Paper 5.3 Seaw

Paper 5.3

Challenges Using DifferentialPressure Meters in Heavy Oil

Measurement

Philip A. LawrenceCameron Measurement Systems, Inc.

9th South East Asia Hydrocarbon Flow Measurement Workshop2nd – 4th March 2010

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Challenges Using Differential Pressure Cone MetersIn Heavy Oil Measurement

Philip A Lawrence Cameron Measurement Systems

Abstract

The conventional global oil supply is at risk politically! This is because the total number ofconventional oil production from all countries in the world, is near the maximum set by theirphysical resource limits. (Excepting of course the five major Middle-East suppliers).

Should the Middle-East suppliers decide to substantially curtail supply, the shortfall cannot bereplaced by conventional oil from other sources.

Over 4 decades production companies have been searching for techniques to efficientlyrecover more oil from “depleted” reservoirs in the North American oil slate which may have asmuch as 35 to 40% of the original oil still in place. More than >50 billion Bbl’s of oil may stillbe available in these depleted reservoirs in the US alone.

During the next decade world production capabilities by conventional means will not meet theenergy demands, therefore oil prices will continue to increase.

The soaring oil prices makes enhanced oil recovery very attractive economically and thismeans that we are now entering an era were unconventional methodology will be used torecover energy resources that were unattractive economically in the past.

These potential energy reserves include: Oil shale, Tar sands , Heavy oils and Non-conventional recovery from existing and known reservoirs.

This paper discusses the use of the “differential pressure cone meter” a technology that hasbeen around for many years, originally stemming from a concept conceived in 1935 by Mr.Burton Dunlinson of the UK, and further refined to the present design configuration in 1985and now available in its present configuration for these emerging applications.

This type of technology has been be used at various measurement points in the process of“extraction” and general process measurement of heavy crude’s and other hydrocarbonproducts however it is not used for fiscal pipeline liquid hydrocarbon measurement.

Allocation measurement of these fluids may be accepted in future developments due to thelow Reynolds numbers experienced when transporting these products in a pipeline and thedifficulty in measurement due sometimes to the Non-Newtonian properties exhibited by thefluids. The device is also used to measure steam a secondary fluid used to extract heavy oilby injection.

After reviewing D.P. data based on water testing over some years it is known that most of thelow Reynolds number (ReD) test data for this meter was published may not show a completestory of this type of Differential Pressure Meter operating on heavy oils due to viscosityeffects.

The recent technical work using computational fluid dynamics (CFD) based on temperatureeffects on crude oil measured by cone meters (A recent technical paper by Hollister) isinteresting.

To show the impact on the measurement of high viscous oil and viscosity change due totemperature using D.P. types of meter one really needs to calibration using a traceablecalibration rig on viscous hydrocarbon fluids.

9thth South East Asia Hydrocarbon Flow Measurement Workshop2ndnd – 4– 4thth March 2010

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Cone Shaped Differential Pressure Meters

All D.P. Cone Meters (non wall tap design) consist of a conically shaped differential pressureproducer fixed concentrically in the center of a pressure retaining pipe, by which a differentialpressure can be obtained across the interface of two cone frustums via an internal port-waysystem.

This allows the downstream pressure P2 to be measured in the center of the meter pipebody.

The fluid is linearized through the meter throat within a region defined by the differentialproducer and the interior surface of the closed conduit, whilst flattening the velocity profile inthe throat region of the device.

The upstream (static) pressure P1P1, being measured at the pipe wall.Fig.1.0 CFD Image.

Fig.1 - CFD Image

The concept of using the center of the cone above to monitor the downstream pressure hasshown certain benefits compared to conventional differential pressure meters such as thefollowing :-

a) Flow Conditioning.b) Large Turndownc) Static Mixingd) Wet Gas usage with Lockhart & Martinelli (Xlm) values up to 0.5.

(A test showing this Xlm value by Stevens el at NSFMW Paper Tonsberg 2003)

Geometrical Considerations.

Manufacturing tolerances are important when making a differential meter that uses aniterative process to determine its coefficient of discharge by calculation or lookup table.

The method assumes a constant geometry subject to a predetermined manufacturingtolerance i.e. orifice plates with machined holes. In the case of a cone meter, each device isusually calibrated against a traceable standard to determine the Coefficient of Discharge(C.d.) This makes sure that the correct C.d. is implemented per each meter manufactured.Some work is being done to obtain repeatable C.d.’s per the same pipe diameter betweensubsequent meters to reduce the need to calibrate each device and therefore allow the C.d.to be iterated or determined from a look up table.

