1. High Liquid Volume Plunger Lift in the Permian Basin
Mike Swihart, Production Lift Systems Inc.
ALRDC Gas Lift Symposium Houston, Texas

2. BACKGROUND Permian Basin Horizontal Wells +/- 10,000’ TVD
(GLR) mcf/bbl
0.31 – 2.68 (WOR) bw/bo
0.7+ psi/ft Initial Reservoir Pressure
1600 psi + BHFP’s
BACKGROUND

3. Artificial Lift Options
High Volume Horizontal Wells
Generally A/L is needed before we are able to rod pump (+/- 300 bfpd)
Historical options for A/L then are:
ESP
Gas Lift
Rod pump
Artificial Lift Options

4. BACKGROUND - ESP PROS: Quick drawdown (acceleration?)
Initial flush production but then return to natural decline
Incremental production is difficult to achieve with incremental drawdown in a high reservoir pressure environment (Vogel)
VSDs & down hole sensors
Speed up or slow down the pump as reservoir dictates
Ability to monitor down hole pump parameters and pressures
BACKGROUND - ESP

5. BACKGROUND - ESP CONS: Short run life
Average lifespan of an ESP is +/- five months
Due to:
Power quality
Fluid solids passing through pump
Gas interference
High cost (+/- $25,000 / month LOE) Due to:
Monthly rental fees
Workover rig time (when ESP fails)
Pump repair costs
Must pull the flowing well to run the ESP
BACKGROUND - ESP

6. BACKGROUND – GAS LIFT Pros Cons
Simple, nothing mechanical in wellbore
Allows for solids to pass through
Wellbore deviation is not generally an issue
Cons
Long flow lines combined with high gas sales line pressure
Compressor reliability & operating expense
Available supply gas
Lines freezing in winter
Commingled leases-Accounting allocation issues
Single well leases coupled with undersized gas gathering systems, limited buy back-lift gas
Operator inexperience
BACKGROUND – GAS LIFT

7. BACKGROUND – ROD PUMP Pros Cons Generally effective-when pumping
Field personnel are generally experienced with this form of lift
Local expertise/support readily available
Cons
Difficulty producing 300+ bfpd
High failure associated with high initial rates and high declines
Difficult to properly size pumping units
Deviated wellbores
BACKGROUND – ROD PUMP

8. CHALLENGE-Reduce Operating Costs
Because of high operating costs associated with ESPs, Gas Lift and Beam Pumps an alternative lift solution was desired
CHALLENGE-Reduce Operating Costs

9. SOLUTION – PLUNGER LIFT
High reservoir pressure
Every time we rigged up on a well for we had to kill the well with several loads of brine. Instead of killing that reservoir energy, why not utilize it?
Advanced plunger systems
Advanced plungers allow for quicker fall times and thus a higher percentage of time that the well is producing
Remote Monitoring Systems provide greater control
Do not have to pull well to install plunger lift
Eliminates potential wellbore/reservoir damage from killing well with heavy brine water
Potential for low operating cost
Plunger lift is a very cheap A/L option
No outside energy requirement
SOLUTION – PLUNGER LIFT

10. Advanced bypass plungers allow gas and fluid to pass thru them during the descent to the bottom of the well thus minimizing drop time or allowing the well to flow during the drop cycle. This is accomplished by either a valve within the plunger or the separation of two pieces at the surface that reconnect at bottom.
BYPASS PLUNGER

11. WHAT DETERMINES SUCCESS
SUCCESS = Maintaining a well near its natural decline while lowering operating costs
RESULTS - Higher Profits
WHAT DETERMINES SUCCESS

12. Production Data Table 1: Plunger Lift Wells Production Data Well # Oil
Water
Liquid
Gas
GOR
WOR
GLR
BOPD
BWPD
BFPD
MCFPD
MCF/BO
BW/BO
MCF/BBL
Well # 1
220
382
602
224
1.02
1.74
0.37
Well # 2
245
239
484
297
1.21
0.98
0.61
Well # 3 99
265
364
279
2.82
2.68
0.77
Well # 4
182
406
299
1.64
1.23
0.74
Well # 5
103
166
269
285
2.77
1.61
1.06
Well # 6
372
114
486
308
0.83
0.31
0.63
Well # 7
272
156
428
210
0.57
0.49
Well # 8
201 89
290
163
0.81
0.44
0.56
Production Data

