Section 12 — Instruments and Controls

Control Systems

IPE Engineering Practice IPE-EP-12-1-1

Document number: IPE-EP-12-1-1 · Section: 12 — Instruments and Controls

SCOPE

• The purpose of this document is to define the general requirements for control systems and instrumentation.
• Any deviation from this Practice must be approved by the procedure described in EP 1–1–3.
• An asterisk (*) indicates that a decision by the Owner or the Owner’s Engineer is required or that additional information is furnished by the Purchaser.
• A revision bar indicates all changes made to this Revision.

2.0 REFERENCES

The following codes and standards shall be considered as part of this Practice. All documents shall be the latest editions in force on the date of issuance of this Practice.

STANDARDS AND PUBLICATIONS

STANDARDS AND PUBLICATIONS (CONT.)

DEFINITIONS

• Contractor - Company or business that agrees to furnish materials or perform specified services at a specified price and/or rate to the Owner.
• Inspector - A Inflection Point Engineering, LLC . appointed engineer or inspector.
• Manufacturer - The recipient of a direct or indirect purchase order for materials and/or equipment. In this context, a direct order is one issued to a manufacturer by a contractor or the Owner. An indirect order is one issued to a manufacturer by a vendor (recipient of a direct order) for materials, fabricated components, or subassemblies.
• Owner - Inflection Point Engineering, LLC .

• Owner’s Engineer - A Inflection Point Engineering, LLC . appointed engineer.
• Purchaser - The party placing a direct purchase order. The purchaser is the Owner’s designated representative.

CONTRACTOR REQUIREMENTS

• General
• Any specifications of a general nature may contain conflicts and omissions. The contractor shall not attempt to interpret IPE requirements in any Practice that is not clear, or appears to conflict with any other Practices, or omits something. The contractor shall request an interpretation or answer from IPE before proceeding. The routine sending of data sheets or drawings on which the details of such a problem are included among other instrument details will not be considered as meeting this requirement. The contractor shall confirm all verbal interpretations, answers or decisions in writing. The contractor will document all meetings.

The following system shall be used as a guideline for numbering of instruments and their

• associated data sheets:

• ISA Standard S5.1: Instrumentation Symbols and Identification shall be the standard. Where there is any conflict between ISA and the existing system, it shall be resolved by written agreement between IPE and the Engineering Contractor.
• A set of numbers shall be provided by IPE.
• This set of numbers shall be used in conjunction with the ISA standards and their use will eliminate confusion resulting from any two instruments having the same number.
• Unless otherwise specified by the Owner’s Engineer, all instruments shall be tagged with an alphanumeric code consisting of 10 characters from the standard ASCI character set.

EXAMPLE: XXX–YYYY

X = LETTER Y= DIGIT

• Parallel numbering shall be used. The first letter of three–letter code refers to the type of the loop: flow, level, pressure, etc. The succeeding letters refer to the function of the individual instrument. The first two digits of the code refer to the numerical designation of the particular area of the plant where the instrument will be used. The succeeding three digits are the sequence numbers. Both the sequence number and the area designation numbers shall be provided by IPE.
• All drawings, indexes, and nomenclature shall comply with the latest revision of ISA Specification S5.1. All P&ID, loop, logic and wiring drawings shall be done in an approved CAD system. Original source files with symbols libraries shall be provided on approved magnetic/optical media. All tag indexes and loops lists shall be provided in an approved relational database on approved magnetic media.
• IPE will provide an approved vendors list which shall be used exclusively. Shop inspection by IPE is required to qualify vendors.

• All “package equipment” is to have the same type and quality of instruments and documentation as the rest of the facility. Vendors shall comply with this practice. Frequent quality control inspections will be required by IPE. Functional acceptance test will be witnessed by IPE before “approval to ship” is granted.
• Process Flow and P&ID Drawings

All Process Flow (PFD) and Piping and Instrumentation (P&ID) drawings shall have been agreed upon by the contractor’s Control Systems representative(s) before being submitted to IPE for review.

