CENTRIFUGAL COMPRESSORS FOR HYDROCARBON SERVICE

As a rule of The Centrifugal Compressor package for hydrocarbon service shall be designed to API 617.
In case of conflict among this specification, data sheets, referred codes & standards and statutory requirements & regulations, the Contractor shall bring the conflict into the notice of Company in writing for resolution before proceeding with the work.
The compressor shall comply with compressor data sheet and this specification. All components shall be suitable for the operating conditions stated on the compressor data sheet.
Material shall be new, free from defects.
All equipment supplied shall be finished machined.  On site only pure assembly work is acceptable.  Piping not completely prefabricated is to be marked on the Piping arrangement drawing(s).  All spare components are to be machined at manufacturer’s shop with suitable tolerances in order to allow replacement without any re-machining.
The compressor and its auxiliaries shall be suitable for outdoor installation (without roof) unless otherwise stated in the data sheet. All equipment supplied must be suitable for start-up and for operation at minimum ambient site temperature as indicated in the specification’s data sheets.

Driver shall be Gas turbine, the specification please see Gas Turbine below.
At normal speed and normal suction condition, the volume capacity at the surge point shall not exceed 70% of the normal operating point. The rise in pressure ratio from the normal operating point to the surge point at normal speed shall not be less than 5%. The head developed at 115% of the normal operating flow at normal speed shall be not less than 85% of the head developed at normal operating point.
Noise emission data shall be provided as well as data of other emissions exhausted to the atmosphere (gas leakages, oil vapour, etc) with the proposal. Please see bellow for specification of noise.
Facility for optical alignment shall be provide and the manufacturer’s supervisor shall be present during initial alignment check at site.
Process gas compressors will be run-in on air in the field. Run-in on air means mechanical test run in the field where compressor is priming and discharging to atmosphere. Compressor manufacturer to propose procedure for run-in on air (flows, discharge pressures and temperature, speed, horsepower requirement, necessity of bleed connections, safety screens, etc) and to provide performance curves and temperature limitations, etc, for this operation. If specified in the specification’s data sheet, process gas compressors will be operated for several weeks on air for pre-start-up equipment drying.
All casing drains shall have isolation valves.  All casing drains down stream of isolation valve shall be connected to common drain header terminated with a flange connection at the edge of skid/base plate.
Compressor shall be designed to withstand the external loading defined bellow:
•    Vertical component. Combined forces and moments due to all piping connections or to any one piping connection resulting in a vertical reaction (either upward or downward) at any support point of at least one-half the dead weight reaction of the compressor at the support point.
•    Horizontal transverse component. Combined forces and moments due to all piping connections or to any one piping connection resulting in a horizontal transverse reaction at any support point of at least one-third the total dead weight reaction of the compressor at the support point.
•    Axial component. Combined axial forces of all piping connections or to any one piping connection resulting in an axial force on the compressor casing of at least one-sixth the compressor weight.
Shaft shall be made of one-piece, heat treated steel that is suitably machined. Shafts shall be made of forged steel.
Impellers shall be assembled on the shaft with fit and a key. Other methods shall not be acceptable without Company approval. Impellers shall be designed to limit the maximum stress at maximum continuous speed to a value not exceeding 70% of the material yield strength. Proven impellers shall be provide.
Balance line sizing shall consider also noise generation due to high gas velocities in the balance line. During mechanical run test in manufacturer’s shop balance line (s) must be installed.
If the compressor is driven by turbine particular attention concerning bearing design must be given to turbine turning gear speed, which may be very low.  Compressor manufacturer to coordinate with turbine manufacturer.
Nonpressurised bearing housings shall be provided with a 25 mm vent connection equipped with the standard breather cap or closed with a steel plug, if no venting is necessary.
Torsional Analysis, A composite torsional vibration analysis shall be performed for all compressor units.  For compressor units driven by electric motor or turbine through a gear box, both the compressor and driver manufacturer shall perform an independent torsional analysis. The input and results of this analysis shall be prepared for submission to Company.
Vibration and Balancing, the final balancing of the rotating element shall be carried out with the coupling half installed. Along with the compressor a fully integrated vibration monitoring system complete with the cabinet (series and protection as defined by Purchaser suitable for service) shall be provided. Vibration probes and system shall be in accordance with API 670.
Drivers shall be sized and rated to develop at least 110% of the horsepower or as specified in data sheet (whichever is higher) at the maximum compressor operating conditions, including either gear or hydraulic coupling losses, or both. Steam turbine drivers for compressors shall be in accordance with API 611 or API 612 as called for in the individual turbine specifications.  Auxiliary drive turbine shall be capable of continuously developing 110 % of the horsepower required at the relief valve pressure of the driven equipment, at the corresponding speed under minimum steam inlet and maximum back pressure.
The coupling (whether hydraulically or mechanically fitted) shall be designed for easy removal. Devices shall be provided by the manufacturer for the mounting and removal of this coupling.

