currentsystem shall be utilized for the condenser waterboxes. Epoxy coating or rubberlining are other acceptable methods. Water quality and end user experience willdictate the proper protection method.





3.15.3 Condensate Pump Suction Piping DesignConsideration

With two 100% condensate pumps, one is normally in operation while theother is in standby. In cases where the standby pump suction isolation valvemay be closed the possibility exists of cross flow leakage through the pump’snon-return valve via the operating pump. This would subject the standby pumpsuction system to pump discharge pressure conditions. In order to precludethis from happening, it is recommended that a sentinel relief valve be installedin the suction piping to the pump downstream of the suction isolation valve.Relief valve discharge or vent line should be piped back to the condenserhotwell to insure no air in-leakage to the condensate system.

The suction of each condensate pump shall be equipped with a permanent,simplex basket strainer. Recommended basket mesh size is mesh 40. Thebasket strainer shall be located for ease of accessibility and maintenanceallowing the basket removal without disturbing any of the adjacent pipingFinal mesh size and the layout shall be part of design reviews prior to issuingdrawings for construction. Each basket strainer assembly shall be providedwith the differential pressure transmitter to alarm the strainer cloggingremotely in the control room.

The NPSH calculations for the condensate pump shall be done for the ratingpoint flow rate and for the pump runout flow rate. The NPSH calculations forthe condensate pump shall include a margin of at least 25% at the rating pointof the pump. The NPSHA at the first stage impeller eye should exceed theNPSHR by at least 25%. The NPSHR at the pump runout flow rate should notbe less than NPSHA at the runout.

The NPSH margin requirement as summarized above shall be included in thecondensate pump procurement specification, and shall be based on “0”NPSHA at the pump suction nozzle. The condensate pump vendor shouldprovide the minimum NPSH required at the pump suction flange to preventflashing at the nozzle or at the top of pump can.

All NPSH calculations should include allowance for the pump suction strainer

(with a 100% margin on the “clean” strainer pressure drop).

3.15.4 Rating of Equipment

The design engineer shall pay special attention to the pressure rating of thecomponents of the condensate system to make sure that the design pressure iscorrect based on the final condensate pump shutoff pressure.





The following components design pressure shall be verified, as applicable:

— HRSG LP Economizer

— Gland Seal Condenser — SJAE Intercooler/After-cooler

— Condensate Polisher

Other components may be affected based on final system configuration.

3.15.5 Condensate Pump Sizing Criteria

The Design flow value is based on the sum of the following:

1. Maximum Continuous operating Flow value

2. Maximum Steam Turbine Bypass Attemperation Flow3. Condensate Receiver and Condenser Expansion Tank quenchwater flow

(nominally 100,000 lbs/HR)

4. Small use flows which is 3% to include Exhaust hood spray flow Glandseal condenser emergency spray flow, vacuum pump flow and pump sealflows)

5. Condenser Water Curtain Flow (calculated to reduce bypass steam

temperature to 175 to 185°F)

6. Blowdown Flow (1% of applicable rating point steam flow)

7. Others as required on a project specific basis

8. Pump margin

For cases with supplemental firing the Maximum continuous flow with firing isconsidered without adding the maximum steam turbine bypass attemperationflow item 2.

The pump margin is normally specified as 11% of the total flow summation ofitems 1 through 7 above. The margin includes 5% for pump wear deteriorationand 6% for non-steady state transient operation.

The Design Point pump discharge pressure is based on the following:

1. Normal Maximum LP drum operating pressure

2. Applicable Economizer pressure drop

3. Pipe friction pressure drop (estimated as 30 psid including flow elements)

4. Other Pressure drops (Gland Seal Condenser, Feedwater Heaters, SteamJet Air Ejectors (typically 10 psid))

5. Feedwater Level Control Valve pressure drop (estimated 50 psid at fullflow)

6. LP economizer Bypass 3-way control valve (nominally 15 psid at full flow)





7. Elevation head to LP drum from Pump

The pump head curve is required to be continuously rising with a shutoff head

at least 120% of the rated pump head and a maximum limit of 160% of ratedpump head. The pump shutoff head should not exceed the applicableeconomizer design pressure less 50 psi excluding Hydraulic Institute (HI)tolerances.

The pump head is required to supply a minimum of 50% or the maximumnormal flow to the LP Drum at the lowest setting of the LP Drum ReliefValves with all other consumers of the condensate pump supplied with themaximum normal water flows.