This method would depend on meter manufacturing tolerances being very close betweeneach meter produced and some method of generating repeatable geometric similarity, theC.d. equation could be a function of Re, beta and diameter, but the test programme wouldhave to be quite large to get reliable data.

Computational Fluid Dynamics ImageShowing Streamlines

MeterThroat

FLOW

P2X-Section. separation

Region

9thth South East Asia Hydrocarbon Flow Measurement Workshop2ndnd – 4– 4thth March 2010

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Manufacturing Concerns

When manufacturing a differential cone type meter there are various important issues to takecare of:

A) Concentricity of the D.P. Cone.

B) Alignment and cone support robustness and stability.

C) Assembly of the Differential Producer and Tap location and Tap design).

D) Cone Angles (both upstream and downstream).

The usual method for Beta Ratio determination of “annulus type meters” is known as beingthe ratio of the root of the square of the displacement member annulus area versus the rootof the square of the pipe area and this reduces to the following universal equation shown inequation (1)

………………..…………………………………………..……. Eq.(1)

Cone Geometry

The drawing in Fig.2 shows a typical generic differential pressure cone geometry as used insome commercially made generic cone meter designs.

Fig 2 – Typical Cone Meter Geometry.

Beta Ratio Change

Cone meter area ratio’s ()’s76# $/' 3$/*'& 1. $%%.,,.&$1' 1)' ,'$02/','-1 .( &*(('/'-1 (+.4rates by changing the cone length and thus the cone diameter (fig 2.0). This changes theeffective diameter of the cone in relation to the pipe diameter and thus the beta or effectivearea ratio and ultimately the flow velocity across the Beta edge boundary. The pipe diameterand beta are chosen to obtain an appropriate balance between measurable D.P. and overallpressure loss for a given flow-rate

Taps: Static Low Pressure&&PP


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Commercially made cone meters operate generally in )"ratios from 0.45 - 0.85. It must benoted that as the beta ratio becomes larger (approaching ) 0.8 - a smaller cone diameter) themeter performance changes and the measurement uncertainty can become larger.

This “performance” effect is caused by the reduced interaction between the cone area andthe fluid, i.e. a smaller cone does less work on the fluid so the flow linearization aspect of themeter is reduced. Care must be taken when using smaller cones where valves or other flowdisturbance generators are in line and upstream of differential pressure cone device.

The cone meter manufacturer should be able to advise of the minimum straight lengths perbeta ratio and diameter versus regarding this effect.

The mass flow rate equation for generic cone meters is exactly the same as per any standardDP device equation, (Orifice or Venturi) with the exception of the C.d. implementation which isusually derived from empirical testing by the manufacturer or other independent labs and notgenerally by a look up table method.

Medium to High Viscosity Testing

When discussing the production of this paper, it was decided to take a 4 inch cone meter to alaboratory that could test on multi-product fluids. The 20 inch ball prover situated in theCameron - Caldon facility in Pittsburgh has the ability to prove meters on 70 cSt and 170 cStcrude oil

The facility is traceable to NIST and has the ability to use Ultrasonic meters (larger sizes) andTurbine meters (smaller sizes) as a secondary standard, after further discussion it wasdecided to use the Brooks Small Volume Prover (SVP) instead, that is also installed as part ofthe laboratory installation as seen in Fig.3.

The cone meter was fitted with an analogue to digital converter which was connected to aScanner 2000 multivariable liquid -gas flow computer to facilitate a pulse output similar to aturbine meter. This would convert the flow rate to a signal that could be interpreted by theCaldon laboratory data acquisition system (DAS).

This method had not been used before by the writer and some worry regarding prover surgeand pulse integrity caused by the SVP piston movement was negated by some pre-testingand analysis at random flow rates to make sure that the expected results were valid.

Fig.3 - Cameron-Caldon, ISO 17025 Multi-Product Flow Laboratory


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Hydrocarbon Test Facility Description

The process fluids (mineral oils) are stored in three tanks. When required, they can be usedto fill the calibration flow line. The chosen oil is pumped from the tank into the flow line,through an interlocked valve system. The system is then pressurized and vented to removegas while circulating the fluid. Flow is typically controlled by two variable speed pumps.

For the lowest flow rates, extra control is added by the use of a butterfly valve (additionalpressure loss). Fluid flows from the pumps and into a heat exchanger (2500 tubes). The tubeshell side is cooled with water/glycol that is pumped to an external chiller. This heatexchanger keeps the fluid temperature stable to ~ 0.5°C.