VIBRATION MONITORING INSTRUMENTS OF PETROLEUM PLANT

The vibration monitoring system shall include key phasors, axial position transducers, vibration transducers, signal conditioning, necessary cable and junction boxes, monitor and provision for remote output signals. Vibration Sensors and mounting hardware material shall be minimum 316 SS. Aluminum material shall not be used for instrumentation.

For rotating equipment operated at speeds below 6,000 RPM the external measuring type vibration detector or transmitter shall be selected. For operating speeds of 6,000 RPM and above the shaft measuring type detector or transmitter is preferred. However, if the installation of shaft measuring type detector is not feasible, the external measuring type vibration detector may be used with prior approval by Company.

External measuring type of vibration detector or transmitter shall be magnetic velocity type. Proximity probes shall be selected for centrifugal gas compressor radial bearing vibrations (X&Y suction and discharge), thrust bearing axial movement (2 Z-direction channels).

Accelerometers shall be used for detection of vibration on the gas producer, power turbine and accessory drive unit.  The signals from these components shall be integrated to velocity in the monitor unit and displayed as velocity levels.

Local mounted vibration switches shall be used for detection of vibration on lube oil and process cooler fans.  A minimum of one (1) switch is required on each fan. The switches shall be manual local reset type.

Detector / Transmitter shall be powered by 24 VDC. Output shall be 4 – 20 mA, 3 wires. Each direction of vibration sensor shall have the individual pair output cable. Enclosure housing shall be approved for explosion proof Class I, Div 1, Group D Hazardous Area.

Sensors and controls for measuring vibration of rotating equipment shall be provided as specified in the project equipment specifications and data sheets. Vibration sensors monitoring / shutdown system shall be provided with a starting time delay to prevent shutdown of equipment during start-up. Delay period shall be in accordance with the recommendation of the rotating equipment Manufacturer. The external measuring type detector or transmitter shall be mounted on a vertical surface in order to respond to the horizontal component of vibration.

The monitoring systems shall be integrated with the unit control panel. Readings shall be expressed in micrometers for amplitude and axial position. Acceleration signals shall be integrated to read velocity in mm/s rms. Alarm indications shall be latched type. All indication and alarms displayed on the vibration monitoring system shall be capable of display on DCS via a serial communication link. The monitoring instrumentation shall conform to API 670 “Non contacting Vibration and Axial Position Monitoring Systems” as appropriate. Vibration monitoring device shall have a LCD display screen which shall be   capable of performing bar graph graphics.

Vibration Monitoring shall be mounted on the respective rotating equipment’s PLC cabinet. Each vibration sensor shall be treated as a separate sensing circuit with individual monitoring display.

PRINCIPLE INSTRUMENTATION OF PETROLEUM PLANT

Instrumentation System Overview

Petroleum plant shall have instruments for measurement and control that are of field proven design and high quality.

