1.7 Instrument Installation - Kishore Karuppaswamy · The primary installation document is commonly called the instrument index (see Figure 1.7a). This tabulates all the tagged physical
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100
1.7 Instrument Installation
I. H. GIBSON
(2003)
COST
• On the order of 40 to 50% of the capital cost of theequipment—extremely variable.
• A full set of PIP Process Control Practices documentscost U.S. $6500 in 2002.
For process measurements to achieve the targets of safety, accu-racy, reliability, and economy, more than measuring equipmentis involved. The entire system—from the process fluid charac-teristics, the ambient conditions, legal and regulatory require-ments, and operations/maintenance requirements—must becoordinated to ensure that the equipment can be installed, cal-ibrated, operated, recalibrated, maintained, and, if necessary,rebuilt or replaced while meeting the above primary criteria.
This section attempts to provide guidance to persons whoare unfamiliar with current industrial practice; it does notattempt to cover all industries and all measurements. Specif-ically, it cannot cover the multitude of legal and regulatoryrequirements mandated by bodies such as the OccupationalSafety and Health Administration (OSHA).
INSTALLATION DOCUMENTATION
The primary installation document is commonly called the
instrument index
(see Figure 1.7a). This tabulates all thetagged physical devices and commonly also includes taggedsoftware devices. Each of the physical devices is then refer-enced to the associated installation drawings, such as thephysical location plans, installation details (mechanical sup-port, piping and wiring), cable ladder and conduit routingdiagrams, and the connection diagrams. The instrument indexis usually one of many documents from a large database,which also keeps track of calculations, specifications, andprocurement documents and may also interface with a three-dimensional CAD model of the plant.
In a plant being designed with three-dimensional model-ing, many of the dimensional drawings that otherwise wouldhave been made previously are generated on demand by selec-tion from the model. This enhances the quality of the designby flagging and eliminating clashes between equipment, pipingand electrical/instrumentation space requirements and permitsvirtual walk-through reviews for operations and maintenancepersonnel.
Physical vs. Schematic Documents
The physical or scalar documents are the location plans (oftensectional plans), cable/conduit routing plans, and the room lay-out drawings. These are based on the mechanical or pipinglayouts, commonly with the instrument information availableas an overlay. The instrument tapping locations will be definedon the vessels and piping, and the final location for the variousinstruments becomes a matter for negotiation between the var-ious groups to balance the requirements for operability withaccessibility for maintenance. Traditionally, the instrumentinstallation details have been essentially schematic, being usedlargely for material take-off. But with the growing use of three-dimensional CAD techniques, there is a tendency to produceapproximately scale models for the common details to ensurethat access requirements are addressed. Connection diagrams(electronic, electrical, pneumatic, hydraulic, and process) arepurely schematic. These are now largely automated, with aminimal amount of input data being fed to a database loadedwith connection rules for the various types of equipment.
SAFETY IN DESIGN
The instrument connections to the process are commonly theleast mechanically secure components in the system. Considerthe relative strength of a 1/2NS (DN15) Sch. 160 pipe as usedby the piping designer to the usual 0.5-inch (12.7-mm) ODseamless 316L tube with 0.049-inch (1.24-mm) wall used forequivalent duty by the instrument designer. Yet this material hasin fact an adequate strength for most applications within therange of Class 600 piping, provided that it is adequately pro-tected and supported. Supported not only when the equipmentis in service, but when any components are removed for main-tenance. Many installations can be found with long runs of tuberun to an absent transmitter, with the tube supported at best bya rope or wire. Not only are long tubing runs a significant sourceof measurement error, the lack of support is inherently hazard-ous. Modern installation details will anchor the tubing runs bysupporting the instrument manifold, which remains in place ifthe transmitter is removed, and minimize any hazard from thetemptation to use tubing runs as a hand (or foot) support.
The first valve off the process (known as the “root valve”)has traditionally been the province of the piping designer.More recently, the selection of this valve has become a joint
responsibility, with ‘process-rated’ instrument valves beingavailable which give ‘double-block and bleed’ (DBB) capa-bility in the envelope of a 1NS (DN40) blind flange (Figures1.7b and c). The ability to close couple a transmitter to theline in this manner can reduce potential leak points andweight significantly for offshore installations at similar costto older designs.
