INSTRUMENTATION AND CONTROL MANUAL

Volume 1: Part 1: Engineering Guidelines and Appendices

CHEVRON RESEARCH AND TECHNOLOGY COMPANYRICHMOND, CA

July 1999

Manual sponsor: For information or help regarding this manual, contact M.S. (Mike) Shigemura, (510) 242-4551

Chevron Corporation July 1999

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Instrumentation and Control Manual

First Edition June 1989First Revision May 1992Second Revision June 1993Third Revision July 1996Second Edition July 1999

The information in this Manual has been jointly developed by Chevron Corporation and its Operating Companies. The Manual has been written to assist Chevron personnel in their work; as such, it may be interpreted and used as seen fit by operating management.

Copyright 1989, 1992, 1993, 1996, 1999 CHEVRON CORPORATION. All rights reserved. This docu-ment contains proprietary information for use by Chevron Corporation, its subsidiaries, and affiliates. All other uses require written permission.

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Chevron Corporation July 1999

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Instrumentation and Control Manual

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100 System Design

AbstractThis section discusses the major phases of the design of instrumentation and control systems. It references other sections of the manual for detailed information on each aspect of the design process. It presents the overall picture of how the many components of an instrumentation design develop, from job scope to turnover to Operations.

Contents Page

110 Introduction 100-2120 Preliminary Design Considerations 100-2121 Getting Off on the Right Foot

122 Designing the Better Control System

123 Choosing a Control System

124 Evaluating Viable Alternatives

125 Life Cycle Costs130 Instrumentation Design Engineering 100-7131 Detailed Design Development

132 Design Specifications

133 Specification of Instrumentation

134 Documentation

135 Instrumentation Database140 Construction and Startup 100-10141 Documenting Field Changes

142 Commissioning

143 System Startup

144 Closing DocumentationChevron Corporation 100-1 July 1999

100 System Design Instrumentation and Control Manual110 IntroductionThe Instrumentation and Control Manual is intended to help engineers and designers design, construct, start up, and maintain typical Company instrumentation systems. It is intended to be used as a guide, with the understanding that no guide can replace sound engineering judgement.This section introduces the many aspects and procedures involved in designing an instrumentation system. Whether designing a small field job or a large facility, the elements of system design are similar.

Protecting People and the Environment is a cornerstone of how Chevron does busi-ness, and must become an integral part of the design of any Chevron facility.

With this commitment firmly in mind, a structured approach to defining, designing, and implementing a control system must be used to ensure success.

120 Preliminary Design Considerations

121 Getting Off on the Right FootFor the Control Systems Engineer, this first step is defining the objectives of the system he/she intends to install. This is a function embedded in the Chevron Project Development and Execution Process (CPDEP), and the analyses described below form an integral part of Chevrons Policy 530.

The Control Objectives Analysis (COA) is a facilitating process for defining what a control system does. The process consists of plant operators, process engineers, and control engineers reviewing plant process flow diagrams and defining the objective of each regulating device (control valve, damper, variable speed drive, etc.) on the drawing. The format of the objective is a single-sentence statement, defining what the regulating device always does to a process variable. (Example: CV-1002 main-tains overhead pressure between limits.)In the case of a new process on which plant engineers and operators do not have hands-on experience, the Control Objectives Analysis should be done with the assis-tance of engineers and operators from other facilities presently operating the process. Finally, experience operating similar processes should serve as a basis for the COA.

Similar facilitating processes define the objectives of safety shutdown systems (Shutdown Objectives Analysis, or SOA) and alarm systems (Alarm Objectives Analysis, or AOA).Only after these objectives have been defined and agreed to by Operations and Engineering, can the design of the control, safety, and alarm systems begin.July 1999 100-2 Chevron Corporation

Instrumentation and Control Manual 100 System Design122 Designing the Better Control SystemWith Objectives firmly in hand, the Control Systems Engineer needs to define the HOW of the control system.

Items which are defined in the Control Design Analysis process include:

System Geography - is control hardware in the field, in remote instrument enclosures or in a rack room in the control center? Will there be multiple sites where the operator can access the control system? Will multiple sites be peer or hierarchical?

System Architecture - what will be the defined and potential data transfer links to other control systems? To control and/or monitoring computers? To a Management Information system?

Control Architecture - how much of the control will be done by the systems front end? Will there be advanced control such as DMC? Will there be a sepa-rate computer for advanced control?

Environmental - what is the Area Classification for the plant and for field sites where controls will be located? For the area where operator interfaces will be located? What are the measurable airborne contaminants for these locations?

Operator Interface - does the operator see the process via a CRT, an array of controller faceplates, or field indicating controllers? Or via a combination of two or three of these methods?

Operability - can the process be manually controlled in the field using a manual bypass around the regulating valve? Will there be field operators to perform this function when required?

Reliability - what is the minimum acceptable operating factor for the control system? What is the economic incentive for increasing reliability by a defined percentage?

Failure Modes - what will be the status of the control system if individual instruments fail? Do all failures result in the control system going to (or tending to) the defined Fail-Safe condition of control valves and drives?

Expandability - if the control system intended for a mature, well-defined process with little potential for expansion, or is this a pioneering process or first step in a multiphase project?

Cutover Plans - for reinstrumentation projects, the plan for cutting over from existing to new instrumentation should be a part of the control design process.

Hot cutovers are typically more labor intensive than conversion en masse during a planned shutdown; however, most plants opt for the hot cutover, since it allows a more gradual conversion, and results in one less unknown during a plant startup.

Urban Renewal - the amount of re-engineering of existing facilities (reverifi-cation of the suitability of reused field instrumentation such as orifice plates Chevron Corporation 100-3 July 1999

100 System Design Instrumentation and Control Manualand control valves) needs to be determined at the initial design phase. This process is labor intensive if done properly - process conditions need to be field verified.

123 Choosing a Control SystemDigital technology now dominates the control hardware market. Electronic analog controls have all but vanished from the scene, and pneumatic controls are viable only in specialized applications where reliable electric power is not available, or where the Area Classification prevents installation of electronic controls without using elaborate cabinet or control room purging.

Note current environmental regulations in California virtually prohibit the exist-ence of Class 1 Division I areas.

Control & Operator InterfaceDigital electronic control should be considered as the default selection for all control systems installed in strategic facilities. With the exception of projects adding to existing control systems, solid justification must be given for deviating to elec-tronic analog or pneumatic controls.

Digital electronic control is available on a broad spectrum of platforms, from Single Loop Digital Controllers (SLDCs) through Programmable Logic Controllers (PLC) to multi-plant Distributed Control Systems (DCS).Note most SLDCs currently offered are in fact multi-loop digital controllers, with the capacity to control up to four valves from a 3-inch x 6-inch panel mounted face-plate.

Operator interfaces range from panel mounted faceplates (which emulate traditional panel-mounted controllers) to color CRTs using interactive graphics for display and control of operating parameters. The industry trend is toward the use of generic color CRTs running system-specific display and control software.

TransmittersSmart process variable transmitters should also be considered as the default stan-dard. These instruments offer higher accuracy and reliability than their electronic or pneumatic analog counterparts, and add the bonus of remote diagnostic data acquisi-tion and calibration checking.

Control ValvesSmart control valves are an emerging technology which offers extensive valve and process diagnostics, using the valve positioner - actuator as a sensor, or using pres-sure and temperature sensors embedded in the control valve body, or a combination of both. This technology should be considered on installations where maintenance access to control valves and drives is restricted.July 1999 100-4 Chevron Corporation

Instrumentation and Control Manual 100 System DesignField CommunicationsCommunications between Smart field instrumentation (transmitters and/or valves) and the control room are typically done over the same twisted pair of wires carrying the transmitter output or valve positioner input signal. Communications protocols range from vendor proprietary systems such as Honeywell DE- 6 Byte to multi-vendor open systems such as HART.

The Fieldbus communications protocol, which is being developed by an interna-tional consortium of instrument manufacturers, will offer the ability to link field instrumentation (transmitters, controllers, field indicators, valve positioners, and auxiliaries) on a multidrop power - communications wire pair. Control functions (algorithm execution) will be downloaded to the lowest possible tier of the system architecture, freeing up higher level computation capacity for running advanced control strategies.

Intrinsic SafetyIntrinsically Safe (I. S.) construction is intended to prevent sources of ignition (elec-tric sparks) in Hazardous Areas by limiting the transmission of power from non-Hazardous areas and by limiting the storage of energy in field devices.