The pump runout flow is required to be greater than 120% of the rating pointflow.


The Design point drop pressure is verified against the bypass attemperatingcase, which is the maximum steam bypass pressure plus line losses and bypassattemperator pressure drops. If this value is greater than the design pointdischarge pressure, which is calculated above, this value is used as the designpoint pressure. Suction pressure is not considered for sizing purposes.

The performance guarantee points are verified to be within the performance ofthe specified pump design conditions. The guarantee point performanceindicates the flow and discharge pressure required to meet the performancerequirements and uses assumptions for pressure drops and elevations at theperformance flow. These assumed values are required to be verified by thepump designer. The pump and driver must not exceed the allotted powerconsumption at the plant rating point, not the pump design point.


3.16 Pipe Cleaning/Pressure Testing

3.16.1 Pipe Cleaning

The AE shall include provisions in the piping design to:

• Install jumper to temporarily bypass major equipment;





• Allow cleaning of the maximum amount of field installed piping;

• Access low point drains and high point fills/vents.

After erection, the piping system shall be cleaned by the installing ConstructionContractor as described below. Cleaning methodology and procedure to besubmitted to the Field Project Manager for prior approval.

Steam

Condensate

Feedwater

Drains

High volume/velocity blowdown using theboiler’s steam OR acid flush followed bysimilar blowdown using compressed air.Targets will be used to verify final level ofcleanliness.

Gas fuel

Compressed air

CO2 – Fire Protection & Purge GasHydrogen

High volume/velocity blowdown usingpipelines gas or dry compressed air at supply

pressure equal or above operating condi-tions. Targets will be used to verify final levelof cleanliness

Liquid fuel (carbon steel piping) Acid flush piping and then neutralize. Usemesh strainers to verify final level ofcleanliness. Displace water with oil sprays.

Lube oil (Note 1)

Seal oil

Hydraulic oil

Liquid fuel (stainless steel piping)

Moderate volume/velocity displacement flushof supply lines using operating fluid andpermanent pumps. Use mesh strainers toverify final level of cleanliness. Flush perspecific equipment supplier requirements.

Water injection

Wash waterCooling water (stainless steel piping)

Deionized water

Moderate volume/velocity displacement flush

using potable water and permanent pumps.Use mesh strainers to verify final level ofcleanliness.

Wash water

Cooling water (carbon steel piping)

Acid flush and then neutralize. Use meshstrainers to verify final level of cleanliness.Refill with operating water/oxidation inhibitor.

Note:

1. Typically a phased flushing of piping circuits will be used to achieve the flushingvelocity required.

3.16.2 Pipe Pressure TestingAfter erection, the piping system shall be tested by the installing ConstructionContractor as described below. Testing methodology and procedure to besubmitted to the Field Project Manager for prior approval.

Steam

Condensate

Feedwater

Hydro static pressure test to ASME Section 1and B31.1, section 354.4 of B31.3, or projectspecific applicable codes (i.e,. Europeandirectives etc.).





Pressurized drains and vents

Sampling and analysis

Fuel oil

Fuel gas

Inlet air heating

Cooling water

Wash water

Demineralized water

Lube oil

Seal oil

Hydraulic

In service leak test

Fire protection – water Hydro static pressure test to UnderwritersTest Code; All water removed at conclusionof testing

Generator Hydrogen supply Air test

Compressed/service/instrument air

Vents (non-steam)

CO2 (fire protection & purge gas)

Drains (non-steam) Check during flushing with water

Note: Air Test – Pressure decay test using dry air or with specified gas.





3.17 Systems First Fills

The following table identifies information sources for developing requiredquantities of first fills for unit liquids and gases:

Fluid GT – G ST – G

Lubricating Oil Mineral OilMLI 0416

GEK-28143 or GEK-32568

Mineral OilVR01

GEK- 46506(A/E To Add Ppg. Cap.)

HydraulicOil

N/A(Expect CC Single-Shaft)

Phosphate EsterVR90

GEK-46357Coolant Water / Ethylene Glycol /

Propylene GlycolMLI 0420 and MLI 0453

GEI-41004

(A/E To Add Ppg. Cap.)

