DEP SPECIFICATION
STEAM, CONDENSATE AND BOILER FEED WATER
SYSTEMS
DEP 30.75.10.10-Gen.
February 2012
DESIGN AND ENGINEERING PRACTICE
DEM1
© 2012 Shell Group of companies
All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, published or transmitted, in any form or by any means, without the prior
written permission of the copyright owner or Shell Global Solutions International BV.
DEP 30.75.10.10-Gen.
February 2012
Page 2
PREFACE
DEP (Design and Engineering Practice) publications reflect the views, at the time of publication, of Shell Global Solutions
International B.V. (Shell GSI) and, in some cases, of other Shell Companies.
These views are based on the experience acquired during involvement with the design, construction, operation and
maintenance of processing units and facilities. Where deemed appropriate DEPs are based on, or reference international,
regional, national and industry standards.
The objective is to set the standard for good design and engineering practice to be applied by Shell companies in oil and
gas production, oil refining, gas handling, gasification, chemical processing, or any other such facility, and thereby to help
achieve maximum technical and economic benefit from standardization.
The information set forth in these publications is provided to Shell companies for their consideration and decision to
implement. This is of particular importance where DEPs may not cover every requirement or diversity of condition at each
locality. The system of DEPs is expected to be sufficiently flexible to allow individual Operating Units to adapt the
information set forth in DEPs to their own environment and requirements.
When Contractors or Manufacturers/Suppliers use DEPs, they shall be solely responsible for such use, including the
quality of their work and the attainment of the required design and engineering standards. In particular, for those
requirements not specifically covered, the Principal will typically expect them to follow those design and engineering
practices that will achieve at least the same level of integrity as reflected in the DEPs. If in doubt, the Contractor or
Manufacturer/Supplier shall, without detracting from his own responsibility, consult the Principal.
The right to obtain and to use DEPs is restricted, and is typically granted by Shell GSI (and in some cases by other Shell
Companies) under a Service Agreement or a License Agreement. This right is granted primarily to Shell companies and
other companies receiving technical advice and services from Shell GSI or another Shell Company. Consequently, three
categories of users of DEPs can be distinguished:
1)
Operating Units having a Service Agreement with Shell GSI or another Shell Company. The use of DEPs by these
Operating Units is subject in all respects to the terms and conditions of the relevant Service Agreement.
2)
Other parties who are authorised to use DEPs subject to appropriate contractual arrangements (whether as part of
a Service Agreement or otherwise).
3)
Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) or 2)
which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said
users comply with the relevant standards.
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any liability of whatsoever nature for any damage (including injury or death) suffered by any company or person
whomsoever as a result of or in connection with the use, application or implementation of any DEP, combination of DEPs
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All administrative queries should be directed to the DEP Administrator in Shell GSI.
DEP 30.75.10.10-Gen.
February 2012
Page 3
TABLE OF CONTENTS
1.
1.1
1.2
1.3
1.4
1.5
1.6
INTRODUCTION ........................................................................................................5
SCOPE........................................................................................................................5
DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS .........5
DEFINITIONS .............................................................................................................5
CROSS-REFERENCES .............................................................................................7
COMMENTS ON THIS DEP .......................................................................................7
DUAL UNITS...............................................................................................................7
2.
2.1
2.2
2.3
2.4
2.5
2.6
2.7
STEAM GENERATION ..............................................................................................8
GENERAL DESIGN CONSIDERATIONS ..................................................................8
BOILERS/STEAM GENERATORS BLOWDOWN......................................................9
CBD/IBD PIPING ........................................................................................................9
CBD/IBD FLASH VESSELS .....................................................................................10
SPARING PHILOSOPHY .........................................................................................10
STEAM LOAD SHEDDING.......................................................................................10
PRESTART UP AND OPERATIONAL CLEANING ..................................................10
3.
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
BOILER FEED WATER............................................................................................12
BOILER FEED WATER QUALITY............................................................................12
ATTEMPERATOR WATER QUALITY......................................................................12
CHEMICAL DOSING FACILITIES............................................................................12
BOILER FEED WATER MAKEUP AND STORAGE ................................................13
DEMINERALISED WATER QUALITY MEASURING INSTRUMENTS ....................13
DEMINERALISED WATER TRAINS ........................................................................14
CONDENSATE RECOVERY SYSTEM....................................................................15
BFW AND CONDENSATE PUMPS .........................................................................16
CONDENSATE TREATMENT ..................................................................................16
BOILER WATER TREATMENT................................................................................18
FLOW ACCELERATED CORROSION (FAC) ..........................................................18
STEAM, BOILER FEED WATER AND CONDENSATE SAMPLING
REQUIREMENTS .....................................................................................................18
4.
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
STEAM HEADERS...................................................................................................20
STEAM DISTRIBUTION HEADERS.........................................................................20
PRESSURE REDUCING AND DESUPERHEATING STATION ..............................22
ATOMISING STEAM LINES .....................................................................................23
DRAINS AND DRIP LEGS........................................................................................23
STEAM TRAPS.........................................................................................................24
CONDENSATE HEADERS.......................................................................................25
THERMAL EXPANSION AND PIPING FLEXIBILITY...............................................27
PIPE SUPPORTS .....................................................................................................27
5.
5.1
DEAERATOR DESIGN CONSIDERATIONS...........................................................28
DEAERATOR FEED WATER PREHEAT SYSTEMS ..............................................28
6.
UTILITY BOILER FUEL SYSTEM DESIGN CONSIDERATIONS...........................29
7.
REFERENCES .........................................................................................................30
DEP 30.75.10.10-Gen.
February 2012
Page 4
APPENDICES
APPENDIX A
TYPICAL STEAM TRAP ARRANGEMENT FOR STEAM LINE
DRAINAGE......................................................................................................32
APPENDIX B
TYPICAL PRESSURE REDUCING AND DESUPERHEATING STATION
ARRANGEMENT ............................................................................................33
APPENDIX C
SIZING CAHRT INDICATING TYPICAL DRIP LEG DIAMETER...................34
APPENDIX D
TYPICAL SINGLE LINE DIAGRAM FOR LIQUID FUEL FORWARDING
PUMPS ............................................................................................................35
APPENDIX E
TYPICAL MP or LP STEAM TIE-IN TO PROCESS.......................................36
DEP 30.75.10.10-Gen.
February 2012
Page 5
1.
INTRODUCTION
1.1
SCOPE
This new DEP specifies requirements and gives recommendations for the design and
engineering of steam, condensate, demineralised water and storage and boiler feed water
systems for offshore and onshore oil and gas production installations, including refineries,
chemical and LNG facilities. Functional requirements are provided for the various
components included in such systems as boilers, feed pumps, water chemistry guidelines
and distribution headers. The detailed technical specifications for the various components
are covered by other DEPs.
Hot water and hot oil systems and fuel oil, fuel gas system and process heating furnaces
are excluded from the scope of this DEP. Nevertheless, boiler fuel oil pumps configuration
which has direct impact on steam system availability has been addressed.
The specific design and engineering of steam generation and consumer equipment is
outside the scope of the DEP; however, some minimum requirements related to the system
design aspects have been included.
Sparing requirements are considered beyond the scope of this DEP and shall be addressed
as part of the Design Class / Value Improvement work processes with requirements
identified in Basis of Design (BOD) documents.
This DEP contains mandatory requirements to mitigate process safety risks in accordance
with Design Engineering Manual DEM 1 – Application of Technical Standards.
1.2
DISTRIBUTION, INTENDED USE AND REGULATORY CONSIDERATIONS
Unless otherwise authorised by Shell GSI, the distribution of this DEP is confined to Shell
companies and, where necessary, to Contractors and Manufacturers/Suppliers nominated
by them. Any authorised access to DEPs does not for that reason constitute an
authorization to any documents, data or information to which the DEPs may refer.
This DEP is intended for use in facilities related to oil and gas production, gas handling, oil
refining, chemical processing, gasification, distribution and supply/marketing. This DEP
may also be applied in other similar facilities.
When DEPs are applied, a Management of Change (MOC) process shall be implemented;
this is of particular importance when existing facilities are to be modified.
If national and/or local regulations exist in which some of the requirements could be more
stringent than in this DEP, the Contractor shall determine by careful scrutiny which of the
requirements are the more stringent and which combination of requirements will be
acceptable with regards to the safety, environmental, economic and legal aspects. In all
cases the Contractor shall inform the Principal of any deviation from the requirements of
this DEP which is considered to be necessary in order to comply with national and/or local
regulations. The Principal may then negotiate with the Authorities concerned, the objective
being to obtain agreement to follow this DEP as closely as possible.
1.3
DEFINITIONS
1.3.1
General definitions
The Contractor is the party that carries out all or part of the design, engineering,
procurement, construction, commissioning or management of a project or operation of a
facility. The Principal may undertake all or part of the duties of the Contractor.
The Manufacturer/Supplier is the party that manufactures or supplies equipment and
services to perform the duties specified by the Contractor.
The Principal is the party that initiates the project and ultimately pays for it. The Principal
may also include an agent or consultant authorised to act for, and on behalf of, the
Principal.
The word shall indicates a requirement.
DEP 30.75.10.10-Gen.
