Intercomparison of Multiphase Flow Facilities: Comparison of NEL and Humble, USA (Texaco)

Intercomparison of Multiphase Flow Facilities: Comparison of NEL and Humble, USA (Texaco) A Report for National Measurement System Policy Unit DTI, London Report No: 144/99 Date: 10 March 1999

Multiphase Flow Measurement Flow Centre Intercomparison of Multiphase Flow Facilities: Comparison of NEL and Humble, USA (Texaco) A Report for National Measurement System Policy Unit DTI, London S U M M A R Y This report describes an intercomparison exercise between the multiphase flow facilities at NEL and at the Humble Flow Laboratory located near Houston, Texas (owned and operated by Texaco). The comparison tests were performed using the Mixmeter multiphase flowmeter, developed at Imperial College, London and commercialised by Jiskoot Autocontrol Ltd. The report shows the method used to compare the results from the two facilities and highlights the principal areas of agreement and disagreement between the tests at the two locations. Prepared by: Dr A R W Hall..... Approved by: Dr W C Pursley..... Date: 10 March 1999 for Dr F C Kinghorn General Manager Report No: 144/99 Page 1 of 18

C O N T E N T S Page SUMMARY... 1 1 INTRODUCTION... 3 2 TEST FACILITIES 2.1 NEL... 3 2.2 Humble... 5 3 THE MIXMETER 3.1 Meter Description... 6 3.2 Claimed Performance Specification... 7 4 TESTS PERFORMED 4.1 NEL... 7 4.2 Humble... 8 5 COMPARISON OF TEST RESULTS... 10 6 CONCLUSIONS... 11 Report No: 144/99 Page 2 of 18

1 INTRODUCTION This report describes an intercomparison exercise between the multiphase flow facilities at NEL and at the Humble Flow Laboratory located near Houston, Texas (owned and operated by Texaco). The comparison tests were performed using the Mixmeter multiphase flowmeter, developed at Imperial College, London and commercialised by Jiskoot Autocontrol Ltd. The report discusses the test facilities, the multiphase flowmeter, the tests performed and shows the method used to compare the results from the two facilities and highlights the principal areas of agreement and disagreement between the tests at the two locations. 2 TEST FACILITIES 2.1 NEL The UK National Multiphase Flow Facility is located in the James Young building at NEL, which also houses the UK National Standards for oil flow measurement. The facility was built under the DTI Flow Programme for 1990-93. The multiphase facility (Figure 1) is based around a 3-phase separator which contains the working bulk fluids. The oil and water are recirculated around the test facility using two variable speed pumps. For safety reasons, nitrogen is used as the gas phase and can be delivered at up to 0.5 kg/s by evaporation of liquid nitrogen on demand. The delivery pressure of the nitrogen is up to 12 bar at the injection point. After passing through the test section, the nitrogen is exhausted to atmosphere form the separator. The different oils and waters used are stored in tanks under the separator and in tanks kept outside the building. When a fluid change is required the separator is drained and the new fluid pumped into the separator. The facility is manufactured entirely from stainless steel and can thus utilise brine substitutes and dead crudes as the working fluids in addition to de-ionised water and refined oils. The oils currently available are: A mixture of 70% Forties and Beryl crude oil, topped to remove light ends and increase flashpoint to 75ºC and 30% kerosine added to restore original viscosity (API gravity 33º, viscosity 15 cp at 20ºC). Topped Oseberg crude oil (API gravity 30º, viscosity 37 cp at 20ºC). The water phases currently available: A solution of 50 kg/m 3 magnesium sulphate (MgSO 4 ) with a density of 1025 kg/m 3. A solution of 100 kg/m 3 magnesium sulphate (MgSO 4 7H 2 O) with a density of 1050 kg/m 3. The test section can accommodate test sections of up to 60 m horizontal and 12 m vertical in a range of pipe sizes from 2 to 6-inch bore. At the centre of the facility is a large three-phase gravity separator, which contains approximately 35 m 3 of water, 25 m 3 of oil and 7 m 3 of oil-water mixture. This acts as the storage vessel for the liquids currently in use for tests, in addition to separating the fluids for Report No: 144/99 Page 3 of 18