StationSpecificDesign

FireSuppressant

CO2

MLI 0426GEK-28138

(High Pressure –6B and 7EA On-base Only)

StationSpecificDesign

GeneratorCooling Gas (Hydrogen)

andPurge Gas

(Carbon Dioxide)Fill and Supply

Dwg. C411, G1EO and G2FAGEK-103763 or GEK-107092

Dwg. C411, G1EO and G2FAGEK-103763 or GEK-107092

Transformer Insulating Oil Main Step-up and MV StationService Transformers

Main Step-up Transformer

Transformer Manufacturer Outline and Nameplate Drawings based onPPE&S SINS Code No. 041 Specifications

GEI-65070Washing Waterand Detergent

Compressor WashingMLI 0461

(MDL-M605)GEK-103623 or

GEK-107122 (F Class)

N/A

HRSG BlanketingGas (Nitrogen)

A/E To Size N/A

Document Sources:

GEI/GEKs GE Power Systems Intranet/Power Plants/EmployeeServices/Library/Documents

MLIs Controls and Accessory Systems Engineering (CASE)

MDLs Power Plant Engineering and Sourcing (PPE&S) DesignDrafting

Steam Turbine andGenerator Drawings

Application/Requisition Engineering (See OrganizationCharts in Power Plant Web Pages)





3.18 Access Platforms and Stairways for Power IslandEquipment

The station designer is responsible to assure that all equipment, valvesinstruments and other items requiring operator action are accessible viapermanently designed stairs, platforms and/or walkways.

The following guidelines to the location of access platforms and stairways gasbeen developed based on operational experience and feedback for CombinedCycle Power Island Equipment. General guidelines on the construction of theseaccess devices should be referenced to Section 9.3 of the Design BasisDocument. The plant design engineer/constructor is required to include thesystems defined in the following paragraphs as part of his balance of plant

(BOP) scope of supply.

Access Platform Standards

Item System Access Requirements

1 High Pressure Steam

a. Access platform for HP Bypass Valves &Attemperation hardware

b. Access platform for HP Bypass IsolationValve

c. Access platform for the Main steamStop/Control Valves, including aux.

Also provide aux. Platform for the Servos& Hydraulics

d. Ladder or access platform for the Before& After Seat MOV drain valves

2 Low Pressure Steam System

a. Access platform for LP Bypass valve &attemperation hardware

b. Ladder or access platform for the LPBypass Isolation Valve

c. Access platform for LP admissionstrainer, stop & control valves.





3 Cold Reheat Steam System

a. Access platform for the CR non returnvalve

b. Access platform for Reverse flow bypassvalve.

c. Access platform for the CR isolationValve.

4 Hot Reheat Steam System

a. Access plat HRH Stop/Intercept Valves,including aux platforms or servos

b. Access platform for the HRH Bypass &

attemperation Hardware.c. Ladder or platform for HRH Stop /

Intercept before & after seat drain valves.

5 Feed Water System

a. Access platform for the BFW minimumflow control valves

b. Ladder for the Temperature controlvalves for HP bypass attemperatorstations

6 Condensate System

a. Provide access ladder Vacuum BreakerValve

b. Provide Access vacuum pump suctionvalve.

c. Condenser water box vent valves

7Aux Circ Water & Aux

Cooling Water Systems

a. Pump suction/discharge isolation valves,or locate valves so that operators canaccess from grade.

8 Gas Turbinea. Ladders or stairs to access GT load

compartment

b. Ladders or stairs to access turbinecompartment roof

c. Ladder or stairs to generator collectorcompartment





9 Steam Turbine

a. Provide access to lube oil tank/HPU.Need access over the containment dike,as well as access to the operating deck ofthe tank. Handrails will also be requiredaround tank operating deck.

10 HRSG Process Drains

Westbrook had access issues withrespect to the HRSG drains. The SanteeCooper HRSG drain lines created majoraccess issues. A definitive standardcovering HRSG drain line routing, accessplatform is required so as to have auniform standard for future projects.

Notes:1. All access platforms should be furnished

with caged ladders in accordance withOSHA and or local requirements.

2. The above list was prepared utilizinglessons learned from the Westbrook &Santee Cooper projects





3.19 Steam Water Sampling and Monitoring System

3.19.1 Sampling Points and Target Values

The following tables are developed for a typical GE STAG 207FA Multi-Shaftand a typical GE STAG 109FA Single Shaft Combined Cycle Power Plants,utilizing a three pressure, three drum natural circulation Heat Recovery SteamGenerator (HRSG) with superheat and reheat steam systems in typical electricgenerating service. All the target values are based on All Volatile Treatment(AVT) for Condensate and Feedwater Systems, and Phosphate Treatment (PT)for HP and IP boiler water.