Use of I.S. construction permits opening field enclosures (including transmitter and valve positioner housings) without first powering down circuits or sniffing the area to verify the absence of flammable mixtures.

There is no necessary correlation between I. S. construction and Hazardous Area Classification ratings nor between I. S. construction and Explosion-proof housing construction.

Because Intrinsically Safe construction severely limits the voltage and current which can be transmitted into Hazardous Areas, special attention must be given to limiting the number and type of field devices which cause voltage drops, and to the quality of field terminations. (Corrosion on field terminals can cause indeterminate voltage drops on current loops.)Final determination of whether this level of protection is appropriate for an installa-tion should be made only after an extensive review of local Electrical and Safety Codes.

The use of Smart field instrumentation, which permits communications from a non-Hazardous area, has diminished the use of Intrinsically Safe instrumentation systems in domestic petrochemical installations.

124 Evaluating Viable AlternativesOnce the scope and function of the control system is defined, the control systems engineer can focus on selecting hardware.

In all likelihood, more than one commercially available system will meet the requirements of the project. Consider the following factors in evaluating viable, competing systems:Chevron Corporation 100-5 July 1999

100 System Design Instrumentation and Control Manual System Integration - determine how well a system integrates:

horizontal integration, or the breadth of control hardware (regulatory and discrete control algorithms; continuous, batch, or state control operation) from a single manufacturer.

vertical integration, or the depth of control hardware (transmitters and valve positioners, controllers, network interfaces, operator consoles, advanced control computers, MIS links) and software to tie the pieces together.

Avoid the entanglements of multiple sources of interface software.

Uniformity - avoid putting one of everything in a control center. A strategic objective should be to have a single type of operator interface for all controls in a center; an absolute requirement should be a single operator interface for each group of plants under the control of a single board operator.

System Maturity - reject sunset technology unless youre fitting in the last piece of a multi-phase control replacement project. Recognize that even though a manufacturer is legally bound to provide spare parts support for a limited period of time following obsolescence of a product, he has limited control over keeping competent engineers in a support function on an obsolete system.

Product Stability - avoid the control system which appears to be in a constant state of evolution. (These are typically a maintenance nightmare.)

Technical Support - investigate the communications paths available for connecting plant support personnel to technical resources at the Factory. Consider also the level of local support you can expect, especially during the first years of system operation.

Configurability - evaluate the magnitude of the configuration task. A system requiring special-skills programmers for initial set-up will require these same specialists, a significant expense to the plant, for every future modification. By contrast, systems which configure with a higher level Operating System can be set up and modified by plant control or process engineers, maintenance techni-cians, or selected operators.

Track Record - past performance is a valid indicator of future actions. Be wary of born again control systems companies with a trail of dissatisfied clients but a promise that all is changed. Check out recent references on a potential vendors Happy Camper list; be prepared for candid dialog.

125 Life Cycle CostsThe quoted cost of a control system is the tip of a financial iceberg. Determine the Life Cycle cost of a system by reviewing the other cost components:

Training - engineers, maintenance technicians, trainers, and operators will all need training on a new system. Significant cost sub-components are tuition, time, travel, and frequency of refresher training courses.July 1999 100-6 Chevron Corporation

Instrumentation and Control Manual 100 System Design System Engineering - include an estimate of the cost of documentation, config-uration, and commissioning services.

Acceptance Testing - this procedure persists in a quality-conscious world. Determine where the system will be staged, how completely application soft-ware can be loaded, and how many User representatives will be needed to give the system a thorough Factory Acceptance Test.

Spare Parts - request a realistic list of recommended spare parts/components from the system vendor; advise him that the cost of these spares will be factored into the cost evaluation of the overall system. (The magnitude of the Recommended Spare Parts List increases once the basic system order is placed.)

Redocumentation - how readily does the system adapt to self-documentation for changes in field instrumentation, control strategy definition, or configura-tion? Does the system use a fill in the blanks configuration format, or does it require proficiency in a high-level computer language?

Maintenance - how much maintenance effort is required to keep the system in reliable operation? Can reliability be increased (and the cost of ownership decreased?) through minor adjustments to system architecture?

130 Instrumentation Design Engineering

131 Detailed Design DevelopmentDetailed design fleshes out the control system skeleton defined in the Preliminary Design phase of the Project. Successful installationsand thus successful projectsare rooted in the patient attention to an almost limitless number of details.

Designs Engineering ContractorsThe detailed design of a system is labor- and document-intensive. For this reason, detailed design work is frequently done by engineering contractors. They offer the advantage of being able to supply skilled technical personnel at short notice, and only for the duration of the project. The downside is that any technical expertise paid for by the Client and acquired by the contractor vanishes at the completion of the Project.Engineering contractors must be provided with current Chevron or plant Standards, Specifications, Drawings, and Forms, if the goals of Uniformity and Quality are to be realized.

Systems IntegratorsIn a similar fashion, systems integrators and packaged systems suppliers must be provided with Chevron or plant specifications stating minimum requirements for controls which they provide, integration with other systems, documentation and all other information normally supplied by vendors of non-packaged instrumentation.Chevron Corporation 100-7 July 1999

100 System Design Instrumentation and Control Manual132 Design SpecificationsDesign specifications are used to guide system designers. The application and the type of contract are important factors in determining the extent of design specifica-tion needed.

A typical design specification (Model Design and Construction Specification, Section J, Instrumentation and Controls) is available from the Projects and Engi-neering Technology Group (P&ET) of CRTC. This specification is modeled to allow for a number of options and is adaptable to fit specific jobs.The design phase of a job produces the construction specification, which usually comes in two parts: a written specification and a construction drawing package. These two parts fully define how an instrumentation system is supposed to be built.

Changes in specifications after a bid has been awarded can be very costly. It is therefore important to form an accurate bid package (specifications and drawings). Because an instrumentation system has many inter-related components, a thorough end-of-job review is recommended.

133 Specification of InstrumentationThe specification of individual instrumentation is usually done on ISA (Instrumen-tation Society of America) specification forms. These forms are widely used throughout the industry, and most contractors and vendors are familiar with them. These forms are found in ISA S20 which is included in Volume 2 of this manual. The ISA form is used during design and construction and startup and by the mainte-nance group after startup.

The ISA instrumentation specification forms include brief instructions for filling in the form. For additional guidance, this manual includes data sheet guides. Various sections of this manual also discuss instrumentation selection and specification.

Consult with the Monitoring and Controls Unit of CRTC for the latest information on computer generated ISA data sheets.

134 DocumentationA system designed in-house by Chevron, or designed by an engineering contractor, or designed and built by a system integrator/packaged systems supplier generally includes complete documentation for design, construction, operation and mainte-nance. These documents will usually satisfy the Federal and/or local safety and health legal compliance requirements for critical instrumentation.

The following should be considered as minimum documentation requirements for control systems installations:

Area Electrical Classification maps

Plot Plans & Elevations, showing location of and access to major equipment and critical instrumentation.July 1999 100-8 Chevron Corporation

Instrumentation and Control Manual 100 System Design Piping & Instrumentation Diagrams (P&IDs) - refer to Section 200. Process Flow Diagrams, showing flow rates and conditions of pressure, temper-

ature and chemical composition for all streams in the plant.

Process Control Diagrams, showing the configuration of front-end control strat-egies, as determined by the Control Objectives Analysis (COA), and verified by the Control Designs Analysis (CDA).

Advanced Control Strategy documents, including Control Narratives, describing Strategies for optimizing the Process. These would include complete DMC documentation.)

Logic Diagrams, defining the functionality of Safety Interlock Systems, as defined by the Safety Objectives Analysis.

Vessel Drawings, showing the elevation and orientation of nozzles and the maximum, normal, and minimum levels of product and/or interfaces within the vessel. (These are required for designing instrumentation bridles and ordering level instruments.)The vessel drawing shall also tabulate the following data for each level instru-ment connected to the vessel.

Type of instrument

Alarm setpoints

Specific gravity of process fluid(s)Specific gravity of seal or capillary fluid

Instrument span with calculations

Zero suppression or elevation

Instrument Data Sheets, describing the physical construction of the instrument hardware items procured for the project. (These Data Sheets must be complete enough to permit ordering instruments without additional descriptive documen-tation.)