February 2012
Page 6
The capitalised term SHALL [PS] indicates a process safety requirement.
The word should indicates a recommendation.
1.3.2
1.3.3
Specific definitions
Term
Definition
Design Class
Design Class is a categorization defining fit-for-purpose facilities
developed through Value Improvement Processes (VIPs) during a
project Front End Development (FED) phase.
Process Safety
Process Safety is the management of hazards that can give rise
to major accidents involving the release of potentially dangerous
materials, release of energy (such as fire or explosion) or both.
Abbreviations
Term
Definition
AC
Accidentally Contaminated
ASME
American Society of Mechanical Engineers
ALARP
As Low As Reasonably Practicable
BFW
Boiler Feed Water
CBD
Continuous Blow Down
DN
Diameter Nominal
DWD
Deposit-Weight-Density
EWLI
Electronic Water Level Indicator
FAC
Flow Accelerated Corrosion
GAC
Granular Activated Carbon
HP
High Pressure Steam (<~68 barg (~1000 psig);
>~22 barg (319 psig))
HAZOP
Hazard and Operability Analysis
IBD
Intermittent Blow Down
IPF
Instrumented Protective Function
LP
Low Pressure Steam (<~6 barg (85 psig))
MB
Mixed Bed
MCC
Motor Control Centre
MOV
Motor Operated Valve
MP
Medium Pressure Steam (<~22 barg (319 psig);
>~6 barg (87 psig))
MSSV
Main Stem Stop Valve
MWLI
Magnetic Water Level Indicator
NPS
Nominal Pipe Size
NPSH
Net Positive Suction Head
OEM
Original Equipment Manufacturer
PCV
Pressure Control Valve
DEP 30.75.10.10-Gen.
February 2012
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1.4
Term
Definition
ppb
Parts per billion
ppm
Parts per million
PRDS
Pressure Reducing Desuperheating Valve
TSO
Tight Shutoff
TOC
Total Organic Content
VdTÜV
Vereinigung der Technischen Überwachungs Vereine
VGB
Vereinigung Grosskraftwerks Betreiber
VHP
Very High Pressure Steam (>~68 barg (~1000 psig);
up to~115 barg (1668 psig))
CROSS-REFERENCES
Where cross-references to other parts of this DEP are made, the referenced section
number is shown in brackets ( ). Other documents referenced by this DEP are listed in (7).
1.5
COMMENTS ON THIS DEP
Comments on this DEP may be sent to the Administrator at standards@shell.com, using
the DEP Feedback Form. The DEP Feedback Form can be found on the main page of
“DEPs on the Web”, available through the Global Technical Standards web portal
http://sww.shell.com/standards and on the main page of the DEPs DVD-ROM.
1.6
DUAL UNITS
This DEP contains both the International System (SI) units, as well as the corresponding
US Customary (USC) units, which are given following the SI units in brackets. When
agreed by the Principal, the indicated USC values/units may be used.
DEP 30.75.10.10-Gen.
February 2012
Page 8
2.
STEAM GENERATION
2.1
GENERAL DESIGN CONSIDERATIONS
The steam pressures shall be selected to meet the process users and steam turbines
requirements and shall comply with the applicable codes and standards for steam
generators and piping. Optimisation shall be performed based on energy efficiency and
investment, taking into account limits to materials and piping class. Refer to
DEP 31.38.01.12-Gen. and DEP 31.38.01.15-Gen.
The steam temperature shall be fixed to provide the maximum degree of superheat for
steam turbine consumers with a reasonable cost of equipment and piping due to higher
ratings of flanges, seals, materials, etc.
The degree of superheat for the steam supplied to steam turbines shall be sufficient as
worked out on the following basis:
•
For a condensing turbine section, the exhaust steam quality shall be least 92 % with
the “state of the art” steam turbine efficiency or as specified by the steam turbine
OEM.
•
For a back pressure exhaust turbine or extraction section outlet steam, under normal
operation, additional superheating is not required to supply this steam to general
process heating uses. However, the desuperheating or tempering requirement of
extraction steam should be verified on a case-to-case basis, duly considering partial
load operation of the extraction and back pressure steam turbines.
The final selection of the steam temperature shall be verified with connected users and the
steam turbine OEM.
The temperature of the steam to the steam distribution headers shall have sufficient degree
of superheat to avoid excessive condensation in the distribution network.
In addition to the above requirements, the selected steam temperature shall be within the
safe and practicable design and metallurgical limits for the steam generators.
The capacity margin and sparing of steam generators shall be selected according to the
design class and project premise considering a wide range of operating conditions. This
includes shutdown of the largest steam generator without curtailing the plant operations. In
addition, minimum turndown operation and ramp rates shall also be considered. Refer to
DEP 00.00.07.10-Gen. for design class tables.
The quality of steam shall be defined based on the steam pressure and intended
application.
For low pressure steam, a total solid content of 1 ppm may be considered an adequate
quality for heating or similar process end use.
For MP, HP and VHP steam, the following steam quality guidelines shall be considered to
avoid formation of deposits on the super heaters, turbines and valves. Refer to (3.12) for
steam sampling requirement.
Steam purity guidelines for turbines in continuous operation
Sr. No.
Parameter
Limit
Unit
1
Conductivity* (at 25°C (77°F))
< 0.20
µS/cm
2
Silicic acid (SiO2)
<0.02
ppm
3
Total Iron (Fe)
<0.02
ppm
4
Total Copper (Cu)
<0.003
ppm
5
Sodium (Na)
<0.01
ppm
*Following cation exchange
DEP 30.75.10.10-Gen.
February 2012
Page 9
2.2
BOILERS/STEAM GENERATORS BLOWDOWN
Depending on the type of pre-treatment applied, boiler feed water will continuously
introduce a certain amount of impurities to a boiler. While pure water leaves the boiler in the
form of steam, the impurities remain in the boiler, resulting in a steady increase in the
concentration of dissolved solids in the boiler water.
In order to maintain the specified boiler water quality and prevent corrosion and fouling in
the boiler and downstream equipment, continuous and intermittent blow down shall be
applied.
2.2.1
Continuous Blow Down
The purpose of continuous blow down is to control dissolved solids in boiler water and to
maintain the specified water chemistry parameters.
For the design of the boilers serving process units where return condensate contamination
is possible and boiler feed water quality is moderate, at least 5 % or higher continuous blow
down shall be provided depending upon BFW make up quality.
For combined cycle steam power plants or installations where all the condensate is clean
and sourced from turbine condensers only, a minimum 3 % continuous blow down shall be
considered in the design which can be optimised during real operation.
A calibrated blow down valve shall be installed closest to the blow down vessel and
therefore minimising pipe sections exposed to high velocities of two phase flow.
CBD from each steam generator shall be routed for disposal and heat recovery to a
dedicated flash vessel operating at low pressure (LP) applicable for the steam system
where the recovered flash steam can be used. The CBD vessel hot water shall be routed to
the atmospheric IBD vessel and disposed from the IBD vessel or recycled back to cooling
tower, if applicable.
Design shall consider CBD adjusted manually or be ratio controlled as per varying loads to
feed water flow ratio. In the case of ratio control, the blow down ratio may be adjusted as
needed, to handle long term changes in feed water quality to meet the boiler water
specifications.
Automatically controlled continuous blow down based on conductivity or automatically
controlled phosphate dosing pumps for boiler drum water pH control shall not be used.
2.2.2
Intermittent Blow Down
Intermittent blow down shall be designed to remove suspended solids and sludge formed in
the boiler water. Intermittent blow down can sometimes, in abnormal operating situations or
start up, be used to bring the drum level back to normal from high-high level. The IBD
system shall be designed to handle such abnormal operation IBD flow rates.
Intermittent blow down shall be routed to the atmospheric IBD vessel. The flash steam shall
be vented to a safe location. Hot condensate in the IBD vessel shall be cooled to less than
60°C (140°F) with service water before being discharged to the AC system to avoid flashing
and vapour cloud formation in the AC system.
2.3
CBD/IBD PIPING
The CBD/IBD piping shall be designed to handle two phase flow with minimal hammering
and vibrations. The CBD/IBD piping shall be adequately sized to allow the transfer of blow
down water and steam formed due to continuous flashing inside the piping.
The average maximum velocity in the blow down lines SHALL [PS] not exceed 3.8 m/s
(12.5 ft/s) near the flash vessel inlet. As a good practice, IBD valves shall be installed close
to the blow down vessels such that flashing fluids directly enter the vessel. In case this is
not possible, pipe sizes downstream of the blow down valves shall be selected such that
fluid acceleration is gradual and the potential for erosion (e.g. in elbows) can be avoided.
Blow down valves shall be suitable for flashing service.
DEP 30.75.10.10-Gen.
February 2012
Page 10
The location of the CBD/IBD flash vessels shall be close to the steam generator and the
CBD/IBD piping length shall be minimised.
Horizontal expansion loops shall be used in the CBD/IBD piping.
The pipe supports SHALL [PS] be designed to allow thermal expansions and to limit the
line movements that can cause piping system failures due to water hammer induced by a
two phase flow.
