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Orifice Plate Flow Meters – a Century of Success Hidden in Plain Sight 100 Years of Experience and Development

Steve Ifft, Emerson Process Management Richard Steven, DP Diagnostics

1. Introduction

“Simplicity is the ultimate sophistication” – Leonardo da Vinci.

With more than a century of development, improvement and use industry has a vast amount of experience with orifice plate meters. The well known and widely understood physical principles on which the orifice meter operates are fundamental, reliable and beautifully simple. With orifice meter sales in 2014 exceeding sales records, the orifice meter remains one of the most popular and capable flow meters used throughout industry. Today’s orifice meter technology is truly modern, with the development of the technology having kept pace with alternative advances in flow metering technology.

Fig 1. Dual Chamber Orifice Meter with Stacked Digital DP Transmitters

Nevertheless, contrary to other flow meter technology manufacturers, orifice meter manufacturers have taken a long term, low key approach to orifice meter marketing. Although orifice meter manufacturers have continually invested in improving the technology, the long term lack of marketing to showcase these developments has resulted in several orifice meter performance misperceptions creeping into some quarters of industry.

The discussions in this paper use defensible facts and statements drawn from standards documents, fluid mechanics text books, mathematics, and DP transmitter manuals. These discussions cover five key widely held orifice meter performance criteria misperceptions:

• Flow rate prediction uncertainty • Flow rate turndown (or “rangeability”) • Permanent pressure loss (or “head loss”) • Diagnostic capability • Wet gas flow performance.

The true performance of an orifice meter is shown to be fully competitive with alternative modern flow meter technologies, which explains why they remain so popular amongst many industries, including the hydrocarbon production and transmission industries.

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2. The Orifice Meter Flow Calculation

The orifice meter is a generic DP meter that measures mass flow rate like all DP meters, i.e. by cross-referencing the physical laws of conservation of mass and energy. The orifice meter therefore uses the generic DP meter mass flow equation set (see equations 1 thru 4).

td PYCA

m ∆−

= ρβ

β2

1 4

2

(1)

D

d=β (2)

( )tPPfY ∆= ,,,κβ (3)

D

m

πµ4

Re= (4)

Note: m - mass flow rate (kg/s) A - inlet area to the meter, i.e. A=(π/4)D2 (m2) β - beta, i.e. diameter ratio, see equation 2 (-) D - inlet diameter (m) d - orifice bore (m) ε - expansion factor, alternatively denoted by ‘Y’ (-), unity for liquids Cd - discharge coefficient, a function of the Reynolds number (Re), found from the standards, or by calibration (-) ρ - fluid density (kg/m3) µ - fluid viscosity (Pa.s) k - isentropic exponent of the fluid (-) P - inlet pressure (Pa) ∆Pt - traditional / standard DP read across the orifice plate (Pa) Re - Reynolds number, see equation 4

The mass flow (m) across an orifice meter is therefore calculated with knowledge of geometry (D & d), fluid properties (ρ, κ & µ), and primary instrument measurements (P, ∆Pt). The temperature, T (K), is usually also measured to facilitate the fluid property calculations and metal thermal expansion.

The requirement for the fluid properties to be supplied from an external source in order that the mass flow rate (or Million Standard Cubic Feet per Day, ‘MMSCFD’) can be predicted is the same requirement of other gas flow meters, like a turbine, vortex or ultrasonic meter.

The discharge coefficient (Cd) is a function of the meter geometry (D & d) and the Reynolds number (Re). This calculation is offered in ISO 5167-2 [16]. Called the Reader Harris-Gallagher (RHG) equation, this equation is unique amongst gas flow meter technology. The availability of the RHG equation means that the operator does not need to calibrate (or periodically re-calibrate) an ISO compliant orifice meter for the meter to have low flow rate prediction uncertainty in service. So remarkably reproducible are the performance of ISO compliant orifice meters, found so from the huge amount of industry experience and the massed publicly available data, that the standards boards accurately predict the performance of the orifice meter

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(i.e. predict the discharge coefficient) without the need for calibration. As calibration (and re-calibration) of flow meters is a significant portion of the overall cost of flow meters, relative to competing technologies this characteristic significantly reduces the overall cost of the orifice meter.

This equation set can appear to some non-flow meter specialists to be rather complicated, especially compared to some other meter technologies. However, this is just perception. The orifice meter is no more complicated to use than any other flow meter technology. In this modern age flow computer software does all the flow meter calculations for the operator. This practically means, as with many modern technologies, an operator does not have to fully understand a flow meter technology to operate it. Most flow meter technologies have simplified flow calculations published, while the technical complexities of the actual calculation routines are hidden from the operator inside the flow computers. These orifice meter calculations are also imbedded in all reputable flow computers. The only difference with the orifice meter is the details of orifice meter equations are much more widely known and understood, and presented in many fluid mechanics text books. The same cannot be said across the board for the other flow meter technologies.

3. Modern Orifice Meter Performance

3a. Orifice Meter Flow Rate Prediction Uncertainty

With the mass flow rate prediction (e.g. kg/s or MMSCFD) being the primary output of a flow meter it’s flow rate prediction uncertainty is one of, if not the most important, performance specification. The orifice meter has a competitive flow rate prediction uncertainty. For example:

• Turbine meters calibrate to predict volume to ≤ ±0.5%, and the density uncertainty is typically ≤ ±0.4%, so the root of sum of squares (RSS) of these uncertainties gives a turbine mass flow rate uncertainty of ≤ ±0.7%.

• ISO 17089:2010 states that ultrasonic meters for fiscal metering have an uncertainty ≤ ±0.7%.

• Vortex meters calibrate to predict volume to ≤ ±0.5%, and the density uncertainty is typically ≤ ±0.4%, so the RSS of these uncertainties gives a vortex mass flow rate uncertainty of ≤ ±0.7%.

Orifice meters also have a mass flow rate prediction uncertainty in the range of 0.7%, and this is shown in the API orifice meter standard (API 14.3 [1]). This API standard is not written predominantly by orifice meter manufacturers trying to promote their technology, but rather by orifice meter users, for orifice meter users. API 14.3 states the facts about orifice meters, for better and for worse.

The API 14.3 orifice meter flow rate prediction uncertainty example is comprehensive. For most components (in Equations 1, 2, & 3) there is a detailed discussion on where this uncertainty statement comes from. There is not enough space (or indeed reason) to reproduce everything here. The reader can refer to the publicly available standards document for further detail. Here we shall therefore only reproduce the end calculation for discussion. Table 1 reproduces the API orifice meter flow rate prediction uncertainty calculation for a mid-size beta (i.e. 0.5β).

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Uncertainty (U95 %)

Sensitivity Coefficient (S)

(U95 S)2

Cd Discharge Coefficient 0.44 1 0.1936 Y Expansion Factor 0.03 1 0.0009 d Orifice Bore 0.05 2/(1-β4) 0.0114 D Pipe Diameter 0.25 -2β4/(1-β4) 0.0011

DP Differential Pressure 0.5 0.5 0.0625 P Static Pressure 0.5 0.5 0.0625 Z Compression Factor 0.1 -0.5 0.0025 T Temperature 0.25 -0.5 0.0156 G Relative Density 0.6 0.5 0.09

Sum of Squares 0.4401 Square Root of Sum of Squares 0.6634

Table 1. API 14.3 Example of Orifice Meter Flow Rate Prediction Uncertainty.

This neutral API document shows that a properly operated orifice meter has a flow rate prediction uncertainty ≤ ±0.7%. However, API has not significantly updated this calculation in many years. From the latest technologies, and publications, there are some debatable uncertainty components in this API calculation.

First, the ISO 5167-2 RHG orifice meter discharge coefficient prediction uncertainty ranges from 0.43% to 0.58% depending on beta and Reynolds number. For the majority of cases the discharge coefficient prediction uncertainty can be considered as ±0.5%, which is higher than the API ±0.44% quote. However, the API prediction of a pressure reading uncertainty of ±0.5%, and the associated density prediction uncertainty of ±0.6%, is rather conservative. Modern Gas Chromatograph, AGA 8 calculations, and pressure & temperature transmitters can typically predict the pressure to ±0.25% and density to ±0.4%. For example, Figure 2 shows a worked example where a Rosemount Pressure Transmitter (3051CA Range 3) of Upper Range Limit of 800 psia (spanned to 700 psia) is used to measure a pressure of 500 psia where the transmitter is exposed to the elements across a seasonal 500F shift. Using the published specifications of this instrument we see that the modern pressure transmitter pressure reading uncertainty is < ±0.25%. The density prediction is also a requirement for most gas meters (e.g. velocity meters such as vortex, ultrasonic, and turbine meters). It is this lower uncertainty that is most often (and quite reasonably) used for these meters uncertainty calculations. Finally, the estimated uncertainty of the differential pressure is rather low at ±0.5%. As with all instruments, the smaller the value being measured the higher the uncertainty in the measurement. As will be shown in Section 3b, there is no need to restrict the useable DP range to that which gives ±0.5%. To maintain the typical gas meter flow rate prediction uncertainty of ±0.7% the useable DP range can be extended up to the lowest DP having a ±0.8% uncertainty.