recirculation. Across much of the operating envelope of the facility, the liquids can be recirculated indefinitely, while at high liquid flowrate (especially for oil-continuous flows) the degree of cross-contamination of the oil and water usually means that the flow must be stopped for a period to allow settling of the liquids. The separator is equipped with pumps and piping to allow transfer of settled liquids between the oil, water and mixture compartments and is additionally equipped with heat exchangers which allow the temperature of the oil and water to be maintained within ±1ºC over the range of approximately 10º to 40ºC. The oil and water are separately drawn from the separator and pumped through the oil and water metering circuits respectively. Both metering circuits have a choice of two meters to allow a large turndown ratio. The oil is measured using Fauré-Herman helicoidal bladed turbine meters: 1¼ inch 0.5-5.5 l/s 3 inch 5.0-41 l/s The water is measured using Quadrina flat-bladed turbine meters: 1½ inch 0.5-9.0 l/s 3 inch 5.0-4 l/s An additional bypass stream flows through the monitors to measure the cross-contamination of the liquid phases. The water content in the oil flow is measured using a capacitance principle in an Endress & Hauser Aquasyst monitor and the oil content in the water flow is derived using a density measurement in a Solartron Coriolis densitometer. The useable water cut range is 5% to 100% since there is always a residual water content in the oil phase even after prolonged periods of separation. The nitrogen is metered through a choice of three Quadrina flat-bladed turbine meters according to the flowrate required: ½-inch 1-inch 3-inch 0.38-2.19 l/s 1.53-19.2 l/s 6.3-38.6 l/s The gas flowrate is measured at the gas supply pressure (typically 12 bar). However, by operating the test section at reduced pressures it is possible to cover the full range of gas volume fractions from 0% to nearly 100%, with gas superficial velocities in the 4-inch test section up to 30 m/s. It is important to be aware of the uncertainties which are present in the reference system, taking into account the uncertainties of the calibrated instruments (better than ±0.5% for the reference flowmeters), observed fluctuations in flowrates during tests, and combination of the readings of a number of instruments to give the final reference values. The exact uncertainties of a particular reference condition will depend on the values of the individual gas, oil and water flowrates and the ratio between them. Over the majority of the operating range of the NEL facility, the combined uncertainties are: gas flow < ±1.5% oil flow < ±1.0% water flow < ±1.0% Report No: 144/99 Page 4 of 18

One of the most significant contributing factors to the oil and water flowrate uncertainties is the uncertainty in the cross-contamination monitoring. This will lead to the greatest error in oil flowrate at high water cut and the greatest error in water flowrate at low water cut. The biggest contribution to the gas flowrate uncertainty is the test section pressure, and the resulting error in gas flowrate is greatest at low test section pressure (which usually occurs when testing at high GVF). Fluctuations present in the multiphase flow mixture lead to constantly varying pressure at the meter test position. 2.2 Humble The Texaco Humble Test Facility allows equipment to be tested under simulated oil field conditions using real fluids in a well monitored and controlled state. The facility provides test conditions for evaluating new technologies prior to deploying them in the field and for troubleshooting problems encountered in field operations with industry accepted equipment. The fluids presently used in the flow loop consist of 11 to 31 API gravity crudes, natural gas and brine. The multiphase flow test components of the Humble Facility (Figure 2) include: 1) a three-phase separator, 2) a liquid phase pumping and metering skid, 3) a gas phase compression and metering skid, 4) a test well, 5) two horizontal piping runs of length approximately 500 m, 6) multiple test stations for pumps, meters and other equipment, 7) a high pressure receiving vessel, and 8) loop control and data acquisition systems. The main components used in the multiphase meter tests are described below. The three-phase separator is a conventional horizontal separator with a bucket and weir arrangement and is used both as a storage vessel and as a separator for the oil, water and gas. Each of the three phases leaves the separator independently and is pressure boosted and metered before being combined with the other phases in the piping manifold system and transported to a test station within the facility. The separator provides a retention of 10 minutes at liquid rates of 36 l/s (20000 bpd). Upon leaving the three-phase separator, the oil and water are piped separately to a pump/meter skid where each is pressure boosted using centrifugal pumps, powered using electric motors operating through variable frequency drives. With this arrangement, the separator oil leg and water leg liquid rates may be controlled at flowrates up to 36 l/s. The oil rate is measured using positive displacement meters covering the ranges and claimed uncertainties: 0-12 l/s (±0.5%) 0-7.4 l/s (±0.15%) 0-36 l/s (±0.15%) The water rate is measured using Coriolis meters covering the ranges: 0-0.75 l/s (±0.2%) 0-36 l/s (±0.2%) Report No: 144/99 Page 5 of 18

