Accurately measuring density at the correct conditions of temperature and pressure is critical for oil flow in pipelines which is measured largely by volume, and conversions involving density are necessary for accurate financial reporting, fair trade, and taxation.
The discovery of an error in densitometer measurements by the UK's DTI Energy Group, Licensing and Consents Unit in 2004 led to a loss of confidence in the measurement of density throughout the UK oil industry, resulting in the potential for disputes and increased financial exposure for companies. The UK Government's Oil & Gas regulator stated that "these errors could constitute the biggest single mismeasurement issue in the history of the North Sea, and could run to several million pounds (dollars) per annum and possibly amount to hundreds of millions over the last 20 years."
NEL's facilities, designed to accurately measure the density of fluids and gases at high pressure and temperature, were selected to provide a solution. Supported by the UK government's National Measurement System and with the help of the government's Oil & Gas Regulator, a solution was developed through a joint industry project (JIP) which was supported by almost 90% of UK offshore operators.
Density measurement is a key element of both mass and volume flow rate measurement in the oil industry, and is fundamental to the commercial operation of facilities. The most widely implemented approach for mass flow measurement is the use of a volumetric flow meter and a densitometer, both of which require periodic calibration. To ensure the highest accuracy, best practice requires that:
- Calibrations use only instruments that form part of a calibration chain traceable to national standards
- Devices be checked and calibrated regularly at actual operational conditions.
All commercial densitometers for gases or liquids operate on an oscillatory principle, and so are dependent on other fluid properties. However, the theory of these methods is not rigorously established, and even with careful design it is impossible to fully uncouple the effects of density from the other physical properties of the calibration fluids. To maximize the accuracy attainable with such densitometers, they must calibrate against reference fluids with similar physical characteristics (such as speed of sound and viscosity) to the fluids to be measured.
Conventionally, the calibration of most industrial densitometers uses fluids with physical characteristics significantly different from the actual working or operational fluids. Furthermore, the range of pressures and temperatures at which the instruments are normally calibrated is limited to near ambient conditions. However, many densitometers, particularly those used offshore, operate under high-pressure/high-temperature conditions, and this can be a significant source of measurement error.
Ideally, calibration is done at metering pressures and temperatures using fluids whose volumetric properties are known accurately across the full temperature and pressure range required for the calibration to the specific application.
It is accepted practice to quote a calibration at a single reference temperature (generally 20°C, or 68°F) and apply correction factors to adjust for the influence of temperature and pressure on both the calculated density and its uncertainty. However, recent work raises a number of issues about the entire calibration process, in particular when a densitometer is operated at temperatures and pressures different from the reference conditions.
As part of previous research programs, the National Measurement System supported establishment at NEL of density standard facilities consisting of two primary standard densitometers, one each for liquids and gases; plus a facility for the calibration of liquid densitometers. Using these facilities, standard reference fluids were characterized, allowing calibration houses and manufacturers to use these as traceable transfer standards, and recommendations were produced for traceable calibration of liquid densitometers at high pressures and temperatures.
On the basis of the JIP work, a number of recommendations were made. The most important one is that densitometers should be calibrated at their anticipated operating conditions, i.e. simultaneously at temperature and pressure, using one or more transfer fluids with known density across temperature and pressure range of the specific application and with an uncertainty ≤ 0.01%, directly traceable to national standards.
The Department of Energy & Climate Change (DECC), as the UK regulator for petroleum measurement and allocation, has incorporated the JIP recommendations in the current "Guidance Notes for Petroleum Measurement, Issue 8., Aberdeen, July 2012."
A conservative estimate of the average error of densitometers calibrated using traditional procedures is about 0.15%, and this translates directly into an allocation error in a pipeline system. For a field producing 5,000 b/d, a 0.15% error in allocation due to a 0.15% error in fluid density measurement leads to an annual error of 2,738 bbl. At an average price of $120 per barrel, this leads to a potential exposure of approximately £212,000 ($332,480) per annum – many times more than the cost to calibrate a densitometer. Furthermore, this error could be positive or negative. Taken over the whole of the UK North Sea oil production, the mismeasurement is on the order of £50 million ($78 million) per annum to operators.
In addition there are taxation implications, as offshore UK oil production amounted to 45 million metric tons (49 million tons) in 2011, and oil and gas production as a whole accounted for a government revenue of £11billion ($17 billion) in 2011/12. These figures rely on the accurate measurement of density so any errors affect the total amount of tax recovered and its fair allocation.
Calibration of densitometers using the new procedure is an important step to reduce the uncertainty of oil density measurement. However, as with any other measurement system, calibration uncertainty is only one component of overall uncertainty. For flow measurement systems, there is a considerable body of knowledge on additional sources of uncertainty including upstream flow disturbances, fluid properties, vibration, and mechanical stress. Taken together, these allow development of complete uncertainty budgets for an installation. However, the corresponding information is not complete for densitometer installations. For example, preliminary work by NEL shows the influence of mechanical stress on densitometer performance, and the Energy Institute (through its HMC-1 Upstream Measurement Sub-Committee) is encouraging further research.
Norman Glen is service leader for densitometers and physical properties of fluids at NEL.