Orifice Data Sheets, detailing flowing conditions for all orifice flowmeters. These data should be supplied by Process Engineers familiar with the plant of similar processes. Inaccurate process data will come back to haunt ALL engi-neering disciplines.

Loop Diagrams, showing the interconnections among all hardware specific components in a control loop.

Junction Box Wiring Diagrams, showing the layout of termination strips and their connection to Main or Branch cables or to field wiring.

Cable Schedules, listing the cables and pairs (or conductors) used for intercon-nection of instrumentation components. (In some cases, these may be combined with Junction Box drawings described above.)Chevron Corporation 100-9 July 1999

100 System Design Instrumentation and Control Manual Installation Details, showing the relative position of process connections, instruments, and Utilities (power, heat tracing, vents, drains, etc.), and listing the materials used for installation.

Configuration Forms, describing the software or firmware (or both) used for creating Control Strategies, Operator Displays, and Reports.

Critical Alarm, Instrumentation, & Emergency Shutdown testing programs (procedures and frequencies for testing).

Indexes, for cross-referencing all of the above.

Documentation may be developed and maintained using paper or electronic media, or a combination of both. In all instances, current documentation must be available to plant Operations, Maintenance, and Technical organizations.

Use of electronic documentation systems with relational data bases increases the speed and accuracy of the documentation effort, since a single data entry event generates (or edits) parameters on multiple, related data files.

Design ReviewsPeriodic reviews of project design documentation ensures that costly rework or reor-dering of material is eliminated. The frequency of these design reviews is best deter-mined by the Project Management team, to which the Control Engineer reports.

135 Instrumentation DatabaseThe efficient handling of the vast array of instrumentation information for a project is a key issue in any instrumentation design. It is desirable to create a Master instrumentation database. Data need only to be entered once and changes are auto-matically updated for all sub-databases.

Software tools are available to control instrumentation information and generate reports and schedules. An instrumentation schedule can be used to document most of the instrumentation information.

140 Construction and Startup

141 Documenting Field ChangesA well-planned and designed control project minimizes the number and nature of field engineering changes.

These field changes should be documented on a master markup set of Drawings maintained in the Project Engineering Office, and should include all necessary supporting documentation.

Field changes must be signed off by the same level of authority as original draw-ings or formal revisions thereto. Prior to issuing Field Change Orders, all appro-priate Management of Change (MOC) requirements must be satisfied.July 1999 100-10 Chevron Corporation

Instrumentation and Control Manual 100 System Design142 CommissioningThe commissioning process consists of verifying the proper installation, connec-tion, and calibration of all instrumentation items on the Project.Specification ICM-MS-1586, Instrument Commissioning, is a guide for preparing newly installed instrumentation prior to plant startup. It describes the contractors responsibility for inspecting, checking, adjusting, and calibrating the instrumenta-tion and documenting all of the work for approval by the Company.

Recent trends in instrumentation have eased the burden of the Commissioning process:

Most Smart process transmitters can be interrogated from the control console or from termination panels in the rack room, to verify that the right trans-mitter is connected to the right terminations. (Forcing the transmitter to iden-tify itself by Tag Number is a technique for electronically ringing out a transmitter installation.)

The accuracy of digital electronic transmitters far exceeds that of field test equipment, and digital transmitters show no tendency to drift. Therefore, shop or field calibration of transmitters becomes superfluous. Instruments can move directly from the Tally Room to the installation site.

The increasing use of Smart valve actuators or positioners permits calibration checks and recalibration of control valves from the rack room or marshaling panel. This minimizes the requirement for cycling control valves through the valve or instrument shop prior to installation.

All instrument installations should be signed off by the installer, the instrument inspector, and an Operator. OSHA regulations (29 CFR 1910) require that Critical instrumentation be installed and inspected by qualified workers.

143 System StartupAt the system startup phase, operation of final control elements is switched over to the new control system.

A major effort is required to tune control loops, especially on a grass-roots project, or loops on a reinstrumentation project which did not previously exist.Prior to attempting to tune control loops, verify that any control configurations which inhibit controller response on changes in set point have been disabled. (These features will need to be re-enabled following controller tuning.)The use of a high speed data recorder (with chart speed selectable up to 6 in. / min.) will aid in the capture of process response to changes in set point or changes in controller tuning constants. Use of high speed trending on a CRT display is accept-able, especially if the set point, process variable, and controller output can be trended on the same display.Chevron Corporation 100-11 July 1999

100 System Design Instrumentation and Control ManualA moderate amount of process variable damping is required for flow loops on digital controllers, to prevent the control algorithm from chasing noise on the PV signal. (The magnitude of this noise is not apparent on analog instrumentation, due to the inherent damping of inputs from volumetric capacity (pneumatic controls) or input R-C filters (electronic analog controls).When tuning Cascade Controllers, tune the slave controller first, then the master controller.

At the conclusion of controller tuning, note tuning constants in a secure logbook, which can be used for future reference to determine is controller tuning constants have been altered.

144 Closing DocumentationAll field changes must be transferred to permanent documentation following turn-over of the control system to the Proprietor of the project.Final, As-Built drawing revisions must be provided to plant Operations, Mainte-nance, and Engineering offices as part of the projects documentation. In addition to the documentation described on Section 134, this final documentation project must include operating instructions, maintenance manuals, and spare parts lists for all equipment installed.July 1999 100-12 Chevron Corporation

200 P&ID Development

AbstractThis section is an introduction and comprehensive guide to the planning, layout, preparation, and review of piping and instrumentation diagrams (P&IDs). It follows the P&ID development process from start to finish and is applicable to drawings of any scale and complexity. Piping, equipment, and instrumentation aspects of the P&ID are given equal weight, and considerable attention is given to the inclusion of specific elements on the drawing. Particular emphasis is given to the P&ID as a major factor in determining the efficiency, operability, maintainability, and safety of a facility.

Note The foldout P&ID drawings referred to in this section are located at the end of this section.

Contents Page

210 The P&ID and Its Uses 200-3220 Planning the P&ID 200-3221 Developmental Stages

222 Layout Styles

223 Types of P&IDs

230 P&ID Symbol Standards 200-8231 Symbol StandardsPiping and Equipment

232 Symbol StandardsInstrumentation and Controls

240 P&ID Content 200-11241 Instrumentation

242 Piping and Equipment

250 Numbering Systems 200-16260 Additional Information 200-19270 P&ID Review 200-21Chevron Corporation 200-1 July 1999

280 P&ID Drawings and Engineering Forms 200-24281 P&ID Drawings

200 P&ID Development Instrumentation and Control Manual282 Engineering Forms

290 References 200-25July 1999 200-2 Chevron Corporation

Instrumentation and Control Manual 200 P&ID Development210 The P&ID and Its UsesPiping and instrumentation diagrams (P&IDs) are the graphic and symbolic summa-tion of the processing aspects of a facility. Although the piping, instrument and equipment information collected on a P&ID can be found elsewhere in a facilitys design records, only the P&ID displays them in comprehensive, coherent relation-ship to one another.

Activities in which P&IDs have a key role include the following:

Design and design review. Defines piping, instrumentation and control systems

Design and construction progress. Provides a graphic framework in which to monitor design and construction

Construction completion check. At plant completion, the construction agency (either a contractor or Company) is responsible for delivering completed as-built P&IDs. This permits a piece-by-piece review of compliance with the design

Startup. Provides critical information during startup of a new facility

Operation. Provides the primary source of operating information and training aid for a plant or facility

New engineer training. Provides a sound example from which to design similar facilities

Maintenance planning and safety. Provides a framework for planning and monitoring cleanup and isolation, inspection, and similar work prior to startup, as well as future maintenance

Governmental communications. Provides a vehicle for communication with regulatory and governing agencies

Additions and modifications. Up-to-date P&IDs provide a basis for esti-mating, design and implementation of future additions and modifications

220 Planning the P&IDAll major P&ID decisions and approval should be secured early in the design process to avoid costly changes. Because this isnt always practical, the P&ID must usually accommodate some additions. Planning consists of determining the number of P&IDs and their arrangement, content, and style. (For more on style see Section 222.)