Refer to Chemistry Guidelines For GE STAG 207FA Combined Cycle Plantsfor detailed design considerations and target valves for different waterchemistry programs, rationale for injection points and action levels, HRSGstorage, chemical cleaning and design considerations for cooling watertreatment.

For HRSG with pressure rating 2000 psig or more, consult GE EngineeringReview Board.

3.19.2 Sampling Point Alarm Settings

For all the continuously monitored steam/water cycle sample parameters(except pH), three alarm levels need to be set consistent with the three actionlevels described in the tables below.







SAMPLING POINTS AND TARGET VALUES (PT HP 1800 psi, IP 400 psi)

Sample PointSC CC Na pH DO SI TOC CL PO4 Fe NaOH SO4 N2

uS/cm uS/cm ppb ppb ppb ppb ppb ppm ppb ppm ppb pp

Condensate PumpDischarge (beforechemical feeds)

< 0.2 < 5 <20 < 200

Condensate afterchemical feeds (LPFW)

Info < 0.2 9.2 – 9.6 <10 < 5 <

Demin. Water(Cycle Makeup)

< 0.1 < 5 < 10 < 200 < 3

Hotwell Zones LeakDetection Trough

Info

LP Drum Water/

HP, IP FWInfo < 0.2 9.2 – 9.6 < 10 < 5 <

IP Drum Water < 45 < 37 < 6 ppm 9.4-10.4 < 4.5 ppm 4 ppm < 10 Info < 1 4 ppm

HP Drum Water < 23 < 20 <3.5 ppm 9.4 – 10.4 < 0.45 ppm2.2

ppm< 5 info < 1

2.2ppm

HP Saturated Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

IP Saturated Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

LP Saturated Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

Reheat Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

HP Superheated

Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

Note: Continuous Monitoring

Once per Shift, Grab Sampling

Weekly Grab Sampling

Testing & Troubleshooting, Grab Sampling

SC – Specific Conductivity, CC – Cation Conductivity, Na – Sodium, CL – Chloride, SO4 – Sulfate, SI – Silica

N2H2 – Carbohydrazide, PO4 – Phosphate, Fe – Iron (total), Cu – Copper (total), DO – Dissolved Oxygen

Action level 1 limits are 2 x Normal Limits (except pH). Return value to normal within 1 week

Action level 2 limits are 4 x Normal Limits (except pH). Return value to normal within 24 hour

Action level 3 limits are larger than action level 2 limits. Corrective action or shutdown of the unit within 4 hours

Immediate orderly shutdown when Bolier water pH < 8.0



3.20 Gas Turbine Air Processing Unit (APU) DesignConsiderations



SAMPLING POINTS AND TARGET VALUES (PT HP 1450 psi, IP 400 psi)

Sample PointSC CC Na pH DO SI TOC CL PO4 Fe NaOH SO4 N2

uS/cm uS/cm ppb ppb ppb ppb ppb ppm ppb ppm ppb pp

Condensate PumpDischarge (beforechemical feeds)

< 0.2 < 5 <20 < 200

Condensate afterchemical feeds (LPFW)

Info < 0.2 9.2 – 9.6 <10 < 5 <

Demin. Water(Cycle Makeup)

< 0.1 < 5 < 10 < 200 < 3

Hotwell Zones LeakDetection Trough

Info

LP Drum Water/

HP, IP FWInfo < 0.2 9.2 – 9.6 < 10 < 5 <

IP Drum Water < 45 < 37 < 6 ppm 9.4-10.4 < 4.5 ppm 4 ppm < 10 info < 1 4 ppm

HP Drum Water < 28 < 24 <4.2 ppm 9.4 – 10.4 < 0.7 ppm2.7

ppm< 6 info < 1

2.7ppm

HP Saturated Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

IP Saturated Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

LP Saturated Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

Reheat Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

HP Superheated

Steam Info < 0.3 < 5 < 10 < 100 < 3 < 3

Note: Continuous Monitoring

Once per Shift, Grab Sampling

Weekly Grab Sampling

Testing & Troubleshooting, Grab Sampling

SC – Specific Conductivity, CC – Cation Conductivity, Na – Sodium, CL – Chloride, SO4 – Sulfate, SI – Silica