Vibration analysis for operating conditions t for CBD/IBD lines shall be carried out in
compliance with DEP 31.38.01.11-Gen. CBD/IBD piping design SHALL [PS] comply with
the pipe stress analysis and supports requirements specified under section 3.5 of
DEP 31.38.01.11-Gen.
2.4
CBD/IBD FLASH VESSELS
Separate dedicated IBD flash vessels shall be provided for each process steam generator
and boiler.
Utility boilers shall have separate CBD vessels from process steam generators. For multiple
process heaters, waste heat boilers, the number of flash vessels can be optimized if it can
be demonstrated that there is no risk of water hammer and vibrations in the piping and is
subject to approval by the Principal.
The provision of diverting CBD to IBD vessel shall be considered in the design to ensure
that the CBD vessel can be isolated for inspection and maintenance.
The water droplets carryover from the CBD flash vessels shall be minimised and the
dissolved solids concentration in the flash steam shall be guaranteed by the Contractor.
The IBD flash vessel shall also be designed for minimum water droplets with vented steam
to avoid unsafe conditions in the area around the IBD vessels.
2.5
SPARING PHILOSOPHY
The capacity and sparing of boilers shall be decided according to the selected design class
and project premise. Refer to DEP 00.00.07.10-Gen. for design class. As a minimum, N+ 1
boiler should be installed to ensure that required steam generation capacity is available
during the periodic statutory shutdowns and during outages for inspection and maintenance
of boilers. The boiler’s reliability and steam availability shall be verified to meet the overall
plant availability criteria. Utility boilers shall be provided with dual drive on forced draft fans
driven with two independent utilities, preferably steam and electricity.
2.6
STEAM LOAD SHEDDING
Steam load shedding shall be considered in the design such that dedicated process plants
or steam drives with low impact and highest steam curtailment shall be shut off during
steam shortage events.
MOVs shall be provided to isolate the steam supply to the plants and steam drives to be
curtailed. All MOVs shall be activated by set point or manual intervention by operator from
the control room. At least 20 % of the steam production capacity of one boiler shall be
maintained as an additional reserve to restore the steam pressure back to normal.
2.7
PRESTART UP AND OPERATIONAL CLEANING
Prestart-up cleaning of the steam generating equipment and the distribution piping network
shall be carried out in accordance with the VGB-R 513 e.
2.7.1
Chemical Cleaning
Chemical cleaning shall be considered as per DEP 70.10.80.11-Gen. and VGB-R 513 e
prior to first start, during operational tenure, based on the extent of fouling of the tubes or
after major repairs.
DEP 30.75.10.10-Gen.
February 2012
Page 11
The degree of fouling expressed as deposit-weight-density (DWD) is mass deposited per
unit surface area in mg/cm2. DWD shall be determined by cutting a tube section from the
boiler according to NACE TM0199 specification.
Typically, for HP utility boilers the following guidelines are used:
DWD [mg/cm2]
Condition
DWD < 15
Clean
15 ≤ DWD ≤ 40
Relatively dirty
DWD > 40
Excessively dirty
Using the guidelines, when 15 ≤ DWD ≤ 40 mg/cm2, then cleaning during scheduled
maintenance outage should be undertaken. When DWD >40 mg/cm2, then cleaning should
be carried out at the earliest opportunity.
Depending on the quality of the boiler water quality control, after 3-6 years of operation
during a scheduled maintenance (or statutory) inspection, a sample for DWD measurement
should be taken from a representative area. Depending on the results of the test, a test
frequency schedule needs to be established.
A comparison of a visual inspection of accessible areas which shall be ensured in design
and a verification of the cleaning process to ensure compliance with the set of procedures
provides sufficient verification of the quality of the cleaning activity.
2.7.2
Steam Blowing
All steam generators and associated distribution pipe work shall be blown with steam to
ensure the cleanliness of the system and to prevent potential damage of steam turbines
and other connected equipment and users. Steam blowing shall be carried out against a
target plate. Refer to DEP 61.10.08.11-Gen for prestart up requirement of steam blowing
prior to steam admission to steam turbine.
A system specific procedure shall be written by the Contractor for steam blowing. The
procedure shall describe in detail all the activities to make a particular system ready for
steam blowing. The procedure shall include strategic locations and type of target plates.
The procedure shall also define the acceptance criteria in terms of the maximum diameter
of indentation and the number of indentations on the target plate.
Silent steam blowing should be preferred over the conventional steam blowing due to a
lower steam requirement, uninterrupted blowing and no environmental disturbance.
DEP 30.75.10.10-Gen.
February 2012
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3.
BOILER FEED WATER
3.1
BOILER FEED WATER QUALITY
BFW quality shall conform to any of the following specifications:
1. VdTÜV (Vereinigung der Technischen Überwachungs Vereine),
2. VGB (Vereinigung Grosskraftwerks Betreiber) specifications
3. EN 12952-12
4. ASME specifications.
The VdTÜV guidelines shall be applicable for boilers with an operating pressure up to
68 barg (1000 psig); whereas the VGB recommendations shall be applied for boilers with
an operating pressure exceeding 68 barg (1000 psig).
Demineralised feed water shall be used for all the boilers with local heat flux densities in
excess of 250 kW/m² (80,000 Btu/hr-ft²), irrespective of boiler pressures.
Recommendations of the boiler Manufacturer/Supplier shall govern if more stringent than
VdTÜV and (or) VGB guidelines.
In some cases, depending on particular local circumstances of a site where steam turbines
are not applied, the steam quality guidelines may be relaxed provided reliable boiler
operation can be guaranteed without impairment of safety.
Prevention of silica breakthrough from the demineralisation plant shall be ensured. The
demineralisation plant shall be provided with online product water quality monitoring. A
silica analyser shall be provided for high pressure steam applications.
3.2
ATTEMPERATOR WATER QUALITY
The attemperator spray water quality shall be the same as the required steam quality. The
spray water shall be sourced from boiler feed water.
In some cases, polished condensate or condensate from steam turbine surface condensers
can be used for attemperation if adequate back up or storage is provided to guarantee a
reliable supply of the de-superheating water.
The purity of steam after attemperation shall meet steam specification required for the
application, see (2.1).
In case the BFW is used for attemperator water, no dosing of solids or phosphates shall be
permissible upstream of the injection water take off.
3.3
CHEMICAL DOSING FACILITIES
Chemical dosing skids shall apply portable solution tanks filled with prediluted chemicals in
the required concentrations. There may be a few exceptions if different blends have to be
mixed up such as a coordinated phosphate program or occasionally other additives as
necessary.
Safeguards shall be in place to prevent accidental dumping of the entire storage tank of
additive. Where applicable, the neat additives shall be injected into the water systems
separately.
Chemical dosing pumps shall comply with N+1 sparing philosophy. However, a common
spare pump is acceptable if several injections of the same additive are done. The dosing
pumps shall be sourced from Manufacturers/Suppliers approved by the Principal.
Injection into a header shall be done with an injection quill to facilitate mixing and to prevent
localised corrosion. Dosing pumps shall be sized to normally run at about 20 % stroke.
The dosing pump outlet shall not be split to more than one injection point.
The dosing pumps shall be of a diaphragm type having all internal components compatible
with the chemicals being dosed for whole range of applicable concentrations.
DEP 30.75.10.10-Gen.
February 2012
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3.4
BOILER FEED WATER MAKEUP AND STORAGE
The BFW makeup system capacity shall be designed in accordance with the applicable
design class per DEP 00.00.07.10-Gen. and the condensate recovery design premise.
Potential failures of a single supply or common mode failure shall be evaluated to
determine the size of the BFW make up water storage capacity.
For outage of demineralised water trains, the availability of emergency demineralised plants
should be considered.
The following factors related to the demineralised water system shall be taken into account
for finalising the BFW storage requirement.
1. common regeneration system,
2. common degasser,
3. pump sparing philosophy,
4. assessment of raw water supply security,
5. availability of regenerants in the area including logistic factors.
The following water storage philosophies shall be applied:
i)
In case of a river water intake with a sound N+1 pumping philosophy and no
drought or line damage risks:
- direct pumping of river water to clarifiers,
- storage of clarified water only to compensate for filter backwashes demand
fluctuations (1 hour, e.g. filtered water sumps below sand filters),
- storage of decationised water in degasser only to allow for surge volume
- BFW make up storage capacity as per the selected design class or 72 hours
storage of demineralised water.
ii)
In case the security of raw water supply is less than described above:
- same as under i) with the raw water storage sized for estimated interruption
duration of water supply in the worst case scenario or at least 3 days of
demand.
For security of the BFW make up water supply, two storage tanks shall be provided. In case
the site has a total shutdown every 4 years or less, each tank may be designed for 50 % of
the required storage, otherwise each tank should have at least 70 % of the required
storage.
3.5
DEMINERALISED WATER QUALITY MEASURING INSTRUMENTS
The following minimum online quality measuring instruments shall be installed. The quality
measuring instruments may be used for more than one demineralisation train.
Sr. No.
Streams/Parameters
pH
Conductivity
Silica
Sodium
1
Cation Bed
X
-
-
X
2
Anion Bed
X
X
X*
-
3
Mixed Bed Outlet
X
X
X**
-
4
Common Header to Storage
Tank
X
X
X
-
5
Demineralised Water Export
X
X
X
-
6
Effluent Pump Discharge
X
X
-
-
NOTES:
*Silica analyser downstream anion beds (range 0 - 2 ppm).
