Lost and unaccounted for natural gas, particularly at pipeline custody transfer points, is becoming a focal point for both buyers and sellers. Even somewhat small measurement error can result in very large economic gains or losses at current natural gas prices. One relatively large source of lost and unaccounted for natural gas is due to pulsation at the orifice meter-induced by compressors, flow control valves, regulators and some piping configurations. This article discusses some historical research and findings surrounding the topic of pulsation. In addition, we will provide some methods of measuring, monitoring and potentially correcting various types of pulsation supported by relevant examples.
In recent years the Pipeline and Compressor Research Council (PCRC), now known as (GMRC) Gas Machinery Research Council and a subsidiary of the Southern Gas Association, commissioned and funded various pulsation research projects at Southwest Research Institute (SWRI) in San Antonio, Texas. The PCRC sponsored research programs concluded that pulsation induced measurement errors to fall into two broad categories:
Primary Element Error: includes Square Root averaging error (SRE), inertial errors, and shifts in the orifice coefficient.
Secondary Element Error: consists of gauge line distortion and gauge line shift, together commonly referred to as Gauge Line Error (GLE).
SRE directly relates to flow measurement error and therefore a very important topic to those who buy and sell natural gas. This paper will focus on methods to measure and quantify Square Root Error and subsequent Gauge Line Error, while also recommending several techniques to reduce pulsation effects on natural gas measurement.
Most natural gas flow measurement in the United States is performed by measuring pressure drop at two points (pressure differential) induced by an orifice plate. The gas flow rate (Q) is calculated using the basic formula Q = K√ΔPXP. The fixed orifice coefficient (K) is derived from a formula found in the latest edition of AGA Report Number 3. Differential pressure ΔP and line pressure P are measured either using mechanical chart recorders or electronic transmitters, remotely or directly mounted to the pressure taps, using a configuration of instrumentation valves, manifolds, and tubing.
Under steady-state flow conditions, gas flow rates can be accurately measured with current state-of-the-art equipment, including highly accurate pressure transmitters and flow computers. Despite the high degree of accuracy of current electronic measurement devices, inaccurate measurement still occurs when the ΔP modulates, or changes, at a frequency greater than the frequency that the measurement system extracts the square root of the ΔP.
This type of measurement error is called Square Root Error (SRE) and is the calculation of unsteady flow using the square root of the average P versus the average of the square root values of the instantaneous ΔP.
Pulsation from gas compressors, control valves, pressure regulators, and some piping configurations are one source of frequent ΔP modulation. Figure 1 is an excellent example that illustrates the amplitude and frequency of pulsation generated by a reciprocating compressor and a control valve. Three separate pulsation peaks are occurring in this system.
Figure 1: A graph exhibits three separate pulsation peaks. The operator can isolate the pulsation source by using new software filtering capability and modifying conditions in the new field. Minimizing and eliminating the pulsation source can ultimately improve the meter’s measurement accuracy.
The field technician operating the SRE Indicator is typically able to isolate the pulsation source(s) by using new filtering software and modifying the field conditions to generate new responses. This enables the operator to make necessary field changes that should improve measurement accuracy.
SRE is the largest component of pulsation induced primary element error. However, inertial error and the coefficient shift will both increase in magnitude under extreme pulsation conditions. A brief explanation of each follows:
Pulsating gas flow will tend to remain in motion due to its inertia. As a result, flow velocity changes lag behind ΔP changes. Inertial errors are insignificant unless pulsation amplitude and frequency are both
Though difficult to quantify, test data indicates that pulsation levels above 1.5% SRE contribute to shifts in the orifice coefficient.
The %SRE is measured at operating conditions and is used to approximate the primary element error induced by pulsation and to determine whether corrective action is necessary.
Percent Square Root Error (%SRE) is measured with a device manufactured and marketed by Parker called the Square Root Error (SRE) Indicator. This analytical instrument utilizes a high-frequency response ΔP transducer and software to calculate %SRE according to the formula developed by SWRI, illustrated earlier in this paper.
The SRE Indicator is used by field technicians to measure the severity of pulsation and calculate %SRE. The results can be used to determine if corrective action is necessary. However, because other primary element errors (inertial error and coefficient shifts) are not directly measured, %SRE should not be used to correct flow measurement readings.
Measurement error caused by pulsation at custody transfer points can create large economic discrepancies between natural gas buyers and sellers. Therefore, many natural gas purchase contracts contain language that set limits on %SRE (sometimes as low as 0.20% SRE) and typically place the burden of reducing or eliminating pulsation on the seller.
The simplest method of reducing pulsation induced SRE is to raise the ΔP by changing the orifice plate. Unfortunately, this may also limit the operating range of the measurement system.
In some cases, the piping system could be modified or the pulsation source could be moved to reduce SRE. This can be time-consuming and costly.