The oil and water meters are operated at a pressure above the three-phase separator pressure to drive any free gas into solution and consequently minimise metering errors associated with gas break-out. The oil and water streams are mixed together in a single piping run immediately downstream of the skid. Fluid temperature control is provided via a 900 kw gas-fired heater, a 1200 kw electric heater, water cooled heat exchangers and a refrigerated ethylene glycol loop. The fluids are heated by routing a side stream from the separator, through the heater and back to the separator. Cooling is accomplished by piping the test fluids through the shell side of a heat exchanger with cooling water flow through the exchanger s tube side. Gas is taken off the top of the three-phase separator and piped to a compressor. The compressor can deliver 2000 l/s (at standard conditions) with an inlet pressure of 15 bar and an outlet pressure of 31 bar. The primary gas measurement is made using a 4-inch ultrasonic flowmeter (±1%) or using orifice meters in either a ¾-inch or 2-inch metering run (< ±2%). The gas is combined with the liquid at locations selected based on the requirements of each test. Piping manifolds enable several multiphase pumps and meters to be configured for testing. The facility easily accommodates three multiphase meters at any one time. Each test station can be isolated from the flowing loop and manifold piping provides various supply and return ports to afford broad flexibility. Control of the liquid and gas compressor is from a panel in a remote control room. The control room provides visual surveillance of the different test sections. Pump and compressor control can be manual or via a PLC. The PLC monitors the loop s separate liquid-leg flowrates and water cut, and adjusts the flow through the water and oil legs to keep the liquid rate and water cut constant. Water cuts can be confirmed by extracting samples for analysis. 3 THE MIXMETER 3.1 Meter Description The Mixmeter uses a static mixer to ensure a homogeneous mixture of the oil, water and gas phases. The mixer splits the flow into two halves which then are rotated in opposite directions and recombined. The resulting swirling flow mixes well and produces a homogeneous flow mixture approximately one mixer length downstream. The arrangement can be seen in the schematic diagram in Figure 3 (where the flow is from right to left). A dual-energy gamma densitometer is located at the point of homogeneity of the flow mixture, measuring the phase volume fractions of oil, water and gas by attenuation of two energies of gamma radiation from a single 137 Cs source. The flow velocity is obtained by measurement of the pressure drop across the mixer which is related to the total velocity and the liquid fraction (obtained from the densitometer) by: ( ε ) ( ε ) P= A V + B V L where P is the measured pressure drop, ε L is the liquid volume fraction, V the mixture velocity and A and B are calibration constants which may be obtained by factory calibration using water. L 2 Report No: 144/99 Page 6 of 18

3.2 Claimed performance specification 3.2.1 Accuracy Liquid flowrate Gas flowrate Water cut ±5% relative ±10% relative ±5% absolute 3.2.2 Operating range These accuracies are claimed over the ranges: 10% < GVF < 90% and 1 m/s < mixture velocity < 10 m/s Based on recent evaluation trials the operating range will be extended to 1 to 20 m/s. 4 TESTS PERFORMED 4.1 NEL 4.1.2 Test fluids The Mixmeter was thoroughly tested at NEL during 1998 primarily as one of the meters under test in a Joint Industry Project to evaluate performance of multiphase flowmeters (Multiflow II). The installation of the meter is shown in Figure 4. In this project the meter was evaluated using a number of combinations of oil types and water salinities. The fluids used for the intercomparison project were: Oil phase Mixture of 70% stabilised Forties and Beryl crude and 30% kerosine Viscosity at 20ºC = 14.65 cp Density at 20ºC = 856.96 kg/m 3 API gravity = 33º Water phase Nominal 50 g/litre Magnesium Sulphate Heptahydrate Gas phase Nitrogen Density at 20ºC = 1025.88 kg/m 3 Actual concentration = 55.5 g/litre Viscosity = 1.127 x viscosity of water Conductivity at 20ºC = 16.9 ms/cm Report No: 144/99 Page 7 of 18