After the heat exchanger, the fluid bifurcates into two 10 inch lines, each with an LEFM 280Cmaster meter. Downstream of the master meters the total flow goes through a 24 inchheader and from the header, the flow can go through one of three test lines. The three testslines are nominally 8”, and two 24”.

The 8” line is designed for smaller meters (4 inch to 8 inch). This line has an actuatedbutterfly valve for lower flow rates. The 24” lines are for meters 10 inches and larger. Finallythe fluid passes through a 20” uni-directional meter prover before returning to the pumps.

The SVP is located in piping sections attached to the main system and also has the sametemperature control availability and variable viscosity fluid streams.Fig.4. The SVP isconnected in parallel at the downstream end of the small (8-inch) test line.

Fig.4 – Hydrocarbon Test Facility Schematic Showing the SVP Location.

Calibration Methodology

The cone meter results were determined using a proving method called CLP 2.0,(The lab hasthis procedure available on request), the flow meter calibration facility is Accredited toISO/IEC 17025:2005 (NVLAP Lab Code 200813-0) and CMC Certified by NMi VSL(certificate number 39330924). The run designated by mode SVP and TMM are not coveredunder the NVLAP accreditation

The 2 x 4 inch diameter meters under test with 0.65 and 0.75 beta ratios were calibrated atthe Caldon - Cameron calibration facility in Pittsburgh USA using Drakeol 5 & 32 mineral oilswhich for these tests had a nominal density of 0.835 and 0.863 g/cc at 15.6°C.

SVP Location


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Both meters under test (MUT) at 0.75 & 0.65 beta ratio where tested over temperaturesranging from 19.9 to 20.3°C. and pressures ranging from 21.7 to 37.5 psig.

System Uncertainty

For runs against the small volume prover (mode SVP) the expanded laboratory uncertainty ofmeter factor, MF, is ±0.028%. The expanded uncertainty, U = kuc, is determined from acombined standard uncertainty (i.e., estimated standard deviation) uc = 0.014% and acoverage factor k = 2.

Since it can be assumed that the possible estimated values of the standard are approximatelynormally distributed with approximate standard deviation uc, the unknown value of thestandard is believed to lie in the interval defined by U with a level of confidence ofapproximately 95%.

Below is shown the uncertainty calculation method used to determine the system uncertainty.

Equations. 3 and Table 1.

Eq.3 - Uncertainty Algorithm

' (V V Expansioneffectsof temperature,pressure,fluid,materialsandconnectingvolume

V

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Table.1 - Uncertainty

Test Fluids

Exxsol - D80 (Drakeol) and two mineral oils with nominal viscosities of 2cst 15cSt and150cSt are available , during a calibration, the viscosity can be varied and controlled usingtemperature control between approximately 1.5cSt and 200cSt.During all steps in thetraceability chain temperature and pressures are measured. All the test instruments aretraceable to a National Metrology Institute or an ISO/IEC 17025 accredited company.

For a full description of the traceability chain the Cameron quality manual document CLM 5.6“Measurement Traceability”, revision 4, document CLP 6 “Uncertainty and traceability - flowloop calibration”, revision 4 and CLP 6.1 "UNCERTAINTY AND TRACEABILITY – SMALLVOLUME PROVER FLOW LOOP", revision 1 , is available upon request.


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Test Matrix

Generic cone meters with beta ratios of both 0.65 and 0.75 were tested on both 15 and 170cst oils both installed in straight runs to allow Reynolds number flow ranges to be generateddown to 580 ReD for the 0.75 beta meter and 450ReD for the 0.65 beta meter, installationas shown in Fig.5 - Meter Test Run and Table-2. Piping Spool Lengths

Usually the minimum ReD range lower limit shown for this type of meter on commercial datasheets is 10,000ReD after which most manufacturers recommend that the meter should becalibrated over an in-field operational ReD on similar product types.

The opportunity to test down to below 500 ReD is very useful in determining this genre ofmeters response to viscous fluids and its response to boundary layer effects.

Fig.5- Meter Test Run As Built.

Table.2 – Piping Spool Lengths

Cone Meter Installation

The cone meters where installed fitted with a Scanner 2000 type flow computer which isdesigned to read static pressure , differential pressure, and temperature and also performintegral liquid hydrocarbon flow calculations based on API algorithms, schematic as seen inFig.6.

Fig.6 - Generic D.P. Cone & Fiscal Flow Computer Assembly (Schematic)


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Test Procedure

Hydrocarbon fluid was passed through the prover loop for a set pre-run time and someprovisional data collected , after some quick calculations and flow comparisons it wasdeemed that the method being used was acceptable for the test. Calculated data from thescanner was converted to a 4-20 mA flow rate signal then this data was transmitted to thelaboratory data acquisition system via the analogue to digital converter.