Another popular corrective action for high SRE is to install a device, such as a restricting orifice, between the pulsation source and the measuring station. However, these restricting devices can result in higher compression cost and a limited flow range. %SRE can also be reduced by installing an acoustic filter to remove most of the pulsation. Although more costly than a restricting device, a properly designed acoustic filter will operate over a much wider flow range with a lower pressure drop.
Gauge Line Error (GLE) exists when the differential pressure (ΔP) at the tips does not equal the differential pressure (ΔP) at the end of the gauge lines. GLE is typically caused by either pulsation or other flow phenomena.
The gauge line starts at the orifice taps and ends at the transmitter, flow computer, or chart recorder connections. It includes any pipe fittings, valves, valve manifolds, tube fittings, instrument tubing, and condensate chambers or bottles that may be installed between the orifice taps and the measurement device.
Research conducted by SWRI determined that gauge line error has two components:
Gauge Line Distortion
Gauge Line Shift
Parker developed its initial GLE Indicator in 1990, following it in 1996 and 2005. The current SRE/ GLE Indicator includes the ability to perform both %SRE and GLE tests, thus measuring and quantifying both gauge line error and square root error.
Figure 2: SRE6 and GLE6 test equipment that enables an operator to perform an SRE and GLE test simultaneously.
The GLE Indicator compares the differential pressure at the orifice taps with the differential pressure at the end of the gauge lines. Any difference between the two signals would be associated with gauge line error.
Extensive field-testing with the GLE Indicator confirmed the research conducted at Southwest Research Institute (SWRI) by PCRC. The lab test examples should provide a better understanding of GLE issues and measurement problems resulting from incorrect transmitter mounting practices.
As noted previously, numerous gas contracts now include pulsation magnitude clauses and many transmission companies require the installation of acoustic filters to minimize pulsation levels and %SRE. However, GLE tests conclude that gauge line error may continue to be present even after the installation of an acoustic filter and despite %SRE readings as low as 0.1%.
System complexity and numerous dependent variables, including pulsation levels, gauge line lengths, gauge line diameters, operating pressure, gas density, and gas velocity make it extremely difficult to observe a measurement location and predict what gauge line error, if any, will be present. GLE testing is currently the only recognized method to determine the presence of gauge line error.
Proper installation of the transmitter and/or electronic flow meter (EFM) in a manner that minimizes or eliminates gauge line error by removing as many of these dependent variables as possible is the best option.
Best practices include:
Closely couple the differential measurement device (transmitter or electronic flow meter/ computer) with the orifice fittings
Remove or minimize system vibration that can affect measurement or the measurement device
Use equal lengths of large bore (0.375" internal diameter or greater) tubing
Maintain the same large bore (0.375" I.D.) through all tubing, valves, and manifolds between the measurement device and the orifice fitting
Use of instrument valves rather than quarter turn ball valves. Opening and closing quarter turn ball valves make it is very easy to shock one side of the measurement device with full line pressure. Any pressure shock may create a significant static shift in the calibration of the transmitter not detectable under normal calibration procedures.
Using a short length of 1/2" O.D. instrument tubing and full opening quarter turn ball valve between the orifice fitting and measurement device creates numerous mating of female NPT connections and small “volume chambers,” which could create gauge line shift (pulsation rectification effects).
“Best practices” suggest using a system that directly mounts and closely couples the measurement device to the orifice taps. This method continues to gain wide acceptance within the industry illustrated by over 10,000 installations currently in service.
Figure 3. Parker’s Direct Mount System. The manifold system reduces the effect of Gauge Line Error on the total measurement system. Note the reduced number of leak points and sensing line length, and the uniform diameter between the orifice ports and the measuring elements.
Pulsation created by compressors, flow control valves, regulators, and some piping configurations may create unacceptable levels of Square Root Error (%SRE) and/or the resulting Gauge Line Error (GLE).
Pulsation at the orifice meter is a major source of lost and unaccounted for natural gas, which can create large economic gain or loss for both buyers and sellers along with a natural gas pipeline system.
%SRE and GLE can be measured and quantified using an SRE/GLE Indicator to verify measurement accuracy at a specific time and place. Pulsation and resulting high % SRE creates a high probability that GLE is present. Volume chambers or numerous measurement devices connected to the same set of orifice taps may compound or create GLE.
Transmitters or EFM should be close coupled to the orifice taps with equal length, large bore (0.375" I.D. or greater), constant diameter gauge lines to minimize or eliminate GLE; however, this process will not reduce or eliminate %SRE. The pulsation source must be eliminated, piping systems modified, ΔP increased, a restricting device installed, or a properly sized acoustic filter installed to reduce pulsation and resulting %SRE.
Article contributed by BJ Jackson, Product Manager - PGI Specialized Systems, Parker Hannifin, Instrumentation Products Division.