The various instruments involved mainly cover the following:

• Flow Instruments: Integrated orifice plate, senior orifice fitting, restriction orifice,        multivariate flow transmitter, coriolis meter, V-cone meter
• Level Instruments: Level gauge glass, displacer (external) type, float type for level transmitter and level switch 
•  Pressure Instruments: Electronic pressure transmitter, pneumatic pressure transmitter, pressure switch, pressure gauge, pressure indicating controller, pressure differential indicator
• Temperature Instruments: Electronic temperature transmitter, temperature gauge, temperature switch 
•  Fire and Gas Detectors: IR3 Flame detectors, UV/IR Gas detectors, Fusible plug 
•  Valves: Control valve, solenoid valve, on/off valve/actuator, pressure safety valve, pressure regulator valve 
•  Miscellaneous: Instrument cables/Trays & accessories, instrument mounting/hook-up accessories, power supply distribution facility, multi-cable transit block, instrument calibration/maintenance tool, etc.

Instrumentation in Package Unit

Instruments for package units shall fully follow the guidelines, philosophy and standards that defined in this specification for selection, design, and installation.

The instrument package vendor shall fully equip all related instruments and control, and services necessary to ensure the delivery of a fully operational package. Package vendor shall be responsible for the project liaison and detailed engineering of all his equipment, instrumentation, and materials manufacturers, fabrication, assembly, calibration, and their quality of workmanship in complying with this specification.

Hazardous Areas

All instruments located in hazardous areas shall be certified & approved for use in accordance with the applicable area classification.  All outdoor instruments and related equipment shall as a minimum be certified to NEMA 7 for installation in API 500 Class I, Division 1 hazardous area, or Division 2 as required by classification drawings.

 The vendor must provide test certificates & approval certificates from statutory authorities like UL or FM for all instruments and related equipment as applicable for weather protection or for their use in hazardous areas.

Environmental Protection

All instruments, enclosures and related equipment installed in open areas of the facilities must be certified to NEMA 4X for weatherproof requirement. All field instruments and associated equipment shall be manufactured of materials suitable for service under the specified environmental conditions over the design period. All field instruments, structural supports and frame works manufactured of carbon steel.

THE PIPING VALVE TYPE

Primary isolation valves shall be shown on the P&ID and identified in accordance with valve identification number. Isolation valves shall be provided for all instrument connections, isolation of equipment that can be serviced when bypassed, multiple (spare) pump installations, etc.

The valve type shall be in accordance with each specific piping material class specification no. Valves description will as given in the valves specification no.  All valves shall be furnished with manual operators unless specified otherwise.

Gear Operators, as furnished by the valve manufacturer, shall be provided for large valves which satisfy both of the following conditions:

Class 150 rating	10” size and larger
Class 300 rating	8” size and larger
Class 600 & 900 rating	6” size and larger
Class 1500 & 2500 rating	4” size and larger

Gear operators shall be sized such that its output torque is at least 1.5 times the maximum required operating torque of the valve proper and shall be suitable for operation in a tropical environment.  The gear ratio shall be maximum 1:60 for valves NPS 8 and smaller or maximum 1:120 for valve NPS 10 and larger.  Gear operators shall be self locking and be provided with a position indicator.

All valves shall be capable of being locked in the open or closed position with a positive position locking device other than chain.

Block valves shall in general be ball valves of fire safe design in accordance with API 607/API 6FA or equivalent and a copy of the certification shall be provided. Butterfly valves may be used in cooling water services. Globe valves will be used when throttling is required.

Valves shall be provided with pressure equalizing bypasses when high differential pressure exists across the closed valve. Valves for which bypasses are to be furnished and the size and type of bypass valve will be shown on the applicable flow diagram.

All 2” size and larger valves shall have flanged ends. 1½” and smaller size valves shall have flanged or socket weld ends.

Check valves will be provided for all lines tying into common headers, or to prevent back flow.

Flanged end valves which are described as outside screw and yoke (OS&Y) in the valve classification tables shall be provided with stem protectors.

Globe, ball, check, and slab-type gate valves shall be field repairable. Balls, seals and seats shall be replaceable without welding or cutting.

Valve dimensions shall be identical to the dimensions specified in ASME B16.10, Face-to Face and End-to-End Dimensions of Ferrous Valves.  Face-to-face dimensions shall be long patterns.

All valves except check valves shall be capable of sealing with design pressure applied from either end of the valve.

Unless otherwise specified, valves shall be suitable for oil, water, and gas service throughout the temperature range of the pressure class.