The point of DBB deserves comment. For a technician towork on a transmitter or gauge, the process must be securelyisolated. If the process fluid is flammable or at high or low
temperature any chance of a leak should be obviated. DBBprovides this by providing two isolation valves between thetechnician and the process, with the space between vented toa safe place. The definition of where DBB is required isnormally part of the operating company’s standards, but Class600 (and higher) piping should always be covered by it. Toxicmaterials call for more stringent techniques, with tubed ventsand designed-in decontamination methods.
Pipe and Tube Material
Current minimum design practice is to use a stainless steelmeeting both 316 and 316L for tubing and fittings for bothpneumatic and process connections. The pneumatic tubingmay be 0.25 inch (6.35 mm) or 0.375 inch (9.53 mm) OD,while process connections are usually 0.375 or 0.5 inch (9.53or 12.7 mm). The wall thickness of pneumatic tube is com-monly 0.035 inch, while process tubing is a minimum of0.048 inch, with heavier (0.064 inch) used for pressuresabove about 1000 psi (6800 kPa). This is the heaviest walltube that can conveniently be bent and fitted off without usinghydraulic benders and setters.
Plants using metric standards may use either metric orinch series tube but mixing the two in the same plant shouldbe avoided, as accidents can be caused by mismatching.12 mm OD tube will fit in a half-inch compression fitting butwill rapidly disassemble itself under test. Always use seam-less drawn tube for compression fitting installations, as elec-tric-resistance-welded (ERW) tube has a small flat on theoutside that makes for difficulty in achieving a leaktightconnection.
316 stainless is a good general-purpose material, but it isprone to chloride attack at temperatures above 140
°
F (60
°
C).
FIG. 1.7b
Current generation instrument isolation and process DBB valves. (Courtesy of Oliver Valve Ltd.)
FIG. 1.7c
Fiscal orifice metering installation using direct-mounting technique.(Courtesy of Tyco/Anderson Greenwood.)
This can be significant both internally and externally—tropicalmarine installations can easily achieve such temperature insunlight. Monel
(cupronickel) and duplex stainless are bothwidely used in such locations; duplex offers higher tensilestrength and pressure rating. Ensure that the tube wall thicknesschosen meets the most stringent pressure and temperature com-bination likely to be found.
If possible, avoid using or having tube with identical diam-eter but different wall thicknesses and materials in the sameplant, even at the expense of using more costly material,because the probability of getting under-rated material installedduring maintenance or modification is severely increased. If itis necessary, ensure that the installations with higher-gradematerial are permanently flagged on drawings and in the field(Table 1.7d).
Electrical Installations in Potentially Explosive Locations
While the practices for piping/tubing installations are similararound the world, there is a split between North Americanand European practices (commonly described as NEC v. IECpractices) in wiring methods. Fortunately this divide is now
closing, as IEC design practices are becoming accepted inparallel with NEC in North America, though there are still afew standards where features mandated by IEC are prohibitedby NEC. The best advice is to determine the statutory andregulatory rules for the site, and try to avoid any violation ofthem. ‘Try’ may be the operative word in many cases, whereconsiderable negotiating might be required with the regula-tory inspectors if ‘state-of-the-art’ equipment is required, andthe approval certification is not quite ready for your site.
Physical Support
The traditional support for field instruments is 2NS (DN50)pipe. Most non-inline field instruments are provided withmounting brackets designed to attach to vertical or horizontalpipe, and also to flat plate. Traditionally, these supports havebeen fabricated from carbon steel pipe and plate and beenhot-dip galvanized after fabrication. Some design detailsendeavour to weld zinc plated material, but this practice isdifficult in achieving good welds and the ‘zinc fume’ fromthe welding is toxic. Therefore, one should generally avoidthe use of zinc coatings. Also, there have been a number of
Notes:Max. working pressure based on the ASME B31.3 formula P
=
2tSE/(D
−
2tY), allowing a factor of 4 safety factort taken as 0.85 of the nominal wall thickness, according to ASTM A-269 manufacturing tolerance.316/316L is a dual-graded cold-drawn seamless tube to ASTM A269/A213, max hardness Rb80.
