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

BACKGROUND Permian Basin Horizontal Wells +/- 10,000’ TVD 0.37-1.06 (GLR) mcf/bbl 0.31 – 2.68 (WOR) bw/bo 0.7+ psi/ft Initial Reservoir Pressure 1600 psi + BHFP’s BACKGROUND

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

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

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

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

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

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

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

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

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

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

Plunger Lift Well #1

Plunger Lift Well #2

Plunger Lift Well #3

Plunger Lift Well #4

Plunger Lift Well #5

Plunger Lift Well #6

Plunger Lift Well #7

Plunger Lift Well #8

Inflow Performance Relationship Solution-Gas Drive Reservoirs

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

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

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

High Liquid Volume Plunger Lift Field Operations

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

Wireline Operations

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

Swabbing Operations

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

Plunger Types

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

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

Wellhead Installation

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

Automation Controllers

Reports & Graphs

Real Time Poll

Conventional Plunger Lift

High BHP- No Packer

High BHP-Packer