Gas Well Deliquification Workshop Sheraton Hotel, February 20 22, 2017 Downhole Gas Separation Performance Lynn Rowlan
Overview Free gas interfering with liquid filling the pump is a major operational problem producing Sucker Rod Lifted wells. Gas interference is when free gas at the pump intake pressure enters the pump filling displacement volume with gas in place of liquid, then significant loss in liquid production and reduced drawdown occurs Downhole Gas Separator Simulation program predicts how a separator will perform in the field so that the proper gas separator and pump can be selected. Operators can analyze a particular separator configuration and view how the gas separator separates the liquid from the gas and also determine separator capacity. 2
Efficiency of the Downhole Gas Separation Process Efficiency of the downhole gas separation process expressed by two different methods: 1) Effective Pump Fillage % - EPF% 2) Gas Separator Efficiency %. Effective Pump Fillage % represents the ratio of effective plunger travel divided by maximum plunger travel expressed as a percent. Gas Separator Efficiency % percentage of free gas at the pump intake pressure condition vented up the casing not entering the pump 3
K Coefficient Determines Free Gas into Pump - Schmidt & Doty May 1989 SPE 15426 Prod Engr 4
Liquid Velocity Should be Less Than ~6 /sec Bubble Rise Velocity from Laboratory Testing Effect of Liquid Velocity 5 inch/sec 243 243 BPD BPD OK FAIL FAIL 6 inch/sec 275 BPD 275 BPD 9 inch/sec 420 420 BPD BPD 5
Separator OK Downward Flow rate 243 BPD 5 inches /Second 6
Separator Fails Due Downward 420 BPD Flow at Velocity of 9 inches /Second 7
Gas Bubbles Must Exit Gas Separator When SV Ball on Seat During SR Pumping Cycle 8
Poor Boy Separator Fails Collar Sized Separator OK Separator Fails 141 BPD Displacement Greater than 96 BPD Separator Capacity Separator OK 141 BPD Displacement Less than 242 BPD Separator Capacity 34.4 Effective Plunger Stroke with 34% Pump Fillage Production of 100 BPD with a Full Pump 9
161 Capacity Poor Boy Separator Fails Net Pump Displacement = 168 BPD @ 6.82 SPM Gas Bubble Rise is 4.6 inch/sec 10 10
161 Capacity Poor Boy Separator OK Net Pump Displacement = 140 BPD @ 6.14 SPM Gas Bubble Escapes Separator @ 4.6 inch/sec 11 11
Longer is NOT better FAILS. Seating Nipple 6 foot 2 7/8 sub 6 foot 2 7/8 Perforated Sub 60 Foot 1 ¼ inch dip tube Tubing Plug 6 foot Perforated sub Baker Latch Assembly Low Capacity Gas Separator 2 7/8 inch Poor- Boy Separator with 60 foot dip tube 324 BPD Pump Capacity EXCEEDS 147 BPD Separator capacity 12
$125K 147 BPD Poor Boy Separator Fails 60 Ft Long Dip tube Does NOT Help 13
Tubing Anchors & Liner Tops Tubing anchor with the gaseous fluid column combine to create a choke mechanism that regulates gas flowing up the casing annulus Gas Separation FAILS due to problem of TAC restricting annular gas flow causing pump filled with gas Tubing Liquid Casing The gaseous liquid column above the TAC is 28 % liquid with 53 MCF/D of gas flowing upward through the gaseous liquid column. Gas flow is restricted from below the TAC. 14
High Capacity 420 BPD Pump in the Rat Hole FAILS TAC restricts annular gas flow Full Partial fillage Stroke 1 Stroke 9 Dynamometer Test After 10 Minute Shut down 15
Gas Separation FAILS if Pump EPF% Less than % Liquid in Annulus Gas Separation FAILS Gas Separation OK Casing Size Limits Gas Separation Maximum Capacity 16
Gas Separators for 4 1/2 inch Casing Separator Type, size, inches Capacity Natural Gas Separator 420 BPD Collar Size Gas Separator 2 3/8 275 Poor Boy Separator 2 3/8 96 17
Gas Separators for 5 1/2 inch Casing Separator Type, size, inches Capacity Natural Gas Separator 580 BPD Collar Size Gas Separator 2 7/8 443 Heavy Wall Gas Separator 2 7/8 372 Packer Type Separator 444 Poor Boy Separator 2 7/8 190 18
Gas Separators for 7 inch Casing Separator Type, size, inches Capacity Natural Gas Separator 1200 BPD Collar Size Gas Separator 4 ½ 1044 Collar Size Gas Separator 4 833 Collar Size Gas Separator 3 ½ 644 Collar Size Gas Separator 2 7/8 443 Heavy Wall Gas Separator 2 7/8 372 Packer Type Separator 1089 Poor Boy Separator 2 7/8 190 19
Gas Separation Efficiency Determined by Gas Produced Up the Tubing and Casing Gas Produced Up the Tubing Is Determined From the Pump Card Calculations Free Gas Produced Up the Tubing/Casing Annulus Is Determined Form the Acoustic Fluid Level Test Performed While Acquiring the Dynamometer Test Data Total Gas Produced Can Be Determined System Gas Separation Efficiency Can Be Determined By Comparing the Gas Produced Up the Casing to the Total Gas Produced. 20
Well s System Gas Separation Efficiency is 51.2% Equal to 9.1/17.8 MscfD 9.1 MscfD 8.7 MscfD 21
Gas Separator Recommendations 1. Use a Natural Gas Separator unless well conditions are unfavorable. 2. When the separator is above the producing zone, the outer barrel of the gas separator should be about 80% of the casing internal diameter in high producing rate wells. 3. The gas separator capacity should exceed the pump capacity. 4. Use the Echometer Gas Separator Simulator Software Program to determine gas separator capacity. 5. Use dynamometer and fluid level analysis to determine pump fillage and separator efficiency. 6. Determining gas separator efficiency from pump fillage when using high slippage pumps can be very misleading since the separator may be separating very little liquid from gas and the actual liquid production rate may be very low. 7. The bottom of the dip tube should extend below the bottom of the gas separator inlet ports approximately 200/SPM inches. 22
Conclusion Both of these gas separation efficiency methods can be misleading and result in the operator not identifying a well having a gas separation problem. Expected performance of downhole gas separators can be calculated based on net pump displacement, size of separator, planned SPM and a gas bubble rise velocity. Using K Gas Separator Performance Factor with PVT properties does Model Field Separator Performance To effectively produce sucker rod lifted wells Gas Separators should be used to within their operational limits. What aout Horizontal Wells? 23
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