Pacemaker Plunger Operations in Greater Natural Buttes

Transcription

1 Gas Well Deliquification Workshop Sheraton Hotel, February 23-26, 2009 Pacemaker Plunger Operations in Greater Natural Buttes Bennie Allen (Anadarko), Mac Burton (Anadarko) & Justin Lake (IPS)

2 Agenda How-it-works Candidate selection, benefits of pacemaker, and equipment options Optimization of pacemaker Empowering the operator Actual optimization results More results Production Economics Dual-stage Pacemaker Idea Results Economics 2

3 Pacemaker Plunger Operation 1. Sleeve and ball start as one piece at the bottom of the tubing string positioned on top of the bottom hole assembly, the same as conventional plunger. (Fig 1) 3

4 Pacemaker Plunger Operation 2. While the well is flowing, the sleeve and ball travel as one to the surface lifting fluid that has accumulated above the plunger. At surface the plunger enters the lubricator and the fluid is then produced down the flowline along with the gas. 3. In the lubricator the specially designed separator rod knocks the ball from the sleeve and the ball begins traveling back down the tubing to the bottomhole assembly. The sleeve is held in place by the separator rod. (Fig 2 3) 4

5 Pacemaker Plunger Operation 4. The controller then sends a signal to the motor valve to close allowing the sleeve to fall from the separator rod and start back downhole. (Fig 4) 5. The large bypass area of the sleeve allows the plunger to fall at a high rate of velocity against flow reducing cycle times and increasing production. 6. Once the sleeve reaches bottom, the ball seals the bottom of the sleeve and begins back uphole to start a new cycle. 5

6 Candidate Selection > 10 MCF / bbl GLR conventional Tested higher LGR with tungsten ball (heaviest) with success Dual-stage pacemaker allows for much higher LGR > 350 MCFD production ( > 75 psi line pressure) Initially > 500 MCFD 6

7 Benefits of Pacemaker Plunger More cycles per day Ball falls against flow At SI, sleeve falls at ~5000 fpm (57 MPH) Less fluid load per trip Requires less casing pressure to lift Lower FBHP Continually lift fluids off formation Creates less line spikes Near-continuous gas flow 7

8 Pacemaker Equipment Options Multiple metallurgy combinations available Desire lightest combination that will still fall in reasonable time Combinations include Sleeves Balls Steel, Titanium Tungsten, Cobalt, Steel, Zirconium, Titanium, Silica Nitrate 8

9 Ball Fall Rates Developed by Dr. James Lea and IPS 9

10 Initial Usable Ball Fall Rate Optimizer Allowed operator to input flow rate information to calculate depth of ball before shutin Problems Had to know desired depth based on EOT No one single space to input data 10

11 User Friendly Pacemaker Optimizer Developed by production engineer (Mac Burton) Operator changes EOT Pick list for line pressure and ball type Operator inputs minute-by-minute flowrate to easily determine optimum shut-in flow rate Rest of sheet protected to keep it simple 11

12 Actual Well Optimization Casing pressure being pulled down over period 15 days shows optimization Casing Pressure Tubing Pressure Line Pressure Gas Rate 12

13 Optimization Continued Zoomed in to 1 day to show cycles including line pressure, rate, and casing and tubing pressure behavior Casing Pressure Tubing Pressure Line Pressure Gas Rate 13

14 Optimization Continued Zoomed in to 3 hours of minuteby-minute data Afterflow time steadily increased to optimize Casing Pressure Tubing Pressure Line Pressure Gas Rate 14

15 Optimization Results Initial increase of 170 MCFD Optimization added additional 80 MCFD Casing & Tubing diverging Casing & Tubing converging 15

16 Average Pacemaker Results Decline is same or better Gas Rate, MCFD Gas, MCFD Results from 150 wells 110 MCFD Increase 23% Increase Gas Well Normalized Deliquification Time, Workshop days Normalized Time, days 16

17 Pacemaker with Tungsten Ball Pacemaker (Cobalt 7.5 oz) Pacemaker (Tungsten 16 oz) 17

18 APC South Texas Results Gas Rate, MCFD 14 wells with pacemakers 35% increase in production Normalized Time, days 18

19 Pacemaker Economics Initial cost for installation = $3500 (can be reused) Average increase in production in 2008 = 110 MCFD, 10 BWPD Revenue increase (110 MCFD * $5 / MCF) (10 BWPD * $3) = $520 / Day Pays out installation in 7 days. Revenue increase over 1 year of $190M per well. 150 wells w/ Pacemakers = $29MM revenue / year 2008 Total Program Production Increase for Field = 16.5 MMCFD 19

20 Stage-Lift Pacemaker Production Before Averaged 250 MCFD loaded up every other day Produced 90 bwpd (GLR = 2.75) Issues GLR too low to run conventional plunger Candidate for conventional stage-lift but gas production too high Idea Install stage-lift tool with pacemakers on top and bottom stage 20

21 Stage-Lift Tool with Pacemaker Rod Check Valve Rubber Seal Collar Stop Bumper Spring Pacemaker Rod 21

22 Stage-Lift Pacemaker Results Separator problems separator problems Gas Rate, MCFD Gas Rate, MCFD Gas Well Deliquification days Workshop 22 Normalized Time, days

23 Stage-Lift Pacemaker Economics Initial cost for installation = $8500 Increase in production = 200 MCFD, 100 BWPD Revenue increase (200 MCFD * $5 / MCF) (100 BWPD * $3) = $700 / Day Pays out installation in 12 days. Revenue increase over 1 year of $255M. 23

24 Gas Well Deliquification Workshop Sheraton Hotel, February 23-26, 2009 Pacemaker Plunger Operations in Greater Natural Buttes Bennie Allen (Anadarko), Mac Burton (Anadarko) & Justin Lake (IPS)

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