While industrial standards and protocols do an enormous amount of good for process industry manufacturers and suppliers, there are times when their generally conservative nature tends to lock in technologies and practices that are, or should be, obsolete.
Tim Wienke discusses just such a situation in his article in the January 2019 issue of Flow Control in an article titled API 18.2: Ensure Safety While Providing Better Level and Volume Measurement Options. He explains how the issuance of API 18.2 provides more options for oil producers than the old API 18.1 standard, providing a major advance for all concerned.
The situation he discusses is the procedure by which oil gets transferred from a well-head storage tank to a truck so it can be delivered to a refinery, a form of custody transfer. The procedure outlined in API 18.1 depends on manual measurements and requires operators to climb to the top of the storage tank at least twice to measure level using a tape, take multiple temperature readings of the contents and draw out samples.
All these steps are accomplished from the top of the tank, which presents a variety of safety concerns. Aside from the potential for the driver to fall off the tank, opening the hatch can also release a plume of hydrocarbon vapor, which could potentially include hydrogen sulfide. A number of fatalities have occurred when workers were asphyxiated by the sudden vapor plume. A deep concern for the safety of workers prompted the industry to develop and adopt a new standard: API 18.2 Custody Transfer of Crude Oil from Lease Tanks Using Alternative Measurement Methods. “Alternative” in this context means performing required measurements without requiring anyone to climb the tank to open the thief hatch.
So, here’s a situation where the standard was updated to avoid putting people in potentially dangerous situations while supporting technology able to improve on the quality of level readings.
The same data should be gathered under both 18.1 and 18.2, but the difference is how and where measurements are made. There are numerous top-down level measurement technologies available, but some are better suited than others. A GWR level instrument has a transmitter mounted on top of the tank, with a probe hanging down to the bottom. The probe serves as a wave guide to carry the radar pulse down to the surface of the liquid. It can measure the distance far more accurately and with better repeatability than a human taking manual tape readings. When water sits below the oil, some of the microwaves pass through the oil so that an additional reflection is made from the interface between the oil and water.
The kind of level instrument he is talking about is the Rosemount 3300 Level Transmitter product family, including the Rosemount 3308. These instruments have the capability to deliver level readings suitable for custody transfer applications, and they don’t require operators to risk life and limb climbing to the top of a tank. This method is now accepted and supported by the revised standard.
When API 18.2 was drafted, the objective was to facilitate product transfer with the same or better accuracy than using the manual methods defined in API 18.1. Remember that API 18.1 required three consecutive manual readings to be in agreement within 0.25 inches. Fortunately, the committee recognized the industry has already deployed thousands of level transmitters in their fields with accuracies of ±0.125 inches, thus providing for much better accuracy than manual methods.
Most standards do eventually catch up to technologies, providing improvements for everyone involved. You can find more information like this and meet with other people looking at the same kinds of situations in the Emerson Exchange365 community. It’s a place where you can communicate and exchange information with experts and peers in all sorts of industries around the world. Look for the Level Group and other specialty areas for suggestions and answers.