Table 2 shows the same API orifice meter flow rate prediction uncertainty calculation if we alter these inputs as described. The orifice meter mass flow rate prediction uncertainty is shown to be ±0.7%, i.e. the same as the other gas meters. Using nothing but API & ISO published calculations and statements respectively, and modern pressure and density measurement uncertainties (similar to those used by competing meter technologies), it can be shown that the orifice meter has a competitive mass flow rate prediction uncertainty rating.

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Fig 2. Rosemount Pressure Transmitter Pressure Uncertainty Reading

Uncertainty (U95 %)

Sensitivity Coefficient (S)

(U95 S)2

Cd Discharge Coefficient 0.5 1 0.25 ε Expansion Factor 0.03 1 0.0009 d Orifice Bore 0.05 2/(1-β4) 0.0114 D Pipe Diameter 0.25 -2β4/(1-β4) 0.0011

DP Differential Pressure 0.8 0.5 0.16 P Static Pressure 0.25 0.5 0.0156 Z Compression Factor 0.1 -0.5 0.0025 T Temperature 0.25 -0.5 0.0156 G Relative Density 0.4 0.5 0.04

Sum of Squares 0.497 Square Root of Sum of Squares 0.7

Table 2. API 14.3 Example of Orifice Meter Flow Rate Prediction Uncertainty with Updated Inputs.

One of the significant advantages of using an orifice meter is that the performance is so reproducible that ISO can predict the discharge coefficient to low uncertainty without a calibration being required. Hence, the un-calibrated orifice meter is shown here by API / ISO to have a gas mass flow rate prediction uncertainty of ±0.7%. The competing gas meters on the market tend to require calibration to achieve a gas mass flow rate prediction uncertainty of ±0.7%.

Operators can (and occasionally do) further reduce flow rate prediction uncertainty by calibrating the orifice meter. However, as the un-calibrated orifice meter performance is comparable to other calibrated flow meter technology performances, orifice meters are not often calibrated. Operators can reduce DP reading uncertainty further by tuning the DP transmitters to specific flow conditions. However, a more common way to reduce DP reading uncertainty further is to utilize the higher specification DP transmitters. For example, the Rosemount 3051S Ultra is specifically calibrated for use with DP flow meters.

The orifice meter uncertainty rating, like other flow meter uncertainty ratings, is the worst case scenario for a serviceable meter. With most flow conditions the orifice meter will predict the flow rate to less than the stated uncertainty, i.e. < ±0.7%.

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3b. Flow Rate Turndown (or Rangeability)

Flow meter ‘turndown’ (or ‘rangeability’) is the ratio of the maximum to minimum flow rate that a flow meter can meter to its stated uncertainty rating. Turndown is used by marketing departments to promote the benefit of one flow meter over another. Industry tends to perceive the orifice meter as having a poor turndown. However, in reality the modern orifice meter turndown specification is competitive with other flow meter technologies. The advent of modern stacked digital DP transmitters significantly increased orifice meter turndown. Furthermore, the long standing ability to switch the orifice plate to one of a different beta gives the orifice meter the rare ability to be used long term over large flow ranges. What’s more, the significance of any flow meter’s turndown rating is often over stated. In practice all that matters is that a flow meter can cover the flow range of an application. Any greater turndown ability will not be utilised and is therefore of academic interest only. Let us discuss these comments in turn.

3.b.1 Orifice Meter Turndown Specifications

A modern orifice metering system has a flow rate turndown specification that is easily within the requirements of the majority of industrial flow metering applications. This fact contradicts the perception of some. Indeed turndown specifications are the one area where users and some standards have not kept up with state-of-the-art technology changes.

An orifice meter’s primary signal is the DP, and hence the flow range is determined largely by the measureable DP range1. Therefore, the turndown of an orifice meter system is largely dictated by the secondary instrumentation, i.e. the DP transmitter DP turndown. The orifice meter DP (∆Pt), has a parabolic relationship with the flow rate (m) as shown in equations 1 & 5. It has been erroneously suggested by some that this non-linear relationship between the primary signal and the flow rate is somehow a weakness of an orifice meter. However, this mathematical relationship is precisely understood and is a consequence of cross referencing the physical laws of conservation of mass & energy. Hence, as long as the DP transmitter can measure the DP produced to a low uncertainty, there is no weakness, and the orifice meter can measure the flow rate to a low uncertainty. The practical flow rate rangeability of an orifice meter is primarily influenced by the DP measurement rangeability.

tPm ∆∝.

-- (5)

Early DP meter systems measured DPs by manometer, Bourdon Gauge (see Fig. 3) or mechanical diaphragm (Chart Recorder) type devices. These early (and largely obsolete) DP measurement methods had a DP turndown of approximately 10:1. This means the maximum measurable DP was ten times larger than the minimum measureable DP. Hence early orifice meters, using obsolete DP measurement methods, had a flow rate turndown (due to equation 5) of √10:1 ( ≈ 3:1), i.e. the 1 The other turndown limitations are the standards discharge coefficient prediction Reynolds number range and the low pressure (P2) to inlet pressure (P1) ratio limit of P2/P1 ≥ 0.75. However, the ISO 5167-2 orifice meter Reynolds number range is extremely wide and covers the vast majority of industrial flows. That is, there is not a practical turndown limitation due to the standards discharge coefficient estimation. Furthermore, the limitation of P2/P1 < 0.75 is only reached with very low pressure gas, with extremely high flow rates. In most hydrocarbon production scenarios P2/P1 >> 0.9, and this issue does not practically restrict the orifice meters turndown.

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Fig 3. Manometer, Bourdon Gauge & DP Transmitters with DP Meter.

maximum measurable flow rate was three times larger than the minimum measureable flow. Hence long ago, before the advent of modern instrumentation, the orifice meter used to have a flow rate turndown of 3:1. This is where the flawed perception of the modern DP meter turndown limitation originates. However, this performance specification is now a historical curiosity. Modern orifice meters can use stacked digital DP transmitters. An individual DP transmitter can now achieve > 10:1 DP turndown, and stacked DP transmitters achieve much higher DP turndowns.

In the last twenty years one of the most significant (and understated) improvements in flow metering technology is the improvement in DP transmitter performance. Modern digital DP transmitters are designed and manufactured by the same corporations that developed the various alternative flow meter technologies. These DP transmitter improvements are a direct result of the continued popularity of DP (and orifice) meter technology leading these corporations to invest in DP meter technology R&D.

The relatively low cost and ease of use of these modern DP transmitters makes it economically viable, and practical, to ‘stack’ DP transmitters, i.e. add DP transmitters that are of different DP ranges. Stacking DP transmitters is simple and approved by industry (e.g. API 14.3 [1] discusses DP transmitter stacking in Section 1.12.2.) To prove the point let us consider worked examples using published DP transmitter manual specifications.

Worked Example 1:

Say an 8”, schedule 80, 0.6β flange tap orifice meter system is designed to operate with a 17.5mW natural gas, at 500 psi (34.5 Bar), 60oF (15.6 oC), with a maximum flow rate of 64.5 MMSCFD (i.e. approximately 20 m/s). The associated maximum DP would be 400”WC2 (approximately 1 Bar). Say the installation is outside where there is no temperature controlled instrument enclosure. The meter experiences a relative large seasonal temperature swing of 500F (280C). Temperature fluctuations have an adverse effect on DP transmitter performance, and hence this example is chosen to show the orifice meter turndown under realistic challenging flow conditions3. A stack of two DP transmitters with Upper Range Limits (‘URL’s’) of 400”WC (100 kPa) and 40”WC (10 kPa) are selected (and spanned to 400 & 40”WC respectively). Taking

2 This example uses a maximum of 400”WC / 100 kPa to represent a typical operator imposed limitation. However API 14.3 Appendix 2-E shows that in many cases orifice meters can have > 1000”WC (2.5 Bar) with no adverse effects. 3 In many installations the instruments are kept in a temperature controlled enclosure and the corresponding read DP uncertainty is significantly lower than this example.