Double seated valves capable of sealing simultaneously against pressure differential from the bonnet section to the adjacent pipe in both directions shall be equipped with self relieving seals.  Valves ANSI Class 900 and above shall have ring joint faced flanges in accordance with ASME B16.20 Ring-Joint Gaskets and Grooves for Steel Pipe Flanges unless otherwise indicated.

Vent and drain valves shall comply with the requirements of the valve classification tables and shall be adequate for the pressure and temperature limits indicated on the material and service classification data sheets.

Valve pressure-class ratings shall be in accordance with ASME 16.5.

For testing of valves, API standard 598, Valve Inspection and Test, or API specification 6D, Pipeline Valves, shall be used as a basis.

Unless otherwise specified on the piping material classification data sheets, gate valves shall be outside screw and yoke (OS&Y) with a rising stem, a bolted bonnet, a bolted packing gland, and a solid wedge gate.

If resilient seat inserts are used, the inserts shall be capable of withstanding the maximum temperature encountered in the service application.  Teflon or reinforced Teflon seat insert is preferred.

Valve seats and seals in service ASME Class 900 rating and above shall be specified explosive decompression resistant.

In general reduced bore isolation valves shall be used in all except the following circumstances:

a.     Manifold valves.

b.    Piggable lines.

c.     Pump suctions.

d.    On drain lines subject to potential blockage.

e.     Where the bore velocity would cause unacceptable pressure loss, noise, erosion, or exceed supplied specified limits for corrosion inhibitor film stability

The valve stem shall not be retained by the packing gland.  A shouldered stem with bottom entry is preferred.

The sealing characteristics of ball valves shall not be impaired by rapid temperature changes or in throttling application.

The following restrictions apply to ball valves installed by socket welding or seal welding:

a.     Installation of ball valves by socket welding, seal welding and stress relieving shall not damage the valve seats.

b.    For all socket weld valves disassembly during the installation will be required.

Check valves other than the check valves listed in the piping material classification data sheets may be required for certain service conditions as given below.

Piping Sizes	Check Valves
2 Inches and smaller	Lift type (ball, piston or disc)
3 Inches and larger	Spring actuated, double flapper type

a.     In services with fluids moving at high velocities or with pulsating vapour flows, piston check valves shall be used.

b.    In severe service applications, non-slam check valves with hydraulic (or another type) damping devices shall be used. Lines 8 inches and larger in services that do not require non-slam devices may use spring-actuated double-flapper type check valves.

c.    Centrifugal pump discharge check valves shall be of either the lift disc; balanced tilting-disc or spring actuated double-flapper type

Check valves shall be provided with drains on the downstream side of the check if required for safe operation and maintenance.

Wafer type check valves may be used as an option to flanged swing check valves in ANSI Class 600 and lower.  Wafer check valves shall be designed to API Std 594, Wafer and Wafer-Lug Check Valves.

Butterfly valves shall be limited to water and air service.  Wafer lug and wafer drop-in type butterfly valves shall normally be used.  Butterfly valves shall be designed to API Std 609, Lug and Wafer Type Butterfly Valves.

INSTRUMENTATION AND CONTROL PLANT SYSTEM

The objectives of Instrumentation and Control System to be installed on petroleum facilities are as follows:

• Distributed Control System (DCS)

• Emergency Shutdown (ESD)

• Fire and Gas System (F&G)

• Package Equipment Systems

• Field Instruments

• Analyzers

Instrumentation and Control System will be interconnected with field instruments, F&G detectors, F&G monitoring, RIO (Remote Input Output), DCS and PLC, Overall Process Control and Safety System. Data parameters in each clusters of block station will be gathered by DCS System trough Remote Input Output (Note: RIO system is provision for future expansion) Unit in Each cluster area to The Distributed Control System ( DCS ) System which will be located in Local Control Room .

The DCS provides manual supervisory and automatic regulatory control, execution of interlock and sequence logic (except safety critical), provision of alarm and status information. The DCS is connected to the other systems in the plant to collect the plant operating status and alarm information. DCS shall be capable of future interfacing with Advanced Control, Optimization and Energy Monitoring Systems. The basic regulatory control is provided for normal start up, operation, and shutdown to achieve the required product throughout and specification.