The Scanner 2000 was pre programmed with the fluid density and meter dimensions (tocalculate the beta ratio) with the discharge coefficient set to 1.0000 so that the C.d couldeasily be determined without extra calculation by comparison with the rig meter factor.

The analogue output was configured from 0 to 300 m3/hr and the analogue output was feedinto the ACROMAG 895M-0800 analogue to pulse converter. The converter was configuredsuch that 20 mA equalled 1000 Hz. As is the DAS requirement. The SVP electronics wereconfigured for a time constant of 1.5 seconds (1 second for scanner 2000 and 0.5 secondsfor the analogue to frequency converter.

It is known that most DP meters exhibit non linear results when tested on low Reynoldsnumber( ReD)ranges (i.e. have poor linearity) but can be repeatable according to somemanufacturers claims.

These particular test’s where performed with 5 minute (SVP) proves per flow rate theaverage of the flow rates collected and used to calculate the average coefficient of discharge(C.d.) per flow point this was then plotted against averaged Reynolds Numbers over thesame time period per run and shows some interesting results in the following graphs .

The fall off of the linearity for D.P. devices is well known and it was expected that there wouldbe a similar response for generic cone meter types also.

Meter Test Configuration

The 0.65 and 0.75 beta ratio meters were tested first on the 15cSt, range liquid hydrocarbongiving ReD ranges from; 32950 to 3200ReD for the 0.65beta unit and then 47200 to4700ReD for the 0.75 beta unit.

Meters where then tested with the 170cSt, hydrocarbon fluid giving ReD ranges from; 4,250to 450 ReD for the 0.65 beta unit and 5973 to 583ReD,for the 0.75beta unit.

All data was recorded and calculations for C.d. for the meters produced in the DAS.

Data was plotted on XL spreadsheets and is shown graphically in Figures 6-11.

Graphical Test Data Generic Cone Meter Beta’s ( ) 0.65 and ( ) 0.75

Fig.6 - 0.75 beta ratio D.P. Cone Meter on 15 cSt. Mineral Oil


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Fig.7 - 0.75 beta ratio D.P. Cone Meter on 170cSt. Mineral Oil




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Fig.10 - Log Scale Chart of 0.65) data sets C.d. / ReD@15cSt&170cSt

Log Scale Graphs

As can be seen on the log scale graphs Fig 10 & 11, the region of overlap the C.d. valuesdiffer up to about 2.5%. This is relevant when compared with the statistical uncertainty in thefollowing tables in the paper.

This may be due to D.P. reading error or density error ? The curves should join up inReynolds number space. It is unfortunate we did not have the lab time to do more tests in the2000 to 10 000 region as this is where this particular effect is occurring. It could be that thisis some form of transitional or laminar flow related effect or it could be due to offset betweenthe electronic systems although this error would be small, or a combination of all the abovemay be prevalent, further testing would be interesting to look at in the future.

170cSt

Fig.11 - Log Scale Chart of 0.75 )"data sets C.d. / ReD@15cSt&170cSt

15cSt

170cSt

15cSt170cSt


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Data Set Review

Figures 7 through 12 show plots of the data sets (11&12 – logarithmically showing the 2)"ratios each on different viscosity) the linearity as is common with D.P. devices, has a slopein the upwards direction as flow rate increases, the slope is seen in the graphs and has asimilar shape for both beta ratios.

The slope showed changes in the C.d. of up to 6% however the meter was repeatable.

The averaged data is displayed in Table-3 below;

Table.3 – Reynolds Number (ReD) and Coefficient of Discharge C.d. Per Cone Meter.

The Uncertainty spread & band of the C.d. is also shown in Table 4 below.

Table.4 - Uncertainty Table.


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Conclusion

The testing at Caldon facility showed that whilst cone type meters can operate and offermeasurement in the low Reynolds regime, care must be exercised in this type of meteringapplication because of the linearity The important thing should be to calibrate over thecorrect Reynolds number range, which may be impractical if using water.

Density changes due to temperature in the product can cause changes in the performance ofall D.P. type meters unless some method of determining the density is applied that isaccurate or well determined, (reference-the log chart data transition).Whether by calculation,densitometer, or API-ISO tables.

The meter is not intended for pipeline quality fiscal/custody transfer measurement of liquidhydrocarbons however, the meter can be used in the process measurement of heavy crudeoils and possibly blending were the fluid process data is well known.

In reality the need to know the viscosity in order to get the correct value of ReD and C.d. is akey factor. The sensitivity (which is really not that bad), in the region of 5,000 ReD, shows afactor of 2 error in viscosity which would produce an error of a few percent in the C.d.