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Fig 4. DP vs. Measurement Uncertainty For Orifice Meter Sized to DPMax 400”WC.

Fig 5. Flow vs. Uncertainty For Orifice Meter Sized to DPMax 400”WC.

typical DP transmitter performance (in this case the Yokogawa DP transmitter EJX110A) let us look at the flow rate turndown performance as flow and DP reduce.

A typical gas orifice meter flow rate prediction uncertainty is the same as other gas meters, i.e. ±0.7%. In order to achieve this uncertainty rating the orifice meters DP transmitters must read the DP to < ±0.8%. (The details of these uncertainty statements were discussed in detail in Section 3a.) Figure 4 shows the increasing uncertainty as the DP reduces. Staring at 400”WC with a DP reading uncertainty of ±0.074%, by 37”WC the DP uncertainty is the maximum allowed ±0.8%. This is a DP turndown of 400:37”WC (i.e. 10.8:1), and an associated flow turndown of √10.8:1 (i.e.3.3:1). Using this single DP transmitter can give a turndown of approximately 3:1. However, modern industry tends to stack DP transmitters. Stacking a second DP transmitter of 40”WC URL (spanned to 40”WC) allows the DP to be read down to 4”WC at an uncertainty ≤ ±0.8%. This is a DP turndown of 400:4”WC (i.e. 100:1), and an associated flow turndown of √100:1 (i.e. 10:1). Figure 5 shows the associated flow

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rate turndown. Like most flow meter designs the orifice meter continues to operate below it’s stated turndown range. It still measures the flow, but at a higher uncertainty than its stated uncertainty rating. Figure 5 shows this.

An operator could easily choose to extend this turndown yet further by adding a third DP transmitter with a lower URL. However, in the vast majority of industrial applications such turndowns are not required, and hence this has not been shown in Figures 4 & 5. A single digital DP transmitter, or a stack of two digital DP transmitters, is all that is usually required for an orifice meter to read the DP across a typical industrial flow range. As we will see in Section 3.b.3 there is little practical difference in the absolute flow range covered between 10:1 and say 20:1 turndown ranges. However, first let us discuss the ability to change the flow range by changing the orifice plate beta (i.e. diameter ratio), and the separate ability of the orifice meter to meter surge flows.

3.b.2 Orifice Plate Meters – Variable Beta Values

Paul Daniel created the dual chamber (‘SeniorTM fitting’) orifice meter more than 80 years ago, and the advantages this design offers are still reaped today. Single or dual chamber orifice meters allow the plate to be replaced by a plate with a different beta, thereby changing the orifice meters effective flow range. The dual chamber orifice meter design allows a plate to be replaced in minutes, without even taking the flow off-line (e.g. see Figure 6). This ability allows the orifice meter to be periodically reconfigured in service to match long term (or seasonal) changing flow conditions. Naturally, the method of changing the beta of an orifice meter is for long term flow condition changes, and not for sudden short term flow rate fluctuations. It is the orifice meter turndown of a given beta value that is set by the stacked DP transmitters. For long term use, where there is the opportunity to periodically change the beta value, it is the variable beta and DP range that dictates the orifice meter’s turndown.

Fig 6. Orifice Plate Removed for Inspection and Possible Replacement to Different

Beta Value at BP CATS Fiscal Terminal in the UK.

Let us continue with the example in Section 3.b.1. Say after several years of service the application has had a significant reduction in flow. Say the typical flow rate has depleted to the minimum flow that this orifice meter configuration (i.e. 0.6β) can meter within the stated uncertainty (i.e. 6.45 MMSCFD / 208.8 m3/hr / 9.45e5 Reynolds number / 2 m/s). This is an extreme flow reduction example, but is deliberately chosen as such in order to highlight the orifice meters remarkable ability to ‘re-invent itself’. This orifice meter cannot meter any further reduction in flow, without an increase in the flow rate prediction uncertainty, unless the beta is changed.

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Let us change the beta from 0.6β to 0.2β. At this flow a 0.2β causes the DP to be 378”WC (compared to 4”WC for the 0.6β). The meter can now read the flow again down to the minimum DP of 4”WC (i.e. 0.67 MMSCFD / 21.8 m3/hr / 9.85e4 Reynolds number / 0.2 m/s). Over the life time of this orifice meter the flow rate turndown is 64.5 to 0.67 MMSCFD, i.e. a flow rate turndown of 96:1. Furthermore, ISO allows use of smaller betas still which increases the turndown further. Contrary to common misperceptions, the orifice meter’s turndown capability is competitive with the competing flow meter technologies.

Some operations can periodically cause flows to ‘surge’, i.e. exceed the maximum flow rate specification of the meter for short periods. A common requirement for such applications is the ability for the meter to survive without damage and meter the flow during these surge events. Again, contrary to common misperceptions, a correctly sized orifice meter with an appropriate DP transmitter is suitable for such an application. The following worked example shows this.

Worked Example 2 (“Surge” / “Over-Speed” Flow):

Orifice meters can use different manufacturer’s DP transmitters. Also, unlike the first worked example many orifice meter installations are inside buildings, or at least the instruments are held in a temperature controlled enclosure, e.g. see Figure 7 (from Skelton [2]). This reduces the DP reading uncertainty. Therefore in this surge flow example we will consider Rosemount DP transmitters installed in a temperature controlled enclosure with a small temperature variation.

Fig 7. DP Transmitters Installed in a Temperature Controlled Enclosure

Let us consider a 12”, schedule 40, 0.6β orifice meter installed in an application with 18mW natural gas at 20 Bar and 20oC. The maximum normal gas flow rate is expected to be 90.1 MMSCFD (i.e. 20 m/s). This would produce a DP of approximately 247”WC. Therefore a stack of range 2 (250”WC URL) and range 1 (25”WC URL) Rosemount 3051S DP transmitters are selected. These transmitters are housed in a temperature controlled environment and see a temperature variation < 10 oF. Under normal flow conditions this pair of DP transmitters produce a DP turndown of 120:1, and a corresponding flow rate turndown of 11:1. Say in this case the operator suspected that the pipeline may periodically suffer from a surge of flow, i.e. an ‘over-flow’ in excess of this nominal maximum flow. Will the orifice meter survive undamaged and will it meter this surging flow? Most real world application's will not surge more than 50% of the nominal maximum flow, i.e. ≈ 135 MMSCFD in this case, so as way of proof that orifice meters can cope with surge flow let us consider a more extreme example. Say the flow may reach up to 174 MMSCFD (i.e. ≈ 40 m/s and a Reynolds number of 1.65e7). If the orifice meter operator knows that

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Fig 8. DP vs. Measurement Uncertainty For Orifice Meter Sized to DPMax 1000”WC.

Fig 9. Flow vs. Uncertainty For Orifice Meter Sized to DPMax 1000”WC.

surge and therefore excessive DPs are a possibility, then the thickest orifice plate allowed will be chosen for maximum structural strength. ISO 5167-2 states the plate thickness (“E”) can be up to 0.05D, i.e. in this case E ≤ 0.597” thick. Such a plate is easily structurally strong enough to operate at > 1000”WC. To cope with surge the operator adds to the stack a range 3 Rosemount 1000”WC DP transmitter (spanned to 1000”WC URL). This DP transmitter is at its maximum DP at 17.4 MMSCFD, i.e. ≈ 40 m/s. As the plate holds firm, the resulting DP turndown (within the required 0.8% uncertainty) across the 3 DP transmitter stack is 1000”WC to 2.1”WC, i.e. 476:1, which corresponds to a flow rate turndown > 21:1. This is shown in Figures 8 & 9 respectively. Contrary to common assumption orifice meters can cope with surge flow. Yes, the permanent pressure loss of creating 1000”WC DP is relatively high, but this is not a concern for the operator during short term accidental surge flow occurrences.