Safe Design PracticesSafe design practices promote operating continuity, prevent upsets and alarm fail-ures, and reduce unnecessary shutdowns. They are the foundation for employee and community safety.Chevron Corporation 200-3 July 1999

200 P&ID Development Instrumentation and Control ManualSpace AllocationTo prevent overcrowding and a confusing process flow, 25% to 50% of the space on drawings should be allowed for future equipment. Disorderly P&IDs may impede the design process, and can be a liability during plant upsetswhen quick compre-hension is important.

D-size (22-inch by 34-inch) drawings are commonly used for P&IDs because they are a manageable desktop size; however, some systems would be seriously over-crowded on a single D-size drawing. For a grouped P&ID (see Section 222) a longer R-size (28-inch-by-unlimited) drawing ensures that all closely related processing equipment is included on the same P&ID. The longer drawing may be avoided by separating stand-alone process, utility, or package systems and placing them on their own major equipment or auxiliary P&IDs.

Arrangement of ElementsThe initial arrangement of each process P&ID is submitted for owner/operator approval. These P&IDs include equipment, piping and instrument manifolds, instru-ment symbols (or reserved areas for them), piping runs (or reserved areashori-zontal and vertical), auxiliary systems and subsystems.Arrangement of equipment and piping should follow a sequence that flows logi-cally across the sheet from left to right; for example, feed comes in on the left, prod-ucts go out on the right. The main flow lines should be heavier than secondary process lines and utility lines, and should not double back. Lines should be spaced evenly, with a minimum of lines crossing. In general, the P&ID should be kept readable.

221 Developmental StagesTo avoid the need for extensive rework and decrease the chance of error, P&IDs are usually revised and reissued several times during their development. This staged approach also makes the job more manageable and allows critical path items to proceed before all aspects of the P&ID are firm. The stages might proceed as follows:

Preliminary stage (permits P&ID layout to proceed)

Stage 1 (permits facility layout and P&ID development to proceed)This revision affects the following critical path elements: site preparation, founda-tions, underground features, structures and pipeways, piping, platforms, ladders and walkways, power and utility supply and distribution systems, etc. This revision is typically issued for design. P&ID elements necessary for this revision include the following:

Major process and utility systems equipment, including driver and numbering system selection. Though not entirely a P&ID function, the estimated size and location of major equipment such as the air cooler, furnace, reactors, etc., is also requiredJuly 1999 200-4 Chevron Corporation

Instrumentation and Control Manual 200 P&ID Development Estimated sizing and most major valving (with sizes) for major process lines and utility and relief headers (with major supply and return branches)

Major piping and control valve manifolds Instrumentation, including the majority of field sensors, transmitters, recorders

and controllers

Stage 2 (permits major instrumentation purchase and equipment fabrication)The second P&ID issue follows closely upon the first. This issue permits major instrumentation purchase and equipment fabrication to proceed, and finalizes the plot plan. In addition, work starts on detailed piping design, and relief and utility areas. P&ID elements necessary for this revision include the following:

Selection of instruments and numbering system, and approval of all equipment and instrument connections

Platform layout and specification of platform attachment clips so that vessel suppliers can begin fabrication

All revisions to previously approved elements

Columns, vessels, tanks, drums, and heat exchangers

Connection sizes and types (flanged or stub welded), location, flange facing and ratings

Relief valve settings

Control valve failure mode: fail-OPEN (FO) or fail-CLOSE (FC) Setpoints of critical shutdown instruments

All instrumentation. Control valve manifolds have been sized, all major instru-ments numbered. Shared-display mounting, board mounting, or field mounting has been specified

Piping. Final valving and sizing of all process lines (and major utility connec-tions) their numbers, insulation requirements and heat tracing. All small piping and utility connections shown

Stage 3 (permits finished piping layout to be completed)P&ID elements necessary for this issue include the following:

All revisions to previously approved elements

Equipment, piping and instrumentation. All necessary additional detail. Sizing and specifying of all relief, utility, and sample connections

All small piping sizes, connections, and fittings, including startup, shutdown, pumpout, steamout, washdown, etc.

Plot limit block valves, fully detailed or on separate drawings, as warrantedChevron Corporation 200-5 July 1999

200 P&ID Development Instrumentation and Control ManualStage 4 (receives approval for construction)P&ID elements necessary for this issue include the following:

All revisions to previously approved elements All operating elements All maintenance elements All safety elements

222 Layout Styles

Note Figures 200-3 through 200-10 are 11x17 foldouts at the end of this section.The three primary P&ID layouts used by the Company are the grouped equipment layout, serial equipment layout, and geographical layout.

Grouped Equipment LayoutThis layout style emphasizes processing interrelationships between closely associ-ated, often interactive equipment. It is used for plants where several feed/product streams are processed concurrently, such as on-plot process facilities (the major manufacturing areas of plants, as opposed to off-plot, or support, areas), utility generation facilities, water and waste treating facilities, etc. (see Figure 200-3). To keep drawing lengths manageable, the facility is divided into essentially indepen-dent functioning elements. For a large processing plant these elements might include furnaces, reactors, distillation columns (towers), compressors, etc., that can be conveniently grouped on separate drawings. On the separate drawings, lines handling lighter products are drawn along the top, lines handling the heavier prod-ucts along the bottom.

Serial Equipment LayoutThis is a convenient layout for plants with a single major process stream that is acted upon sequentially at essentially independent stations, for instance, a pack-aging plant or production facility (see Figure 200-4). The P&IDs for plants laid out in this style can be many feet long when on a roll or multifold paper. When prop-erly laid out, these may be broken down into individual drawings to more easily fit desktops or for inclusion in record books. Each segment holds usually one, some-times two processing elements.

Serial-style P&IDs often have equipment information blocks along the top, process gas, relief, vent and flare headers just below, the equipment in the middle, intercon-nection lines just below the equipment, and pumps and compressors along the lower edge.

Geographical LayoutThis layout is used for collections of independent processing elements that are not linked by process relationships, such as tankfields, utility distribution systems, plot limit manifolds, and interconnection diagrams. A roughly geographical layout is often the most logical way to present them. (See Figure 200-5).July 1999 200-6 Chevron Corporation

Instrumentation and Control Manual 200 P&ID Development223 Types of P&IDs

Main P&IDsThe main P&IDs show process flow, mechanical equipment, and instruments and controls. For small plants the main P&ID is all that is required.

Major Equipment P&IDsMajor processing equipment such as compressors, reactors, furnaces, treaters, and refrigeration systems are often placed on separate P&IDs (See Figure 200-6). This accomplishes the following:

Provides the space to show the interrelationships of complex mechanical elements with their instrumentation and supporting supply systems

Shows precise location details, particularly for critical temperature points

Unclutters the main P&IDs

Auxiliary P&IDsEquipment not directly in the main processing stream is often referred to as auxil-iary equipment. Examples are seal, flush, and purge systems; lube oil, hot oil, and oil mist systems; and glycol heating systems (see Figure 200-7). These may be placed on separate P&IDs to reduce crowding on the main P&ID or when they serve equipment on different P&IDs. When small, they may be combined on a single drawing with other auxiliary systems.

When auxiliary equipment is supplied assembled in a package unit from a vendor, it should be depicted within a dashed-line box, with attention given to the following Company/vendor interface areas:

Equipment supplied at the boundaries. Otherwise, pickled pipe may arrive without mating flanges, the pipe material may be wrong, or both Company and vendor may supply block valves

Instruments. Otherwise, both parties may supply duplicate sets, or Company-supplied instruments may not fit vendor-provided connections

Plot Limit Block Valve Manifold P&IDsThis is a type of geographical layout (see Section 222). In major petroleum and petrochemical processing facilities individual plants or groupings of plants are set up as isolable entities. A single major assemblage of block valves at the end of a central pipeway, the plot limit block valve manifold (plot limit manifold), ties the individual plant headers into an interconnecting pipeway system serving other facil-ities (see Figure 200-8). With a few exceptions (primarily underground lines) all lines in the plant pass through the plot limit manifold. This facilitates supervisory review of plant isolation prior to a major planned shutdown. For small plants the plot limit block valves may be shown on the process P&IDs themselves. For larger plants a plot limit manifold drawing is prepared.Chevron Corporation 200-7 July 1999

200 P&ID Development Instrumentation and Control ManualInterconnection DiagramsThese specialty drawings show, on one drawing, the relationship between control systems located in different plants.

Utility Distribution System P&IDsThese are usually laid out geographically to preserve the sequencing and relative locations of all elements (see Figure 200-5). In mid-sized plants, several utility systems (steam and condensate, all gases, water, etc.) may either be layered on a single drawing in separate well-defined strips or superimposed.

