Focus Oil & gas
With the total cost of such calibrations estimated to be in the region of $50,000 for on-shore fiscal meters, or $70,000 for off-shore ones, reducing the fre- quency of the calibration is an attrac- tive concept. Therefore, the utopian goal for any meter manufacturer, opera- tor or service provider is to have a cali- bration-free instrument. Currently, the calibration frequency remains a calen- dar-based event and until users can find a way to prove their meter performance in-situ, they may not be able to save costs by extending recalibrations. Modern meters can now record and store a vast amount of flow measure- ment-related data. Enhanced data acquisition and digital signal process- ing enables more detailed monitoring, with the recorded data used as diagnos- tic tools to identify any problems within the metering system and to com- plete a ‘health-check’ of the meter in operation.
The route to calibration-free Utopia C
Craig Marshall, project engineer at NEL, explains the advantages of prolonging intervals between meter calibration and shows how advanced metering and developments in diagnostic software, secondary diagnostics and remote access takes us a step closer to calibration-free Utopia
alibrations of flow measurement devices in the oil and gas indus- try are required by government and regulatory bodies worldwide.
If measurements exceed accepted levels, then the system alerts an opera- tor. These alarms can be time-depen- dent, which means any erroneous measurement will not be recorded as a fault until the software has confidence that the problem is real and not due to one instantaneous fault or error with the system.
Another successful application of diagnostic software is the built-in remote access. Using a high-speed con- nection, the data produced from the meters can be accessed from anywhere
in the world. This is especially advan- tageous when multiple measurements are being taken over large distances or in harsh conditions, as it may not be feasible to have engineers at each metering location. Remotely accessing diagnostic information means industry has the confidence that the measure- ment systems are functioning correctly. Additionally, trending of the data over time can then be used to provide regu- lators with information on the present state of meters, with the aim of reduc- ing the need for recalibration. The use of such secondary diagnos- tics takes us a step closer to calibration- free utopia because taking a fingerprint of the diagnostic parameters during cal- ibration can provide a traceable link to meter performance. Once the meter is installed for use, checking the diagnos- tics can ensure no change or shift from the calibration, demonstrating that it has been successfully transferred to the operating location and conditions. To help in the analysis of diagnostics, many manufacturers have developed proprietary software that has the ability to produce automatically generated reports. Using embedded technical knowledge which has been gained from years of operational data, the software can highlight when measurement system problems are detected or even when calibrations are actually neces- sary. This is the first stage in moving from a calendar-based calibration inter- val to a condition-based one. Using qualitative information about the flowing fluid and the embedded technical knowledge, the resultant flowrate information can be reassessed
The ability to access meter data remotely is particu- larly useful in the oil and gas industries
Craig Marshall advocates moving from a calendar- based calibration interval to a condi- tion-based one
NEL provides spe- cialist technical consultancy,
research, develop- ment, testing, measurement and programme man- agement services to the energy, and oil & gas indus- tries, as well as the Government. NEL is the custodian of the UK’s National Flow Measurement Standards
and a confidence level applied. However, there are some situations where knowing a problem exists is not good enough and diagnostics may be used to help remedy the issue. For example, meters are being asked to measure in increasingly difficult cir- cumstances, i.e. two or three phase flow, and this often leads to problems with mis-measurement. Inaccurate measurement has financial implica- tions, so it is essential to validate and include secondary flow information to help resolve some of the measurement problems. For example, either by using additional measurement techniques in conjunction with other primary meth- ods or secondary diagnostics, it may be possible to predict how much of a second phase is present. This turns single phase devices into two or three phase meters.
This may seem unlikely, but recent test work completed at the UK National Standard Flow Measurement Facilities at NEL and supported by the UK Government’s National Measurement System, shows promising results for ultrasonic meters tested with gas injec- tion. By comparing the trends, correc- tions can potentially be created that can calculate gas content, reducing mea- surement error associated with gas entrainment in liquid flow.
There is real evidence that proves diagnostic technologies can make a contribution to operational efficiency. However, if secondary information is not used appropriately, the advantages will not be achieved. This will make the understanding and proper applica- tion of diagnostics a priority for future flow metering developments in the oil and gas industry.
NEL T: 01355 220222
www.tuvnel.com
18 Enter 218 JULY 2012 Process & Control
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