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3.b.3 ‘Turndown’ is Overrated

The meaning of ‘turndown’ is not well understood. Turndown is the ratio of the maximum to minimum flow rates that can be metered within a stated flow measurement uncertainty. For example, say Meter A has flow range of 100 to 1 units of flow (i.e. 100% to 1% full scale), then the turndown is 100:1. Now say a Meter B has flow range of 100 to 10 units of flow (i.e. 100% to 10% full scale), then the turndown is 100:10, or 10:1. However, because Meter A has ten times the turndown of Meter B, all too often people falsely associate that to mean Meter A has ten times the flow range of Meter B. It does not! In reality Meter A with a turndown of 100:1 has a flow range of 100 down to 1 units of flow (i.e. a range of 99 units of flow) while Meter B with a turndown of 10:1 has a flow range of 100 down to 10 units of flow (i.e. a range of 90 units of flow). Therefore Meter B covers 90/99 * 100% = 90.9% of Meter A’s range. The difference in flow range between 100:1 and 10:1 turndown is not 10 times difference but only about 10% difference!

Fig 10. Flow Rate Range to Turndown Comparisons

( )( ) %100*

1

1%

−−

=Φxy

yx --- (6) ( )( ) %7.94%100*

12010

11020% =

−−=λ -- (6a)

Most meter designs are capable of being sized to a given applications maximum flow rate (i.e. 100% full scale). Turndown is commonly a description of how much lower a flow rate than this maximum can be metered (see Figure 10). Differences in absolute flow range between any two meters of different turndowns are not as great as is often assumed. Say Meter 1 has a turndown of x:1 and Meter 2 has a turndown of y:1, where x > y. Let us denote the percentage of Meter 1’s flow range that can be covered by Meter 2, when both meters are set to the same full scale flow rate, as %Φ . Equation 6 shows how this percentage (%Φ ) is calculated.

Consider an example where Meter 1 has a 20:1 turndown, e.g. an orifice meter with a 3 DP transmitter stack (x = 20). Meter 2 has a 10:1 turndown, e.g. an orifice meter with a 2 DP transmitter stack (y = 10). The difference in rangeability is not double (i.e. 20/10) as is often superficially assumed. In reality a 10:1 turndown meter covers 94.7% of the 20:1 meters range (see equation 6a). The 20:1 turndown meter has 5.3% more range than a 10:1 turndown meter (see Figure 10). This explains the comment in 3.b.1 that adding a 3rd DP transmitter to a stack is often superfluous.

Figure 10 shows flow rate range vs. turndown. As turndown increases for a set maximum flow rate (i.e. 100% full scale), a law of diminishing returns exists. Each step increase in turndown creates a smaller actual increase in flow range is attained.

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The only practical issue with any meters turndown is whether the meter can cover the flow rate range required for a particular application, not what maximum turndown a manufacturer claims. In reality orifice meters, just like other competing flow meter technologies, are able to cover the common industrial flow ranges / turndowns.

Most meter applications do not have flow conditions that allow any flow meter to utilize its full range / turndown specification. Gas pipeline operations tend to cap the velocity at 30 m/s for operational reasons. (Orifice meters can operate at this maximum flow rate.) Turndown therefore typically means “how low can the meter go”? That is, increasing turndown means reading ever smaller (and less financially important) flows. Many applications have a low flow cut offs below which the flow meter (of any design) is off-line. Therefore, in reality most industrial flow meter applications do not operate greater than 30 m/s or less than about 3 m/s. For example, if we look at example 1 the application flow doesn’t exceed 20 m/s. In this example, the ability of a meter to read higher flows is of no practical interest to the operator.

3.c. Permanent Pressure Loss (i.e. “Pressure Drop” or “Head Loss”)

Fluid flows along a pipeline due to pressure drop. Without pressure drop there is no flow. However, pressure drop is an operating expense, and hence minimizing this pressure drop, or “permanent pressure loss” / “head loss”, for a given mass flow rate minimizes the operating expense. Orifice meters are perceived to have relatively high pressure drop and this can be seen as a disadvantage. Let us now look at the pressure loss performance of orifice meters.

Flow meters are inherently used as an integral part of a pipeline, and hence their permanent pressure loss can only be seen in proper context when viewed relative to the overall pipeline permanent pressure loss. There is now a tendency for some to compare the relative pressure drop of different meter types directly, as if they are isolated stand alone systems. Flow meter marketing can imply flow meters with half or double the pressure drop of another design can have a very significant impact on the big picture, i.e. the overall pressure drop across the whole piping system. However, when viewed as part of the bigger picture, i.e. when considered relative to the piping systems overall losses, flow meter pressure drop contribution, and differences in flow meter type pressure drop can be small.

Non-intrusive flow meters and Venturi DP meters have a low pressure drop relative to other flow meters. However most meters, non-intrusive flow meters inclusive, require upstream flow conditioners, which adds pressure drop to the metering system. The orifice meter has a moderate to relatively high pressure drop (as it varies with beta) amongst the various flow meter designs. Some designs have lower pressure drops, while other designs, can have larger pressure drops still. But how do these pressure drops compare relative to the overall pipe loss across the pipeline system in which they are used?

There are various challenges that pipeline operators face to minimize over all pipeline pressure drop. Unless these challenges are actively addressed and acted upon, in many cases a flow meter’s contribution to the overall pressure loss (and any difference in pressure losses between flow meter types) is very small, and sometimes practically negligible. Let’s consider a practical worked example to highlight this fact.

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Worked Example 3:

As one of the most popular flow meter technologies, orifice meters are used in a myriad of different applications. Let us consider just one popular orifice meter application as a generic example to discuss a general point. Natural gas transmission requires gas compression stations at intervals along the pipeline. The number of gas compression stations, their location and their size (i.e. power) along a transmission pipeline, is dependent on multiple variables such as:

• the size of the pipeline for the volume of gas being transported, • the roughness of the wetted surface of the average pipe, • the number of pipe line components in use (including flow meters), • the pressure rating of the pipe line, • elevation changes, • liquid or particulate entrainment • and others

Consider a hypothetical 24”, schedule 80, natural gas transmission line. Gas (of 18mW) exits a compressor station at 80 Bar(a) and 20oC. The gas density (ρ) is approximately 68.4 kg/m3. The flow rate is 300 MMSCFD, i.e. 74.9 kg/s, which is a velocity (V) of 4.65 m/s. The Reynolds number is 15.8e6. New typical commercial pipe has a roughness (‘e’) of approximately 0.046mm.4 After a few years of service a typical pipe may therefore have a roughness of about 0.06mm. The inside diameter is 21.56” (i.e. 547.62mm). The relative roughness (i.e. e/D) is therefore approximately 0.00011. The Moody diagram shows the associated friction factor ‘f’ at this relative roughness and Reynolds number is approximately 0.012.

Gas compression stations on transmission pipelines are typically spaced between 40 and 100 miles apart. The pressure drop that matters to the pipeline operator is the pipe drop along the whole system. It is therefore rather arbitrary what length of pipe we use in our example. Let’s consider a relatively short (i.e. 1000 ft), moderate (1 mile) and long (40 miles) length of pipe. The 40 miles is chosen as the nominal minimum gas compression station distance. In such a system there can be various pipe components. In this example let us say the pipeline has the following:

• a plug disk design globe valve for flow control (3/4 open) • a butterfly valve for emergency shut of control (fully open) • 4 standard elbow / bends • a tee junction • a sample probe • a couple of thermowells • a flow meter • possibly a flow conditioner

Convention labels the pressure drop associated with the pipe friction as the ‘major’ loss, and the pressure drop associated with the combined pipe components (inclusive of the flow meter) as the ‘minor losses’. What are the associated ‘major’ & ‘minor’ losses’? How relevant is the flow meter pressure loss to the overall picture?

4 From “Introduction to Fluid Mechanics”, 6th Edition, by Fox & McDonald Ch. 8, Table 8.1, Page 338.

15

The ‘major loss’, i.e. the pressure drop due to pipe friction (∆PPPL, major) over a given pipe length, is calculated by Equation 7. Each pipe component contributes a ‘minor loss’. Each components ‘minor loss coefficient’ (Kl,minor) is (hopefully) published in text books, manuals etc.. A pipe components minor loss coefficient is sometimes expressed as the equivalent length (Le) of straight pipe to sustain the same pressure drop (see Equation 8).The overall ‘minor losses’ are the summed individual pressure loss of each component (see Equation 9).