To reduce clutter, only the tie-in portions of utility systems should be shown on the main P&IDs. These should include all valving and instrumentation associated with the control or isolation of the processing equipmentchecks, block valves, flow indicators, etc.; the utility P&IDs themselves show little valving. The tie-ins should be labeled with the utility P&ID line and drawing numbers, and, if desired, their service.

Small, in-plant utility facilities are usually shown on their associated utility P&IDsinstrument air dryers, fuel gas knock-out drums (separators that remove entrained water from the gas), condensate dryers, etc. Larger utility supply and processing systems are usually shown on separate process P&IDswater treatment plants, boiler plants, etc.

Relief System P&IDsFigure 200-9 shows a typical geographical layout for a relief system. Relief valves and bypasses are not shown here, but are included on the main process P&IDsthe usual practice for process operations information.

All calculated relief loads should be recorded on this drawing, since they are not always found in the plant design records. Relief system P&IDs are very helpful in determining relief system modifications when adding major equipment in the future.

230 P&ID Symbol StandardsThe following drawings show the P&ID symbols commonly used in newer plants. These symbols are derived from the nationwide Instrument Society of America (ISA) standards (see Standard Drawings and Forms): ICM-EF-824A, Standard Piping and Equipment Symbols ICM-EF-824B, Standard Instrument Symbols ICM-EF-824C, Standard Logic and Instrument Symbols ICM-EF-824D, Guidelines for P&ID Presentation of Level Instrumentation

EF drawings may be adapted and condensed to a single sheet for a major facility.July 1999 200-8 Chevron Corporation

Instrumentation and Control Manual 200 P&ID Development231 Symbol StandardsPiping and EquipmentWhen making plant additions or modifications, it is sometimes best to continue using the existing symbology familiar to plant personnel. However, new facilities should use modern ISA symbology to ensure clear communications with installa-tion personnel.

An ISA symbol exists or can be adapted for almost any instrument. Equipment symbols are another matter. It is often necessary to elaborate on ICM-EF-824A for complex machinery such as compressors, multistage pumps, and materials handling equipment.

All project-specific symbols and other unusual symbology should be clearly recorded either on the project P&ID symbol drawings (if incorporated as project drawings) or in the notes column of the P&IDs themselves. Such symbols must also be used consistently throughout the project. This is vitally important because P&IDs may be the only drawings available to those unfamiliar with a particular project or facility, such as engineers involved in facility additions and modifications. Often what is regarded as a universal standard symbol by one organization is found to be different elsewhere.

232 Symbol StandardsInstrumentation and ControlsThe following should be agreed upon before much work is done on the P&IDs for a project: A standard for continuous modulating controls A standard for process safety and sequencing logic How to document P&ID special symbols The degree of details to be shown on the P&ID

Continuous Modulating ControlsModulating controls indicate and control variables that can change continuously over a range of values. ISA Standard S5.1 (see Appendices) is the preferred standard.

Process Safety and Sequencing LogicVariables for process safety and sequencing logic can normally assume only two states; a pump is either on or off; a temperature either is or is not too high; a burner either is or is not lit; a filter is or is not ready to be backwashed.

The logic symbol standard used most often is ISA Standard S5.2, (see Volume 2, Industry Codes and Practices). These symbols are most suitable for representing binary process logic, thus for documenting most safety systems. They do not easily represent sequencers such as drum programmers which have many output states.

In most cases the sequencing logic will be complex enough to require separate func-tional logic diagrams. The S5.1 symbols connect the individual instrument symbols to a box labeled with the name of the logic system. For example, a boiler P&ID may Chevron Corporation 200-9 July 1999

200 P&ID Development Instrumentation and Control Manualshow a box labeled BURNER MANAGEMENT SYSTEM. There may be more than one logic box shown on the P&ID to represent different logic systems (see ISA S5.2, Appendix A, Figure 1).The box should direct the reader to a logic document that is recoverable by future users of the P&ID. This logic document might be a drawing, such as that shown in S5.2, Appendix A, Figure 2. Note that this drawing is tied to Figure 1 by the instrument balloons on the interlock system in Figure 1 and adjacent to the logic in Figure 2.

Word descriptions can supplement or replace logic drawings such as that provided in S5.2, Appendix A, Section 3.1.

Figure 200-1 is a type of word description called a control philosophy. This is a very effective way to communicate complex or simple process control schemes.

Fig. 200-1 Control Philosophy

Dirty Water Tank

EQUIPMENT: T-4

REFERENCES: P&ID F-40001

PROCESS DESCRIPTION: Tank T-4 is the dirty water surge tank for the produced water plant. It is 38 feet diameter and 24 feet high. It receives produced water from the FWKO vessels, coalescers, and other locations. This water may contain some oil that needs to be skimmed. From this tank the liquid goes to the flotation units which further separate the oil from the water.

PROCESS CONTROL

Level Control Level control is very important in this tank. It is controlled by LIC-T4 at 18 plus or minus 2 feet. There needs to be a constant head in the tank so that relatively constant flow can be supplied out of the tank to the flotation units. (See the control philosophy of the flotation units.)

PROCESS UPSETS:

High Level

Low Level

Emergency S/D

High level could occur if there is a block in the outlet line, the controller or control valve fails, or more water is coming into the system than can be handled. LAH-T4 will alarm at 22 feet in the control room if this happens. (The operator may then decide to manually control the flow out of the tank with the bypass valve to lower the level.) It will also close FV-T5 to keep from transferring to T-4.

The level may fall below the control range if there is a controller or control valve failure or there is a leak. In this case LAL-T4 will alarm at 7 feet in the control room.

LV-T4 closes during an ESD #1.July 1999 200-10 Chevron Corporation

Instrumentation and Control Manual 200 P&ID DevelopmentControl philosophies (when used) are an integral part of the P&ID. They can be placed in an expanded note section of a P&ID or on separate P&IDs.

Simpler safety and sequencing logic can be shown entirely on the P&ID using the symbols of ISA Standard S5.1. For example, a low-level shutoff for a tank valve actuated by a level switch may be depicted without the need for a separate logic diagram.

Special SymbolsAny special symbols should follow the rules in ISA S5.1 and S5.2, and be defined on each drawing.

Degree of DetailISA S5.1 identifies three levels of detail, depending on user requirements, as follows:

Simplified loop. See ISA S5.1, Section 6.12, Figure 1. Simplified symbolism and abbreviated identification identify the principal measurement and control functions. Process control diagrams often use simplified loops

Conceptual loop. See ISA S5.1, Section 6.12, Figure 2. Functionally oriented symbolism and abbreviated identification show the control function but not the implementing hardware. Advanced process control diagrams and P&IDs intended primarily for the process operator normally use conceptual loops. Detailed loops are frequently shown on additional drawings

Detailed loop. See ISA S5.1, Section 6.12, Figure 3. Detailed symbolism and more complete identification show the type of hardware and kinds of signals. Detailed loops are often needed by the plant control engineer and the design, control engineering and maintenance staffs. For operator training, the concep-tual loops must frequently be shown on additional drawings

240 P&ID Content

241 InstrumentationThe development of process and equipment control schemes, and the placement of minor instruments are discussed in this section and depicted in Figure 200-2.

Process Control SchemesProcess flow and control diagrams generally do not show equipment controls, safety controls, and miscellaneous minor instruments. When incorporating process controls on the P&ID, the plant designer makes hardware and software choices that were unavailable to the process control designer. These choices can affect the func-tion of the process controls and should be reviewed with the process control expert.Chevron Corporation 200-11 July 1999

200 P&ID Development Instrumentation and Control ManualEquipment Control SchemesIf they are very simple, major equipment controls should be shown on the process P&ID. Otherwise, they should be shown in detail on a separate equipment P&ID and referenced on the process P&ID.

Equipment control schemes should be developed in coordination with equipment vendors, and Company and design agency equipment control specialists. The resulting P&IDs should be reviewed with an equipment control expert.

Review and approve equipment controls that are completely determined by the Vendor in packaged systems. With packaged systems, a Company instrumentation expert should be consulted before it is too late to make changes.

