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01 May 2004

Pipelines dig the fieldbus

Foundation fieldbus is no longer a mere pipe dream.

By Ian Verhappen

In today's cutthroat oil-and-gas marketplace everyone is seeking ways to operate facilities more reliably at higher capacity for less money than ever before.

For pipeline operators the task is even more difficult due to the widely distributed nature of their facilities, in some cases spanning the continent or flowing beneath the ocean (often in environmentally sensitive or densely populated areas), transporting everything from water to flammable materials.

This is the type of environment where one should be certain of what is happening at every point along the way. Of course, producers and suppliers, operators, regulatory agencies, and governments—to get their royalties—also want to know how much of what is where, and to know it as accurately as possible as well.

Sophisticated software systems can closely monitor these pipelines, not only for potential leaks or failures, but also to estimate where a fault lies, if there is one. The ability to meet these demands of fault detection and custody transfer relies heavily on the instruments and control devices along the pipeline system, starting at the production and supply point, such as a wellhead or processing plant, through the various pumping and compressor stations and terminals to the final customer delivery point.

Fieldbus devices and networks provide an opportunity for improvements at many points and in many ways along this system.

A typical modern microprocessor-based transmitter analog signal loop engages in multiple conversions from digital to analog (D/A) and back again (A/D). Each conversion introduces a small error into the final measurement. Granted, with today's devices the error is minimal when compared against the reduction in accuracy due to the natural variation and noise in the process itself.

However, in the case of custody transfer, accuracy is more important. Fieldbus devices, being all digital, have only the A/D converter of the physical sensor itself. In fact some transmitters are indeed all digital, often being frequency based, right from the sensor.

Fieldbus systems also have a number of additional features to increase confidence in the information available to the pipeline operator, including:

• Process variable status at every measurement
• Built-in diagnostic capabilities including locally stored maintenance history
• Faster response to process changes

How do these items improve the operation of a typical custody transfer application such as a pipeline?

Avoid potential false alarm

Status: If operators are aware of the status—good, bad, or uncertain—of every process reading they receive every time, it gives them and the associated leak detection software more confidence in a reading. If the reading is other than good, it allows them to react accordingly.

The panel operator, or perhaps a computer-based maintenance system, can notify maintenance to repair the device, while the leak detection system will know not to include data from this sensor in its computations, thus avoiding a potential false alarm.

Diagnostics: When maintenance technicians learn that a device is about to fail or is already dead, fieldbus systems allow them to view the device from their shop before going to the field, so they can diagnose the problem in advance. This ensures they have the right parts and equipment with them to repair the fault in one trip.

Many device manufacturers are now taking these diagnostic capabilities one step further to include the ability for devices to predict their health and level of deterioration. This means a technician will be able to conduct regular electronic rounds or surveys of field devices, archive the information, and compare the rate of deterioration for every fieldbus device on the network.

True predictive maintenance will result, such as scheduling work when the best opportunity presents itself rather than changing something because it is time or worse yet, because of an unsettling emergency.

In addition, the device itself will store any changes made to its configuration in its memory. Typical information stored in memory includes the date of last change, the previous settings, and a technician identifier—who made the change.

Another advantage of using fieldbus technology is that each device requires about half the energy of its conventional analog counterpart, while providing far more information. A typical analog transmitter requires approximately 30 mA to power itself and its associated current loop, sending only one piece of information—the process variable. A fieldbus transmitter, on the other hand, uses about 18 mA and provides an array of additional information besides the process variable. This can be significant, particularly for remote operations where energy is at a premium.

Response: Foundation fieldbus (FF) systems also provide the possibility of tighter control closer to the set point because of their all-digital sensors and networked communications. By configuring a loop's scan/update rate to match the process response time, a more representative measurement and response to changing conditions will be possible.

As well, FF provides single-loop integrity with its link active scheduler (LAS) and back-up LAS technology. The LAS functionality allows control in the field and an associated level of reliability. An FF loop can continue to control to set point as long as there is power to and communication between the field devices in the loop. Therefore with a properly designed system, one can install a highly reliable system with local control/indication where the largest risk is loss of view remotely at the central control room.

Of course communication is a key piece of the control and custody transfer equation, and fieldbus high-speed Ethernet (HSE) technology makes it possible to communicate with remote sites in a single environment.

High-speed Ethernet uses conventional Ethernet technology as the physical layer while incorporating all the functionality of H1, including function blocks, in the user layer. Because HSE rests on Ethernet, it uses commercial-off-the-shelf technology such as switches, routers, and hubs to transfer data from one location to another. It also means that as Ethernet evolves and improves in speed it will be available for use in control, as represented by supervisory control and data acquisition (SCADA) systems, as well. In fact in many cases, just as today's SCADA systems share telephone and satellite communications with commercial and business transmissions to manage costs, the computer infrastructure used to connect offices in several locations into a common network can be used for Ethernet-based SCADA systems as well.

Configure or change a remote

The enabling technology for connecting H1 field devices to HSE is a linking device. Individual linking devices typically each accept two to four H1 networks, and multiple linking devices can connect through routers, switches, and hubs to accommodate the necessary number of signals at a facility.

Linking devices also include support for full redundancy, which means highly reliable communication, because if one device or signal route fails another is standing by to take over. HSE redundancy supports both redundant linking devices (i.e., operating and hot standby) but also redundant communication paths/Ethernet networks to the host system. In addition, because this is Ethernet technology one can use the Internet and Virtual Private Network (VPN) technology to communicate from one site to another as an additional way to manage system connectivity costs.

HSE incorporates H1 technology. The result is that the entire system is a single network, making it possible to access any device and its associated parameters from anywhere else on the network. As a result, one can access and if necessary configure or change a device at a remote pump station from the central facility. As a minimum, this type of information means maintenance teams will have everything required to correct a problem when they arrive at a remote site.

Each wellhead has a series of pressure, temperature, and control signals to manage the production rate from the reservoir. A single HSE linking device collects and concentrates these signals. Several wells come together at a separator facility where each phase of fluid is metered and possibly sampled and analyzed.

The custody transfer process begins through the measurement of each of the produced phases, typically hydrocarbon liquid, gas, and water. A single linking device should be able to integrate the signals associated with this unit operation.

Multiple separators feed the first compressor or pump station. This facility will likely have some form of human-machine interface (HMI) for the roving operator and maintenance staff to access the system. Because the control network leverages Ethernet, these local HMI stations simply become additional nodes on the network and need not be part of the traditionally proprietary control system offering.

The final stage of the collection process connects the multiple pumping and compressor stations to a distribution center that is also typically where the central system control facility resides. With gathering complete, the product or products now transfer across the continent to the remote markets, where the entire gathering process reverses, going from larger systems to smaller delivery points, where once again the custody transfer operation is completed. One company in Japan has taken a fieldbus-based system to the level where it has individual fieldbus flowmeters on liquefied natural gas delivery vehicles. These battery-operated meters, when reconnected to the network at the central station, are automatically recognizable to the control system, and the current readings transfer to the host. Due to the long distances involved along this network, the Internet with VPN tunneling technology frequently serves to connect the various nodes.

As one can see by this example, the networking capability, flexibility, and ability to expand to HSE, as well as the enhanced measurement and diagnostics of fieldbus and that of a pipeline system, are well suited to each other and should be considered the system of choice by automation professionals.

Behind the byline

Ian Verhappen is an ISA Fellow. He is director at ICE-Pros, Inc., an independent instrument and control-engineering consulting firm specializing in fieldbus, process analyzer sample systems, and oil sands instrumentation/control. Write him at Ian.Verhappen@ICE-Pros.com.