A Technicianís Perspective
Energy Measurement using Ultrasonic Flow Measurement and Chromatography:

Integrating the chromatograph into an ultrasonic metering system provides energy measurement, AGA 8 detailed compressibility values and, moreover, verifies meter performance, say Charles W. Derr and Charles F. Cook.

Introduction
Gas volume and energy metering stations using gas chromatography and ultrasonic metering are becoming a “mainstream” field operation and a new challenge to metering personnel. They are easy to adapt to, while adding a new dimension of value to the field professional. Technicians will invariably be the link to the success of any changing technology that would survive and thrive in the real pipeline environment. Meter stations must be maintainable and provable. The system and requirements will be examined from that perspective.
Ultrasonic Gas Flow Meter
An ultrasonic meter measures gas flow rate by sending bursts of high frequency sound upstream and downstream, diagonal to the flow and then measuring the transit time in each direction. Measuring the time difference to travel upstream and downstream along a known fixed path length gives path velocity. Correcting for the angle between the path and the axial flow gives average axial velocity for the portion of the pipe’s area represented by that path. Path average axial velocity times area gives actual volume rate for the portion of the pipe’s cross-sectional area represented by that path. Sound will take longer to travel the path length against the flow than it will with the flow. The time difference is proportional to the flow velocity. The total time to travel both upstream and downstream divided into two path lengths gives Speed Of Sound (S.O.S.). It will become significantly important to remember that the speed of sound is measured with the same two “path timings” as the gas velocity. A significant error in the S.O.S. measurement means that there is a significant error in measuring flow. Excellent agreement means that an accurate job of measuring flow is being done. The speed of sound can be calculated
by use of an AGA 8 based program and by entering the gas composition percentages (from a chromatograph), line temperature and pressure.

A Technician’s Perspective
For installing an ultrasonic meter, follow the AGA 9 recommendations. Construct a checklist. Example:
0 Calibration data available
0 Dimensional information available......................

Understanding ‘Calibration’ on
USM’s
Ultrasonic flow meters are pure rate meters. They measure the time to travel a known distance. Geometry is everything. During production, manufacturers should precisely measure path lengths, placement, angles, bores, etc. Knowing these measurements, makes an ‘inherently’ calibrated or ‘Dry’ factory calibrated meter. Inferring angles and lengths by ‘tweaking’ them to correctly read S.O.S. should be reserved for in-situ (hot-tapped) meters where small welding variances may occur. On a spooled custody transfer quality meter, the meter body measurements should be absolute. Applying forced lengths and angles should mean that the meter requires flow calibration. Flow calibration on a properly measured ‘Dry’ calibrated meter usually removes a slight zero offset. If flow is calibrated, a Meter Factor should be installed by thetest agency if necessary, and
should be verified at start up. Flow lab data should also accompany the meter for records. The technician should routinely check that the complete database of the meter is correct, its performance parameters are correct and that the USM’s measured speed of sound is within a tight margin of agreement against calculated speed of sound. Maintaining the meter’s accuracy usually requires very little effort. Comparing measured to calculated S.O.S. allows one to know if any of the primary energy system measurements have shifted or drifted. The sensitivity to the S.O.S. change is a function of the change in gas composition – vs– temperature –vs– pressure and is shown in the following example of comparing slightly different methane -vs- ethane contents, temperature changes and pressure changes. This example uses a real and typical) production inlet gas to a gas plant.......................

Have you ever considered making a major product purchase such as a car, without first evaluating whether it meets your operational needs and personal safety requirements? Most likely, prior to making such a big investment you would ask questions such as: How does it perform? How reliable are the brakes? What is the fuel consumption rate? What are its safety features? What is the safety record? Does it have an acceptable maintenance schedule? What does “consumer reports magazine” say about this car? Would you blindly rely solely on the answers given by the salesman? Furthermore, how would you react to a company that told you that you could only see the owner’s manual after you bought the car? This scenario may sound ridiculous. Yet, there is a disturbing trend in the industry when evaluating process safety systems that the level of scrutiny normally observed in our private lives has been lowered and the demand for full disclosure is not enforced. This is further complicated by vendors claiming as proprietary, the documentation that fully discloses the restrictions and conditions of use of Programmable Electronic Systems (PES) in process safety structures.

Safety Instrumented System Certifications

A Safety Instrumented System (SIS) is a PES applied for protection or monitoring, based on one or more programmable electronic devices. It includes all elements of the system such as power supplies, sensors, data highways and final safety elements. The SIS layer lies above the basic process control system and acts as the critical independent line of insurance to bring a process to the safe state when certain conditions are violated. Over the past several years, there has been rapid movement to develop standards and regulations with the objective of mitigating and/ or minimising the impact of industrial accidents on people, equipment and the environment. From a users’ perspective, the applicable standards are ANSI/ISA S-84.01 in the U.S., and IEC 61511 internationally.
Third party certification of Safety PLCs will typically be validated to
the following standards:.....................

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