The manual supervisory control is via the Operator Consoles in the Main Control Building. The automatic regulatory control, sequence logic, data acquisition is carried out in the     Local Control Room. Typically the DCS will consist of controllers and signal input / output cabinets where the controller program / logic are executed. These controllers located in the Local Control Room and are connected via a computer data highway to the Operator Console computers. The controllers also acquire alarm and status information and transmit it to the Operator Console via the data highway. This allows manual supervisory control by the control room Operator. The Control Room consoles allow the plant status to be viewed, and any changes to the plant set points to be entered and to be sent via the data highway to the controllers. Alarm and Event printers shall be provided for each plant as required by the Licensor.

The ESD system provides the plant protection system. It protects the plant against defined conditions such as high temperature, high pressure etc that may take the plant beyond the design limits. The ESD system shall be divided into the Process Safety System and the High Integrity Shutdown systems to provide the appropriate reliability proportional to the hazard, and based on the appropriate technology. The Process Safety System shall be provided to reduce the frequency of relief valve operation (to reduce flaring and upstream / downstream upsets), to provide protection against minor mechanical damage to the plant, contamination of the product or other systems leading to minor loss of availability  or serious injury to personnel. Minor damage is defined as damage to items that can be replaced within days from spares or longer if a redundant unit can provide back up to continue operation. The logic will be specified by the process licensor. A High Integrity Shutdown System may be required in a limited number of defined circumstances to protect against major / catastrophic equipment damage leading to a long period of shutdown and / or multiple loss of life. Such circumstances shall be identified by the Process Licensor. Major equipment damage is defined as items not available as replacement from spares, requiring long lead time to replace and not provided with back up units to allow operation to continue.

The Fire and Gas system will provide any necessary electronic as opposed to mechanical monitoring for the presence of fire and to provide detection of hydrocarbon or hazardous gases. These detection systems are only applied to areas where there is a significant risk of fire or gas release or significant volume of Hydrocarbon Storage. These will be identified by the Process Licensor. The purpose of the Fire and Gas system is to alert the engineer and where necessary personal local to an incident. The Operators having been informed of the incident can then manually initiate action to control the situation. This action will be in the form of fire fighting, evacuation and where appropriate manual initiation of process shutdown and containment via the ESD system. It is mandatory that manual pushbuttons shall be provided on the Operator Console for this purpose.

There are several items of Process equipment that have integral control and protection systems. For example a generator turbine will generally be purchased complete with a governor for speed control, pressure regulators for gland steam and lube oil control. In most cases has a full understanding of how to control the equipment to keep it with in design limits, and is therefore best placed to specify and procure such equipment as may be required. If these controls are provided by a third party there may be warranty problems in the event of an incident, and there is also a risk that the control scheme may be less than effective. The specification of protection logic systems is generally simpler than control systems and therefore it is not unusual for this to be provided by a third party as an integrated part of the ESD system. In such cases, however, the engineer shall provide the logic description / specification of the equipment to be protected. It is envisaged that this policy will be applied, depending on the equipment involved. For example a Gas Turbine Generator would be supplied with all controls and protection equipment. All such systems will be located in the Plant Engineering Control Center or integrated outstation with air conditioned and clean environment for maximum reliability and ease of maintenance.

The field instrumentation provides the data to the Control and Protection systems. These will consist of individual electronic instruments via single pair cables marshaled at local junction boxes. These junction boxes will be connected to the Local Control Room (refer section 1.5.1)   equipment via multicore cables. The signals will generally either be 4-20mA or on/off status using 24Vdc or 230Vac where volt drop is a problem. The use of field bus/multiplexing systems will only be considered for non-critical indications where cabling would be simplified or where it is part of a standard equipment package. The field instruments will be located outdoors in a tropical, coastal, dusty environment, and in areas at risk of having explosive gas mixtures. They will therefore be designed accordingly with the necessary weatherproofing IP55 and IEC hazardous area certification.