• Detailed Design Requirements
• The contractor will furnish for the approval of IPE:
• Unless otherwise specified by the Owner’s Engineer, a I/O list/index shall be provided. The information and format of the index shall be approved by the Owner’s Engineer. Unless otherwise specified by the Owner’s Engineer, the index shall be provided in a dBase compatible database on approved media. The Data Base structure and format shall be approved by the Owner’s Engineer.
• Data sheets for all instrumentation and analyzers should use the IPE’s’ numbering system. The Engineering Contractor will be responsible for providing data sheets for each instrument furnished on “package equipment.” The Owner’s Engineer shall approve the form of the data sheet. Acceptable forms are the Data sheet from the RP, ISA S20 forms, or an approved equal. Electronic data bases may be provided in a approved database/software on an approved media.
• Individual loop diagrams showing all interconnecting wiring and tubing shall be provided. Controller and control valve action shall be included. Loop drawings shall be provided by the Engineering Contractor for all instrument loops appearing on P&ID or control and instruments diagrams. ISA standard S5, Instrument Loop Diagram, or approved substitutes shall be used. In the case of “interlocking instrument” or a “shutdown sequence,” ladder diagrams, logic sequences, block diagrams and a written description shall be provided. When such is the case, loop drawings may be omitted but only with the written approval of Owner’s Engineer. The size of drawing shall be 11 x 17 inches. For ease of handling in the field, reduced copies of 8–1/2 x 11 inches shall be provided.
• Instrument installation and winterization details shall be provided. Winterizing and freeze protection drawings shall include isometric drawing of traced line, protection device, energy source (steam or electrical), junction boxes, traps, power lights and all associated hardware as required. The Owner’s Engineer shall approve the format and content of the drawings.
• Location plan views showing instruments, junction boxes, local panels, and analyzer houses.
• Conduit and cable schedules and routing plan.
• Junction box and marshalling cabinet termination details.
• Pneumatic piping and tubing routing plan.
• Control panel lay–out and design.
• Local control panel lay–out and design.
• Control house design and floor plan, showing location of all consoles, racks, and associated equipment.
• Rack design with input and output arrangement.
• Symbolic logic diagrams which shall use “and–or” logic. Alarm and shutdown logic diagrams shall note trip points. All logic diagrams shall also have a narrative explanation.

• Details of all analyzer hardware.
• Details of analyzer and other local instrument buildings, showing size, utilities, doors, etc.
• A schematic drawing of analyzer sampling systems and a calculation of sample system lag time.
• Composite drawings of any special systems such as combustion controls and compressor controls.
• Bid specifications as required i.e. instruments, DCS systems, analyzers, computer, panels, combustion systems, package equipment, and other special systems.
• The contractor shall furnish for the review of the Owner’s Engineer:
• Orifice calculations, if not included in above data sheets.
• Copies of all purchase requisitions written for instrumentation.
• List of recorder chart numbers.
• Piping drawings showing all in–line mounted instruments unless a model is available for review before the piping drawings are made.
• Alarm and shutdown list showing trip points.
• All vessel drawings or models that show location of all nozzles, connections, ladders and platforms related to instrument locations and connections.
• Vendor drawings and recommended spare parts list.
• Any detailed design involving a “distributed control system” (DCS) shall conform also to EP 12–3–1.
• Any detailed design involving a “programmable controller” (PC) shall conform also to EP 12–5–1.
• The engineering contractor shall furnish manufacturer’s certified drawings, instruction manuals, and recommended spare parts lists for all instrumentation provided. The spare parts lists are needed in time to get delivery before startup. This item shall be included in the master schedule for distribution six months prior to mechanical completion.
• As–built drawings are generally required for the following: Instrument Index, Data Sheets, Orifice calculations, Loop Diagrams, Conduit and Cable schedules, Junction box termination details, Panel lay–outs, Alarm and Shutdown list, Symbolic logic diagrams with narrative, and all special systems i.e. analyzers, combustion controls, and compressor controls. Provisions will be made on an individual project basis.
• When specified by the Owner’s Engineer, all the above documentation shall be collected and issued in bound volumes separate from other manuals and issued three months prior to mechanical completion. Updates as a result of as–builts shall be issued. Unless otherwise specified by the Owner’s Engineer, all documentation/drawings written by the contractor shall be provided in approved electronic format on approved media.
• The contractor/vendor should notify the Control Representative of alternative measurement and control devices that could result in lower cost or improved reliability. When alternatives are proposed, the Owner’s Engineer shall approved all changes.
• Installation Requirements
• Installation shall conform to EP 12–2–1, EP 12–2–2, EP 5–6–5 and all applicable codes referenced in this document.

• When specified by the Owner’s Engineer, the contractor shall provide expected man–power loading levels by craft complete with supervision and construction schedule with bid.
• When specified by the Owner’s Engineer, the contractor shall furnish a field instrument supervisor, approved by IPE, who is experienced and capable in this line of work. This supervisor shall be on the job during all phases of construction and until the plant startup has reached the point where all the instrumentation is accepted by Owner’s Engineer. Supervision of instrument field work shall not be considered adequate if turned over to a supervisor of electrical, pipefitting, or other trade group.
• The contractor shall provide weekly progress reports and the next week’s planned schedule.
• The contractor is to be self–sufficient with respect to tools, calibration equipment including air supply, test equipment, equipment trailers, and office space. The Plant will only provide 120 VAC power.
• The contractor shall work out each design conflict as it arises with on–site IPE

representative before installation.

