Process Control System Integration and Interface with other Disciplines

This article is about technical requirements for connecting Process control system with other disciplines like Emergency Shutdown Systems and Burner Management Systems, Vibration Monitoring Systems, Compressor Control Systems and DAHS.

Integrating and Interfacing with PCS for Optimal Performance

As Process Control Systems (PCSs) become more complex, the need for effective integration and interfacing of PCS with associated subsystems and auxiliary systems grows. This article will explore the general requirements for integrating and interfacing PCSs with emergency shutdown systems, burner management systems, vibration monitoring systems, and more. We will also provide best practices for configuring and utilizing these systems to ensure the highest levels of performance.

General Interface Requirements for PCS

When integrating PCSs with other systems, it is important to ensure that standard hardware and software devices are used in order to comply with industry standard protocols. Modbus TCP/IP is typically the preferred choice for transferring critical, real-time data, while Modbus Serial may be used for systems which do not support Modbus TCP/IP. OPC Version 2.0 or higher is also acceptable for monitoring points, history data, and alarms and events. It is important to note that this requirement does not apply to subsystems designed and manufactured by the PCS vendor which reside on the same control network; in this case, the vendor’s standard method of communication should be utilized.

In addition, redundant communication interfaces should be supplied for any interface which is used to send commands from the DCS to an auxiliary system for operation and control. This requirement applies to both the DCS and the auxiliary system’s interface. In cases where an auxiliary system does not support a redundant interface to the DCS, hard-wired I/O for control commands with data used for monitoring only transmitted through the communications interface should be considered.

Time Synchronization for PCS

Time clocks for all stations which are part of the PCS should be synchronized to 100 milliseconds or better. The preferred method for synchronization of all stations connected to the PCS is time synchronization using Global Positioning System (GPS) and a networked time server which supports Simple Networked Time Protocol (SNTP). Synchronization should be performed at a minimum of once every 24 hours.

Interface to Emergency Shutdown Systems and Burner Management Systems

When integrating PCS with Emergency Shutdown Systems (ESD) or Burner Management Systems (BMS), communications should be via dedicated, redundant communications paths. It is important to ensure that there is no single point of failure in the system which would result in the loss of communications between the DCS and ESD or BMS system.

In order to ensure the highest levels of performance, it is important to configure “first out” and “sequence of events” (SOE) logs. First out refers to the specific variable or tag which initiated the shutdown of a particular process or equipment, and should be configured in the system initiating the shutdown. ESD systems should be configured to record “first out” data as specified in SAES-J-601 Section 10.7. First out messages should initiate a high priority alarm to the DCS operator console responsible for monitoring of the equipment, and the tagname, description, time & date and process value of the parameter which initiated the trip should be shown on a DCS process display associated with the equipment or process whenever a shutdown has occurred.

SOE logs refer to a chronological listing of all event messages from the ESD system, and should not be configured to initiate a process alarm at the DCS operator console. The system should be configured to enable console operators and engineering / maintenance personnel to view SOE logs from their respective consoles, and the message repository should be configured to automatically overwrite older messages when the maximum number of messages has been reached.

Input Bypasses for PCS

All inputs to shutdown logic should have an input bypass switch to facilitate maintenance and testing. Bypass switches should be software configured using a mechanism to restrict access to activation or de-activation of the bypass. Status indication on the primary operator graphic should be visible whenever an input bypass is activated, and activation and de-activation of an input bypass should initiate an alarm at the primary operator workstation. Activation and de-activation of an input bypass should also be recorded in an operator event log with time & date, tag ID and station from which the activation occurred.

The system should be configured to re-alarm input bypasses at the DCS once every 24 hrs for the period of time during which the bypass is active.

Startup Bypasses for PCS

Startup bypass systems should be configured for devices which would prevent the normal startup of plant equipment, such as minimum flow for a pump, etc. Startup bypasses should be configured in the system initiating the shutdown for the equipment, and should be automatically activated when all startup permissives have been met (i.e., ready to start is active). Automatic startup bypasses should be reset automatically by the system whenever the equipment is started successfully or after a time period not to exceed thirty minutes, whichever is sooner.

Interface to Vibration Monitoring System

When integrating PCS with Vibration Monitoring Systems (VMS), communications should be via dedicated, redundant communications paths. Modbus TCP/IP is typically the preferred method. All inputs to the VMS systems should be transmitted to the DCS for display at the primary operator console, with real-time values transmitted once every two seconds as a maximum scan time.

The DCS to VMS link should also be configured to enable the console operator to bypass individual vibration probes or bearing temperature sensors from the primary operator screen at the DCS. A separate graphic for each equipment or equipment train (i.e., pump, gearbox, motor) should be created to display VMS data, with high and high-high alarms visually indicated on the process graphic when active. Individual bypass indicators for each VMS tag should also be shown on the display, with the ability to bypass an individual vibration probe or temperature sensor within the VMS system from the operator console. Activation of a bypass should be logged in the system as an event with the time / date it was activated and the login ID of the operator who activated the bypass. Lastly, the display should contain a selection box which will call up a real-time trend for all VMS data associated with the equipment or equipment train.

