Oil and gas engineers face a major problem in accurately and reliably measuring and monitoring the various fluids that are introduced into oil pipelines from well site pumping stations. A thorough understanding of both the oil separation process and the properties of valves and actuators is required to correctly specify a system that will sufficiently measure and monitor these various types of fluids. Also, the conditions downstream from each well are different, requiring valves and actuators to be highly customized to their specific role in the process.
Existing pipeline equipment is often outdated and lacks the ability to deliver the performance and reliability of modern measurement and monitoring technology. However, it is costly and time-consuming to replace an entire monitoring station on a pipeline. The solution is to retrofit customized valves and actuators onto existing monitoring stations, thus improving performance and reliability while minimizing cost and time investments.
The key to correctly specifying valve and actuator pairs for pipeline monitoring stations is to match the process conditions with the equipment that will ultimately provide the greatest control. These process conditions include pressure, temperature and the composition of media within the pipeline including the type of material and the percentage of distribution of that material.
Pipeline Process Conditions
Pipeline retrofit projects each have a very specific set of process conditions that process engineers have to carefully consider in order to create the most reliable and accurate measurement system. For example, common line sizes vary from 2 to 14 inches along a pipeline. Well site flow rates can reach 1,200-1,500 bpd when the well is first brought on and then settle down to a 200 bpd volume for the longer term.
This varying amount of liquid flowing into the pipeline can cause a wide variance in flow rate within the pipeline. As these flow rates change over time, valve settings often need to be adjusted to compensate. Also, many valve and actuator combinations that were installed over a decade ago do not meet new measurement standards for many pipeline operations.
Pipeline monitoring station pressure often fluctuates from 25-250 psi, and temperature variation can be significant, depending on location and climate, generally 40-160°F. The material in pipelines is generally all liquid, but gas or solids have the possibility of entering the system if there is a malfunction upstream. These are additional conditions that require further customization of valves and actuators being retrofitted to individual systems.
Standard Pipeline Monitoring Equipment
In all monitoring stations attached to pipelines, it is necessary to maintain constant back pressure to keep pressure in the system, prevent gas from entering the system and achieve accurate measurement. This is normally accomplished using a self-operated back pressure regulator valve with no feedback or control system available. This is a less expensive valve with no automation option necessary to make any error corrections.
While self-operated pressure regulators are able to make corrections based on flow and pressure fluctuation, their capabilities are very limited and can cause inconsistent back pressure. For example, if the regulator is set at 100 psi, the actual pressure can vary by plus or minus 10 psi. This is known as the “droop” of a self-regulating valve, an inherent feature of these inexpensive pieces of equipment.
Additionally, when the regulator is set at a specific pressure, it is also set at a matching flow rate. When this flow rate increases or decreases, the pressure naturally changes along with it. A pressure regulator will not be able to adequately respond to these changing conditions and may result in damage to the system or inaccurate measurements.
This self-operated pressure regulator is one example of a generic piece of equipment that could be significantly improved by retrofitting an upgraded valve and actuator that are specifically customized to match the process conditions of the system.
Also, while most isolation valves on pipeline monitoring stations are manual quarter turn due to industry price concerns, newer functionality available using supervisory control and data acquisition (SCADA) systems have convinced many to upgrade to automated valves. These upgrades are readily available, assuming that process conditions can be adequately handled by the new equipment.
Matching Retrofitted Valves and Actuators to Process Conditions
When retrofitting new valves and actuators onto an existing pipeline measuring and monitoring system, it is vital to consider the existing equipment and adjust the specifications accordingly. A failure to do so could result in more severe problems than the original system.
In the example of the self-regulated valve, a process engineer would take the unwanted pressure variance into consideration and determine that an automated control valve would be required to meet the needs of the system. There can be other automated valves in a system that affect pressure such as a distribution center with multiple well sites feeding into one pipeline. The default actuator in this situation would be a lower-cost pneumatic actuator if an air compressor were available.
An electric actuator is the alternate choice due to electricity available at all monitoring stations. In the case of a pneumatic actuator, a diaphragm-type actuator would be preferable if increased positioning accuracy is needed, but if no compressed air is available to power a diaphragm actuator, then a high-performance electric actuator would be used instead.
As stated above, the flow rate of each well feeding into a pipeline can range from 1,200-1,500 bpd before decreasing to just 200 bpd after several months. As more wells feed into the pipeline, the flow range can vary significantly over time. Valves and actuators on monitoring stations need to be adaptable to meet the demands of these changing process conditions. This change in flow could create an additional challenge in states that require measurement to be proved on a regular basis.
In this application, the measurement system OEM designed a system with regulators and manual isolation valves. Because of the wide variance in flow rate, the regulator could be led to operate in an unstable manner during low flow conditions or could create a choke flow condition during high flow. Choked flow is the point where the pressure drop across the valve orifice has reduced the actual pressure below the media’s vapor pressure. Under this condition, fluid is flashed to gas and the downstream measurement is inaccurate, making the meter nearly impossible to prove.
To improve the accuracy and reliability of the measurement, the solution was to design a system that would allow for a wide variation in flow rates over time. A PLC-based solution was implemented that would sense flow rate via a Coriolis meter while utilizing a program that took into account the rapid changes between high and low flow rates. It was vital to choose a control valve that had suitable rangeability to manage the extremes in flow rates.
Rangeability in a control valve is the amount of capacity that the valve can physically handle. It is determined by dividing the highest possible flow rate by the lowest possible flow rate and expressed in a ratio, e.g. 10:1. While self-operated pressure regulators commonly have a rangeability of 10:1, more robust control valves can offer performance up to 300:1. This higher performance allows the control valve to be more adaptable to changing flow rates while still achieving accurate measurement.
In the example application above, the choice was to utilize a segmented ball valve design which has a nearly full flow characteristic in the open position, and a tapered slot on the low end of the valve stroke which will control and pass the appropriate flow rates. This valve has an equal percentage characteristic, meaning that equal changes in valve position produce equal percentage changes in flow capacity. This means there is finer resolution for control on the lower end of the valve stroke and high-capacity changes on the upper end of the stroke.
The actuator that was chosen was an electric actuator. This was preferable because the maintenance of a pneumatic system in the very cold environment at this particular site was becoming a burden to the operations and maintenance teams involved. The actuator has a high accuracy electronic modulating card with feedback, internal heater and battery backup so the valve would move to a desired position in the event of a power loss.
This integrated solution has allowed the oil company to keep its measurement-monitoring system operating while reporting flow rates within the state’s required accuracy standards. This was completed while retaining the majority of the existing equipment with only a few retrofitted upgrades to the control system, and control valves properly suited for the process conditions of the application.
For further information, visit to http://www.custodytransferlact.com/
Author: Ray Herrera is Vice President of Business Development for the Process Control Division at Valin Corporation. He has over 25 years of experience sizing, selecting, selling, and servicing process control equipment specializing in control valves and instrumentation. He holds a B.S. in industrial engineering and A.S.T in electrical engineering technology.
LACT Unit 3