**Silica downstream mixed beds (range 0 - 50ppb).
DEP 30.75.10.10-Gen.
February 2012
Page 14
Silica and sodium analysers shall be employed for HP and VHP steam applications. In case
more than one cation unit is feeding a single degasser, it is necessary to be able to
determine which of the cation units has failed if the conductivity on all anion units goes up.
A sodium analyser downstream cation unit shall be applied in such cases.
The conductivity ratio measurement on the cation beds as an alternative to a sodium
analyser shall not be applied.
3.6
DEMINERALISED WATER TRAINS
Demineralisation trains capacity and sparing shall be based on the applicable design class,
project premise and storage capacity. Loss time in regeneration of a train shall be taken
into account to determine the effective train capacity. Necessary feed water, degassed
water and demineralised water flows shall be ensured for simultaneous trains in service
and in regeneration.
A degasser for CO2 removal shall be provided when the OPEX savings justifies additional
CAPEX depending upon the water quality.
The design of pre-treatment facilities including filtration, free chlorine and organic
components removal shall be based on design feed water quality that takes into account
the projected feed water quality in the worst case.
Ion exchange resin throughput calculations, type of resin and Manufacturer/Supplier shall
be approved by the Principal.
Ion exchange resin vessel internals shall comprise of the nozzle arrangement. Laterals
shall not be used. In cases where this is not practical, such as mid bed internals in a mixed
bed, mechanical integrity of the lateral support shall be ensured with strong beams
supporting the laterals over the entire length.
Demineralisation train manway covers on the resin vessels shall be designed and
constructed to ensure that no traces of acid or caustic can be trapped.
Safeguards shall be provided to prevent regeneration chemicals ingress into the product
water stream. Adequacy of safeguards shall be confirmed through IPF and HAZOP
reviews.
Resin traps shall be provided in the process outlet of the vessels such that no bypass is
possible around it. Consideration shall be given to possible resin loss through backwash
and regeneration, particularly where resin could enter the process lines bypassing the resin
traps. Resin traps shall be provided with differential pressure indication.
Demineralised water shall be selected for the seal water system, if necessary.
The pump curves for pumps feeding cation and anion units shall be verified. The filtered
water and degassed water pumps shall be sized to cater to high pressure differentials in the
resin vessels due to fouled resin or fines.
Valves shall be in accordance to DEP 31.38.01.11-Gen. and shall be sourced from
Manufacturers/Suppliers approved by the Principal. For the regeneration effluent drain, a
closed system to the effluent neutralisation pit shall be provided. If a tundish type of effluent
collection is applied, it shall be ensured that the effluent does not spill on the floor because
acid will eventually attack the concrete. The drain lines shall have sufficient support close to
the tundish to prevent severe vibration of the lines. The tundish shall be designed with a
sufficient safety margin and shall have a splash cover. Calculations shall be made for a
tundish based drain system to indicate that the tundishes will never flood, even with more
water usage for the backwash or rinsing.
Air bubbles shall be prevented from being drawn into the acid or caustic from the dilution
tanks, if the regenerant is used for up flow regeneration.
On-line QMI shall be sourced from Manufacturers/Suppliers approved by the Principal.
Conductivity analysers shall be sufficiently robust to handle severely off-specification water.
DEP 30.75.10.10-Gen.
February 2012
Page 15
Sight glasses shall be installed to monitor the resin bed level during service and backwash
conditions. For mixed beds, a sight glass shall be positioned to monitor the resin separation
at the mid-bed laterals.
Sight glasses shall be at least 200 mm (8 in) high and shall be removable for cleaning. It is
recommended to install a sight glass with a light source opposite of the normal sight glass.
The position of this sight glass shall be slightly above the highest backwash resin level in
order to make lighting of the resin possible under all normal circumstances. A proper
access shall be provided to the sight glasses with a platform or a ladder.
In case measuring tanks are used for regeneration chemicals, a sight glass should be
installed on each measuring tank in order to check the amount of acid and caustic used for
the regeneration. Clear marks shall indicate the high level and the low level in the tanks.
The capacity of the measuring tanks should be 30 % larger than the nominal consumption
in order to allow for increased chemicals consumption after a full bed backwash or under
adverse circumstances. Where direct dilution of acid and caustic for regeneration using
concentration analyser without measuring tank is applied, the analyser type shall be
approved by the Principal and shall be sourced from an approved Manufacturer/Supplier
and the compatibility of material of construction of analyser with the regenerant chemicals
shall be ensured.
In order to be able to backwash and to reclassify the resin, there shall be at least
40 percent freeboard relative to the height of the resin bed for bed expansion. This will help
prevent resin loss in case no strainer is installed on the backwash outlet.
Regeneration flow shall be controlled by the fixed position of drain valves.
3.7
CONDENSATE RECOVERY SYSTEM
Condensate shall be routed through a flash drum if the temperature and pressure are too
high for a storage tank or a low pressure deaerator. Condensate shall be deaerated before
use as BFW.
Condensate sources shall be segregated according to the following classification. The
condensate treatment system shall be designed based on the possible contaminants
picked up in the condensate streams, for details refer to (3.9).
• Oil-contaminated condensate, subdivided further as
-
suspect condensate (steam pressure > process stream pressure),
-
highly suspect condensate (process stream pressure > steam pressure)
• Clean condensate (from steam turbines, ejector condensers, etc.)
Clean condensate in a unit can be used internally as BFW with deaeration. The condensate
stream used internally in a unit shall be provided with an on-line cationic conductivity
analyzer with alarm.
Suspect condensate to be used as BFW shall be returned to storage so that there is
residence time to respond to a contamination incident. Facilities to divert contaminated
condensate out of the BFW system shall be provided. Contaminated condensate from
steam turbine condensers may be diverted to a cooling tower.
Plants using condensate for desuperheating or attemperation shall be provided with a
conductivity analyzer with an alarm on the tank or stream being used for desuperheating.
If the potential leak into the suspect condensate is naphtha or lighter, a volatile hydrocarbon
analyzer on the tank or on the deaerator or high pressure steam vent shall be provided.
If the potential leak into the suspect condensate is a soluble hydrocarbon, a TOC analyzer
shall be provided on the tank or stream. The analysers shall be supplied by
Manufacturers/Suppliers approved by the Principal.
The extent of condensate recovery in the design shall be decided based on economics, a
water master plan and energy efficiency criteria, considering the following factors.
DEP 30.75.10.10-Gen.
February 2012
Page 16
1.
Energy saving (warm water to the deaerators)
2.
Water saving (e.g. refineries using seawater as source for boiler feed water).
3.
Demineralisation plant capacity constraint
4.
Reducing reliance on a single water source for the boilers
5.
Reduction of waste water flow to an effluent treatment plant
6.
Treatment of oily condensate
Volatile amines shall be used in BFW system for controlling the pH in the condensate
system to minimise corrosion.
3.8
BFW AND CONDENSATE PUMPS
The design and selection of BFW and condensate pumps shall comply with the requirement
of DEP 31.29.02.11-Gen. BFW pumps shall be provided in accordance with the selected
design class per DEP 00.00.07.10-Gen. or N+2 sparing philosophy.
To achieve higher reliability, a combination of steam turbine and electrical motor driven
BFW pumps should be used, such that adequate number of BFW pumps are available to
cater to normal steam demand, in case of failure of any one utility. If the power supply is fed
from reliable independent sources, then all BFW pumps can be electric motor driven.
Where steam turbine driven pumps are employed, they shall be kept normally in operation
and electrical power driven BFW pumps shall be on standby. All standby BFW pumps shall
have an auto start facility on low boiler feed water pressure. In case boilers have separate
dedicated BFW pumps, each boiler should have 2x100 % BFW pumps.
An automatic minimum recirculation valve shall be provided for each boiler feed water
pump.
Pumps delivering condensate should be provided with N+1 sparing.
If BFW makeup or de-superheating water relies partially on condensate return, condensate
supply pumps shall be spared such that, in case the largest steam turbine driven pump is
out for maintenance and there is a power outage, the required BFW demand can still be
met.
3.9
CONDENSATE TREATMENT
For recycling condensate to the BFW system, the condensate treatment system shall be
designed to meet BFW quality requirements; refer to (3.1).
Note:
The treated condensate shall be deaerated to achieve oxygen content specification and shall be
conditioned for pH adjustment.
Recovered steam condensate may contain free undissolved oil, dissolved oil (light
hydrocarbons) and emulsified oil. The first treatment step for oil-contaminated steam
condensate shall be a de-oiling process, after which the final treatment is identical to that
for oil-free condensate.
In the case of the potential for LPG carry over from a reboiler, etc., a separate stripping
column shall be employed.
Further treatment shall comprise a filtration step, followed by a polishing ion-exchange step.
Granular Activated Carbon (GAC) filters shall be applied to reduce the hydrocarbons
content to 0.5 ppm (with the exception of light fractions, such as C4-C5) and for fine filtration
of undissolved oil and corrosion products, such as rust particles, etc.