Ultimate tensile strengthTemperature Correction at othertemperatures at nominal temperature(above)
significant failures of stainless and high alloy piping whenminor fires melted the zinc from galvanized walkways, etc.If molten zinc comes in contact with an austenitic alloy, itpenetrates its grain structure within seconds and the strengthof the alloy vanishes. To protect from this effect and to avoidcorrosion, a number of sites are now using stainless steel“strut” supports.
PROCESS INDUSTRIES PRACTICES
A consortium of the major petroleum, chemical, and relatedmanufacturers, together with major engineer-constructors havejoined to form the Process Industry Practices (PIP) division ofthe Construction Industry Institute, an organization associ-ated with The University of Texas at Austin. The PIP officesare located to 3925 West Braker Lane (R4500), Austin, TX78759.
PIP (website
http://www.pip.org
) has generated a wide-ranging series of standard practices in a variety of engineer-ing fields. Among the 20 Practices for Process Control aresome 9 sets covering instrument installation. These are avail-able to members of the consortium and subscribers for theirdirect use, and can be purchased by other organizationsFigures 1.7e, f, and g).
In an effort to minimize the cost of process industry facil-ities, these Practices have been prepared from the technicalrequirements in the existing standards of major industrialusers, contractors, or standards organisations. By harmonis-ing these technical requirements into a single set of Practices,administrative, application, and engineering costs to both thepurchaser and the manufacturer should be reduced. Whilethese Practices are expected to incorporate the majority ofrequirements of most users, individual applications mayinvolve requirements that will be appended to and take pre-cedence over individual Practices. Determinations concern-ing fitness for purpose and particular matters or applicationof the Practice to particular project or engineering situationsshould not be made solely on information contained in thesematerials.
The tabulation of PIP installation documents (Table 1.7h)is not exhaustive, and they are frequently edited and extended.
Bibliography
Process Industry Practices (see Table 1.7h) issued by Process Industry Prac-tices, 3925 West Braker Lane (R4500), Austin, TX 78759, USA.
FIG. 1.7e
Typical PIP transmitter installation detail.
Notes:1. All instrument piping and piping components to be per instrument material specification PIP PCSIP001 unless otherwise noted.2. Mounting support, brackets, and electrical considerations to be as indicated in the instrument index.3. Horizontal tube run slope to be 1" per foot (minimum) down toward the transmitter.4. All penetrations to be per enclosure manufacturer.5. Pipe tees should be at the same elevation (+/− 1/8").
ITEM QTY UM DESCRIPTION 1 1 EA 3-Valve Manifold 2 4 EA Male conn 1/2"T × 1/2"P 3 A/R FT Steam traced tube bundle w/two 1/2" O.D. tubes
and one 1/4" O.D. copper tracer 4 1 EA See enclosure detail 5 2 EA End seal kit 6 2 EA Male conn 1/4"T × 3/8"P 7 1 EA Steam heater coil w/brackets 8 2 EA 1/2" Pipe tee 3000# thrd 9 2 EA 1/2" Hex head pipe plug thrd 10 2 EA 1/2" Pipe nipple - sch 80 minimum
Notes:1. Tap orientation is shown for orifice flange taps. Orientation may be used with other taps (e.g., pipe taps, radius taps) and venturimeters, flow nozzles, etc.2. Slope down (minimum 1 inch per foot) from process taps to equalizing manifold.3. Refer to installation details in PIP PCIDPOOO for materials.4. If required, locate optional tee pressure transmitter connection in high pressure side of flow measurement in close proximity to equalizing manifold.5. Refer to piping connection details in PIP PNF0200.
Process Industry PracticesInstallation Details
Head meter with remote transmitterbelow for liquid and steam servicehorizontal run - horizontal side taps
Tap orientationEnd view(Note 1)
Flow
By piping
By instr.H
L
To transmitter
(Notes 2, 3, & 4)
Notes:1. All instrument piping and tubing components to be as specified in the instrument index per material specifications from PIP PCSIP001, instrument piping and tubing specifications, unless otherwise noted.2. Routing, installation and support to be per PIP PCCIP001, instrument piping and tubing systems criteria.
ITEM QTY UM DESCRIPTION 1 FT 1/4" O.D. Tubing. See note 1 2 4 EA 1/4"T × 1/4"P Male tube connector. See note 1