13. Plunger Lift Well #1

14. Plunger Lift Well #2

15. Plunger Lift Well #3

16. Plunger Lift Well #4

17. Plunger Lift Well #5

18. Plunger Lift Well #6

19. Plunger Lift Well #7

20. Plunger Lift Well #8

21. Inflow Performance Relationship Solution-Gas Drive Reservoirs

22. CONCLUSIONS Plunger Lift resulted in lowering Lease Operating Expense
On average direct plunger related LOE expense = +/- $ 2,150 / well / month
SDB average direct ESP related LOE expense = +/- $25,000 / well / month
Thus plungers result in an direct LOE savings relative to ESPs of ~ $23,000 / well / month
Plungers (with a few exceptions) have bridged the gap between flowing and rod pump
The majority of plunger lifted wells have maintained their “natural decline”
We have successfully run plungers to less than 300 bfpd which allows us to skip the step of running a high cost ESP
Earliest plungers have been running for over 1 year and generally continue to have good performance
CONCLUSIONS

23. CONCLUSIONS – KEYS FOR SUCCESS
Reservoir energy and fluid characteristics
Without reservoir pressure and gas nothing else matters
Advanced styles of plungers
Allows for faster fall times than conventional plungers and thus more production time
SCADA
Real-time monitoring is a necessity with plunger lift to optimize performance
Experienced personnel (Company/Vendor) overseeing plunger operations
Frequent monitoring of plunger lift to optimize performance
Time consuming, but well worth the effort in terms of cost reduction
Over time pressures and fluid ratios decline and plunger settings need to be changed accordingly
After 1,000’s of plunger cycles the elements on the plunger start to wear and result in poor seal efficiency, fluid slippage and loss of production
CONCLUSIONS – KEYS FOR SUCCESS

24. CONCLUSIONS & FUTURE CHALLENGES
Optimize plunger cycle settings and plunger selection
Communication-Field/Engineering/Vendor
Determine optimal plunger install time before wells start to load up with fluids
Determine optimal plunger install time to control paraffin, solids and scale build up inside the tubing
CONCLUSIONS & FUTURE CHALLENGES

25. High Liquid Volume Plunger Lift Field Operations

26. Wireline Work Tubing ID (Internal Diameter) Gauge Ring Tight Spots
Paraffin
Scale
Corrosion
Broaching
Chemical Treatment
Bottom Hole Spring Assembly
Seating Nipple
Tubing Stop
Collar Stop
Combination
Wireline Work

27. Wireline Operations

28. Swabbing Operations Removing Kill Fluids Initial Kick Off- Pressure Up
Sales Line
Production Tanks
Frac Tank
Tank Truck
Swabbing Operations

29. Swabbing Operations

30. Plunger Types Conventional Bypass Scale Buster Aeration Sand Cutter
Brush
Pad
Bypass
Internal Shift Rod
External Shift Rod
Two Piece
Plunger Types

31. Plunger Types

32. Plunger Choice/Sequence
Cleanup- Solid Grooved Variation
Conventional- Pad-Brush
Bypass- Drop Times/Constant Flow
Plunger Choice/Sequence

33. Change Out- 6 months
Wear-Solids/After-Flow
Seal-Pad/Brush
Close/Drop Time-Bypass
Plunger Factors

34. Wellhead Installation

35. Automation Cell Phone/Radio Monitoring Adjustments Run Times
Pressures (T/C/L)
Flow Rates
Production (O/W/G)
Adjustments
Off Time
After-Flow
Pressure
Flow-Rate
Automation

36. Automation Controllers

37. Reports & Graphs

38. Real Time Poll

39. Conventional Plunger Lift

40. High BHP- No Packer

41. High BHP-Packer