The GAC filters shall be operated according to the "merry-go-around" principle, i.e., at any
time two AC filters are in series, with the "fresh one being the last one". Cartridge filtration
may be required for clean condensate systems (free of oil) removing iron-and copper
oxides as particulates, to meet BFW quality requirements.
DEP 30.75.10.10-Gen.
February 2012
Page 17
During start-up or after an overhaul, usually 50 or 100 micron cartridges should be installed.
During normal operation, 10 to 25 micron cartridges can be used.
Contaminated condensate from consumers shall be cooled to ambient temperature before
it is discharged into surface water sewer systems.
The iron and copper shall be removed from the condensate to comply with applicable BFW
specifications. Refer to (3.1). Condensate polishers shall be applied to remove iron, copper
and other contaminants removable by ion exchange process.
For condensate polishing using the ion-exchange process, one of the following
configurations shall be applied depending upon the contaminants present in the
condensate.
i)
Mixed Bed (MB) polisher.
ii)
Cation-exchanger followed by MB polisher.
In MB polishers, traces of cations and anions are removed from the condensate.
Appropriate linear velocities and bed-depth shall be selected per Manufacturers/Supplier’s
standard. The selection of the right Manufacturer/Supplier is important for the assurance.
Only those resins, which are resistant to attrition should be applied.
The design of the polisher shall take into account the conditioning chemicals present in the
condensate. A cation exchanger upstream of the mixed bed should be considered in the
case of condensates conditioned with ammonia, morpholine or cyclohexyl-amine for
protection of condensate system against CO2 corrosion by means of neutralising amines
and small amounts of salinity due to possible cooling water leaks.
Trims of (control) valves used in BFW / condensate systems shall not contain stellite.
Stellite is incompatible with amines which attacks cobalt-based materials such as stellite. It
delaminates in layers, a process called 'chelation'. The amines are commonly injected to
BFW /condensate systems for pH control. Hardening should be done using an overlay of
colmonoy. Colmonoy is nickel based and does not get attacked by amines.
The condensate shall be deaerated before use as BFW, unless oxygen ingress in the
condensate system is fully prevented.
Condensate feeding directly to a steam generator within a process unit should be avoided
because of corrosion risk with high oxygen content in feed water particularly during start up
and such design shall require the Principal’s approval.
For mixed bed polishers application, the condensate shall be cooled to less than 60°C
(140°F).
A condensate polisher should be installed according to the N+1 sparing philosophy. In
addition, a bypass shall be provided, which can be used for short periods.
The regeneration frequency of the polisher bed will vary with ionic loading. The polisher bed
capacity shall be such that the regeneration frequency is a maximum of
1 regeneration/week with the design condensate feed quality.
Multiport valves shall not be used on the polishers. The polisher shall be equipped with a
subsurface backwash. Condensate shall be used for backwash and brine dilution.
The polishers shall have a PLC or DCS to control all regeneration steps. Regeneration
flows shall be controllable and regeneration shall be manually initiated. It shall be possible
to adjust timers or flows or to go to any step manually. There shall be a pH and conductivity
analyzer cum recorder on the combined polished condensate stream and a conductivity
analyzer on the outlet of each polisher vessel.
Safeguards shall be provided to prevent regeneration chemicals get into the product water
stream. Adequacy of safeguards shall be confirmed through IPF and HAZOP reviews.
A polished condensate storage capacity shall be a part of the overall BFW makeup storage
capacity strategy.
DEP 30.75.10.10-Gen.
February 2012
Page 18
3.10
BOILER WATER TREATMENT
A chemical treatment programme along with overall steam-water cycle chemistry
supervision and management shall be applied to maintain integrity of the capital equipment
(boiler, WHB, and steam turbines) and productivity throughout the design asset life.
The boiler water treatment shall be based on a conventional “coordinated phosphate”
program or an “equilibrium phosphate” program with an alkalinity buffer. “All volatile”
treatment shall not be applied to sub critical boilers.
3.11
FLOW ACCELERATED CORROSION (FAC)
There is usually a pattern of corrosion (FAC) in BFW systems. The flow of fluids, the angle
of impingement, velocity and water chemistry factors determine the severity of erosioncorrosion. FAC particularly affects mild steel and is more likely found where turbulence is
caused due to fluid velocity and directional changes such as bends, reducing sections, pipe
section with orifice plate, form of gullies, grooves, etc. Metal loss rates can be high; on the
order 2 – 4 mm/yr (5/64 to 5/32 in./yr).
The BFW system design shall consider the following measures to minimise the possibilities
of FAC.
3.12
1.
Adequately sized piping with velocity equal to or less than 2.4 m/s (8 ft/s) when
using carbon steel metallurgy.
2.
Minimised turbulent areas in the piping system by elimination as far as practical
and use of best practices in the design of the components.
3.
Application of alloy steel with low levels of chromium (>=1 %) in the FAC prone
areas, since it reduces the corrosion rate significantly.
4.
Provision of facilities to maintain water chemistry within limits, pH>9.0 helps in
terms of relative corrosion attack.
STEAM, BOILER FEED WATER AND CONDENSATE SAMPLING REQUIREMENTS
The following steam sampling concepts shall be applied.
•
For steam uses at 40 barg (600 psig) and above, steam sampling is required for
the steam generators, due to higher risk of carry-over of impurities to steam.
•
For LP and MP steam, steam purity is maintained by managing quality of BFW and
boiler water. An existing steam sampling facility is maintained to capture the
occasional purity checks and for troubleshooting purposes.
Steam sampling arrangement shall be designed for iso-kinetic sampling collection
requirement as per ASTM D1066 and ASME PTC 19.11. The sample shall be cooled and
conductivity shall be measured following cation-exchange. As a minimum, the following
sampling facilities shall be provided for the steam, feed water and boiler water quality
measurement. On line analysers (pH, conductivity) should be considered for robust control
of chemistry.
Sr. No.
Streams/Parameters
pH
Specific
Conductivity
Cation
Conductivity
Dissolved
Oxygen
Silica
1
BFW
X
X
X
X
X
2
Saturated Steam1
X
X
X
-
X
X
X
X
-
X
X
X
-
-
X
3
Superheated Steam
4
Boiler water
NOTE 1:
1
Not mandatory for LP and MP steam.
DEP 30.75.10.10-Gen.
February 2012
Page 19
All other parameters, i.e. boiler water, PO4 and alkalinity, shall also be tested on a regular
basis in the laboratory.
The condensate sampling facilities shall be provided at the individual equipment
condensate collection points and at each of the segregated condensate streams (suspect/
highly suspect/ clean) header or storage.
In the event of contamination, the particular condensate streams shall be dumped when
contamination level exceeds the treatability limit of the downstream condensate treatment
unit. The usual various contamination limits set for condensate are as follows.
Sr. No.
Analyzer
Alarm Limit
1
Volatiles Analyzer
>10 %
2
TOC
>5 ppm
3
Visual Cup
Hydrocarbon Floating
4
Total Hardness
>1 ppm
5
Conductivity
>15 mmhos
6
Cation Conductivity
>2 mmhos
DEP 30.75.10.10-Gen.
February 2012
Page 20
4.
STEAM HEADERS
4.1
STEAM DISTRIBUTION HEADERS
Steam distribution headers and piping shall be designed, fabricated and installed in
compliance with DEP 31.38.01.11-Gen.
The main factors to consider during the selection and design of the steam piping include
but are not limited to pipe size, wall thickness, materials selection, types of joints, proper
insulation, protection of piping and insulation from mechanical and water damage,
condensate drainage, thermal expansion and anchorage provision, and safety provisions
shall be reviewed and confirmed. The design shall comply requirements in the
DEP 31.38.01.11-Gen
Steam distribution headers shall be designed for high reliability considering that, in general,
there is no shutdown possible for the steam headers in most oil and gas installations.
All HP and MP steam lines shall have welding joints. Flange joints shall be minimised and
used only when considered absolutely necessary.
Reliability of critical block valves shall be ensured. Valves shall be sourced only from
Manufacturers/Suppliers approved by the Principal. As a minimum, the following block
valves shall be considered as critical block valves:
1.
Main Steam Stop Valve (MSSV) at the steam generator outlet
2.
Process Unit Battery Limit Valve
3.
PRDS Isolation Valve
4.
PRDS Water Spray Isolation Valve
5.
Distribution Header Section Valve
6.
Distribution Header End Valve, if provided
7.
1st Isolation Valve in the branch lines from the main headers
Double isolation valves shall be provided for all 900 class and higher rating applications in
accordance to DEP 31.38.01.11-Gen. All critical valves for process and utilities areas
valves, where shutdown of steam supply is not possible or desirable or where valves are
the sole isolation of equipment, shall also be double block valves.
Flanges shall be provided at these locations to allow for (or spectacle blinds to isolate) the
steam systems during maintenance of the unit. Instrument connections for flow, pressure
and temperature measurements shall be installed downstream of the block valves to the
plant or unit.
Pipes to consumers shall branch off from the top of the steam supply pipe, in order to
prevent steam condensate from going to the steam consumers. Accumulated steam
condensate is drained from the common steam supply pipe via drip legs and steam traps
from the bottom of the steam supply pipe. If entrained condensate is required to drain from
the steam supply pipe to an individual consumer, a steam trap shall be installed at a low
point from the bottom of the individual steam supply pipe.
