Measuring the results of pipeline integrity technology

Pipe and pipeline integrity is always an issue whether the pipe is in a rack, below ground, or underwater.

Ian Verhappen
Industrial Automation Networks Inc.

Pipe and pipeline integrity is always an issue whether the pipe is in a rack, below ground, or underwater. As seen in recent years with offshore and onshore failures leading to environmental incidents, the challenge continues to grow as the infrastructure grows older. Fortunately, automation based solutions are available to help.

A mass balance calculation of the pipeline is the most basic form of pipeline integrity check, but offshore it is often multi-phase flow. However, until it has been processed on the FPSO this is often a very difficult calculation. Multi-phase flow pressure drop models do not yet have the same level of accuracy as single-phase gas or liquid flow calculations. As a result it is more difficult to determine if the pressure drop observed along the line is a modeling problem or due to changes in the fluid phases in the line as a result of different than expected temperature gradients. While offshore systems have significant temperature gradients to contend with such as ocean temperature changes, onshore pipelines tend to be buried deep enough that their "ambient" temperature is almost constant year round.

Leak detection relies on accurate pressure and flow measurements to balance the material in and out of the pipe. The American Gas Association and American Petroleum Institute developed standards to define the proper ways to measure hydrocarbon gases and liquids respectively. Companies can apply to have their measurement equipment (typically a combination of meter and flow computer) certified against these standards as custody transfer quality measurements. In Canada this authority is Measurement Canada.

Modern instruments with their microprocessors have several advantages over their predecessors in that they are able to continuously monitor not only the health of their own electronics but also the sensor used to measure the flow. For example, differential pressure meters used for orifice and venture flow monitor the frequency and amplitude of the pressure impulses in both legs and compare these over time to determine if one or both of the pressure taps are deteriorating (plugging). Therefore, action can be taken at an opportune time to resolve the problem before it affects the measurement itself. This is a simple form of flow assurance.

Differential pressure-based and other flowmeters are now capable of both measuring and reporting digitally multiple variables from a single device. Therefore, it is possible to use a differential pressure meter to measure both the flow and the bulk line pressure to calculate a pressure compensated flow, or use a vortex meter with integral thermocouple to calculate a temperature compensated flow. Integrated differential pressure meters with the orifice directly connected to the pressure sensors and a vortex meter with pressure and temperature compensation sensors are available to calculate mass flow of vapor or steam flows from one device. In addition to saving the cost of having to install and maintain separate meters with their associated process connection and cabling back to the control system, using integrated multi-variable sensors also saves space and weight both critical in the offshore environment.

Intelligence in devices extends to more than sensors as the same microprocessor-based technology is being used in "smart pigs" to measure the mechanical integrity of pipelines. "Smart pigs" are able to measure pipe thickness by identifying any deterioration, such as general corrosion or more significantly pitting, and correlate where these are to a location or distance along the pipeline. Hence if a problem is identified, the location to within a few meters is known. Because these tools effectively measure metal thickness, they are able to detect internal and external deterioration as corrosion can easily happen from outside pipe such as from a pinhole in the coating material.

Cathodic protection is a commonly used technique to protect pipelines from corrosion. Because of the widely dispersed nature of these protection systems, wireless networks are often used to gather the data from the various sites to the central processing area. In addition, a number of manufacturers now have continuous corrosion monitors that use a suite of electrochemical methods to determine a linear polarization resistance (LPR), which is a direct monitor of corrosion rate as well as a "pitting factor" to determine the likelihood of pitting corrosion occurring in addition to the general uniform corrosion of the pipe materials. These sensors tend to communicate wirelessly back to the data collection system which is able to use the resulting measurements with an appropriate model to estimate additional corrosion indicating parameters.

Pipe and pipeline integrity is a significant risk item. However, new tools and data processing management techniques when combined with new technology and accurate predictive sensors make it possible to reduce and manage risk. One challenge of having this information is converting it into useful metrics that can be easily understood and acted upon by operators and maintenance technicians in a timely manner. New standards such as ISA18 (alarm management) and ISA101 (human machine interface) are being developed to resolve that challenge.

The author

Ian Verhappen, P. Eng., is an ISA Fellow, ISA Certified Automation Professional, and a recognized authority on Foundation Fieldbus and industrial communications technologies. Verhappen operates a global consultancy Industrial Automation Networks Inc. specializing in field level industrial communications, process analytics, and hydrocarbon facility automation. He can be reached ativerhappen@gmail.com.

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