• Instrument inspection and testing shall conform to EP 12–2–2.
• All instrumentation shall be loop checked after installation and before commissioning. As specified by the Owner’s Engineer, loop check shall be done by the installation contractor, engineer, third party contract, or IPE. This check will consists of operating all the instruments in the loop, starting with the primary sensing device and going through the final control element. The calibration shall be checked by the contractor. IPE shall have the right to witness all loop-checking and to have any instruments aligned, calibrated, or corrected to give an accurate, operable control system. The method and documentation of loop checking shall be approved by the Owner’s Engineer. Loop checking shall conform to

EP 12–2–2.

• During loop check, a general or spot RFI test shall be made with a plant radio. any deflection greater than 1/2% of full scale when a radio is keyed at 3 feet from any instrument, wiring, etc. indicates that the loop is not RFI immune and shall be studied for possible solution.
• Orifice plates shall be installed after all line flushing. A separate list of all orifice plates shall be furnished showing installation date.
• Startup assistance may not be required from the contractor, however the Field Supervisor shall remain for liaison with the contractor until the instrumentation has been accepted by IPE.

• The contractor must take full responsibility in the storage and handling of instruments, control valves, racks, consoles, panelboards, etc. to ensure that they are in new condition when turned over to IPE. This includes responsibility for loss or shortages. This includes responsibility for loss or shortages. Inspection and storage shall conform to EP 12–2–1.
• Vendors and Fabricators Inspection

All systems as well as instrumentation on package equipment, shall be subject to inspection by IPE. A quality assurance plan shall be developed itemizing those systems or packages to be inspected in the shop. Frequent quality control inspections may be required by IPE.

The contractor/fabricator shall advise IPE two weeks before functional test and check– out.

• Model or 3D CAD Requirements
• All transmitters shall be shown, generally as meter boxes, in their appropriate location.
• Control valves shall be shown with appropriate actuators, handwheels, drains, blocks and/or bypasses.
• Pressure gauges, local output gauges, thermometers, thermocouples, analyzer taps, switches, etc., shall be shown as a white tag only with full tag number designation. When direct connected, the tag shall be located on a tap connection at its proper location on the line or vessel. When remote mounted, the tag shall be shown on structure members or pedestals.
• Level devices shall be piped with block valves shown. Displacers shall have a representative model. DP cells shall be shown as meter box.
• Instrument lines shall generally not be shown.
• Proper orientation and accessibility for all instruments and control valves shall be shown or indicated.
• Analyzer houses, major junction boxes, and local panels shall be shown.
• Flow meter runs shall be modelled with proper upstream and downstream run lengths.
• All instrument symbols shall be tagged with full tag characters.
• Major cable and tubing racks and conduit runs shall be modelled.

DESIGN AND MATERIALS

• General
• All instrument and construction materials shall be new and unused.
• Separate process connections shall be used for all instruments.
• Stainless steel shall be the standard material of construction for all pressure elements and wetted surfaces unless otherwise specified or approved by the Owner’s Engineer. All process connecting piping shall be 1/2 inch stainless steel tubing unless otherwise specified or approved by the Owner’s Engineer. Tubing and fittings shall meet the requirements of EP 5–2–3.
• All instruments shall be permanently tagged by the manufacturer or contractor with a screwed metal tag bearing the tag number and service. Thermocouple assemblies, pressure gauges, etc., shall be tagged also, however, their tag may be attached with stainless steel wire, 20 gauge minimum. Instruments installed in individual houses shall also have an engraved bakelite nameplate on the outside of the house showing both tag number.
• Instruments shall not be mounted on handrails or vibrating equipment or lines. This applies also to pressure gauges on pumps having high frequency vibration.
• Shutdown devices shall be completely separated from other sensing devices. All shutdown systems shall have a final checkout by mechanically actuating the primary sensing device. Shutdown and interlock logic may be provided by a programmable logic controller. If a programmable controller is used, refer to EP 12–5–1.
• Blind transmitters shall have a receiver gauge on their output. They should be visible from grade or permanent platforms and associated control valve, grade or permanent platform.