Exhaust steam pipes from equipment shall enter at the top of the exhaust collecting pipe to
prevent steam condensate from running back into neighbouring steam consumers.
Steam relief devices discharging to the atmosphere and a steam silencer shall be located
at the maximum practical elevation, to keep discharge piping at a safe location and as short
as possible.
If a silencer is used, the silencer shall have its own drain system, equivalent in size and
design to the drain located in the low point of the discharge piping downstream of the
discharge valve. The location of the outlet of the steam piping or silencer that discharges to
the atmosphere shall be above the pipe rack or above any other obstruction that can
redirect the discharging fluid onto equipment or personnel. The discharge valve shall be
DEP 30.75.10.10-Gen.
February 2012
Page 21
away from the outlet of the discharge piping or silencer and shall not be located under the
outlet of the discharge piping or silencer.
An atmospheric relief device discharge piping shall be corrosion resistant (hot dip
galvanized or stainless steel construction) and shall have a weep hole of approximately
13 mm diameter (½ in.) at the lowest point of pipe to ensure complete removal of all liquids
that could accumulate in the discharge piping system.
4.1.1
Warming-up facilities
A vent shall be installed to enable the pipes to be warmed up prior to commissioning and
the capacity of vents shall be established based on the warm up flow requirement.
Piping in steam service shall be arranged such that steam condensate accumulation is
avoided.
Stagnant and reverse-flow conditions should be avoided in steam distribution systems.
Quick introduction of steam into a cold line can result in violent water hammer as the steam
alternately collapses from condensation and re-flashes. Therefore warming-up facilities
SHALL [PS] be provided for the steam lines and connected equipment. All 200 mm (8 in.)
and above block valves and pressure let down control valves SHALL [PS] be provided with
integral bypass for line warm up.
On 40 barg (600 psig) and higher steam pressure systems, DN 25 (NPS 1) or DN 50
(NPS 2) warm-up lines SHALL [PS] be provided with valves bypassing main system
isolation valves. These valves are opened to introduce steam slowly into higher pressure
lines to avoid the violent reaction.
Warm up rates for steam piping systems with size DN 400 (NPS 16) and larger SHALL [PS]
be selected as 1°C/min (2°F/min) to avoid excessive steam trap capacities and 2°C/min
(4°F/min) for steam piping systems below DN 400 (NPS 16).
For steam service, a bypass valve shall be installed as per the following:
a) Battery limit isolation valves SHALL [PS] have a warm up bypass of minimum size
DN 20 (NPS ¾) for preheating and pressure-balancing.
b) Valves DN 150 (NPS 6) and larger in ASME rating class 600# and higher
SHALL [PS] have a bypass valve for preheating and pressure-balancing. The bypass
size shall be as follows:
Bypass Valve,
nominal size, DN (NPS)
Main Valve,
nominal size, DN
For warming-up of pipe and
for pressure-balancing of
pipes with limited volumes
For pressure-balancing
of other pipes
150 (NPS 6)
20 (NPS ¾)
25 (NPS 1)
200 (NPS 8)
20 (NPS ¾)
40 (NPS 1 ½)
250 (NPS 10)
25 (NPS 1)
40 (NPS 1 ½)
300 (NPS 12)
25 (NPS 1)
50 (NPS 2)
350 (NPS 14)
25 (NPS 1)
50 (NPS 2)
400 (NPS 16)
25 (NPS 1)
80 (NPS 3)
450 (NPS 18)
25 (NPS 1)
80 (NPS 3)
500 (NPS 20)
25 (NPS 1)
80 (NPS 3)
600 (NPS 24)
25 (NPS 1)
100 (NPS 4)
DEP 30.75.10.10-Gen.
February 2012
Page 22
For warming-up of pipe and for pressure-balancing of pipes with extensive volume, the size
of bypass valve shall be calculated as per the following:
DN_bypass = (DN_header/500) * (Length of piping system)
NOTE:
½
Length of piping system is in meters.
To avoid the water hammer caused by stagnation in the looped steam headers, flow and
temperature measurement in each looped header SHALL [PS] be provided to facilitate
pressure control and adjustments on the basis of alarms.
Steam lines shall be insulated before being taken into operation to avoid excessive
condensate formation. Water resistant covering shall be employed. For sites in locations of
heavy rainfall, steam loads increase due to rain falling on the distribution headers. This load
increase shall be considered as 15 % of the total steam load for estimating the steam
generation capacity.
Piping shall be designed to permit steam to blow up to the inlet and outlet flanges of the
turbine before start-up.
Steam vents shall be routed to a safe location and SHALL [PS] not be combined with any
lubricating oil, seal oil or process vent.
For
steam
piping,
refer
to
DEP 20.05.60.10-Gen,
DEP 30.75.10.30-Gen.,
DEP 31.24.00.30-Gen. and the DEP Standard Drawings referenced in those DEPs.
4.1.2
Pressure Relief and Safety Valves
Pressure-relief systems shall be in accordance with DEP 80.45.10.10-Gen.
Pressure safety valves SHALL [PS] be installed downstream of the pressure letdown
stations in the steam distribution system to protect the downstream piping and equipment in
the event of failure of the pressure control valve to contain the pressure within the
maximum allowable working pressure limits of the piping and downstream equipment.
LP steam header downstream of let down station may be provided with electromatic relief
valve for instrumented venting of steam in case of pressure build up. This will avoid
frequent lifting of the spring loaded safety / relief valve resulting in to valve seat damage.
The set pressure of the relief valve in the turbine exhaust systems SHALL [PS] not exceed
either the turbine design pressure or the pressure of the exhaust piping, whichever is the
lesser. The relief valve SHALL [PS] be installed between the turbine outlet and the check
valve. The calculation for the relief valve orifice SHALL [PS] be based on the turbine inlet
nozzle.
The pressure drop from the boiler MSSV to the turbine inlet shall not be more than 3 %.
For recommended steam velocities for pipe sizing, refer to DEP 31.38.01.11-Gen.
Future tie-in point to the steam distribution headers with isolation valve may be provided as
per project requirement.
4.2
PRESSURE REDUCING AND DESUPERHEATING STATION
The steam system shall be designed to operate with no let down of higher pressure steam
to lower pressure steam under normal operation as far as practicable.
A PRDS shall be provided and sized to cater to the maximum total demand of the
downstream consumers on the low side header while duly considering abnormal scenarios
of outage of alternative sources of steam supply, such as back pressure or extraction
turbine.
A spare PRDS shall be installed in accordance to the N+1 sparing philosophy for critical
services where alternative sources including back pressure turbines are not available. The
critical services are those users and services where shutdown is generally not possible.
The pressure reducing station shall comprise an upstream and downstream isolating valve
to shut the system down for maintenance. This includes the strainer, drains and upstream
DEP 30.75.10.10-Gen.
February 2012
Page 23
and downstream local pressure gauges along with pressure transmitters for the control
room display.
Reliability of pressure reducing and desuperheating station shall be ensured. The pressure
control valve and desuperheater, or PRDS combined, shall be sourced only from the
Principal approved Manufacturers/Suppliers.
The water spray PCV SHALL [PS] have long term tight shut off performance with tightness
class V as per IEC 60534. The spray valve design shall use a hard metallic seat which
resists trash cutting and a high seat loading to provide reliable and repeatable long term
shutoff for high pressure differentials. The steam PCV isolation valve shall be provided with
a small bypass valve for warm up and the PCV shall be designed with minimum steam flow
necessary for maintaining the let down line under warm operating condition. The PRDS
downstream line shall be designed for the upstream design temperature conditions up to a
certain piping length. The vibration and stress analysis shall include PRDS piping with a no
load to a full load operation of the PRDS.
4.3
ATOMISING STEAM LINES
A common atomising line for more than one boiler shall not be used. Each utility boiler shall
be provided with a dedicated atomising steam line from the main steam header. In the case
of double steam header systems, the atomising steam shall be supplied from both the
headers.
Steam traps, in terms of capacity and numbers, shall be reviewed taking into account that
the atomising line may be idle for a long time, for example, when alternative gas fuel firing
is in use. At least one spare trap assembly shall be installed at low points on atomising
steam lines.
4.4
DRAINS AND DRIP LEGS
The drain points shall be located and designed to ensure that the condensate can reach the
steam trap. Consideration shall be given to condensate remaining in a steam header at
shutdown, when there is no steam flow and condensate will collect by gravity at low points
in the system. Steam traps shall be provided at all low points.
The risk of water hammer due to slugs of condensate at high velocities shall be minimised
by proper engineering design, installation and maintenance.
Eccentric reducers with a flat bottom shall be used where necessary. Design SHALL [PS]
include warming up provisions to facilitate charging and slowly warming up steam lines
during start-up from cold conditions.
Check valves shall be installed downstream of all those steam traps where condensate
backflow is possible during shutdown.
Steam line for users shall be tapped from the top of the main steam header to ensure dry
steam supply. The isolation valves for the user tappings shall be provided near to the off
take to minimise condensate accumulation in the branch line during shutdown for any
extended periods. Branch lines shall be provided with steam traps at all low points and
upstream of the end users.
