247859214.xls.ms_office Overview This standard calculation spreadsheet is based on the paper "Condensate flow in wet-gas lines can be predicted", R.S. Cunliffe, Oil and Gas Journal, Oct 30, 1978. The first part of this standard calculation spreadsheet uses Eaton's correlation to estimate liquid holdup in wet-gas pipelines for pressures up to 1500 psig, which traverse relatively flat topography. Liquid holdup volumes calculated here for initial and final flowrates, can be used in the second part of the spreadsheet. Alternatively a more accurate method of calculating liquid holdup may be to use a simulation program such as PIPESIM. The second part of the spreadsheet uses the Cunliffe method to predict the volume of held up liquid that will be displaced and the time taken to displace it (and hence liquid flow rate), resulting from a gas flow rate change. This is used to estimate the slug catcher holdup volume required. Data to be input is in blue, calculated values are in black. Eaton's Correlation Eaton's correlation can be used to estimate liquid holdup in wet-gas pipelines for pressures up to 1500 psig, which traverse relatively flat topography. This part of the spreadsheet can be used to estimate liquid holdup in the pipeline for initial steady state gas/liquid flow rates and then again for final steady state gas/liquid flow rates. Maximum and minimum flow rates should be used as these will give the greatest difference in liquid holdup and the most conservative amount of liquid that will be displaced due the flow rate change. The two liquid holdup values obtained from this part of the spreadsheet can be used in the second part of the spreadsheet, or alternatively values obtained from a program such as PIPESIM can be used, which may be more accurate. Slugcatcher sizing based on the Cunliffe method 1. Enter the initial and final steady state gas flow rates that the pipeline and downstream plant will see. Maximum and minimum values should be used to provide a conservative sizing bases for the slug catcher. 2. Enter the calculated condensate holdup for the initial and final steady state gas flow rates. These can be calculated in the Eaton's correlation part of the spreadsheet or from a program such as PIPESIM. 3. Enter the initial and final average condensate flow rates at the initial and final steady state gas flow rates. 4. The initial and final condensate/gas ratios are calculated. 5. Enter the initial and final average water flow rates at the initial and final gas flow rates. These may be zero if water has been included as part of the condensate flowrates. 6.The initial and final total liquid flow rates are calculated. 7. The initial and final liquid residence times are calculated based on the liquid holdup and the total liquid flowrate. 8. The incremental liquid flow rate is calculated based on the difference in liquid holdup and the final residence time. 9. The transition period flowrate is calculated which is the sum of the incremental flow rate and the final liquid flowrate. 10. Enter the maximum liquid outflow rate from the slug catcher to the plant that can be accommodated. 11. The liquid accumulation that the slug catcher should be designed for is calculated. This is the volume accumulated due to the transition period flow rate less the maximum liquid outflow rate, for the transition time (final residence time). It assumes that the maximum liquid flow rate from the slug catcher to the plant will be maintained during the transition period. PROJ No. PHASE/CTR ACTIVITY CALCULATION NUMBER WS-CA-PR-016 PROJECT FILE SUBJECT SHEET 1 OF 1 REVISION DATE BY CHECKED APP'D REVISION DATE BY CHECKED APP'D 0 25-Jul-03 MMc Case: Slug catcher onshore for Subsea Wells at Kipper Holdup calculation based on Eaton's correlation Pipe internal diameter, D 6 in 152 mm Pressure, P 400 psia 2758 kPa a Base press for gas measurements, P B 14.7 psia 101.4 kPa a Gas flowrate 250 actual ft 3 /min 0.118 m 3 /s Superficial gas velocity, V SG 21.2 ft/s Liquid flowrate 10 ft 3 /min 0.005 m 3 /s Superficial liquid velocity, V SL 0.85 ft/s Liquid viscosity, µ 20 cp Liquid density, ρ L 55 lb/ft 3 881 kg/m 3 Liquid surface tension, σ 15 dyne/cm Liquid velocity influence No. N LV 2.28 Gas velocity influence No. N GV 56.91 Pipe diameter influence No. N D 115.72 Liquid viscosity influence No. N L 0.152 Correlation parameter, N E 0.044 Liquid holdup fraction R L 0.13 valid for approx. 0.006 < N E < 0.7 (based on Eaton's correlation) Pipe length 1.207 km Approx. liquid holdup in pipe 2.916 m 3 Slug catcher sizing based on the Cunliffe method Gas Flowrate MMsm 3 /d MMscf/d Predicted Liquid Holdup m 3 bbl Average Condensate Rate m 3 /hr bbl/hr Condensate to Gas Ratio (GOR) Average Water Rate m 3 /hr bbl/hr Total Liquid Rate m 3 /hr bbl/hr Liquid Residence Time hr Incremental Liquid Flowrate m 3 /hr bbl/hr Transition Period Flowrate m 3 /hr bbl/hr Maximum Liquid Outflow Rate m 3 /hr bbl/hr Liquid Accumulation m 3 (for slug catcher sizing) bbl 3088 21.1 132.9 129.2 812.9 400.0 108.1 680.1 110 692.3 491 0 0 bbl/MMscf 63.56 108.06 52.0 25.6 0.0 0.0 63.6 64.0 65.3 4.247 3305.12 7.079 250.0 400.0 680.1 LIQUID HOLDUP CHANGE AND SLUG CATCHER SIZING Initial Final 150.0 (Reference : Condensate flow in Wet-gas Lines Can be Predicted, Cunliffe, Oil and Gas Journal, 30/10/78) 20800 2764.86 17400
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