=∆

2

2

,

V

D

LfP majorPPL

ρ --- (7)

D

LfK e≡minorl, --- (8)

=∆ ∑ 2

2

minor,min,

VKP lorPPL

ρ --- (9)

As this discussion is on flow metering associated pressure drop we will look at the orifice meter and flow conditioner separately to the other pipe line components. Table 3 shows the minor loss coefficients for the pipeline components. Public knowledge of the minor loss coefficients of the many and various pipe components is scattered and incomplete. For example, it is very difficult to find minor loss coefficient predictions for various valve designs across their full range of settings, and virtually no published minor loss coefficient predictions show any relationship to Reynolds number, or give an associated uncertainty value. The footnotes show where the various values in this example were obtained.

The incompleteness of the archived minor loss coefficient information available gives a strong hint how difficult it is for operators to accurately predict pressure drop across large pipe systems. In practice some pipeline operators tend to make reasonable efforts to optimize their piping to achieve minimum pressure drop, but due to the limitations of the published component loss coefficients, and practical realities of installing pipe systems, these efforts are still approximations. In our example: A 1000ft (304,800mm) length of such 20.56” (547.62mm) pipe has a ‘major loss’ of:

( ) ( )Pa

V

D

LfP majorPPL 4937

2

65.4*84.60*

62.547

304800*012.0

2

22

, =

=

=∆ ρ

-- (7a)

A 1 mile length of such 20.56” pipe has a ‘major loss’ of:

( ) ( )Pa

V

D

LfP majorPPL 068,26

2

65.4*84.60*

62.547

1601344*012.0

2

22

, =

=

=∆ ρ

-- (7b)

A 40 miles of such 20.56” (547.62mm) pipe has a ‘major loss’ of:

( ) ( )Pa

V

D

LfP majorPPL 746,042,1

2

65.4*84.60*

62.547

64373760*012.0

2

22

, =

=

=∆ ρ

-- (7c)

16

As we are considering the same pipe components for different pipe lengths the minor losses (minus the flow conditioner and orifice meter contributions) are the same and found by Equation 9a.

+++

++=∆2

242

%100,%75,minor,

VKKK

D

LfKKP probthermt

ebvgvPPL

ρ -- (9a)

( )( ) ( )( ) PaV

PPPL 896,112

09.009.022.030012.041132

minor, =

+++++=∆ ρ

-- (9b)

Pipe Component Minor Loss Coefficient, Kl,minor, Or equivalent (f*(Le/D))

Plug Disk Globe Valve 75% open5 Kgv,100% = 13 Butterfly Valve 100% open6 Kbv,100% = 1

Standard Elbow7 f*(L e/D)std elb = 30 Tee Junction (Straight Through)8 Ktee = 0.2

Sample Probe9 Kprobe = 0.09 Thermowell10 Kthermo = 0.09

Flow Conditioner 11 Kfc = 2 Table 3. Typical Pipe Component Minor Loss Coefficients (or Equivalent)

Let us now consider the pressure drop contribution of a flow meter. If the operator chose a non-intrusive flow meter then the meter itself has no pressure drop (other than that which is equal to the pipe which it has replaced). However, such non-intrusive meters typically require the same flow conditioner as often used with an orifice meter. The flow conditioner minor loss is calculated by Equation 10.

( ) PaV

P rconditioneflowPPL 478,12

22

, =

=∆ ρ

-- (10)

( ){ } 2

2

24

minorl, 111

−

−−=

ββ

d

d

C

CK -- (11)

( ) PaV

P meterorificePPL 439,52

36.72

, =

=∆ ρ

-- (12)

ISO 5167-2 states the minor loss coefficient of an orifice meter. This ISO expression is reproduced as Equation 11 here. For this example let us consider a 0.65β orifice plate. The ISO RHG equation discharge coefficient (Cd) for this meter geometry and flow condition is 0.6024. The associated orifice minor loss coefficient is therefore 7.36. In this example the orifice meter pressure drop is calculated by equation 12.

5 Found (with difficulty) by internet search. 6 Average value from internet quotes. 7 “Introduction to Fluid Mechanics”, 6th Edition, Fox &McDonald, page 346 Table 8.4 8 “Fundamentals of Fluid Mechanics”, 5th Edition, Munson, Young, Okiishi, page 445 Table 8.2 9 Estimated to be similar to a thermowell. 10 Skelton et al [2]. 11 ISO 5167– 2 [16]. Flow conditioner minor loss coefficient range: 1.8 ≤ Kl,minor ≤ 3.

17

Fig 11. Pressure Loss Along 1000 ft of Pipeline.

Fig 12. Pressure Loss Along 1 Mile of Pipeline.

Figures 11, 12 & 13 show the overall estimated pressure drop across the 1000 ft, 1 mile, & 40 mile of gas transmission pipe with the same pipeline components respectively. Configuration 1 shows the pipe and pipe components with no flow meter installed. Configuration 2 shows Configuration 1 with the addition of a flow conditioner to represent the installation of a non-intrusive flow meter. Configuration 3 shows Configuration 1 with the addition of a flow conditioner and orifice meter.

Figure 11 configuration shows that over 1000 ft of pipe the pipeline components contribute a slightly larger pressure drop than the pipe. The flow conditioner and orifice meter contribute a relatively small and moderate pressure drop contribution respectively to the 1000ft of pipe. However, as the length of pipe being considered increases (to more typical industrial pipe line length) the contribution of all pipeline components (flow conditioner and orifice meter inclusive) becomes relatively small.

The increase in overall pressure drop across 1000ft, 1 mile, & 40 miles, due to the addition of flow conditioner (and non-intrusive flow meter) is 9%, 4%, & 0.14% respectively. The increase in overall pressure drop across 1000ft, 1 mile, & 40 miles, due to the further addition of the orifice meter is 30%, 14%, & 0.5% respectively.

18

Fig 13. Pressure Loss Along 40 Miles of Pipeline.

Fig 14. Pressure Loss Along 40 Miles of Pipeline with Rougher Pipe.

It is not by accident or by error that fluid mechanics convention calls the pipeline losses the ‘major’ losses and the pipe component losses the ‘minor’ losses. As seen in Figure 12 & 13, as the distance of pipe considered increases the ‘major’ pipe losses dominate. Across pipeline systems ‘major’ pipe pressure loss can dwarf the ‘minor’ loss of pipeline components (such as flow conditioners and orifice meters). So a flow conditioner (perhaps with a non-intrusive flow meter) and an orifice meter can indeed produce minor pressure losses when compared to many systems in which they are applied. In this example we see that the orifice meter has a minor loss coefficient approximately 3.7 (i.e. 7.36 / 2) times that of a typical flow conditioner. However, this is 3.7 times a small pressure drop. The contribution of an orifice meter to the overall pressure drop between gas compression stations is a very small component of the total, as shown in Figure 13.

This example shows rather favourable conditions. In reality there are extra major pipe losses due to inevitable elevation changes, any light liquid contamination in the gas flow, pipe roughness increasing over time, more pipe components in the longer pipe etc.. Furthermore, to keep the example simple an approximation has been made that the gas dynamic pressure stays constant across the length of pipe. In reality the dropping pressure causes an increase of gas dynamic pressure down the pipe, which

19

adds an extra pressure loss component of another few percent, mainly in the major pipe loss component. These factors further reduce the significance of flow meter pressure loss. Figure 14 shows the additional major pipe losses due to a modest increase in pipe roughness along the distance between gas compressor stations. This increases the average friction factor from 0.012 to 0.013 causing an 8% additional increase in major pipe loss. Even this modest increase in friction factor dwarfs the contribution of flow conditioners and orifice meters.

Orifice meters do have a relatively high permanent pressure loss relative to some other flow meter designs. Compared to some (but not all) flow meter designs pressure drop can be a con for orifice meters. However, the real significance of relative pressure losses between different flow meter designs is sometimes over played. The scale and significance of a flow meter pressure loss contribution to overall pipeline system pressure loss is case dependent and should always be taken in proper context. If the application is for a relatively short pipe run, the pressure loss is critical, and the operator has gone to the considerable effort of actively theoretically and practically trying to minimize the total pressure drop to the extent of:

• using as smooth a pipe as possible for the whole pipe length • minimizing bends and other pipe components during design, • selecting valve designs for minimum pressure drop, • periodically checking valve settings during operation etc.,

then orifice meter pressure drop is a practical con compared to non-intrusive meter designs. However, in many flow meter applications the pressure loss of any flow meter is a small to negligible factor in the overall pipeline pressure loss. Unfortunately this reality is often obscured by aggressive meter marketing between manufacturers of flow meter types. In any case permanent pressure loss is not the only consideration in flow meter design characteristics, and orifice meters certainly have several other beneficial characteristics.