Strainer shall be provided upstream of each steam trap, flow meter, reducing valve and
regulating valve. The removable cap or a blow down valve shall be provided to allow
cleaning of the screen regularly.
Drip legs SHALL [PS] be provided to collect condensate formed in steam lines, to facilitate
drainage and to prevent entrainment of water slugs with fast moving steam causing water
hammer.
Drip legs SHALL [PS] be installed in both saturated and superheated service at low points,
upstream of vertical line sections, near “dead” ends including line sections to control valves,
battery limit valves and other block valves where steam can be at stagnant, in sections
downstream of desuperheaters to remove injection water in excess of evaporation capacity.
DEP 30.75.10.10-Gen.
February 2012
Page 24
Minimum drip leg diameters are indicated in (Appendix C). The bottom of the drip leg shall
be fitted with a blow down valve for cleaning purpose.
Drip leg shall be provided in accordance with the following dimensions:
a) For steam pipe of size DN 150 (NPS 6) and above, the nominal diameter of the drip
leg shall be at least 50 % of the steam pipe size.
b) For steam pipe of size DN 100 (NPS 4) and below, the nominal diameter of the drip
leg shall be same as that of the steam pipe size.
c) Minimum distance of steam trap branch connection shall be 50 mm (2 in) from the
closure piping component weld.
d) To prevent re-entrainment from drip legs a minimum depth shall be applied. The
length of a drip leg shall be 2.0 times the nominal steam line diameter with a
minimum of 250 mm (10 in.) and a maximum of 500 mm (20 in), measured from the
bottom of the steam line to the bottom of the drip leg.
e) Steam lines shall be installed sloping towards the nearest drip leg and necessary
measures shall be incorporated to minimize line sagging. In case, where sagging of
lines is unavoidable, the position and sizing of drip legs shall be such that it
minimises the risk of transporting slugs of water from a sag over longer distance at
high steam velocities.
The drain line from the drip leg down to the steam trap shall have a first block valve that
can be operated from grade or a platform and a tee with a drain valve that can be used for
removal of condensate during line warming up, as bypass during trap maintenance and for
blow out of dirt collected in the vertical line to the steam trap. The other part of the tee
hooks up to the steam trap with an upstream second block valve and strainer.
In case of drainage from superheated steam lines, where condensate discharging from the
trap can be expected only during warm up and severe upset conditions, it is acceptable to
discharge the trap to the AC system in a safe manner. Discharges from superheated steam
lines where condensation during operation can be expected shall be hooked up to
saturated steam lines.
In case of drainage from saturated steam lines, the steam trap shall discharge into a
condensate recovery system. For start-up and trap checking, the discharge shall be
provided with a bypass valve to the AC system.
For energy and water conservation, steam traps should discharge into a closed system.
However, open discharge is acceptable for steam traps on superheated steam lines and on
remote lines with very small condensate flow. The maximum temperature of discharging
condensate shall be compatible with the receiving system and safety of people shall not be
jeopardized.
An open drain shall collect the condensate from discharges along pipe tracks with steam.
To prevent the steaming hot condensate in the drain from imposing a HSE risk, it will be
flushed with firewater using water hoses during line warm up.
4.5
STEAM TRAPS
The steam trap design, performance and manufacturing shall comply with the following
codes and standards:
•
ANSI/ASME PTC 39.1
•
ANSI/FCI 69-1
•
ANSI/FCI 85-1
Steam trap selection shall be robust to avoid water hammer and frost damage. Trim
material for traps and strainers shall be stainless steel. For steam tracing traps, the body
material shall also be stainless steel.
The size of valves and piping at steam trap shall be the same as the trap.
DEP 30.75.10.10-Gen.
February 2012
Page 25
Steam trap isolation valves shall be provided for steam trap maintenance without having to
turn off the steam supply at the root valve.
Bypasses around steam traps shall be installed to allow traps removal and repair and for
start-up. Refer to also DEP 31.38.01.11-Gen for requirements.
Steam traps shall not be insulated. For safety, the use of expanded metal screening
wrapped around a trap, instead of insulation, can provide personnel protection where
necessary.
Steam traps shall not discharge into the open within an operating area. Traps shall be
accessible and near the equipment being drained. The maximum distance between two
consecutive steam traps for steam headers shall not exceed 50 m (165 ft) for saturated
steam and 150 m (500 ft) for superheated steam.
Condensate collecting piping for grouped tracer traps shall be such as to avoid excessive
back pressure on traps and trap discharge lines and should be based on the lowest
expected steam supply pressure.
Each tracer shall have its own steam supply valve and steam trap.
For heat conservation service, each trap shall have a block valve upstream and
downstream of trap. Traps will have an integral strainer and plugged drain. In winterization
service, no blocks will be required at steam traps. Drains will be valved.
The condensate load per trap shall be calculated based on condensation during warming
up and heat losses, other condensate entering the steam line, e.g. from branches, actual
number of drip legs in section, etc.
Placement of steam trap connection shall be on the side of the drip leg. The end of the
main steam headers shall be provided with a valved blow-off connection of the minimum
DN 20 (NPS ¾) size.
Suitable steam trap types shall be selected for given applications, sized for their duty and
installed correctly for the type of the steam trap.
A strainer of 40 mesh screen size with a blow-off valve shall be installed upstream of any
steam trap which does not include an integral strainer. Strainers shall be installed for any
thermodynamic disc trap or orifice trap.
The pressure due to the lift shall be added to the pressure in the overhead return line when
determining the total back pressure against which the trap discharges.
The steam trap back pressure shall not exceed 50 % of the upstream pressure.
Steam traps up to and including DN 40 (NPS 1-½) size should be welded and should have
removable internals to allow repair without performing hot work.
Steam traps shall be positioned so that they are easy to maintain and replace. The
connecting piping up to and including the first downstream block valve shall be designed for
the full steam pressure and temperature.
Steam pipes shall not discharge steam condensate into sewer systems but instead shall
run to a safe location such as collecting steam condensate pits, accidentally-contaminated
water rundown systems, gravel pits, gullies, etc. The safe locations shall be combined as
far as practical.
4.6
CONDENSATE HEADERS
Condensate headers at different pressure (such as HP/MP/LP) shall not be connected
directly to one common header. The condensate system shall be designed so that each
condensate pressure level to common header is routed through a flash vessel designed
with sufficient volume for separation of fine water droplets travelling with flash steam.
For condensate lines, pressure drop increases rapidly with line length, due to two-phase
flow and steam density rapidly decreasing, resulting in higher steam velocities. The
DEP 30.75.10.10-Gen.
February 2012
Page 26
maximum length of a trap or control valve discharge line shall be such that the maximum
steam velocity does not exceed the specified values.
Mixing of cold condensate with hot condensate shall not be applied.
Long condensate lines or lines with intermittent users shall enter flash vessels separately
instead of a tie in to another condensate line. Alternatively, these lines shall be drainable
before use.
For drainage capacity of condensate from steam lines, two cases shall be considered.
•
Condensate formed during warming up of a line from cold to operating pressure.
•
Condensate formed during operating conditions.
Condensate lines of systems which discharge condensate at saturated steam temperatures
shall be sized to handle the flash steam content as well as the condensate.
All condensate headers shall be provided with protective heating or insulation to prevent
freezing of condensate in the areas where freezing can occur.
Condensate discharge piping system leading to an open drain system shall be sloped away
from the trap and generally, no point in the piping system shall be higher than the trap level.
Condensate from steam traps that are not readily accessible to a condensate header or
condensate receiver shall be routed to the nearest suitable drain, or provided with a
pumped condensate return system, if warranted by the quantities involved. Contaminated
steam condensate, e.g. from process heat exchangers, shall be routed to the contaminated
water system or shall be treated and returned to the boiler feed water system. Equipment
producing condensate shall have a full capacity drain to the contaminated water rundown
system.
Level-controlled condensate pots should be used in lieu of steam traps for any of the
following condensate applications:
a) Heat exchangers with inlet steam throttling control and nominal steam supply
pressures greater than 17 barg (250 psig);
b) Heat exchangers with inlet steam supply pressures of 3.5barg (50 psig) or less, with
or without inlet steam throttling, that discharge into a closed condensate system,
and;
c) Heat exchangers with a steam usage greater than 3630 kg/hr (8000 lb/hr) that
discharge into a closed condensate system.
For condensate collection headers usually not all condensate suppliers operate at
maximum capacity at the same time. The following maximum steam velocities shall be
used:
•
For steam trap and CV discharge lines
Size piping for maximum condensate mass flow with flash steam velocity of
15 m/s (50 ft/s) or less. The line shall tie in to the top of a condensate collection
header to prevent back flow.
•
For condensate collection headers
Size the line for normal operating condensate mass flow with a flash steam
velocity of 10 m/s (33 ft/s) or less.
Condensate return system shall be designed in accordance with the lowest value of the
maximum allowable backpressures specified for the connected upstream process
equipment.
Horizontal expansion loops shall be considered for a hot condensate collection network.
DEP 30.75.10.10-Gen.