• Package equipment is to have the same type and quality of instruments as the rest of the facility. All engineering details pertaining to control systems on package equipment shall be made available for review by IPE before the design is finalized.
• All recorders shall be mounted on the main control panel or console. Local controllers shall be the indicating type, except displacement level controllers, and shall be limited to simple applications requiring infrequent set point changes such as seasonal changes. Self–contained regulators shall also be limited to simple applications and where operator attention is not required.
• All field instruments and control valves shall be within working reach of a man standing at grade or on a permanent platform. Preferred height is 4 feet 6 inches to the centerline of instruments.
• All gauge glasses and indicating dials shall be oriented to be readable by a man standing at grade or on a permanent platform.
• Individual filter regulators shall be furnished for the air supply to each pneumatic instrument except on panels.
• Tubing and conduit to control valves and instruments shall be routed in the field so as to avoid obstructing walkways or ladders and present damage from personnel traffic.
• Electronic systems are preferred to pneumatic. Generally, only local field loops will be pneumatic.
• Provision shall be made to paint all steel instrument supports and mounting brackets for corrosion protection. Aluminum supports and brackets or hot–dipped galvanized steel can be used as a substitute for painting.
• The use of pneumatic transmission over 250 feet shall be approved by the Owner’s Engineer.
• All instruments shall be RFI immune. Manufacturers shall test their equipment per SAMA Standard, PMC 33.1. All instruments shall be affected by no more than 1% of span when exposed to a field strength of 10 volts per meter (Class 2) with a frequency range of 50–500 MHz (band b and c).
• Unless otherwise specified by the Owner’s Engineer, steam condensate from heat exchangers shall be removed via an external pot with level controller and control valve.

• Temperature Instruments
• All thermometers, thermocouples, and temperature switches shall be installed in wells. Wells with an insertion length of 24 inches or less shall be of drilled bar stock. Wells over 24 inches shall require approval by the Owner’s Engineer. Wells shall be of 316 stainless steel unless otherwise approved by Owner’s Engineer . Tapered wells are required in vibrating service. Extension necks are not needed on flanged wells. Screwed wells on insulated lines and vessels shall have a minimum 2 1/2 extension neck. screwed wells shall have one (1) inch NPT connections to the process. Well depth shall be engraved or stamped on a tag attached to the head of the well.
• Bimetal dial thermometers of the adjustable angle type are acceptable for local indication. Fully compensated filled systems with remote dials shall be used where required for readability or protection from vibration.
• Iron–constantan (type J) thermocouples shall be used for services up to 1000 F. ChromelAlumel (type K) thermocouples shall be used for services 1000 F to 2500F. For temperatures in excess of 2500 F Platinum–Rhodium (type R) thermocouples shall be used. Furnace skintube thermocouples shall be sheathed and magnesium oxide filled. Other types of thermocouples shall be approved by the Owner’s Engineer.
• Temperature controllers shall have a dual thermocouple element in the same thermowell and wired to an acceptable readout device. Where design allows, distributed control system or computer logging shall be used for multi–point temperature indication.
• Thermocouple extension wire material shall match the thermocouple.
• All multiple point temperature indicator systems shall have provisions for a serial device interface.
• Multi–point temperature instruments shall have the tag number clearly and permanently identified.
• All temperature instruments shall include a provision for thermocouple burn–out indication. Temperature shall have up scale burn out.
• All temperature controllers shall be three mode unless otherwise specified and approved by the Owner’s Engineer.
• When specified by the Owner’s Engineer, resistance temperature elements or temperature transmitters may be used.
• Primary Elements and thermowells shall comply with EP 12–1–6.
• Pressure Instruments
• All process pressure connections shall be 3/4 inch minimum with at least a 3/4 inch block valve. Valve and connection shall comply with EP 5–2–3.
• Pressure elements measuring a steady normal operating pressure should not exceed 75% of their maximum range. Pressure elements measuring a fluctuating pressure should not normally be operated beyond 60% of their maximum range.
• For the measurement of slurries, viscous, or highly corrosive fluids for which a bourdon tube or bellows element is unsuitable, liquid filled diaphragm sealed element shall be used.

• Pressure gauges shall comply with EP 12–1–19.
• Unless otherwise specified by the Owners Engineer, pulsation dampeners shall be long taper plug needle valves. Cases filled with dampening liquid are also acceptable and shall have fill identified.
• There shall be a pressure gauge on the discharge of all pumps and it shall be visible from the discharge block valve.
• Steam eductor shall have a globe type throttling valve and a pressure gauge downstream of such valve on the steam inlet to the eductor.
• Local pressure controllers shall have weatherproof cases with adjustable reset and adjustable proportional band.
• A pressure gauge shall be installed with all self-contained regulators. Air sets on the pneumatic supply tubes to instruments shall have supply and output gauges.
• Flow Instruments
• Square–edged, concentric–type orifice plates with weldneck orifice flanges shall normally be specified. Associated minimum meter run lengths shall be sized according to API 550 or AGA 351 at a d/D ratio of 0.75. Meter runs shall normally be between 2 and 12 inches in diameter. Sizes larger than 12 inches shall be approved by the Owner’s Engineer.
• Orifice plates in horizontal meter runs on saturated steam and vapors near their dew point shall have drain holes. Where this is upstream of steam turbines, a drain valve shall be provided also just upstream of the plate.
• Unless otherwise specified by the Owner’s Engineer, differential pressure transmitters shall be used for all flow measurements.
• Orifice flange specification, tap sizes, and installation requirement shall comply with EP 5–2–3 and EP 5–6–5.
• Orifice plates shall not be in the line during pre-startup flushing or hydraulic testing.
• All blind flow transmitters shall have a local indicator on the transmitter output. The indicator shall be visible from grade/platform and the control valve associated with the transmitter.
• Orifice plates shall not be used in a line less then 2 inches in size without approval of the Owner’s Engineer. Smaller lines shall be increased to 2 inches for orifice metering. For lines under 2 inches in size, special purpose meter runs, or differential pressure transmitters with integral orifice may be used with approval of the Owner’s Engineer.
• Mechanically protected glass tube variable area meters may be considered for use on suitable non-hazardous flow service and temperatures up to 250F. Maximum rotameter size shall be 1 inch. For hazardous service, glass tube meters shall not be used, metal tube meters shall be provided.
• For steam and vapor applications, flow nozzles and venturies may be used with approval of the Owner’s Engineer. Where minimum pressure drop is required, pitot, proprietary insertion head meters, and thermal dispersion flow meters may be used with approval of the Owner’s Engineer.

