100

1.7 Instrument Installation

I. H. GIBSON

(2003)

COST

On the order of 40 to 50% of the capital cost of theequipmentextremely 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 systemfrom the process fluid charac-teristics, the ambient conditions, legal and regulatory require-ments, and operations/maintenance requirementsmust 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

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1.7Instrum

ent Installation

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FIG. 1.7a

Typical instrument index report (extracted from Intools database).

No. By Date Chk App

1

Dwg. Name:

Sheet of 3

Domain:FDMELB

DEFAULT STYLE ReportTest 1 Test 2 Test 3 Test 4

Filter: NoneSort: None

Plant name:Area name:Unit name: Crude unit 1

Crude AreaNew Refinery

Horizontal Section 1 of 1Last Revision:

Revision Client

Tag Number Instrument Type I/O Type Status Service Location Equipment Manufacturer Model Price101-FE -100 D/P TYPE FLOW ELEMENT N Feed from V-8 Field FISHER-PORTER $110101-FT -100 D/P TYPE FLOW TRANSMITTER AI N Feed from V-8 Field ROSEMOUNT 1151DP4E22S2B1M2 $1095101-FY -100 I/P TRANSDUCER AO N Feed from V-8 Field FISHER 461 $580101-FV -100 CONTROL VALVE N Feed from V-8 Field FISHER ES $3250101-PI -100 PRESSURE GAUGE N Heat exchanger inlet Field ASHCROFT MGS-136 $65101-PI -102 PRESSURE GAUGE N Heat exchanger outlet Field ASHCROFT MGS-136 $65101-HY -101 I/P TRANSDUCER AO N C-101 Bypass Field C-101 FISHER 461 $580101-HV -101 CONTROL VALVE N C-101 Bypass Field FISHER ET $2100101-FE -102 D/P TYPE FLOW ELEMENT N Feed from C-1 Field $120101-FT -102 D/P TYPE FLOW TRANSMITTER AI N Feed from C-1 Field ROSEMOUNT 1151DP4E22S2B1M2 $1095101-PI -101 PRESSURE GAUGE N F-102 Stripper inlet Field ASHCROFT MGS-136 $65101-TW -203 THERMOWELL N F-102 Overhead Field

101-TI -203 BI-METAL THERMOMETER N F-102 Overhead Field ASHCROFT EVERY-ANGLE-13/02 $45101-PSH -208 HIGH-PRESSURE SWITCH N F-102 Overhead Field ASCO 8351B23 $720101-PT -201 PRESSURE TRANSMITTER AI N F-102 TOP Field F-102 ROSEMOUNT 3051S1256 $1095101-LT -201 DISPLACER TYPE LEVEL AI N F-102 Middle section Field F-102 MASONEILAN 9600 $1095101-LY -201 I/P TRANSDUCER AO N F-102 Middle section Field FISHER 461 $580101-LV -201 CONTROL VALVE N F-102 Middle section Field FISHER ED $1340101-TW -202 THERMOWELL N F-102 Top Field F-102 $45101-TE -202 THERMOCOUPLE N F-102 Top Field F-102 ASHFORD TE-11-34/13 $22101-TT -202 TEMPERATURE TRANSMITTER AI N F-102 Top Field F-102 ROSEMOUNT 3051S1256 $650101-TY -202 I/P TRANSDUCER AO N F-102 Top Field FISHER 461 $580101-TV -202 CONTROL VALVE N F-102 Top Field FISHER V500 $2300101-TW -201 THERMOWELL N F-102 Top Field F-102 $51101-TI -201 BI-METAL THERMOMETER N F-102 Top Field F-102 ASHCROFT EVERY-ANGLE-13/02 $45101-FT -201 D/P TYPE FLOW TRANSMITTER AI N Stripping Steam to F-102 Field ROSEMOUNT 1151DP4E22S2B1M2 $1095

DI

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General Considerations

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 companys 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.)

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This can be significant both internally and externallytropicalmarine 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

TABLE 1.7d

Instrument Tubing Properties

198

C