Minor InstrumentationThe P&ID designer is responsible for putting all minor instrumentation on the P&ID, including the following:

Locally mounted pressure gages Remote temperature indicators Local temperature indicators Local level indication Remote flow indicators Alarm and shutdown systems Pressure sensors for automatic pump starters Toxic and combustible gas monitors Transmitter output indicators

Fig. 200-2 Development of the Instrumentation Portion of P&IDsJuly 1999 200-12 Chevron Corporation

Instrumentation and Control Manual 200 P&ID DevelopmentThe following paragraphs give guidance on the proper application of each of the minor instruments listed.

Locally Mounted Pressure GagesPressure gages should be installed on the following process equipment and piping locations to monitor operation and performance:

Discharges of pumps and compressors

Vessels and the bottom vapor space of columns

Near the process connection for nonindicating pressure transmitting instruments

Furnace fuel oil, fuel gas and atomizing steam branch headers

Furnace draft. A single draft gage should be manifolded to the inlet of the convection section and to a position below the stack damper on each furnace

Pressure test points consisting of a process connection with a plugged valve are located in process equipment and piping, as follows:

Near the inlet and outlet of all packed vessels and columns At all indicating pressure transmitter instruments Inlets and outlets (both shell and tube side) of each heat exchanger and reboiler Inlet and outlet of each air cooler

Remote Temperature Indicators (Thermocouples and ResistanceTemperature Devices [RTDs])Remote temperature indication should be provided, as follows, on most process equipment and piping:

Columns. All inlet and outlet lines

Vessels. All inlet and outlet lines expected to have different temperatures

Fired heaters. Inlet line and outlets from each pass, header pass points from the convection to the radiant section, on the tube wall as recommended by the furnace supplier (a minimum of three per pass), and on the stack just ahead of the damper

Process stream junctions. Downstream of the junction point of all important process streams

Coolers. All liquid product inlets and outlets

Temperature controllers and transmitters. These instruments should have an additional thermocouple and thermowell separate from the controller or trans-mitter. Instruments on high pressure piping and reactors may use a common thermowell

Orifice flow meters. For heavy hydrocarbons. Used to estimate viscosity and make flow corrections from fluid temperature changesChevron Corporation 200-13 July 1999

200 P&ID Development Instrumentation and Control Manual Parallel piping lines. Temperature transmitter thermowells should be installed in both lines, and the sensing bulb for the transmitter in one line. The installa-tion should permit transfer of the sensing bulb to the other well

Process compressors or blowers. Inlet and outlet lines. One point is required on the combined inlet and one on the combined outlet of compressors or blowers in parallel on the same service

Local Temperature Indicators (Dial Thermometers)Local temperature indication should be provided for process equipment and piping where required for manual field control. Such temperature indicators should measure outlet water temperature from all condensers or coolers, discharge of all blowers, discharge of each compressor cylinder, and lube oil and water for pumps, turbines, compressors and similar mechanical equipment.

Heat exchanger thermowells. Thermowells should be located at the inlets and outlets of heat exchangers (shell side and tube side) that dont have remote temperature indicators. If a thermocouple point or dial thermometer is present temperature test points are not needed

Compressor temperature alarms and shutdowns. High discharge tempera-ture alarms are necessary on each cylinder of a main reciprocating compressor and, frequently, on other compressors as well. Thermocouples and thermistors may be used for this service; filled thermal systems should not be. Because high temperatures must be detected at very low or zero flow, the sensing point should be either in the compressor nozzle or immediately downstream of it

Local Level IndicationLocal level indication should be provided for all columns, vessels and drums to determine total and interface (if any) level. Gage glasses. Gage glasses are preferred for local level indication, with the

following exceptions:

At pressures above 900 psig, except for steam or water service Where they are unsuitable for the process fluid (dirty stocks that will coat

the glass, etc.) Determine if a gage glass for an elevated vessel will be readable from

grade and, if not, include an additional indicator at grade

Displacer-type level transmitters. When level glasses cannot be used, include a displacer-type level transmitter with a local receiver gage. Usually, any level alarm should be taken from this transmitted signal. This transmitter should be separate from the level controller loop

Differential pressure level transmitters. Use with a flange-mounted diaphragm capsule when neither a gage glass nor a torque-tube displacement type instrument is suitableJuly 1999 200-14 Chevron Corporation

Instrumentation and Control Manual 200 P&ID Development Pyrometer-type level sensors (rams horns). Use for heavy oil columns (e.g., atmospheric and vacuum columns) if approved by the operations representa-tive. No fewer than five should be used

Automatic tank gages. Tanks used for inventory control should have auto-matic tank gages readable from the ground, and level transmitters that display in the central control house (if there is one). Heated tanks and tanks storing product at above-ambient temperature should have remote readout of spot tank temperatures. If there is an existing tank gaging system, a project decision should determine whether automatic tank gages should read out on it

Remote Flow IndicatorsAll feed, product and utility lines should have remote flow indication.

Alarms and Shutdown Systems Shutdowns and interlocks. Automatic shutdown and interlock systems (see

Section 1200) prevent the startup of equipment or portions of the plant when operation would be a serious hazard. Alarms may be anticipatory or activated at the time of shutdown, and are displayed on the central control room alarm system

Alarm and safety setpoints. Setpoints for alarms and safety trips should be recorded on the P&ID if they require setting in the field

Low flow shutdowns in high energy systems. When a centrifugal pump is injecting liquid into a high energy system, shutdown of the pump can cause disastrous reverse rotation if the check valve fails to hold. In such cases, a low flow reading on the feed meter should close a control valve to prevent the backflow

Computer communication. The process computer (if used) should monitor alarm and shutdown status

Pressure Sensors for Automatic Pump StartersIn services where continuous flow is critical, drivers for spare pumps should auto-matically start on loss of flow from the prime unit.

Toxic and Combustible Gas MonitorsToxic and combustible materials require special attention. Facilities handling hydrogen sulfide (H2S) require an ambient H2S monitoring system. Monitoring stations should be judiciously located around equipment handling high H2S concentrations.

Transmitter Output IndicationBlind transmitters (except level) should have at least one indicating gage on the transmitted signal. If a control valve is associated with several transmitted variables (directly or indirectly as with flow and level indicators on the same stream) the gages should be readable from the manual bypass valve. Gages for split range instruments should be readable from each valve. A gage is not required for level Chevron Corporation 200-15 July 1999

200 P&ID Development Instrumentation and Control Manualtransmitters if the gage glass can be read from the control valve. The same applies to any indicating transmitter that can be read from the control valve.

242 Piping and Equipment

Physical Size and Mechanical Design InformationThe physical size and mechanical design information almost universally found on P&IDs for all major processing and production facilities is as follows: Piping elements. Nominal pipe diameters and sizes of valves, flanges,

reducers, connections and miscellaneous and special fittings

Columns, vessels, tanks. Internal diameter(s) (ID), seam-to-seam height(s) or length(s) and equivalent boot and dome dimensions

Relief valve setpoints

Additional Mechanical and Process InformationMajor processing plants usually control operating conditions by varying feed stream composition, throughput, heat input, etc. As a result, relief valve setpoints are usually the only mechanical design information shown on the P&IDs. By contrast, additional mechanical design and (sometimes) process information (such as design temperatures and pressures, duties, horsepowers, speeds, capacities, and throughput) are shown on production facility P&IDs, because actual conditions can be quite different than anticipated.

Some operators of major processing facilities now request expanded equipment information on their P&IDs. This information can be of considerable help in opera-tions, and in estimating and designing additions and modifications.

250 Numbering Systems

Plant, Equipment, and Piping Numbering SystemsThere are so many systems in use throughout the Company that it would serve little purpose to discuss more than a few general principles here. API RP 14C, Table 2.2, Component Identification is another system of line numbering and equipment identification.

Facility Names and Plant Numbering SystemsMajor facilities (both upstream and downstream) are generally named for their loca-tion. Small facilities such as small producing gas plants and small stand-alone asphalt plants are not further subdivided. Larger processing facilities are broken up into distinct plants. These plants are generally named for their function (crude unit, gas dehydration, boiler plant, effluent treating plant, etc.). They are usually also assigned a number. During construction and later, during maintenance, this provides a rough-cut way of segregating, by construction area, the hundreds (and sometimes July 1999 200-16 Chevron Corporation

Instrumentation and Control Manual 200 P&ID Developmentthousands) of items of delivered equipment. Local management should be consulted in determining plant numbers for a new project.Operations approval should be obtained for numbering systems (plant, piping, equipment, and instruments) at the beginning of a new project. Once drawings and specifications are issued for quotation, the cost of changing numbering systems is surprisingly high. A confirming letter or memorandum emphasizing the importance of this decision is helpful.