February 2012
Page 27
4.7
THERMAL EXPANSION AND PIPING FLEXIBILITY
The piping system shall be designed to be sufficiently flexible to accommodate the
movements of the components as they expand. Any difference between the thermal
expansions of the two connected piping systems, due to different operating temperature
such as steam piping and condensate piping, shall be taken into account during system
warm-up. The adequacy of expansion loops shall be verified during design. For piping
stress analysis requirements, refer to section 5 of DEP 31.38.01.11-Gen.
4.8
PIPE SUPPORTS
Steam and condensate pipe supports shall be provided as per the requirements laid down
in DEP 31.38.01.29-Gen. Hanger supports shall not be used in systems with two-phase
flow or where excessive vibration may be expected.
DEP 30.75.10.10-Gen.
February 2012
Page 28
5.
DEAERATOR DESIGN CONSIDERATIONS
The sparing of deaerators shall be in accordance with the selected design class as per
DEP 00.00.07.10-Gen. For higher reliability of BFW supply, it should be ensured that the
site BFW demand can be met when one deaerator is out of service.
The deaerator shall not be bypassed since oxygen pitting can be significant in a short time.
When multiple deaerators are operated in parallel, the pressure of all deaerators shall be
kept the same. The deaerator pressure equalizing lines shall be sized adequately to ensure
that the pressure drop is minimal across the pressure equalizing line to support a reliable
parallel operation.
A spray and tray type deaerator only designed to reduce dissolved oxygen levels to below
20 ppb shall be applied.
Low pressure steam with minimal pressure letdown shall be used for deaeration. Makeup
water and condensate shall be mixed just before entering the deaerator.
The temperature difference of the incoming water and the saturation temperature of the
incoming steam shall be at least 20°C (36°F) subject to confirmation by the
Manufacturer/Supplier on the dissolved oxygen removal performance considering the entire
design envelop.
The deaerator steam vent shall not exceed 0.1 % of the incoming water to the deaerator.
The holdup volume between normal level and Low Low level shall be designed to cater for
at least 20 minutes of the designed BFW consumption.
Oxygen scavengers shall be dosed upstream of the BFW pump to ensure sufficient
residence time for a reaction before the BFW reaches the preboiler circuit.
The necessity of an oxygen scavenger addition is caused by upsets around the deaerator,
and the expected air in-leakage upstream of the BFW pumps.
The deaerator oxygen rich section and dome shall be constructed of stainless steel.
5.1
DEAERATOR FEED WATER PREHEAT SYSTEMS
Applications using deaerator feed water for heat recovery from hydrocarbon streams
involve risk of feed water contamination. There is also an additional risk of corrosion in the
heat recovery system due to high dissolved oxygen in the deaerator feed water.
An evaluation shall be made during design of deaerator feed water preheat systems to
demonstrate that adequate safeguards against BFW contamination risk and corrosion
abatement measures are provided in the design.
DEP 30.75.10.10-Gen.
February 2012
Page 29
6.
UTILITY BOILER FUEL SYSTEM DESIGN CONSIDERATIONS
The fuel system shall be designed in accordance with the DEP 20.05.60.10-Gen.
For liquid fuel fired boilers, fuel supply pumps sparing will be as per the selected design
class. Refer to DEP 00.00.07.10-Gen.
For a robust liquid fuel supply system for utility boilers, 3x100 % pumps should be selected.
At least one of these pumps shall be provided with a power supply from a different MCC or
shall be steam turbine driven to minimise the impact of local power failure. At least two of
the motor driven pumps shall be provided with emergency power.
The liquid system should be provided with N+1 fuel heaters for robust designs. Heaters
shall be located downstream from the fuel pumps.
Return loops shall be provided from the farthest point of each distribution branch and main
supply header, to ensure liquid fuel circulation sufficient to maintain the specified
temperature at the farthest consumer.
The liquid fuel header shall be thoroughly insulated to minimise heat loss. Refer to
DEP 30.46.00.31-Gen. for insulation requirements and steam tracing that can be applied, if
required, to maintain the fuel supply temperatures. Refer to DEP 31.38.30.11-Gen.
All fuel pumps shall be provided with dual filters or strainers in the suction line with
individual isolation valves. Dual gang valves arrangements to switch the filters
simultaneously in one operation shall not be applied.
Provisions to check the water accumulation in the fuel oil tank shall be provided. This
includes sample points and drains with valves, end blinds at the appropriate locations in the
liquid fuel storage tanks, to facilitate the monitoring of settled water and its safe and proper
disposal. Pump suction line connections in the tank shall be at least 1 m (3 ft) above the
bottom level for large tanks.
DEP 30.75.10.10-Gen.
February 2012
Page 30
7.
REFERENCES
In this DEP, reference is made to the following publications:
NOTES:
1. Unless specifically designated by date, the latest edition of each publication shall be used,
together with any amendments/supplements/revisions thereto.
2. The DEPs and most referenced external standards are available to Shell staff on the SWW (Shell
Wide Web) at http://sww.shell.com/standards/.
SHELL STANDARDS
Design class tables
DEP 00.00.07.10-Gen.
Fuel systems
DEP 20.05.60.10-Gen.
Thermal insulation
DEP 30.46.00.31-Gen.
Water-tube boilers
DEP 30.75.10.30-Gen.
Fired heaters (amendments/supplements to ISO 13705)
DEP 31.24.00.30-Gen.
Pumps- Selection, testing and installation
DEP 31.29.02.11-Gen.
Piping –General requirements
DEP 31.38.01.11-Gen.
Piping Classes - Refining and chemicals
DEP 31.38.01.12-Gen.
Piping Classes - Exploration and production
DEP 31.38.01.15-Gen.
Pipe supports
DEP 31.38.01.29-Gen.
Protective steam heating of piping systems
DEP 31.38.30.11-Gen.
Instruments for measurement and control
DEP 32.31.00.32-Gen.
Field inspection prior to commissioning of mechanical equipment
DEP 61.10.08.11-Gen.
Cleaning of equipment
DEP 70.10.80.11-Gen.
Design of pressure relief, flare and vent systems
DEP 80.45.10.10-Gen.
STANDARD DRAWINGS
Closed Vessel with Wet Leg (Instrument Hook-Up Drawing)
S.37.001-311 through
S.37.001-320
AMERICAN STANDARDS
Pressure Rating Standards for Steam Traps
ANSI FCI 69-1
Standards for Production and Performance Tests for Steam Traps
ANSI FCI 85-1
Steam Traps Performance Test Codes
ANSI/ASME PTC 39.1
Standard Method of Sampling Steam
ASTM D1066
Steam and Water Sampling, Conditioning, and Analysis in the
Power Cycle
ASME PTC 19.11
Power Piping
ASME B31.1
Process Piping
ASME B31.3
EUROPEAN STANDARDS
Water-Tube Boilers and Auxiliary Installations - Part 12:
Requirements for Boiler Feedwater and Boiler Water Quality
EN 12952-12:2003
DEP 30.75.10.10-Gen.
February 2012
Page 31
INTERNATIONAL STANDARDS
Standard Test Method for Measuring Deposit Mass Loading
("Deposit Weight Density") Values for Boiler Tubes by the GlassBead-Blasting Technique
NACE TM0199
OTHER GUIDELINES
VGB PowerTech e.V. – Guideline for Feedwater, Boiler Water and
Steam for Steam Generators Exceeding 68 bar Operating PressureTube Steam Generating Plants and Associated Pipe Work
VGB-R 450 L
VGB PowerTech e.V. - Internal Cleaning of Water-Tube Steam
Generating Plants and Associated Pipe Work
VGB-R 513 e
VdTÜV-Guidelines for Feedwater, Boiler Water and Steam for Boilers
with Permissible Operating Pressures up to 68 bar;
(Germany)
MB TECH 1453
DEP 30.75.10.10-Gen.
February 2012
Page 32
APPENDIX A
TYPICAL STEAM TRAP ARRANGEMENT FOR STEAM LINE DRAINAGE
saturated
superheated
steam line
steam line
drip leg
drip leg
for >900#
for >900#
for >900#
for >900#
steam trap
steam trap
to condensate
recovery
1 2 strainer 3
AOC
AOC
Saturated Steam Line Arrangement
AOC
1 2 strainer
AOC
AOC
Superheated Steam Line Arrangement
AOC
Injection
water
ST
TC
PC
PI
Injection
water
ST
TC
PC
PI
Injection
water
ST
TC
PC
Steam
consumer
Steam
generator
Steam
consumer
G
LP steam
MP steam
HP steam
APPENDIX B
PI
Steam
generator
DEP 30.75.10.10-Gen.
February 2012
Page 33
TYPICAL PRESSURE REDUCING AND DESUPERHEATING STATION
ARRANGEMENT
DEP 30.75.10.10-Gen.
February 2012
Page 34
APPENDIX C
SIZING CAHRT INDICATING TYPICAL DRIP LEG DIAMETER
Drip Leg Sizing
600
400
300
200
100
Steam Line DN
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
0
Drip Leg DN
500
DEP 30.75.10.10-Gen.
February 2012
Page 35
APPENDIX D
TYPICAL SINGLE LINE DIAGRAM FOR LIQUID FUEL FORWARDING PUMPS
DEP 30.75.10.10-Gen.
February 2012
Page 36
APPENDIX E
TYPICAL MP or LP STEAM TIE-IN TO PROCESS