N2H2 – Carbohydrazide, PO4 – Phosphate, Fe – Iron (total), Cu – Copper (total), DO – Dissolved Oxygen

Action level 1 limits are 2 x Normal Limits (except pH). Return value to normal within 1 week

Action level 2 limits are 4 x Normal Limits (except pH). Return value to normal within 24 hour

Action level 3 limits are larger than action level 2 limits. Corrective action or shutdown of the unit within 4 hours

Immediate orderly shutdown when Bolier water pH < 8.0



3.20.1 INTERCONNECTING PIPING BETWEEN GASTURBINE & AIR PROCESSING UNIT (APU)

3.20.1.1 Plant Installation Requirements for the APU

The APU is delivered to the plant on a dedicated skid. The GT plant providesa transfer pipe to deliver a flow of compressor air from the GT to the APUskid. Typical temperature is around 750F at 260 psig. It is required that theair be free of liquid water at the entrance to the APU skid. The APU skid willoperate at full rate flow during GT inlet air filter cleaning and return to lowflow (tower regeneration about 10% to 15% of rate flow) once the filtercleaning cycle is completed

To insure this, the transfer pipe temperature should be maintained well above

the dew point temperature of the air under normal operating conditions(>250F). While it is normal for considerable condensation to occur in thehigh-pressure air system (as high as 3 gal/hr in summer) when the air is cooledto meet the operating requirements of the air dryer, the condensation isexpected to occur within the APU unit. It must be emphasized that the APU isdesigned to remove only the water that condensates within the APU heatexchanger. It is not designed to remove water, which has accumulated in thetransfer piping and is subsequently transferred, perhaps suddenly, to the APU.

It must be anticipated that condensation will also occur in the transfer pipe, inparticular during shut down and subsequent cool down, or during start-up

The transfer pipe must therefore be properly designed to remove anycondensed water originating either at the GT or in the transfer pipe. To insureproper removal of condensed water in the transfer pipe, the pipe must besloped continuously, without low spots where water can accumulate, towardthe APU heat exchanger inlet according to standard engineering practice. Ifthis is not possible, then any low spots where water could accumulate musthave adequate drainage via an automatic drainage system. Further, dependingon the type of system chosen, this system must insure that water is not presentduring start-up and during shutdown periods. Failure to control liquidcondensate in the transfer pipe to the APU will shorten the APU life, reducedits reliability and cause performance deterioration.





3.20.1.2 Freeze Protection

During normal operating conditions, insulation of the transfer pipe is expectedto meet plant personnel safety considerations. In climates where the ambienair temperature falls below 32 F (0 C), additional freeze protectionconsiderations may be required. If any water is present in the transfer pipe, therisk of freezing exists. In some cases, adequate heat tracing and insulation maybe required to eliminate the risk of freezing depending on the type of automaticdrainage system selected and the installation method.

3.20.1.3 Stress Analysis

Designer of interconnecting piping system is to carry out a detailed stressanalysis unless documented justification is provided to justify other means ofassuring sufficient flexibility. The analysis would require evaluation of loads,moments, displacements and stresses including consideration of StressIntensification Factors and stiffness coefficients for all piping components.

3.21 Condenser Circulating Water System

3.21.1 Pump Design & Performance

1. The recommended CCW pumps configuration is 2 x 50% pumps. Thephilosophy for 2 x 50% pumps rather than 2 x 100% configuration, is theability to maintain flow to the condenser upon failure of one of the runningpumps.

2. A secondary reason is that in aggressive water applications, e.g. sea orbrackish water, an idle pump is generally more susceptible to corrosionthan the operating pump.

3. The 2 x 50% pumps should be arranged in parallel, sharing flow such thateach pump supplies water through all condenser tubes. For dividedwaterboxes, a common supply header fed by both CCW pumps is thepreferred configuration. The configuration of dedicated pump per waterboxis not recommended, since loss of the dedicated pump means that there isno flow through one of the waterboxes.

4. Upon loss of one 50% pump, the plant will operate with a highercondenser backpressure, calculations should be done to confirm the highestcondenser backpressure with one 50% pump in operation.