Equipment Numbering SystemsWhere plant numbers are used, they should be incorporated into equipment numbers, and, often, into the instrument numbers. Where plant numbers are not used (such as for offshore platforms) many prefer that the instrument numbers relate to uniquely numbered equipment. This method is used on platforms built to API RP 14C to associate safety devices with the equipment they protect. Some facilities incorporate a plant number into the equipment number and associate instruments with equipment.

Most facilities also use alphanumeric systems with a letter prefix that indicates the type of equipment involved. For instance, the prefix MAF designates a 7-tray glycol contactor for an offshore platform (see API RP 14C). The same equipment in a downstream major processing plant would be denoted by a C for column.The prefix system allows the number series to be restarted for each type of equip-ment, so that numbers can usually be limited to two digits. Equipment is numbered serially or in decade steps for major equipment. Thus, for plant 20, three sequential columns might be numbered 2010, 2020, 2030. P-2021 might be the reflux pumps for column C-2020. Skipped numbers are acceptable in a system such as this.

Instrument Numbering SystemsAssignment of instrument numbers must be coordinated with all design agencies that are developing P&IDs or subsections of P&IDs. A unique identification for each instrument is assigned in accordance with ISA Standard S5.1 (see Appen-dices), as follows:

70-FIC-101

Reading left to right, the first element of the code is the plant number. This is normally omitted on the P&IDs, but it is included in the instrument number for other purposes such as ordering, I. D. tags, etc. The letters that follow represent the instrument type according to ISA Standard S5.1. The final element is the loop iden-tification common to all instruments and components in a loop. If possible, loop identifiers should be in order of their positions upstream in the process flow; that is, feed loops have the lowest numbers, and product and final effluent loops the highest.Chevron Corporation 200-17 July 1999

200 P&ID Development Instrumentation and Control ManualLoop Identification SystemsFor additions, the existing instrument numbering system is usually extended to include new instruments. For new construction, the following methods are avail-able:

Functional orientation. This system was developed for large distributed control systems. Its restricted identifier size accommodates electronic data-bases. It is organized as follows:

100 to 899. Except for safety relief devices, major instrument loops take their identifiers from this block. An alphabetical suffix is added where more than one of the same component is present in a loop, as with split range control valves. Temperature points that are part of the control display system use this block

900-999. Safety relief devices, relief valves and bursting disks have 3-digit groups from this block

Four-digit groups. Minor instruments have 4-digit identifiers

Hardware orientation. This system was developed when individual control-lers were mounted in control panels. Seven blocks of numbers are used:

100 to 399. Loops monitored or controlled from the control center 400 to 499. Field controlling, recording and indicating loops, including

dial thermometers 500 to 599. Field contacts for alarms 600 to 699. Pressure gages 700 to 799. Level gages 800 to 899. Board temperature points, including test wells 900 to 999. Relief valves and bursting disks

Major equipment orientation. This system provides much information to the plant operator. However, it is unwieldy and is not recommended except where already used

Line Labeling SystemsLines generally require four to seven identifying elements. Symbology depends on the facility and organization involved. These elements are as follows:

Plant number

Service. Also called a line identification letter (i.e., process, instrument air, caustic)

Line number. Often (and best) a separate unbroken series restarting with each service designation (critical for large jobs to keep number length reasonable)

Nominal line size

Piping classification. Service classification, service, etc. Specifies pipe, valves and fittingsJuly 1999 200-18 Chevron Corporation

Instrumentation and Control Manual 200 P&ID Development Insulation

Heat tracing

See Standard Drawing ICM-EF-824A. For major processing plants in which many additions and changes are anticipated during the design phase and later, sequential line numbering that follows process and utility flow is recommended.

Processing FacilitiesTo minimize line numbers and better indicate process relationships, line numbers at processing facilities usually run unchanged from one piece of equipment to the next, including branches to multiple or similar pieces of equipment such as a pump and its spare. Also, the number is not changed for a change in pressure or materials.

Producing FacilitiesCOPI and some producing organizations change line numbers when the pressure classification (piping classification) changes, on branches to multiple or similar equipment, and when a materials change is required. Their requirements differ from major processing plants. They have many fewer piping classifications and much larger pressure changes that need to be clearly indicated. COPI assigns a different series of sequential numbers for each service, and has a very organized numbering procedure.

Line SchedulesIn larger plants (particularly those constructed by large contractors) it is necessary to keep track of assigned line numbers using line schedules. Otherwise, accidental re-use of the same number would surely occur. In addition, line schedules are required by some governmental agencies for permitting.

A line schedule often becomes a valuable control document summarizing all piping design criteria, including the following:

Design/process information critical to line design and specification (service flow, pressures, temperatures, viscosity, density, pour point, etc.)

Resulting design information (pipe size, piping classification, insulation, heat tracing specifications, etc.)

Line connection points (to/from)

260 Additional Information

Miscellaneous ElementsA variety of components, details, and descriptions are shown on typical P&IDs, including the following:

P&ID revisions. Changes should be clearly identified by sequentially numbered symbols, such as diamonds, to pinpoint the location of each revi-sion on the drawing. These changes are listed in the revision block or on a Chevron Corporation 200-19 July 1999

200 P&ID Development Instrumentation and Control Manualseparate sheet issued and filed with the P&ID. Avoid the use of vague terms such as general revision

Line classification changes. Line classification changes may occur where different streams join, for instance: Where utility piping ties into process lines with a higher corrosion rate,

temperature or pressure Lines entering and leaving a vessel where processing changes occur that

require additional valves of a higher class than dictated by conditions within the line

P&IDs should be carefully reviewed to ensure that all line classification change symbols are shown. This is particularly important when the plant is modeled, because there are no piping layout drawings (plans and elevations). The model, piping isometrics (spool drawings) and P&IDs are then the only records of line classifications.

Level, alarm, and shutdown setpoints and operating ranges. Although often shown on other drawings, such as vessel drawings (see Section 134) and the level instrument piping drawings, these should be shown on the process P&IDs when they are critical to the safe or proper operation of the process

Flanges. Most often, all 2-inch and larger equipment connections and valves are flanged, but there are some which are not, such as welded stub nozzles (a welded line-to-equipment connection often used on high, hard-to-reach vessel connections and between stacked exchanger pairs) and weld-in valves used in higher pressure services

To distinguish welded from flanged connections, either show all the flanges or stipulate that all 2-inch and larger connections are flanged except where a symbol (sometimes WE for weld-end) is placed adjacent to the connection. The P&IDs may then be used as a blinding control drawing during shutdowns, and to indicate flanged connections to the design draftsman. When different from the piping classification, flange sizes and rating are also shown on the P&IDs.

Entering and leaving line designations. Careful labeling of lines as they enter and leave the P&ID allows good continuity from one P&ID to another. Labeling includes the reference P&ID drawing number, the line identification (noted along the line or enclosed in a rectangular tag or balloon), the to/from equipment number, and a service description

Equipment internals. P&IDs should include a graphic representation of vessel internals whose function (or lack of it) may impact the operation of the facility. Examples include column and vessel internals, gas and liquid distribution and segregation mechanisms, internal level floats, heat exchanger overflow weirs and tubes, furnace tubes and dampers, and many more. For complicated equip-ment such as reactors, a separate major equipment P&ID is often prepared to document critical bed temperature points, process gas flow path, quench feed points, etc.July 1999 200-20 Chevron Corporation

Instrumentation and Control Manual 200 P&ID Development Detail reduction. Level, pressure, and flow instrument piping details on process P&IDs (e.g., testing and maintenance isolation valving and connections) can be greatly reduced by using auxiliary instrumentation draw-ings (see Figure 200-10). Repetitive (and sometimes complicated) vent, drain, and sample system details may also be included on a separate schedule

Reference Drawings. A reference drawing block is often incorporated along the lower edge of the P&ID. It lists major associated drawingsplot plans, piping layout, electrical, etc., with type of drawing, item or area covered, and drawing number. This can help locate associated drawings that may be scat-tered among hundreds of project drawings. When modifying a facility it is equally important to add new reference drawings to the drawing reference blocks

Drawing Titles. Many styles are used throughout the Company for drawing titles. Titles may contain helpful information on the type of drawing (P&ID, instrument, piping, etc.) the item or area covered, the project title or plant name, and the name of the facility or division. Depending on the organization, title blocks may be sequenced differently or omit some items

Information Not Shown on P&IDsThe following information is usually not shown on P&IDs:

Pipefitting details are not shown, except for reducers. These details include hydrotest high- and low-point vents and drains, elbows, tees, other joints, and (sometimes) unions

Pipe supports are not shown. These supports include hangers, anchors, guides and pipe expansion loops

Structural information is usually not shown. This information includes most support structures, platforming, ladders, etc.