• Unless otherwise specified by the Owner’s Engineer, the orifice meter differential range shall be 100 inches of water, dry calibration. If the differential is over 200 inches of water at 0.75 d/D, the line size shall be increased. For gas and vapor service, the differential pressure range in inches of water should not exceed the static absolute pressure in PSIA. The d/D (beta ratio) shall normally be between 0.20 and 0.70.
• Unless otherwise specified by the Owner’s Engineer units of flow measurement shall be:
• Steam - Lb/HR
• Water - GPM
• Hydrocarbon - IPE
• Gas flow - SCFH
• All flow measurements that are cascaded with level shall be linearized.
• Liquid product for custody transfer shall be measured by turbine or positive displacement flow meters. The meters shall be temperature compensated. Upstream filters and air eliminators shall be provided when necessary. Connections for a meter prover shall be provided.
• Unless otherwise specified by the Owner’s Engineer, custody transfer meters of liquids of 20 cST or less viscosity shall be turbine. For liquid above 20 cST, displacement meters shall be used.
• Design and construction of custody transfer metering systems shall comply with the API Manual of Petroleum Measurement Standards, Chapters 4 and 5. Meter provers shall comply with the IPE Petroleum Products Measurement Manual.
• Turbine meters shall comply with EP 12–1–14.
• Positive displacement flowmeters shall comply with EP 12–1–15.
• Electromagnetic flow meters may be used for measuring the flow of conductive liquids. Magnetic flowmeters shall comply with EP 12–1–13.
• Level Instruments
• Common vessel connections shall not be used for separate level instruments. Displacers, gage glasses, alarms, shutdowns, etc., shall all have separate vessel connections. Pipe size, connection, and material for bridles shall comply with EP 5–2–3.
• Unless otherwise specified by the Owner’s Engineer, transparent gage glasses with explosion proof wedge type illuminators shall be provided. Gage glasses shall meet the requirements of EP 12–1–18.
• Gage glasses shall be used in services only up to 75% of their manufacturer’s rating and not to exceed 1000 psig. Above 1000 psig, metal tube gages shall be used.
• Gage glasses shall be visible from the associated level instrument and the visible length shall cover or exceed the span of the level instrument.
• Level displacers shall comply with EP 12–1–16. Approval of the Owner’s Engineer is required for displacer ranges over 72 inches.
• All blind level transmitters shall have a local indicator on the transmitter output. The indicator shall be visible from grade and the level control valve associated with the transmitter.
• Level chambers and displacers shall have drain discharge piping required by EP 5–1–2.

• Unless otherwise specified by the Owner’s Engineer, only external level devices with valved connections shall be used.
• Where process considerations dictate, capacitance, radioactive, ultrasonic, and other type level instruments may be used with approval of the Owner’s Engineer
• Storage tank level gauges shall comply with EP 12–9–1.
• Level displacers shall comply with EP 12–1–16.
• Control Valves

Control Valves shall conform to EP 5–3–17.

• Safety Valves
• Design of pressure relieving systems shall comply with the requirements of EP 3–7–1.
• Safety valve requirements and data sheets shall comply with EP 5–3–14.
• Panel Instruments
• Panel instruments shall be approved by the Owner’s Engineer.
• The centerline of lowest control instrument shall be not less than 36 inches from the floor/grade and the highest not more than 63 inches from the floor/grade.
• When required the air header shall be brass.
• Pen color shall be as shown in Table 1.
• Annunciators shall be solid state.
• Each electronic instrument or power supply shall be protected by internal protective devices or external fuses/circuit breakers.
• Distributed Control Systems

Distributed Control Systems shall meet the requirements of EP 12–3–1.