3d Orifice Plate Flow Meter Diagnostics

A comprehensive diagnostic system (or ‘suite’) is almost a prerequisite for a flow meter to be considered a cutting edge, state-of-the-art, modern flow meter. Whereas the orifice meter is a beautifully simple traditional technology, quite counter-intuitively, it also has arguably the most modern, comprehensive, and beautifully simple, easy to understand diagnostic suite of all flow meters.

Fig 15. Orifice meter with instrumentation sketch and pressure field graph.

DP Diagnostics delivered to industry an orifice meter diagnostic system. The diagnostic system is called ‘Prognosis’. An overview of these patented ‘pressure field monitoring’ diagnostics is now given. For details the reader should refer to the descriptions given in by Steven [3, 4], Skelton et al [2] & Rabone et al [5].

20

Figure 15 shows a sketch of a generic DP meter and its pressure field. The DP meter has a third pressure tap downstream of the two traditional pressure ports. This allows three DPs to be read, i.e. the traditional (∆Pt), recovered (∆Pr) and permanent pressure loss (∆PPPL) DPs. These DPs are related by equation 13. The percentage difference between the inferred traditional DP (i.e. the sum of the recovered & PPL DPs) and the read traditional DP is δ%, while the maximum allowed difference is θ%.

DP Summation: PPLrt PPP ∆+∆=∆ , uncertainty ± θ % --- (13)

Traditional flow calculation: ( )tttrad Pfm ∆=.

, uncertainty ± x% --- (14)

Expansion flow calculation: ( )rr Pfm ∆=exp

.

, uncertainty ± y% --- (15)

PPL flow calculation: ( )PPLPPLPPL Pfm ∆=.

, uncertainty ± z% --- (16)

Each DP can be used to independently meter the flow rate, as shown in equations 14,

15 & 16. Here tradm.

, exp

.

m & PPLm.

are the mass flow rate predictions of the traditional, expansion & PPL flow rate calculations. Symbols

tf ,rf &

PPLf represent the traditional,

expansion & PPL flow rate calculations respectively, and, %x , %y & %z represent the uncertainties of each of these flow rate predictions respectively. Inter-comparison of these flow rate predictions produces three diagnostic checks. The percentage difference of the PPL to traditional flow rate calculations is denoted as %ψ . The allowable difference is the root sum square of the PPL & traditional meter uncertainties, %φ . The percentage difference of the expansion to traditional flow rate calculations is denoted as %λ . The allowable difference is the root sum square of the expansion & traditional meter uncertainties, %ξ . The percentage difference of the expansion to PPL flow rate calculations is denoted as %χ . The allowable difference is the root sum square of the expansion & PPL meter uncertainties, %ν .

Reading these three DPs produces three DP ratios, the ‘PLR’ (i.e. the PPL to traditional DP ratio), the PRR (i.e. the recovered to traditional DP ratio), the RPR (i.e. the recovered to PPL DP ratio). DP meters have predictable DP ratios. Therefore, comparison of each read to expected DP ratio produces three diagnostic checks. The percentage difference of the read to expected PLR is denoted as %α . The allowable difference is the expected PLR uncertainty, %a . The percentage difference of the read to expected PRR is denoted as %γ . The allowable difference is the expected RPR uncertainty, %b . The percentage difference of the read to expected RPR is denoted as

%η . The allowable difference is the expected RPR uncertainty, %c .

Fig 16. Normalized Diagnostic Box (NDB) with diagnostic results

These seven diagnostic results can be shown on the operator interface as plots on a graph. That is, we can plot (Figure 16) the following four co-ordinates to represent the seven diagnostic checks: ( )%%,%% aαφψ , ( )%%,%% bγξλ ,

( )%%,%% cηνχ & ( )0,%% θδ . For simplicity we can refer to these points as (x1,y1), (x2,y2), (x3,y3) & (x4,0).

21

The act of dividing the seven raw diagnostic outputs by their respective uncertainties is called ‘normalisation’. A Normalised Diagnostics Box (or ‘NDB’) of corner coordinates (1,1), (1,-1), (-1,-1) & (-1,1) can be plotted on the same graph (see Figure 16). This is the standard user interface with the diagnostic system ‘Prognosis’. All four diagnostic points inside the NDB indicate a serviceable DP meter. One or more points outside the NDB indicate a meter system malfunction. Different problems can cause different plots (i.e. ‘diagnostic patterns’) and this can help narrow down the source of a malfunction.

ISO 5167-2 states a discharge coefficient and a Pressure Loss Ratio (PLR) prediction. From these two factors DP Diagnostics have shown the other diagnostic parameters can be derived. Hence, for orifice meters, Prognosis effectively monitors if the orifice meter performance is behaving as ISO states it should be behaving. That is, for orifice meters, Prognosis does not need to be set by calibration, and Prognosis effectively gets its authority from ISO 5167. To argue the capability of Prognosis is to effectively argue against the orifice meter performance stated by ISO 5167-2. No other flow meter diagnostic system can trace its entire operating principle back to a published standard and axioms in fluid mechanics and mathematics.

‘Prognosis’, has been successfully tested multiple times by multiple parties. The following is a small sample of the list:

• Field Beta Site BP CATS, UK (see Skelton et al [2]) • Field Beta Site CoP TGT, UK (see Skelton et al [2]) • Field Beta Site CoP / Rosneft, Polar Lights, Russia (see Rabone et al [5]) • Field Beta Site CoP Franklin, Texas, USA • BP Funded CEESI Wet Gas Facility Test (see Steven et al [6]) • CIATEQ Mexican National Water Flow Laboratory (see Moncada et al [7]) • ATMOS Training Facility, Plano, Texas, US (see Steven [8]) • SP Water Flow Facility in Sweden (Tested by Evaluation International [9]). • TUVNEL in the UK (report is confidential by 3rd party funder)

Prognosis results from the field test at BP CATS are shown here to give sample results. (For more details see Skelton [2].) BP operates a natural gas processing facility located in Teeside, UK called the Central Area Transmission System (i.e. ‘CATS’). A Prognosis system was installed on an ISO compliant 16” (sch 120) 0.5965β fiscal orifice meter. Figure 17 shows the meter run (on the right). Note the header, two valves and flow conditioner installation upstream of the meter. (This is an example of how the pressure loss example in Section 3c is realistic.) The orifice meter is insulated under the walk way that leads to the temperature controlled instrument room (see Figure 7). Most orifice meter runs (e.g. Daniel orifice meter runs) have a series of thermowell, sample and pressure ports available downstream of the meter. Therefore a downstream pressure port is usually already available, and the ISO 5167 text allows derivation of the diagnostic baseline without calibration, hence, most installed orifice meters can have Prognosis retrofitted. This was the case at BP CATS. Figure 18 shows downstream of the orifice meter and the insulated pressure ports that allowed Prognosis to be easily installed.

The meter run received approximately 175 tonnes/hr of gas. The line pressure remained constant through out the extended test period at approximately 111 Bara with a gas density of approximately 147 kg/m3. The associated Reynolds number was

22

Fig 17. BP CATS upstream orifice run. Fig 18. BP CATS downstream tap set up.

approximately 1e7. The system had a DP stack for reading the traditional DP. (This is an example of how common stacked DP transmitters are – as stated in Section 3b.) One Rosemount transmitter was spanned to 62kPa and another to 15kPa. For the diagnostics field trial BP added DP transmitters spanned to 50kPa and 25kPa to read the PPL and recovered DP respectively.

Figure 19 show a sample BP CATS Prognosis result from the initial baseline tests on the live fiscal orifice meter. The allowable variations of the diagnostic parameters

were set at the default conditions. As expected, the meter was performing as predicted by ISO and the diagnostics showed no problem.