Electrical information is not shown, except for special controls such as three-way switches

Instrument piping/tubing is not shown, except for level instrumentation piping. In major processing facilities, level piping valves and details are placed on auxiliary P&IDs or piping drawings, leaving only a skeletal piping outline on the main process P&IDs. By contrast, producing organizations usually retain valving and level piping details on the main P&IDs

270 P&ID ReviewVarious P&ID review techniques may be used to ensure full consideration of facility design, including safety, operability, maintainability, reliability, etc. These tech-niques include the following:

Parallel element review. A comparative analysis of all occurrences of a single detail to verify design consistency. The types of review should be discussed and agreed uponChevron Corporation 200-21 July 1999

200 P&ID Development Instrumentation and Control Manual Line-by-line review. A stepwise review of small related groupings of design elements (such as all the elements associated with a single line). It is used primarily to obtain owner/operator approval of the design

Design practices review. Focuses on all features ensuring operating continuity (the foundation for employee and community safety). Covers piping, equip-ment, and instrumentation and control systems that protect against upsets and failures

Hazard Assessment, Mitigation, and Hazard Abatement. An evolving set of lengthy, formal techniques (both qualitative and quantitative) being adopted on a national scale. Primarily intended for the analysis of new or untried processes or facilities (or elements thereof) where there is a potentially significant hazard to employees or the community.

Parallel Elements ReviewThis technique involves the comparative analysis of all occurrences of a single design element on all P&IDs. These elements are easily located even on complex P&IDs by the design engineers or an individual familiar with the type of facility. Parallel element review is fast, thorough, and very revealing of errors and omis-sions. It works well with groups and for individual review.

Optimally, only one element at a time is selected for analysis, because several aspects of each element may need examination simultaneously, such as use, need, aptness, and engineering rationale. One might take several passes through the P&IDs to review the following equipment connections: vessel drain size for each vessel, flanged versus stub weld connections, all flanged thermocouple locations, piping classification changes for lines tying into vessels in corrosive service, etc.

Line-by-Line Review (Operational and Maintenance Review)Conducted by the design/operations team, line-by-line review is the stepwise review of related groupings of design elements. Groupings may comprise an individual piece of equipment or a line with its valving, drains, sample connections, piping classification, insulation, heat tracing, etc. The review follows the general path of process flow.

This review is often used to obtain acceptance or approval by operations. It is logical and sequential (often a yellow marking pencil shows progress, a red pencil additions or changes). However, since the elements in each grouping usually have different functions, the immediate impact of a parallel element review is lost. Further, the process can be tedious, particularly when involving many lines with repeating features. Suggestions for conducting a line-by-line review:

Break up sessions with parallel element review to dispose of the most repeti-tive elements

Use interactive role playing, in which the operator walks through all steps needed to start up, run and shut down the plant. Design engineers, process representatives, etc., point out erroneous or missing piping, equipment and instrument elementsJuly 1999 200-22 Chevron Corporation

Instrumentation and Control Manual 200 P&ID DevelopmentDesign Practices ReviewThis is employed, particularly in larger, more complex facilities, to confirm that good design practices have been used. It is best conducted using finished P&IDs. Its objectives are as follows: Identify elements whose failure could, through malfunction or human error,

endanger operating continuity, employees, or equipment

Confirm that good design practices have been incorporated, including safety systems, mitigating systems, alarms and shutdowns, etc., to eliminate or reduce the consequences of failure to acceptable levels

Estimate the potential for alternate failure modes

Determine whether the consequences of failures constitute an acceptable risk

Modify (or provide additional) design features or safeguards to reduce conse-quences to acceptable levels

Design practices review focuses on the active elements of the facilityinstruments and controls, pumps and drivers, furnaces, compressors, utility supply systems, etc. These elements are examined in brainstorming sessions that consider both historic and unusual equipment and control system failure modes. Techniques of inquiry include the what if method and the related, more powerful Hazard and Opera-bility Study Method (see the American Institute of Chemical Engineering (AIChE) Hazard Evaluation Procedures and, in this manual subsection, Hazard Assess-ment). Usually an abbreviated, verbal run-through of these techniques resolves concerns or identifies problem areas for later evaluation.

Hazard AssessmentWhen used in the early design phase, hazard assessment review techniques uncover necessary changes that can be made at minimum cost. Later, errors may be extremely costly to correct.

Almost without exception a representative of the owner/operator/client must be present at every review meeting. Other interested organizations include process, designs, maintenance, operations, safety, reservoir engineering, plant or drilling foremen, area superintendent, other management, etc.

Hazard assessment may also include mitigation and abatement techniques such as the Hazard and Operability Study, Failure Mode and Effects Study, Fault Tree Anal-ysis, SAFE charts, Blast Effect Analysis, Atmospheric Dispersion Study, Radiant Heat Study, etc. These can be quite costly, particularly when full documentation is required. They are used when mandated by federal, state or local laws and regula-tions or as judged appropriate by the responsible manager.California and New Jersey have passed legislation requiring the application of these techniques to plant processes and equipment for stipulated toxic or flammable mate-rials whose catastrophic release could impact the general population (see API RP 14C, Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms). AIChE has published Vapor Cloud Dispersion, Chevron Corporation 200-23 July 1999

200 P&ID Development Instrumentation and Control ManualVapor Release Mitigation, Guideline for Safe Storage and Handling of High Toxic Hazard Materials, and Hazard Evaluation Procedures. The Hazard and Operability Study covered in Hazard Evaluation Procedures has been accepted by the EPA as definitive. Future publications planned are: Quantitative Risk Assess-ment and Guidelines for Process Control.

Because of the many safe design practices built into Company standards and proce-dures, these AIChE Proceduresand their reporting requirementsmay be found to be unnecessarily formal and lengthy. Modification and shortening should be considered if the full procedure is not legally mandated.

The AIChE guidelines do not define what level of risk is acceptable, and this is a complex subject affected by conditions peculiar to a facility such as closeness to a population, amounts and types of materials involved, and regulatory emission limits. A guideline recommending applicable projects, techniques, sources of help, refer-ences, suitable consultants, waiver procedures, and other appropriate guidance to operating company personnel is under consideration by the Hazard Assessment Steering Committee. Contact HE&LP for an update.

280 P&ID Drawings and Engineering Forms

281 P&ID DrawingsThe end of this section contains the following figures referred to in the text of Section 200:

282 Engineering Forms

Figure 200-3 P&IDGrouped Equipment LayoutFigure 200-4 P&IDSerial Equipment LayoutFigure 200-5 P&IDGeographical LayoutFigure 200-6 Major Equipment P&IDFurnaceFigure 200-7 Auxiliary P&IDTempered OilFigure 200-8 P&IDPlot Limit ManifoldFigure 200-9 P&IDRelief SystemFigure 200-10 Auxiliary Instrumentation Drawing

ICM-EF-824A Standard Piping and Equipment SymbolsICM-EF-824B Standard Instrument SymbolsICM-EF-824C Standard Logic and Instrument SymbolsICM-EF-824D Guidelines for P&ID Presentation of Level InstrumentationJuly 1999 200-24 Chevron Corporation

Instrumentation and Control Manual 200 P&ID Development290 References

Instrument Society of America (ISA) ISA Standard S5.1, Instrument Symbols and Identification ISA Standard S5.2, Binary Logic Diagrams for Process Operations

American Petroleum Institute (API) API RP 14C, Analysis, Design, Installation, and Testing of Basic Surface

Safety Systems for Offshore Production Platforms, Table 2.2, Component Identification

American Institute of Chemical Engineering (AIChE) Guideline for Safe Storage and Handling of High Toxic Hazard Materials Hazard Evaluation Procedures Vapor Clou