• Programmable Controllers
• Programmable controllers shall be used in applications where they improve reliability, maintainablity, and efficiency by reducing cost and downtime.
• Programmable controller applications for shutdown and protective instrumentation shall comply with EP 12–10–1.
• Unless otherwise approved by the Owner’s Engineer, interface between a Programmable control and distributed control system shall be by a serial device interface.
• Programmable controllers shall meet the requirements of EP 12–5–1
• Process Stream Analyzers
• All process analyzers shall meet the requirements of IPE EP 12–7–1.
• Analyzer shelters shall meet the requirements of EP 12–7–2
• Alarms, Switches, and Interlocks
• Protective instrumentation shall meet the requirements of EP 12–10–1.

• Switches for alarms and interlock systems shall be used for on–off application only. Switches shall be approved for and installed to meet the electrical area classification.
• Flow switches for direct operation by process fluids shall be of paddle type or thermal dispersion type. Flow transmitters with external switch function may also be used.
• Level switches for direct operation by process fluids shall preferably be of the packless type (i.e. torsion rod, diaphragm or magnetic coupled). Unless otherwise specified by the Owner’s Engineer, internal trim shall be 316 stainless steel. Nuclear, capacitance, and ultrasonic devices may be used with approval of the Owner’s Engineer.
• Solenoid valves shall comply with EP 12–1–22.
• First out sequence shall be used for solid state annunciators. Alarm sequence shall be per Table 2.
• Power supply voltage shall be approved by the Owner’s Engineer.

SYSTEM INSTALLATION

• Panels
• Control Room Panels shall be built by an approved control panel fabricator. The panel shall be built, tested and delivered to the facility ready to operate. Field work shall consists of loop checking external wiring, installation of separately packaged instruments, and the connection of external utilities.
• The following information, drawings and literature shall be furnished to the panel fabricator:
• Ambient temperature and relative humidity ranges.
• NEC electrical area classification.
• Detailed panel cutout information.
• Panel clearances to surrounding equipment.
• Any required physical layout for the panel front and inside of the panel.
• Any required wiring details.
• Any required diagrams for pneumatic instrumentation and process connections.
• Dimensional details, connection diagrams and instruction manuals for all panel equipment supplied by the Owner.
• Any required ladder diagrams for relay logic systems.
• The panel and all equipment within it shall be suitable for the area classification.
• The panel fabricator shall purchase all materials not supplied by the Owner. All materials shall comply with IPE Engineering Practices. A bill of material shall be submitted to the Owner’s Engineer for approval prior to construction.
• Panels shall be self supporting, and have adequate stiffener bars to prevent distortion. Removable lifting eye-bolts shall be provided on the top of the panel capable of supporting the panel without distortion.
• The external panel color shall be approved by the Owner’s Engineer. One quart of paint shall be shipped with the panel.
• The panel shall have adequate mounting holes and provisions for anchoring to the foundation.

• All terminal strips shall have each terminal clearly identified. All wires shall be labeled on each end.
• Tubing shall be installed and connections made to instruments so that each instrument is accessible for removal, maintenance, adjustment, or repair without removal or distortion of tubing and or equipment.
• All instruments shall be installed so that they are easily accessible for maintenance and inspection.
• All panel instruments shall be permanently identified. All panel instruments locations shall be identified on the face of the panel with a plastic name plate. Name plate colors shall be approved by the Owner’s Engineer. The name plate shall show tag number and process description. This name plate shall not be mounted on the removable cover of the instrument. Each instrument in the back of the panel and terminal strips shall be identified with similar nameplates showing the tag numbers.
• The panel fabricator shall perform the following tests prior to final inspection:
• Wiring point to point continuity check.
• Process and pneumatic leak checks.
• Operational action checks of all switches to ensure they agree with drawings.
• Control panels shall include ”as built” documentation with the following information:
• Detailed structural and panel cut-out drawings.
• Front and rear panel arrangement drawing showing equipment locations.
• Wiring details for power, auxiliary circuits, and instrument wiring.
• Piping diagrams for pneumatic instrumentation, and process connections.
• Dimensional details, connection diagrams, and instruction manuals for all instrumentation.
• Ladder diagrams for any logic systems.
• Inter-connection wiring diagrams show all terminal connections between the panel and external instrumentation, equipment, and other panels.
• The panel may be shop inspected by the IPE during and after final completion. The panel fabricator shall notify IPE two weeks in advance of when the panel will be available for final inspection. The panel fabricator shall make available as required, power, analog signal sources, pneumatic signal sources, jumpers, meters, and measurement devices, and a technician to assist in the functional check out and inspection of the panel.
• All shelf mounted or delicate instruments shall be removed from the panel for shipment and packed separately.
• All control panels shall be shipped to the plant location with no intermediate off loading permitted.
• The following color coding shall be followed in the design of graphic panel sections.
• Process Equipment and Vessels—Dark Green
• Hydrocarbons (Liquid or Vapor)—Dark Green
• Hydrocarbon Lines on Equipment—Light Green
• Steam—Red
• Water—Blue
• Fuel Gas—Yellow
• Non–Hydrocarbon gases—Brown