5. With a 2 x 100% pump configuration, a trip of a running 100% pump mayresult in loss of cooling flow to the condenser until the standby pump can





be started. Auto-starting of a large standby 100% CCW pump can alsoresult in system water hammer.

6. Waterhammer analysis should be done for both once-through and coolingtower circulating water systems. The analysis should include thesequencing of the pumps and valves during system charging, pump starting,pump shutdown and pump transfers.

7. The specifying engineer should calculate the system head curves for therange of operation that the pump will experience over its design life:

a. Once-through systems – For once-through cooling systems, in additionto intake losses, the range of operating conditions in CCW systeminclude the effect of pipe corrosion on flow resistance and the affect ofvariations in intake water level due to seasonal and/or tidal variations inthe intake water level. Typically, two system head curves should beprepared, one curve for the clean pipe, high water level condition andone curve for the corroded pipe, low-water level.

b. Cooling tower systems – For cooling tower applications, the variationin CW system operating conditions is due to pipe corrosion, and/orpump operation with the cooling tower bypass open (if applicable).

c. For the two (2) 50% pumps, the CCW pump calculations shall includethe single pump operation which must be checked with the system headcurves, to ensure hydraulically stable pump operation in this mode.

d. Submergence of the CCW pump must be evaluated as follows:

– Submergence required to prevent vortexing/cavitation through theentire flow range of the pump including the runout

– Submergence required to prevent vortexing/cavitation based on onepump operation at runout flow (assuming 2 x 50% paralleloperating pumps)

– Submergence of the CCW pump shall be based on the intake lowwater level and shall include the intake head losses (if applicable).





3.21.2 Condenser Air Removal System

3.21.2.1 Design Basis

a. The capacity of the venting equipment shall be not less than recommendedby the HEI “Standards for Steam Surface Condensers” Table 9. The airremoval equipment capacity shall be based on the air removal pressure of 1in. Hg abs or the condenser design pressure, whichever is lower, and at atemperature 7.5 degF below the saturation temperature corresponding tothis suction pressure.

b. The ratio of non-condensible load removed to the design capacity of theventing equipment must be not greater than values in HEI Table 4 toguarantee the oxygen content (typically 7ppb for the deaerating

condensers).c. Total make-up water introduced to the condenser at the temperature lower

than the inlet steam temperature should not be more than 3% of the steambeing condensed for 7ppb oxygen content, otherwise a vaccum typedeaerator may be required to achieve 7ppb oxygen level.

3.21.2.2 Air Removal Equipment

a. The recommended air removal equipment configuration is two(2) x 100%vacuum pumps. One vacuum pump is used during normal holdingoperation, while the other is on standby. Both pumps can be used inparallel operation during hogging, as condenser vacuum is brought up.

Typical hogging performance for a water cooled condenser is to establish10 “ Hga vacuum within 30 minutes. The volume to be evacuated includesboth the condenser volume as well as the LP turbine volume.

b. The preferred type of the vacuum pump is a constant speed, rotarydisplacement, liquid ring pump of a two-stage, tandem design.

c. Other possible options for the air removal equipment may include steam jetejectors or a combination of the two, i.e., a steam jet first stage followed bya second stage mechanical vacuum pump commonly called a “ HybridSystem”.





d. The capacity of liquid ring mechanical pump is affected by the temperatureof the cooling water supplied to the seal water heat exchanger. It isrecommended that the heat exchanger be cooled by the same water that

cools the surface condenser. If the cooling water is supplied from theclosed loop cooling water system, the cooling water temperature will behigher than the condenser cooling water temperature. In this case, it isessential that the capacity of the vacuum pump be based on the actual heatexchanger cooling water temperature for properoperation.

3.21.2.3 Condenser Waterbox Priming

For systems where the water side of the condenser may be under vacuumconditions (e.g. once through system), a vacuum priming system shall beprovided.

3.21.3 Water Quality Data

A complete water analysis of the circulating water is required as described inSection 1.4.3. The water analysis should also contain information on the solidscontent of the water, including seasonal variations. For cooling tower systemsa complete water analysis of the make-up water is required, including seasonalvariations in the make-up water quality and the number of cycles ofconcentration at which the tower will be operated. For all systems, thetreatment regime for the cooling water, for both biological treatment andtreatment for hardness and pH, must be considered.

3.21.4 Hydraulic Model Study of Intake Structure

A hydraulic model study for the intake structure may be warranted by thespecific plant application and/or by the customer.