Introduction to Compressor Control Systems

Compressors are an integral part of many industrial processes and are often used to provide pressurized air or other gases for various applications. As such, it is important for compressor control systems (CCS) to be properly designed and maintained to ensure optimum operation and efficiency. This article will discuss the interface between the DCS (Distributed Control System) and CCS, including the requirements for communications and graphics, as well as the interface to long-term data acquisition and historization systems (DAHS) and third party packaged systems. We will also discuss the interface to electrical substation equipment.

Interface Requirements between the DCS and CCS

For efficient and reliable operation, CCS must be properly integrated into the overall DCS. To ensure this, the following requirements must be met for communications and graphics between the DCS and CCS:

Communications between the DCS and CCS

Redundant communications modules and paths must be used to ensure reliable communication between the DCS and CCS. Critical alarms generated in the CCS must also be transmitted to the DCS for annunciation at the operator console responsible for operating the machine.

Graphics for Compressor Operating Display

The DCS must be configured with a set of graphics for each compressor. As a minimum, three graphics are required for each machine: a compressor operating display, a compressor performance display, and a compressor equipment status display.

The compressor operating display must show the entire compressor recycle loop on a single graphic. This graphic must contain process data for all critical variables associated with the compressor, including but not limited to suction pressure upstream of the suction throttling valve (if present), compressor KO drum level, compressor suction pressure, temperature, and flow, compressor discharge pressure and temperature, gas temperature downstream of an exit cooler, compressor motor HP or amperage, and recycle valve position.

For multi-staged compressors, the compressor operating display may be designed using a single display per stage.

Compressor Performance Display

The compressor performance display is intended to show parameters critical to the operation of the compressor anti-surge control and compressor load-sharing (if applicable). The display must contain a live compressor operating map which shows the location of the compressor operating point with respect to the ASC control line. Data displayed on the compressor operating map must be transmitted from the CCS to the DCS for indication and must not be calculated within the DCS.

Where load-sharing is configured for a compressor, a separate ‘load-share’ display must be developed. This display must indicate the value of the load-share variable for each compressor, the position of the load-sharing manipulated variable for each compressor, and the PV, SP, and MV of the overall load-share control loop.

Compressor Equipment Status Display

The compressor equipment status display must show process data associated with auxiliary systems used to support the operation of the compressor. These must include, but not limited to, lube-oil circulation systems, mechanical seal systems, vibration and bearing temperature monitoring systems, and turbine control systems for turbine driven compressors.

Interface to Long-term Data Acquisition and Historization System
The interface between the DCS and DAHS must comply with the requirements set out in 23-SAMSS-072 Section 9. The system must be configured to have the DCS OPC Server communicate with the DAHS OPC client.

The DCS OPC server must support Data Access (DA) and Historical Data Access (HDA) functionality to enable backfilling of data in the event of communications disruption. The design of the interface must consider segregation of tags by major operating area into separate interfaces or scan nodes in order to distribute loading. All field inputs, controller PV, SP, and MV values, and other critical process data must be configured to be transmitted to the DAHS. Scan rates for DAHS tags must be defined in the DAHS system and the system design must ensure that scan rates do not produce excessive loading on the DCS modules and/or control networks.

Interface to Third Party Packaged Systems

Where PLCs or stand-alone control systems are provided to control process equipment supplied by the equipment manufacturer, the PLC must be integrated into the PCS. All critical variables monitored and/or controlled by the PLC must be transmitted to the PCS for display on process displays on the associated operator console.

If supported by the PLC, PLC device status indication must be transmitted to the PCS for monitoring and alarming at the operator console responsible for the equipment. The requirements for interfacing of third party packaged equipment must also be met.

Interface to Electrical Substation Equipment
The requirements for the interface between the PCS and electrical substation equipment must also be met. The use of OPC, Modbus, or IEC-61850 protocol for transferring run status of individual motors and for monitoring of the status of electrical equipment is acceptable. The use of OPC, Modbus, or IEC-61850 protocol for sending commands (e.g. start/stop) to electrical substation equipment must be limited to non-critical motors only.

The requirements for segregation of redundant equipment in the PCS must apply to commands sent from the PCS to electrical substation equipment. If the interface between the PCS and the substation automation system is implemented as a single interface on a plant-wide level (PSA Level 3 as per SAES-P-126 item 9.3), the PCS interface must utilize redundant interfaces.

Conclusion

Integrating and interfacing PCS with other systems is a complex process which requires careful consideration of hardware and software requirements. This article has explored the general requirements for integrating and interfacing PCSs with emergency shutdown systems, burner management systems, vibration monitoring systems, and more. We have also provided best practices for configuring and utilizing these systems to ensure the highest levels of performance.

Compressor control systems must be properly designed and maintained to ensure optimum operation and efficiency. This article has discussed the interface requirements between the DCS and CCS, including the requirements for communications and graphics, and the interface to long-term data acquisition and historization systems (DAHS) and third party packaged systems. We have also discussed the interface to electrical substation equipment. By following the requirements outlined in this article, CCS can be properly integrated into the overall DCS for efficient and reliable operation.