Fig 19. BP CATS Orifice Meter as

Found

BP then (with permission from the UK Petroleum Inspectorate) deliberately induced various problems to check the diagnostic system. Due to constant flow and correctly operating orifice meters in parallel runs, BP could estimate the induced flow rate prediction biases. A common problem with orifice meter operation is the keypad entered meter geometry being

Fig 20. Inlet Diameter Entered Low Fig 21. Orifice Diameter Entered Low

23

different to the actual meter geometry. Figure 20 shows the response of Prognosis when the inlet diameter was keypad erroneously entered as 13.562” (i.e. the nominal value of 16” schedule 120 pipe) instead of the actual measured diameter of 13.738”. This inlet diameter negative error induces a positive flow rate prediction error of approximately +0.4%. Alternatively, Figure 21 shows the response of Prognosis when the orifice diameter was keypad erroneously entered as 8.1” (i.e. missing the last two digits of the actual 8.195” value). This orifice diameter negative error induces a negative flow rate prediction error of approximately -2.6%. In both cases Prognosis indicates a problem (i.e. points are outside the NDB). In both cases the DP reading integrity check remains inside the NDB. Prognosis is showing something is wrong, the problem does not lie with the DP readings, but with the physical meter (i.e. in this case the meter is a different geometry to that being assumed.)

Fig 22. Plate Installed Backwards Fig 23. Orifice Plate Edge Worn

Orifice plates are required to have a sharp upstream orifice edge. Therefore, orifice plates installed backwards that have a bevel on the downstream side, or worn orifice edges, cause significant biases in the flow rate prediction. Figures 22 & 23 show the response of Prognosis when BP installed the plate backwards and then installed a plate with a worn orifice edge. The reversed plate and worn edge tests induced negative errors of -15% & -2% respectively. In both cases Prognosis indicates a problem (as points are outside the NDB) while the DP reading integrity check remains in the NDB. Prognosis is showing something is wrong, the problem does not lie with the DP readings, but with the physical meter (i.e. in this case the orifice geometry is different to the required geometry.) Furthermore, the reversed plate changes the correct geometry to a specific different geometry. Hence, the Prognosis response is a specific pattern for that specific geometry change, which is an indicator that the problem is specifically a reversed plate. Note that a reversed plate presents the oncoming fluid with the bevel, i.e. an extreme reduction in sharpness. It is therefore not a coincidence that the Prognosis response for a slightly worn edge plate is a similar pattern but just not as extreme.

Fig 24. A Saturated DP Transmitter

24

During the field trials the traditional DP being produced by the orifice meter was in the order of 17.5kPa. The high & low DP transmitters were spanned to 62kPa & 15kPa respectively. The 17.5kPa was initially being read correctly by the 62kPa spanned transmitter. BP deliberately induced a -10.4% DP reading and corresponding -5% flow rate prediction error by switching to reading the saturated DP transmitters output. Figure 24 shows the Prognosis response. The DP integrity check (x4,0) now clearly shows there is a problem with a DP reading. Furthermore, two of the other three points are outside the NDB. As Prognosis is showing a DP transmitter reading issue the pattern then tells the operator more. Only one point is still inside the NDB, i.e. (x3,y3). This is the only point that does not use the traditional DP. Therefore, Prognosis has identified that the traditional DP reading has the problem. Hence, the recovered & PPL DP readings are trustworthy. The traditional DP can therefore be found via equation 13 allowing the traditional flow rate calculation to continue while equations 15 & 16 also give the flow rate. Whereas traditionally an orifice meter with a saturated DP transmitter may continue in service giving an unnoticed erroneous output, with Prognosis the problem is not only identified, but the correct flow is still found and the meter is still serviceable until the operator can organise maintenance on the known problem.

BP presented these Prognosis test results in 2010 (see Skelton [2]). Since then Prognosis has been repeatedly proven in further 3rd party laboratory tests, various field tests, and in service on various orifice meter operations. Prognosis has now been proven to show an alarm on most common field problems, e.g. wet gas flow, buckled plate, partially blocked orifice, contaminated meter run, unseated plate, blocked impulse lines etc. The UK DECC Guidelines for Petroleum Measurement [10] promote the generic concept. The Canadian Alberta Directive 17 [11] promote the use of diagnostics which for orifice meters practically means using this generic concept. With the delivery of Prognosis orifice meters now have one of the most capable, or perhaps the most capable, advanced diagnostic systems of all flow meters.

3e. Orifice Meter Wet Gas Flow Performance

Wet gas flow metering is extremely challenging. Although there are high end expensive wet gas meter technologies on the market, due to economic necessity the majority of wet natural gas and wet (‘saturated’) steam flows are still metered with standard single phase meters, such as orifice meters. Although long assumed a poor wet gas meter, recent research has shown that quite counter intuitively the orifice meter is one of the most predictable and reliable meters with wet gas flow. This has led to ISO TR12748 [14] and ISO TR11583 [13] both listing the same orifice meter wet gas correlation. This correlation is the most advanced and wide ranging wet gas correlation for any gas meter design on the market. Furthermore, the orifice meter diagnostic system Prognosis has been shown to identify wet gas flow.

The Definition of Wet Gas Flow Parameters

Wet gas flow is defined (by ASME [12] and ISO [13,14]) to be any two-phase (liquid and gas) flow where the Lockhart-Martinelli parameter (XLM) is less or equal to 0.3, i.e. XLM ≤ 0.3.

hom,

.

,

.

l

g

g

totall

LM

m

mX

ρρ

= --- (17)

25

The Lockhart-Martinelli parameter (equation 17) is a non-dimensional expression of

the amount of liquid with the gas. Note that gm.

& totallm ,

.

are the gas and liquid mass

flow rates respectively (where totallm ,

.

is the sum of the individual liquid component flows), while ρg & ρl,hom are the average bulk gas and liquid densities respectively.

The gas to liquid density ratio ( hom,lgDR ρρ= ) is a non-dimensional expression of

pressure. The gas densiometric Froude number (gFr ), shown as equation 18, is a non-

dimensional expression of the gas flow rate. Note that ‘g’ is the gravitational constant, ‘D’ is the meter inlet diameter and ‘A’ is the meter inlet cross sectional area.

( )glg

gg

ggDA

mFr

ρρρ −=

hom,

.1

---- (18)

With one single liquid component a wet gas has one liquid density. With multiphase wet gas flow there is two (or more) liquid densities. In this case the liquid density used to calculate the Lockhart martinelli parameter, gas to liquid density ratio and the gas densiometric Froude number is the average liquid density ( hom,lρ ).

With upstream natural gas production multiphase wet gas with a mix of water and liquid hydrocarbon is common. “Water cut” is the ratio of the water to total liquid volume flow rates when the fluid is at standard conditions. The “water to liquid mass ratio” (or ‘WLRm’) is defined as the water (wm

.

) to total liquid mass flow rate ratio. The WLRm is calculated here by equation 19.

totall

w

m

m

mWLR

,

.

.

= --- (19)

An example of a homogenous liquid phase density (hom,lρ ) calculation is given by

equation 20. This example is for a water and hydrocarbon liquid mix. Note that wρ

& hclρ are the water and hydrocarbon liquid densities respectively. For multiphase wet

gas flows it is this liquid mixture density that is used to calculate the wet gas flow parameters.

( ) ( )mwmhlc

hlcwl WLRWLR −+

=1hom, ρρ

ρρρ --- (20)

Equation 1 shows the orifice meter single phase gas mass flow equation. The liquid induced gas flow rate prediction error is usually a positive bias and often called an ‘over-reading’, denoted here as “OR”. The traditional DP read when the flow is wet (∆Ptp) is different to that which would be read if that gas flowed alone (∆Pg). The result is an erroneously high, or “apparent”, gas mass flow rate over-prediction,

apparentgm (see Equation 1a). Note that apparentgm , tpε and tpdC , are the apparent

(incorrect) gas mass flow rate prediction, the gas expansibility and the discharge coefficient found respectively when applying the wet gas differential pressure. (For many flow conditions εε dtptpd CC ≈, .) The over-reading is expressed either as a ratio

(equation 21) or percentage (equation 21a) comparison of the apparent to actual gas mass flow rate. Correction of this over-reading is the basis for orifice meter wet gas correlations.

26

tpgtpdtpapparentg PCA

m ∆−

= ρεβ

β2

1,4

2

--- (1a)

g

tp

g

tp

d

tpdtp

g

Apparentg

P

P

P

P

C

C

m

mOR

∆∆

≅∆∆

==ε

ε , --- (21)

%100*1%100*1%

−

∆∆

≅

−=

g

tp

g

Apparentg

P

P

m

mOR --- (21a)

The ISO TR 12748 & ISO TR 11483 Orifice Meter Wet Gas Flow Correction Factor

By 2011 a cross industry consortium had gathered a massed horizontally installed orifice meter wet gas flow data set (of the range 2” ≤ D ≤ 4”) from multiple owners, tested at different facilities, over many years. Figure 25 shows a large sample of this data set. Table 4 shows the multiphase wet gas flow data range used to create the ISO correlation (presented here as equation set 22 thru 27b).