A physical hydraulic model study shall be conducted for the pump intakeswhen any of the following features exist:

a. Non-uniform or non-symmetric approach flow to the pump sump.

b. Intake structure geometry that deviates from the HI Pump Intake DesignStandard.

c. Intake geometry is in accordance with HI Standard, but the design is notproven, i.e, there are no intake structures of the essentially identical designthat have been confirmed by a hydraulic model.

A hydraulic laboratory specializing in modeling pump intakes shall conduct themodel study. The study and testing shall be in accordance of the HI PumpIntake Design Standard.





The intake structure geometries shall also be given to the pump vendor fortheir concurrence.





3.22 Revision Table

DATE AUTHOR LIST OF CHANGED SECTIONS

14 Jan. 2002 B. Baran Added Mechanical Drawings (6 total)

28 Feb. 2002 B. Baran Revised 3.16.1

7 March 2002 B. Baran Revised notes in Section 3.1.3 to address secondarycontainment reference

27 March 2002 B. Baran Added redundant air dryers to Instrument Air Systems

Sect. 3.7.2

8 May 2002 X. Gao Added ACW head tank vent design to ACW system Section3.13.2

Added condensate pump suction piping design considerationto Condensate system Section 3.15.3

13 May 2002 B. Baran Added Access Platforms and Stairways for Power IslandEquipment, Section 3.18

24 May 2002 X. Gao Added Steam Water Chemistry Section 3.19

11 June 2002 X. Gao Revised Unit Conversions

21-June-2002 X-Gao Added 3.13.3 – Corrosion Inhibitors

24 June 2002 B. Baran Revised Sect. 3.1.2 and 3.15.3 and Added Sect. 3.1.3.1 – Critical Valves and 3.15.4 – Rating of Equipment

03 July 2002 B. Baran Revised Sections 3.12.4.4 and 3.15

18 July 2002 X.Gao Revised Section 3.2.2,3.2.3 and Added Sampling Points andTarget Values Charts

19 July 2002 B. Baran Revised Section 3.12.4.2 and Added Section 3.13.4 AuxiliaryCooling Water Pumps

12 August 2002 X.Gao Revised Section 3.19 SAMPLING POINTS AND TARGETVALUES Charts

13 Sept. 2002 G. Finnerty Added Section 3.13.5 Combined Cycle Lube Oil CoolingDuring Loss of Service Power

28 October 2002 X. Gao Revised Section 3.19.1 Sampling Points and Target ValuesCharts

21 November 2002 B. Baran Revised Section 3.14.2 Piping Recommendations and 3.15.3Condensate Pump Suction Piping Design Consideration

29 January 2003 B. Baran Added Section 3.15.1.9 Installation Considerations

11 February 2003 B. Baran Revised Section 3.15.3 Condensate pump suction pipingconsiderations and Revised Section 3.14 for BFP Pump

Protection Criteria

DATE AUTHOR LIST OF CHANGED SECTIONS





12 February 2003 B. Baran Revised Section 3.12 Fire Protection (Fuel Tanks)

13 February 2003 B. Baran Revised Section 3.6.4 Gas turbine drain design criteria

27 February 2003 B. Baran Added Section 3.20 Gas Turbine Air Processing Unit (APU)Design Considerations

Modified Freeze Protection Section 3.1.7

3 March 2003 B. Baran Added Section 3.21 Condenser Circulating Water System

24 March 2003 B. Baran Added Section 3.6.7 Gas Turbine Water Injection SystemsPiping

18 April 2003 B. Baran Revised Section 3.21 Condenser Circulating Water System

22 April 2003 B. Baran Added Section 3.21.2 Condenser Air Removal Systems

24 April 2003 X. Gao Revised Section 3.19.1

1 June 2003 B.

Tandlmayer

Added 3.14.5 and 3.15.5

3 July 2003 S.Mccullough

Revised 3.16

9 July 2003 X. Gao Revised Section 3.19.1

10 July 2003 B. Baran Revised Section 3.15

5 August 2003 B. Baran Revised Section 3.1.3.1.1 NDT Requirement and Section3.2.5 Piping Layout

5 August 2003 Manzur Huq ALL

24 November 2003 B. Baran For Section 3.2.2, Major Components, Added sloperequirements between HRSG and blowdown tank For

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