SCADA And Telemetry In Gas Transmission Systems

February 2015, Vol. 242, No. 2

Russel W. Treat, President and CEO, EnerSys Corporation, Houston

SCADA systems provide combinations of field devices, communications infrastructure and software integrated into a system that provides for safe and reliable operation of remote facilities.

Producers, gatherers, midstream operators and pipelines use SCADA system for operations. In addition, SCADA gathers data used by advanced applications such as measurement accounting. SCADA is an important key for highly profitable operation.

The physical connection of the SCADA system to the pipeline is the instrumentation. It is connected to programmable logic controllers (PLCs), remote terminal units (RTUs) or flow computers, depending on the type of remote station. Data then flows from remote devices through the communications network to the SCADA host, also referred to as the SCADA master or master station.

Examples of applications at the top of the pyramid would be advanced control and optimization applications used by the gas controllers as well as business applications, such as back-office measurement and marketing used by other departments within the company.

SCADA Topology

The previous diagram is a functional component view. Another way to depict the system is by SCADA system equipment and the physical connectivity, referred to as a topology diagram. The term “field device” refers to the automation device installed at the remote facility to provide data collection, automation and communication to the SCADA host.

• PLCs are programmed to perform critical process control and typically require AC power and some level of environmental control and programming. PLCs are generally used at larger facilities.
• RTUs are smaller, low-power, lower-cost devices primarily used to convert electrical signals from instrumentation to data, and to make that data available to the SCADA host.
• Electronic flow monitors (EFMs) are special, for-purpose RTUs build to measure in compliance with the various API and AGA standards. In addition, EFM creates an auditable record of measurement and makes this auditable record available to the measurement back office.

The term “station” refers to the remote facilities. In natural gas pipeline you typically find compressor stations, valve stations and meter stations. Larger facilities, such as gas storage, gas processing and fractionators in midstream, can also be considered stations. Basically, stations are remote facilities that affect the operation of the pipeline.

Each compressor typically has its own unit PLC, supplied by the compressor manufacturer. These are interfaced to a station PLC that aggregates the unit data as well as station-specific data such as pressures, valve positions, liquid levels, power information, fire and gas detection, and analyzers. The SCADA host communicates with the station PLC.

Most compressor stations have a local human machine interface (HMI) so that a local operator can view station information. Although there is often a meter station at or near the compressor station, the meter station is usually handled separately.

It is not uncommon for large compressor stations to have dozens of PLCs and multiple HMIs. These stations may also serve as communications hubs to pick up data from nearby valve and meter stations. In total, millions of dollars of automation and communications equipment might be installed at a major compressor station.

Meter stations can range from small, single-run stations to large multiple run, bi-directional stations. Common primary measurement elements are orifice meters, turbines and ultrasonic meters. The EFM is used to perform measurement complaint to AGA and API standards.

Logic and controls for tube switching, pressure regulation, heaters, valves and odorant control may be provided by the EFM or by an additional PLC or RTU. Some meter stations have local HMIs although it is more common for the operator to interface remote device via a laptop.

Valve Stations are the simplest station on the pipeline. A small RTU is installed to monitor pressure – often both upstream and downstream of the valve – and to support remote operation of the block valve by activating remote control commands to open and close the valves and indicate current positions.

Historically, SCADA was supported by narrow band, serial communications technologies using satellite or data radios. While much of this equipment still exists in the field, wireless communications are undergoing radical and accelerating change, particularly with regards to cellular and newer Internet protocol (IP) radios.

Whose life hasn’t been changed by the communication revolution? High-speed digital communication is available almost everywhere. For SCADA, moving data from the field to the host has become almost a no-brainer.

Most major gas transmission companies have extended their wide area networks to at least their major compressor stations. Smaller stations, or more out-of-the-way sites, are easily picked up by inexpensive spread spectrum radios and mesh networks, which use the IP communications protocol, for example. Even satellite costs, both hardware and time, have decreased drastically.

When a SCADA topology diagram is used to describe the various hardware components and the physical (Ethernet or serial wires) connections in a SCADA system, a SCADA data flow is used to describe software connections and the logical connections (protocols).

The primary purpose is the real-time operation of the pipeline. To meet this requirement, the following major functions are performed:

• Communication with the field devices
• Processing and storage of data in the real-time database
• Arrangement and storage of real-time data
• Visualization data is transmitted to controllers
• Alarm data functions when defined operating limits are exceeded

The diagram below provides a simple SCADA data flow diagram.

The SCADA host must be capable of interfacing to the various communications circuits employed to communicate with field devices. The hardware interface is the easy part; more difficult is the software interface between the host and the field devices. Put another way, the arbitration of numerous asynchronous (serial) connections from the synchronous (IP) processes.

It is not uncommon for a major gas transmission company to have 10, 15 or even more different types of PLCs, RTUs and flow computers installed on the pipeline, each communicating through a different serial protocol.

There have been attempts to establish gas industry protocol standards, such as Enron Modbus, but for the most part, it is still a requirement that the SCADA hosts have a library of protocol drivers to handle the wide variety of devices. The software must be able to support backup communications paths to key stations.

Real-Time Database
The core of a SCADA system is the real-time database where all the data from the field is processed and stored. For a large system it must be capable of handling hundreds of thousands of data points quickly and robustly. The database is memory-resident – meaning all of the data is stored in the random access memory (RAM) of the server, not on the disk. Alarm processing, control sequences and other functions are all performed by the real-time database.

The real-time database also provides data to the human machine interface (HMI) typically installed on operator workstations, as well as to other real-time applications such as leak detection. The real-time database often runs on two servers in redundant fashion to provide nearly total availability.

The HMI or client software is the graphic display environment used by the gas controllers to view and control the pipeline. Examples would be situation overviews, area overviews, overview maps, station displays and control pop-ups.

Advanced Applications
Line Pack – Advanced applications are those software components that provide specialized functionality. Line pack and draft calculations are examples. These applications are used to calculate the natural gas inventory in the pipeline. It would not be unusual for a major pipeline to have well over 1 Bcf of storage available to meet deliveries. The line pack application requires that the user input the pipeline segment data (length and diameter). The application acquires real-time pressure measurements (and temperature and gas composition, if available) from the SCADA system. The calculated information on line pack is returned to the SCADA system for display to the gas controllers.

Gas Scheduling – Another common application is Gas Schedule Tracking. This application takes the gas plan from the nominations system and compares it to the real-time flow values to help the controller meet the receipt or delivery requirements.

Real-time Transient Models – Many gas transmission companies have built numerical hydraulic models for both offline and online uses. One of the primary online uses is leak detection. The actual pressure and flow readings from the SCADA system are compared with the modeled pressure and flow readings. Discrepancies could indicate a leak. Other model-based applications include the following:

  • Look-ahead simulation
  • Survivability analysis
  • What-if analysis
  • SCADA data validation
  • Flow studies for smart pigging

Models are also used to build training simulators. With a training simulator, an offline copy of the SCADA system is connected to a model that simulates the pipeline. An instructor, through a training console, introduces an upset in the model which propagates through to the SCADA system. The trainee operates the SCADA console as if he was operating the pipeline.

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