4.1.2 Operating conditions The tests were performed at an average temperature of 40 C and an average line pressure (downstream of the Mixmeter) of 3.9 barg. Taking into account the difference in molecular weight between nitrogen (28) and Humble field gas (22.61) this test pressure is the equivalent of testing at Humble at 5.1 barg (to give the same gas density). 4.1.3 Test matrix The test matrix covered the full range of liquid flowrate, gas volume fraction and water cut which could be achieved with a 3-inch Mixmeter in the NEL facility. Two factors constrained the range of conditions which could be tested: the pressure drop through the Mixmeter and the mixing of the oil and water phases. The combination of mixing and the long test times required (16 minutes) led to excessive carry-over of water into the oil and therefore reference water cut could not be held constant. Target Test Matrix for Mixmeter Tests at NEL Gas Volume Fraction (%) Liquid flowrate 10 25 40 50 60 70 80 85 90 92.5 95 97.5 (l/s) 4 X X X X X X X 6 X X X X X X 9 X X X X X X X 12 X X X X X 18 X X X X 24 X X Water cuts: 5%, 90% - all flowrates 25% - up to 9 l/s 40%, 60% - up to 12 l/s 75% - up to 18 l/s 4.2 Humble 4.2.1 Test fluids The Mixmeter was tested at Humble in November 1998. The installation of the meter is shown in Figure 5. The fluids used for these tests were: Oil phase Ladybug crude oil API gravity = 32 Density at 20 C 864 kg/m 3 Report No: 144/99 Page 8 of 18

Water phase 1.36 molar Petronius brine Gas phase Density at 20 C = 1052.6 kg/m3 Concentration of NaCl = 79.5 g/litre Viscosity = 1.133 x viscosity of water Conductivity at 20 C = 100.46 ms/cm Humble field gas Component Mol % Nitrogen 0.137 Carbon Dioxide 4.169 Methane 76.752 Ethane 7.604 Propane 5.611 iso-butane 1.521 n-butane 2.060 iso-pentane 0.890 Pentane 0.622 Hexane 0.634 4.2.2 Operating conditions The tests were performed at an average temperature of 48 C and an average line pressure (downstream of the Mixmeter) of 12 barg. 4.2.3 Test matrix The following tests were planned to make best use of the time available within the operating constraints of the test facility and other meters which were installed in series with the Mixmeter: Gas/oil tests Oil flowrate (bbl/day) 1200 2401 7203 12004 Gas flowrate (ft 3 /min) GVF (%) 5 50 33 14 9 19 80 67 40 29 37 89 80 57 44 56 92 86 67 55 112 96 92 80 168 97 95 Report No: 144/99 Page 9 of 18

40% water cut tests Additional oil/water ratio tests Oil flowrate (bbl/day) 1200 2401 4802 Water flowrate (bbl/day) 1800 3600 7203 Gas flowrate (ft 3 /min) GVF (%) 9 44 29 17 37 76 62 44 56 83 71 55 112 91 83 Oil flowrate (bbl/day) 9123 7203 2401 480 Water flowrate (bbl/day) 480 2401 7203 9123 Gas flowrate (ft 3 /min) GVF (%) 9 20 20 20 20 37 50 50 50 50 Oil flowrate (bbl/day) 2401 1921 720 240 Water flowrate (bbl/day) 240 720 1921 2401 Gas flowrate (ft 3 /min) GVF (%) 37 78 78 78 78 5. COMPARISON OF TEST RESULTS It will be immediately apparent from comparison of the tables in 4.1.3 and 4.2.3 that the test conditions at the two facilities were not identical, and in particular that many more test conditions were covered at NEL than in the shorter time available at Humble. It is therefore not possible to compare the results point by point; indeed this would be statistically questionable. What is required is a method to compare and visualise the entire test results in a concise manner. Two such methods have been developed during the multiphase metering evaluation Joint Industry Project (Multiflow 2) currently in progress at NEL. The first is the yield curve devised by Shell, the second is the contour plot, introduced to multiphase meter interpretation by Texaco. 5.1 Yield curves The yield curve shows the cumulative total of test points which lie within a specified accuracy. This is best illustrated by reference for example to Figure 6 which shows yield curves for water cut from the tests at NEL and the tests at Humble. The upper curve shows the water cut obtained at NEL and it will be seen that 68% of the data has an error in water cut within ±5%, 88% of the data within ±10%, 93% within ±15%, etc. This performance is as expected, taking into account that a good proportion of the test data were outside the meter s 10% to 90% operating envelope. The same is true of the tests of the meter at Humble, where the water cut yield curve lies close to that obtained at NEL (within the specified accuracy of the meter). Report No: 144/99 Page 10 of 18