• Acid and Misc. Chemicals—Purple
• Caustic—Lavender
• Temperature Points—Red Triangles (white lettering)
• Instrument Symbols—Black circles (white lettering)
• Electrical Signals—Dashed black line
• Pneumatic Signals—Silver Line
• Unless otherwise specified by the Owner’s Engineer, control panels shall not be used when a Distributed Control System is available.
• Local Control Panels
• 1 instrumentation shall comply with all other sections of this Practice.
• All doors shall be gasketed, have a 3–point latching system with a key locking handle, and have stainless steel hinges and hardware.
• Sheet metal pockets for holding drawing and documents shall be provided on the inside of the panel door.
• Field tubing terminations and electrical conduits on local panels shall enter the side of the panel. Low point drip legs and drains shall be added to all conduit just before entering the panel. Connection between the field and panel tubing shall be made by means of a brass bulkhead and tube fittings.
• Sheet metal shall be stainless steel. Panels in outdoor service shall meet NEMA 4x classification. Gasketed hinged covers with safety glass or acrylic front, and key lock latch shall be provided for all flush mounted instrumentation that would not meet NEMA 4x or that would permit air leakage through the front of the panel.
• Control Centers
• A centralized control concept is preferred.
• Instrument racks shall be located against the wall behind the control panels. The face of the panels shall be 8 feet from the wall. This allows approximately 4 feet of clear working space between the racks and panels. Panels on opposite sides of the room shall be at least 20 feet face–to–face. For arrangement of Distributed Control System in the control center, a separate rack room is preferred.
• The Owner’s Engineer shall approve the location and method of entry into the control center for field cables.
• The plant communication system (intercom and/or radio) shall be provided in the control center.
• Control Centers shall comply with EP 12–6–1.
• Electronic Transmission
• Instrument DC signal wire and thermocouple extension wire shall comply with EP 12–1–25.
• Insulation, suitable for high temperature, shall be used where ambient temperatures exceed 140 F.
• Main cable runs from the field to the control center should be installed underground in concrete or in overhead in conduit/tray. Conduit/tray installation shall comply with EP 13–2–1.

• Where overhead cable runs are used, the junction box centerline shall be located 4 feet 6 inches above grade or platform with top of box not to exceed 6 feet 6 inches. Entry into junction boxes shall be made on the bottom or side of the box. Conduits shall have a drip leg at the box.
• Separate cable, conduit, and junction boxes shall be used for the following applications: DC control wiring; DC alarm wiring; thermocouple wiring. On revamp projects using existing infrastructure, combining 4-20 ma. DC analog signal with 24 VDC digital signals in the same cable, conduit system, and junction box shall be permissible.
• All field instrument wiring between a field measuring element and its associated field transmitter element shall be installed in separate conduits from the signal conduit.
• Pull boxes shall be located between the control house and first field junction box. Barriers shall be installed in the pull box to isolate control, thermocouple, alarm cables.
• AC power wiring and instrument wiring shall be separated per EP 13–2–1.
• All instrument cables shall be meggered both before and after pulling for shorts and/or grounds with results recorded. Megger voltage shall be 250V DC. Instruments shall not be connected until after meggering. Records shall show details of faults only.
• Tubular clamp type sectional terminal blocks shall be used throughout. The terminals shall be mounted on a raised base. Junction boxes shall be sized to allow 6 inch spacing of terminal strips and a minimum of 6 inches clearance between walls and terminal strips and a 6 inch box depth. Junction box location shall be approved by the Owner’s Engineer. All junction points shall be permanently identified with loop number. Splices are not allowed. The boxes shall be numbered and tagged with engraved bakelite nameplates. All field junction boxes shall be stainless steel NEMA Type 4X. All junction boxes installed indoors in general purpose areas shall be NEMA Type12.
• All wiring between junction boxes shall include 20% spares. Spares shall be labelled and terminated at terminal blocks.
• Wire pulling lubricants shall be per EP 13–2–1.
• Conduit materials and installation shall comply with EP 13–2–1.
• Thermocouple, control, and other instrument transmission wires shall not be terminated both incoming and outgoing to the same side of terminals in junction boxes.
• Flexible conduit shall be used between the thermocouple head and the rigid conduit. Flexible conduit shall be used to connect rigid conduit to all instruments. Flexible conduit material and installation shall comply with EP 13–2–1.
• Signal wires at all instruments shall be identified according to positive or negative lead. Where black and white pairs are used, black is positive ()) and white is negative (*). In addition, all wires shall be labelled as to loop number and wire, using permanent heat–shrink type labels or acceptable sleeve–type labels.