References

1) Hayward A. “A Source Guide for Users” Edition Published 19782) Braid C Mr. (Barton Canada) first principle calculations for flow computers May

1999. Environmental Engineering, Univ. of Iowa, Iowa City.3) D. D. Knight, 1982, “ Application of Curvilinear Coordinate Generation Technique to

the computation of Internal Flows”, Numerical Grid generation, Elsevier SciencePublishing Company.

4) Sveedmen SWRI Homogenous Model and OFU liquid effect( report)5) Ifft Wet Gas Testing at SWRI 1997 - V-Cone Meter6) Lawrence Wellhead Metering by V-Cone Technology NSFMW 2000 Gleneagles

Scotland7) Braid C Cameron Inc (Canada) Cone Equations for Flow Computer a Technical

Document 20068) Lawrence ISHM Oklahoma Class 8210.1 Cone Meters for Gasses and Liquids May

20099) Lawrence South Asia Workshop-NEL-Forward and Reverse Flows in Closed

Conduits Paper 7.1 March 2009 – Malaysia.10) HOWS Conference Brazil 2009 – J. Hollister - The Effect of Temperature Gradients

on the Differential Pressure Measurement of Heavy Oils, Paper 3.0.11) Flow Laboratory Data Set – Cameron - Caldon – Ultrasonics, Bobby Griffith - January

2009 – Pittsburgh USA.

Appendix I

Other Photographs of the Cone Meter Test Installation at the Laboratory.

Fig.12-Scanner Flow Computer. Fig.13-Cone Meter +Scanner. Fig.14-Brooks SVP.


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Appendix II

Cameron - Caldon Liquid Hydrocarbon Test Facility General Main Specification.

The overall specifications for the main calibration facility are as follows:

Floor Area: Approximately 684m² (7,360 ft²)

Flow System: Pressurized system that operates at a nominal pressure of 75 psi. Flow iscirculated and controlled using two pumps.

Pumps: Two variable speed 250HP pumps located in a separate pump room.

Maximum flow rate: 3600 m3/hr (nominal 20cSt oil)

Minimum flow rate: 40 m3/hr

Meter Sizes: 100mm (4 inch) to 600mm (24 inch) meters can be calibrated in threedifferent lines. A 7.5 ton crane is used for handling the meters andpiping.

Prover: 10m3, unidirectional, 0.508m (20-inch) ball

Master Meters: Two LEFM 280C 0.254 m (10 inch) -meters installed in parallel

Calibration Fluids: Exxsol D80 and two mineral oils with nominal viscosities of 2 cSt, 15 cStand 150 cSt. During a calibration, viscosity can be varied and controlledbetween approximately 1.5 cSt and 200 cSt.

Storage Tanks: Three, double-walled storage tanks. The tanks are 6.1m (20 ft.) high and3.65 m (12 ft) in diameter with a 45.4 m3 (12,000 gallon) capacity. Twoinside tanks are located in a 1.52 m (5 ft) deep containment pit. The thirdtank is located outside.

TemperatureControl:

Temperature is controlled to better than 0.5 degC over the range of 15.6to 48.9 degC using a chiller system. Oil passes through a tube and shellheat exchanger as it circulates in the lab. The oil temperature iscontrolled by adjusting the rate of coolant fed into the shell side of theheat exchanger from the chiller.

Control: System is operated from a control room, mounted on a mezzanine andwith full view of the entire laboratory. The system can also be operatedfrom the test floor via two touch-screen control panels.

Ball Prover

The ball prover is a 20-inch nominal bore, 10 cubic meter Ball Prover with a flow ratecapacity of 40 to 2200 m3/hr. The ball prover has 4 detectors, 3.3 cubic meters betweenany two consecutive detectors and can be used to fully calibrate all meters between 4inch and 10 inch in size. A calibration run is initiated when the prover ball is launchedby the operator. The ball drops down and is carried by the flow into the piping. Theposition of the ball is monitored by a series of four detectors. A precise volume of 3.3cubic meters corresponds to the movement of the ball between any two consecutivedetectors or for larger meters the full 10 cubic meters is used. A perforated plate in themain piping forces the ball back to its launch point.

Master Meter

Master meter proving uses the two 10-inch LEFM 280C meters. They are used to calibrate10-inch and larger meters particularly at flows greater than 2200 m3/hr. Flow can passthrough one or both master meter lines and then into any of the three calibration lines.The calibration flow is set, and the master meters are calibrated by the prover. Thiscalibration is then used for the calibration of the meter under test (MUT).

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