Similar yield curves can be produced for other parameters and these are shown in Figures 7 to 9 for liquid flowrate, gas flowrate and oil and total hydrocarbon flowrates. In the case of liquid flowrate, the curves from NEL and Humble are in reasonable agreement (the difference most likely arises from the lower number of data points from Humble giving not a very smooth curve). Gas flowrate (Figure 8) shows the largest discrepancy, with none of the tests giving agreement at Humble within ±10%. Oil and total hydrocarbon flowrates agree well, and as expected, the total hydrocarbon flowrate is measured slightly more accurately than oil rate. (Total hydrocarbon rate is calculated from the sum of mass flowrates of oil and gas). 5.2 Contour plots Contour plots can be created from data in an (x, y, z) format using the Surfer for Windows program from Golden Software. The plots shown in Figures 10 and 11 are created using (x = reference gas volume fraction), (y = reference water cut) and (z = measurement error). One plot has been created for each of oil flowrate error, water flowrate error, gas flowrate error, liquid flowrate error and water cut error. Figure 10 shows these plots for tests at NEL and Figure 11 for tests at Humble. These plots are best interpreted without focusing on too much detail. This is because of the way the contouring algorithms work. If a large number of data points are used in the plot they may conflict (for example two tests performed at a similar combination of GVF and water cut but different liquid flowrate or pressure) and this leads to small isolated colour spots, as can be seen on the NEL data plots. If a small number of data points are used in the plot, the contouring program may fill in areas of the plot for which there is no underlying data. Therefore these plots should be interpreted with care. Oil flowrate, water flowrate, liquid flowrate and water cut in Figures 10 and 11 are broadly similar, taking into account the above comments. The general trends of measurements of these parameters with GVF and water cut are similar from the two locations. The gas flowrate plots are quite different, however, which is consistent with the yield curves shown in Figure 8. The contour plot shows that the gas flowrate from the meter is consistently about 25% too high in the tests at Humble. 6. CONCLUSIONS This work has allowed the comparison of an identical multiphase flowmeter at two multiphase flow test locations. Test data was collected from both locations over a wide range of conditions (in terms of liquid flowrate, water cut, gas volume fraction). Two methods to present and compare this data have been presented. These methods are designed to compare the bulk data sets without focusing on individual measurements, which are difficult to compare due to the number of different parameter which describe each test condition. The comparison of most parameters shows agreement between the tests at NEL and at Humble which was consistent with the expectations of the meter used for the tests in terms of its claimed measurement accuracy and operating range. This was true for water cut, liquid flowrate and oil flowrate measurement. An improvement between measurement of oil flowrate and measurement of total hydrocarbon flowrate was shown at both test locations. Report No: 144/99 Page 11 of 18