• Two independent sources of power shall supply the instruments. The 120 volt AC circuits to the instrument panels shall be supplied from a separate distribution panel shall serve only instruments and alarm circuits. This distribution panel shall have 15 amp protection devices. Approximately 20% spare circuits shall be provided. Each DCS rack and CRT shall have a separate branch circuit. Each panel section or multiloop DC power supply shall have a separate circuit.
• AC power supply and grounding systems shall comply with EP 13–2–1.
• Power/Noise Conditioners
• Power/noise conditioners shall be provided for all field (where powered from the instrument rack), control, and interlock instruments, all control room instruments, and all rack and computing instruments. Power/noise conditioners may be omitted where their function is performed by an acceptable Uninterruptible Power System (UPS).
• Power/noise conditioners shall comply with EP 13–18–1.
• Uninterruptible Power Systems (UPS)
• Uninterruptible Power Systems shall comply with EP 13–17–1.
• Uninterruptible Power (UPS) shall be provided for all safety and shutdown interlocks, analog, and microprocessor–based distributed instrumentation.
• The UPS shall be designed to provide continuous power without interruption or under–voltage or over–voltage for a time period of no less than 30 minutes.
• Specifications, location and ventilation requirements for UPS batteries shall comply with EP 13–1–1.
• Air Transmission
• Plastic coated copper tubing shall be used for pneumatic transmission. Minimum size is 1/4 inch OD. Stainless steel may be used with approval of Owner’s Engineer in areas where severe copper corrosion exists.
• Tubing runs consisting of four or more tubes shall be made by using bundled tubing.
• The tubing bundle shall consist of polyethylene plastic covering extruded over the bundle of copper tubing positioned adjacent and parallel.
• Tube, tube fittings, and installation shall comply with EP 5–6–5.
• The minimum number of spare tubes per tubing bundle shall be as shown in Table 3.
• All tubing bundles shall be supported in channels or trays. Individual tubes or groups of individual tubes shall be supported in conduit or angle iron. Wiring or attaching to a pipe shall not be done. Angle iron shall not be attached to a control valve or instrument by the valve/instrument bolts.
• All tubing installations shall be leak–tested by using a bubbler systems and 30 psi instrument air. A leakage rate of more than 2 bubbles per minute is not acceptable and shall be corrected.
• Tube fittings shall be installed in strict accordance with the manufacturer’s instructions. When specified by the Owner’s Engineer, connections shall be checked for proper make up with “go/no–go” gauge, or visual inspection by breaking/making the fitting.

• Tubing shall be tested per EP 5–5–3.
• All tubing bends shall be made with benders.
• All air headers and subheaders shall comply with EP 5–2–3 and EP 5–6–5
• Teflon tape shall not be used on pipe threads in instrument air or pneumatic signal service.
• Any underground tubing for instrument service shall be in steel conduit and protected with a minimum of three inches of red dyed concrete.
• Weather Protection
• All instruments receiving weather protection shall be noted on the P&lD.
• Unless otherwise specified by the Owner’s Engineer, all differential pressure and pressure transmitters, direct–connected recorders and/or controllers located outdoors shall be installed in an enclosure. Enclosures shall comply with EP 12–1–3.
• Heating shall be provided per EP 5–6–5.
• Filled thermal temperature systems shall be specified with fill that does not need winterizing.
• Electronic instruments which may be damaged by low temperature shall be installed in heated enclosures. Precautions shall be taken to prevent excessive heating of electronic components.
• Sample systems for analyzers which require a liquid stream shall be treated in the same manner as the pipe line from which the sample is obtained. Precautions shall be taken to prevent overheating or vaporizing of the sample.
• When specified by the Owner’s Engineer, gas samples to analyzers which may contain condensables shall be provided with heat to prevent condensation.
• Weather protection shall be installed so as to facilitate maintenance and removal of instrument.
• Steam heat tracing shall comply with EP 5–6–8.
• Electrical tracing shall comply with EP 13–1–1.
• Hydrotest Procedures

The criteria shown in Table 4 shall be followed during hydrotesting, for protection of instruments.

7.0 TABLES

TABLE 1 RECORDER PEN COLORS

TABLE 2 ALARM SEQUENCES

TABLE 3

SPARE TUBES REQUIREMENTS

TABLE 4

PROCEDURES FOR PROTECTING INSTRUMENTS DURING HYDROTESTING

NOTES:

(1) Caution—do not force reverse flow.

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