2

,

..

1 LMLM

apparentgg

XCX

mm

++= --- (22)

n

g

l

n

l

gC

+

=

ρρ

ρρ hom,

hom,

--- (23)

( )WLRFrtransitiong *2.05.1 += -- (24)

( )( ){ }WLRA −−+= exp*1.04.0# -- (25)

2

,

#

2

1

−

=transitiong

stratFr

An -- (26)

stratnn = for transitiongg FrFr ,≤ -- (27a)

2

#

2

1

−

=gFr

An for transitiongg FrFr ,> -- (27b)

Note that ∞→Frg then 21→n as required

Parameter Range

Pressure 6.7 to 78.9 bara Gas to liquid density ratio 0.0066 < DR < 0.111

Frg range 0.22 < Frg < 7.25 XLM 0 ≤ XLM < 0.55

Inside full bore diameter 1.94” ≤ D ≤ 4.026” Beta 0.341 ≤ β ≤ 0.683

Gas / Liquid phase Gas /Liquid Hydrocarbon/ Water Table 4. Multiphase Wet Gas Flow Data Set Flow Range.

Figure 25 shows the uncorrected data, and the data corrected for known liquid flow rates. For known liquid flow rate inputs this correction factor has a 2% uncertainty to 95% confidence.

27

Fig 25. 2” to 4” orifice meter wet gas data with and without correction.

This correlation has now been shown to be applicable when there is also MEG and heavier hydrocarbon liquids present (see Steven et al [6]). It has also been tested with 8” orifice meter multiphase wet gas data where it was found to operate at 3% uncertainty at 95% confidence (see Steven et al [6]).

Wet gas flow is a very adverse flow condition for all gas meter designs. As with all gas meter designs, the orifice meter is significantly effected by wet gas flow. However, it has been repeatedly proven that an orifice meter does not significantly dam liquid, and liquid presence does not make the DPs too unstable to be useful (e.g. Steven [15]). The orifice plate is sturdy enough that most survive long term in wet gas flow applications, and if the plate was ever damaged, it is a simple and relatively inexpensive procedure with a dual chamber fitting to replace the plate. Furthermore, unlike some gas meter designs the orifice meter continues to operate even with significant liquid loading (i.e. relatively high Lockhart Martinelli parameters), and unlike most gas meters the orifice meter wet gas flow response has been found to be repeatable, reproducible and characterized by ISO.

The orifice meter diagnostic system can identify wet gas flow through an orifice meter. Rabone [5] showed results for when ConocoPhillips (CoP) installed a Prognosis system on a 12”, 0.636β orifice meter on the Jasmine development. Figure 26 show sample Prognosis results from this meter. (In this case the recovered DP was not read directly and was only inferred from Equation 13. Hence, Figure 26 shows no DP check diagnostic (x4,0) - as it was not available.) The Prognosis output is usually averaged over a period of time to give a clear result. This sample data set was recorded once a minute for three hours. The averaged result is shown on the left. The right hand graph is the 180 individual results plotted together. Here we see that the diagnostic plot varies with time. The averaged data gives a diagnostic alarm which fits several possible problems – in which wet gas is one of the possibilites. However, amongst this short list only wet gas flow is known to show such unstable / dynamic

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diagnostic response seen in on the right hand side of Figure 26. Therefore, Prognosis strongly suggests wet gas flow was the probable issue. CoP investigated and confirmed this.

Fig 26. Jasmine 12”, 0.636β Orifice Meter Test Separator Gas Outlet Diagnostics.

4. Conclusions

Orifice meters continue to be one of the most popular and widely used flow meters through out industry. A century of evolution has produced an economical meter with truly remarkable and predictable performance characteristics.

The orifice meter has sometimes been called “…just a hole in a plate meter”. And yes, that is precisely what it is! Just a hole in a known geometry plate with a DP read across it. It is beautifully simple, elementary. It is this very simplicity that makes the orifice meter technology so enduring. As Leonardo da Vinci is accredited with saying “Simplicity is the ultimate sophistication”.

For a huge range of flow conditions the standards correctly predict the orifice meter performance “out the box”. The modern uncalibrated orifice meter has an out the box flow rate prediction uncertainty on a par with the latest calibrated flow meter technologies.

The orifice meter with one plate / beta and modern DP transmitters has a turndown suitable for most industrial applications. Furthermore, if a flow range changes significantly over the life time of the application the orifice meter may be the best metering technology for the application. The orifice meter uniquely offers the rare ability to ‘re-size’ the turndown by simply and easily switching out the plate to a different beta.

The orifice meter does have a moderate permanent pressure loss performance relative to other meter designs. However, the significance of this can be over played by marketing of other meters. Relative to the overall pipeline system pressure drop the flow meter pressure loss is often a very small component.

The orifice meter can now be fitted, or retrofitted, with ‘Prognosis’, i.e. one of the most modern diagnostic suites available. Prognosis has been comprehensively tested in multiple laboratories, field trials and now employed in many industrial

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applications, by different third parties. This orifice meter diagnostic system is the equal to any flow meters diagnostic system.

Contrary to early assumptions, orifice meters have a remarkably good wet gas flow performance. The orifice meter does not cause significant damming of liquids. ISO has now published for the orifice meter the most comprehensive multiphase wet gas correlation (i.e. correction factor) for any flow meter. Furthermore, whereas with many gas meter technologies the operator does not know when wet gas is present, and would have no correlation available even if they did know, the orifice meter diagnostic system can identify wet gas flow through an orifice meter.

Orifice meters remain one of the most advanced, trusted, well understood and versatile flow meters on the market. Industry has vast experience with the meter over a century, and the orifice meter has continually evolved with the challenges of modern industry.

References

1. API 14.3 Report No. 3, 3rd Edition, 1990 2. Skelton M. et al, “Diagnostics for Large High Volume Flow Orifice Plate Meters”, North Sea Flow Measurement Workshop October 2010, St Andrews, Scotland. 3. Steven, R. “Diagnostic Methodologies for Generic Differential Pressure Flow Meters”, North Sea Flow Measurement Workshop October 2008, St Andrews, Scotland, UK. 4. Steven, R. “Significantly Improved Capabilities of DP Meter Diagnostic Methodologies”, North Sea Flow Measurement Workshop October 2009, Tonsberg, Norway. 5. Rabone J., et al “Advanced DP Meter Diagnostics – Developing Dynamic Pressure Field Monitoring (& Other Developments)”, North Sea Flow Measurement Workshop October 2014, St Andrews, Scotland. 6. Steven R. et al “Expanded Knowledge on Orifice Meter Response to Wet Gas Flows”, North Sea Flow Measurement Workshop October 2014, St Andrews, Scotland. 7. Moncada D, at al “Results of Testing an Orifice Meter Diagnostic System at a Mexican Government Water Flow Facility”, Flomeko, Paris, France 2013. 8. Steven R. et al “Testing of an Orifice Plate Meter Diagnostic System at the ATMOS Energy Corp. Training Center”, AGA Conference, Florida May 2013. 9. Rabone J, et al “Differential Pressure Meter Diagnostics – Independent Evaluation on Orifice Meter with Liquid Flow”, International Flow Measurement Conference 2015: Advances and Developments in Industrial Flow Measurement, Coventry UK July 2015. 10. UK DECC “Guidance Notes for Petroleum Measurement Issue 8”, 2012. 11. Alberta Energy Regulator, Directive 17, “Measurement Requirements for Oil & Gas Operations”. 12. American Society of Mechanical Engineering MFC Report 19G “Wet Gas Metering”. 13. ISO TR 11583 “Measurement of wet gas flow by means of pressure differential devices inserted in circular cross-section conduits running full — Part 1: General principles and requirements” 14. ISO TR 12748 “Wet Gas Flow Measurement in Natural Gas Operations”

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15. Steven R., Stobie G., Hall A. & Priddy R., “Horizontally Installed Orifice Plate Meter Response to Wet Gas Flows” North Sea Flow Measurement Workshop Oct. 2011, Tonsberg, Norway. 16. ISO, “Measurement of Fluid Flow by Means of Pressure Differential Devices, Inserted in circular cross section conduits running full”, no. 5167, Part 2.