The one area of disagreement between the two sets of tests was in the gas flowrate measurement, which was measured consistently high in the multiphase meter tests at Humble. There was no apparent deficiency in the measurement of gas rate in the Humble test facility nor with the measurements produced by the multiphase flowmeter. A larger version of the Mixmeter was tested at Agip s hydrocarbon production facility at Trecate, Italy without showing such a discrepancy. It appears likely that the discrepancy arises from the method used to compensate for mass transfer between the liquid and gas phases. In a live hydrocarbon facility, like that at Humble, there will be a significant dissolution of gas in the liquid. The actual flowrates of gas and liquid are determined by phase equilibrium calculations (based on PVT data obtained from samples of the oil and gas). If the fluids are not at equilibrium this calculation may result in an incorrect split between gas and liquid. In the tests at the Humble test loop there was a meter upstream of the Mixmeter multiphase flowmeter which operated by partial separation of the multiphase mixture. The gassy liquid and wet gas streams produced in this meter were metered and then recombined before passing through the Mixmeter. If this process caused gas to be evolved from solution in the oil, and there was not sufficient time for equilibrium to be re-established then the Mixmeter would register too high a gas flowrate. These findings are of great significance in the application of multiphase metering to live production facilities, if, as demonstrated here, the phase equilibrium calculations may have a significant influence on the final metered values. Figure 1: Schematic of NEL Multiphase Facility SEPARATOR WATER MIXTURE OIL WATER IN OIL MONITOR NITROGEN SUPPLY DENSITOMETER 1 1 2" TURBINE METERS 3" 1" 1 2 " TURBINE METERS 3" 1 1 2" TURBINE METERS 3" TEST SECTION Report No: 144/99 Page 12 of 18

Figure 2: Schematic of Humble Multiphase Facility Figure 3: Schematic of Mixmeter Multiphase Flowmeter Report No: 144/99 Page 13 of 18

Figure 4: Mixmeter installation at NEL Figure 5: Mixmeter installation at Humble Report No: 144/99 Page 14 of 18

Figure 6: Yield Curve (Water Cut) 9 8 Cumulative number of points (%) 7 6 4 3 2 1 Water cut (Humble) Water cut (NEL) 5.0 1 15.0 2 25.0 3 35.0 4 45.0 Error value (%) Figure 7: Yield Curve (Liquid Flowrate) 9 8 Cumulative number of points (%) 7 6 4 3 2 1 Total liquid flowrate (NEL) Total liquid flowrate (Humble) 5.0 1 15.0 2 25.0 3 35.0 4 45.0 Error value (%) Report No: 144/99 Page 15 of 18

Figure 8: Yield Curve (Gas Flowrate) 9 8 Cumulative number of points (%) 7 6 4 3 2 1 Gas flowrate (NEL) Gas Flowrate (Humble) 5.0 1 15.0 2 25.0 3 35.0 4 45.0 Error value (%) Figure 9: Yield Curve (Oil and Total Hydrocarbon Flowrate) 9 8 Cumulative number of points (%) 7 6 4 3 2 Oil flowrate (NEL) 1 Total HC (NEL) Oil flowrate (Humble) Total HC (Humble) 5.0 1 15.0 2 25.0 3 35.0 4 45.0 Error value (%) Report No: 144/99 Page 16 of 18

Figure 10: Contour plots for tests at NEL Oil flow diff Water flow diff 9 9 8 8 7 7 6 4 6 4 3 3 2 2 1 1 1 2 3 4 6 7 8 9 1 2 3 4 6 7 8 9 Gas flow diff Liquid flow diff 9 9 8 8 7 7 6 4 6 4 3 3 2 2 1 1 1 2 3 4 6 7 8 9 1 2 3 4 6 7 8 9 W/cut diff Data definition 9 8 Water: 50g/l MgSO4 7 Oil: Forties/kerosine 6 4 3 2 1 1 2 3 4 6 7 8 9 25.0 1 5.0-5.0-1 -25.0 - - Report No: 144/99 Page 17 of 18

Figure 11: Contour plots for tests at Humble Oil flow diff Water flow diff 9 9 8 8 7 7 6 4 6 4 3 3 2 2 1 1 1 2 3 4 6 7 8 9 1 2 3 4 6 7 8 9 Gas flow diff Liquid flow diff 9 9 8 8 7 7 6 4 6 4 3 3 2 2 1 1 1 2 3 4 6 7 8 9 1 2 3 4 6 7 8 9 W/cut diff Data definition 9 8 Water: 80g/l NaCl 7 Oil: Ladybug 6 4 Gas: Methane 3 2 1 1 2 3 4 6 7 8 9 25.0 1 5.0-5.0-1 -25.0 - - Report No: 144/99 Page 18 of 18