1. A Single Completions Solution
Enhance flowback, extend natural flow period to cost effectively transition to artificial lift
5th ALRDC Seminar for New Artificial Lift Technology
August 2, 2017
Presenter:
Rob Hari, VP Product Development

2. Agenda Challenges producing horizontal wells Root cause analysis
Enhance frac flowback
Extend natural flow
Case histories for lift transition

3. Hydrodynamic flow regime - GLR, pressure
Slug Flow Mechanisms
Terrain
well geometry - undulations, toe-up trajectory
Hydrodynamic flow regime - GLR, pressure
Operational
Interruptions – stops, starts
Shut in for 45 minutes for a fluid shot
Production annulus gas rate

4. Production Engineer’s Predicament
Implement the lowest cost lifting system as quickly as possible.
Maximize drawdown (lowest BHP) at the lowest operating and capital cost for the artificial lift required
Always a trade-off, can’t have your cake and eat it too!
Place pump high to reduce workover frequency and solids production, limits production
Place pump low to capture drawdown increases the likelihood of gas interference and pump/rod failures

5. Reduce CAPEX and OPEX: Fewer, less expensive system transitions
Extend Natural Flow
Avoid Intermediate Lift

6. HEAL System™ Components
HEAL Seal
forces flow into SRS
creates large solids sump
Sized Regulating String (SRS)
variable internal diameter
slug flow mitigation
reduces fluid density to lift fluids into build section of well
engineered for low risk retrieval
HEAL Vortex Separator
separates solids
separates gas
minimizes foam generation

7. Multiphase Flow
SRS is sized for longevity and should not require re-sizing or maintenance
Bubble Flow
Slug Flow
Annular Transition
Mist
Source: Purdue University

8. Frac Flowback Goals Maximize hydrocarbon recovery
Maximize load fluid recovery
Reduce damage to fractures
Source: Wilson, Kurt et al. (2016). Geomechanical Modeling of Flowback Scenarios to Establish Best Practices in the Midland Basin Horizontal Program, Presented at URTeC, San Antonio, Texas, URTEC MS.
1-5 psi/hour helps to significantly reduce the peak stress imposed on the proppant pack
A study found that <100 psi/day (4.2 psi/hr) helped to mitigate wellbore damage and increased cumulative production
Source: Tompkins, Darryl et al. (2016). Managed Pressure Flowback in Unconventional Reservoirs: A Permian Basin Case Study, Presented at URTeC, San Antonio, Texas, URTEC MS.

9. Frac Flowback Goals Keep BHFP high to reduce stress on proppant
Control BH fluid velocity to reduce proppant flowback
Maintain stable BHP and reduce cyclic loading on proppant pack
Typical managed flow back involves 2-4 weeks of surface equipment and careful analysis to determine choke change timing and sizes
Often 1 choke change per day; up to 28 choke change events
Source: Tompkins, Darryl et al. (2016). Managed Pressure Flowback in Unconventional Reservoirs: A Permian Basin Case Study, Presented at URTeC, San Antonio, Texas, URTEC MS.

10. Controlling Flowback – Example – 1 of 2
Maximum pressure to maintain stability of proppant pack
Maximum flow rate (velocity for sand transport)
In the example below, rates were above the level of proppant pack stability.
Source: Schlumberger (accessed 26 July 2017).

11. Controlling Flowback – Example – 2 of 2
Stay within the stable operating envelope from day one to maintain maximum proppant conductive ultimately enhancing production and EUR.
In the second part of this example, flow rates were controlled within the stable operating envelope and sand production was minimized.
Source: Schlumberger (accessed 26 July 2017).

12. Managed Pressure Flowback with HEAL System
Choke rocking – rotate the choke to clear debris or change choke size can cause significant pressure waves that are transmitted downhole
With HEAL assisted flowback, fewer choke changes are required
This limits any choke rocking effect due to fewer surface changes, and also any transient pressure changes induced on the horizontal and fractures themselves
Frictional effect of the HEAL System can dampen surface transients during compressible flow
With HEAL System, 2-3/8” tubing to KOP, then 1.5” ID SRS to 80°
Once hydrocarbons flowing, SRS is not excessively frictional as pressure drop is low during HP high-flow and also during LP low-flow
800 psi

13. Extend Natural Flow
Multiphase flow around a horizontal well’s build section is complex.
Thickening of liquid film on downward side of inclined pipe results in a substantial increase in critical liquid lifting rate in the 15° - 45° inclination range, up to 50%!!!
The HEAL System extends the natural flow period by designing a variable ID SRS that controls liquid loading in the 15° - 45° inclination range as the well declines.
Luo, S., Kelkar, M., Pereyra, E., & Sarica, C. (2014, November 1). A New Comprehensive Model for Predicting Liquid Loading in Gas Wells. Society of Petroleum Engineers. doi: / PA
Shekhar, S., & Kelkar, M. (2016, October 17). Prediction of Onset of Liquid Loading in Vertical, Inclined and Near Horizontal Wells. Society of Petroleum Engineers. doi: / MS

14. Slug Flow and Sand Transport
The HEAL Systems flow regulating technology can:
aid in smoothening the downhole slugging flow in the lateral section,
reduce Taylor bubble and liquid slug lengths (pressure cycling) thereby reducing the transportability of solids and ensuring more proppants stay in the fracs themselves, and
efficiently separate the flowing phases after the bend for improved pump efficiency during the well's life
HEAL System Installed
Source: Anand Nagoo et al Multiphase Flow Simulation of Horizontal Well Artificial Lift and Life-of-Well Case Histories: HEAL System Modeled in PipeFractionalFlow. Presented at URTeC, San Antonio, Texas, URTEC MS.

15. HEAL Slickline System: Extend Natural Flow and RP Transition
Flowback and Natural Flow
Rod Pump
Well is no longer capable of natural flow and can be cost effectively transitioned to rod pumping without pulling tubing
Slickline reconfiguration from flowing to pumping
Land insert pump and rods into upper nipple profile or PSN
Casing is open for separated gas
HEAL System protects pump from gas and solids, as well as maximizes production drawdown
Post frac HEAL Slickline System is installed (snubbed in or after well dies flowing up casing)
HEAL Slickline Separator in flow through configuration (HEAL Slickline Separator is bypassed)
All produced fluids and entrained solids are produced to surface
SRS is sized to mitigate slug flow during flowback to control proppant flowback and solids with minimal pressure loss
Extends natural flow period as SRS lifts fluids around bend and delays the onset of liquid loading
INSERT PUMP
HEAL Slickline Separator in flow through configuration
HEAL Slickline Separator
c/w Separator Mandrel
Formation Fluids (Oil, Water, Gas)
Separated Gas
Oil / Water
SRS
SRS
HEAL Seal
HEAL Seal
Separated Solids

16. Case Study: Improve Production Performance Wolfcamp, Permian
23 neighboring wells and 140 readings over seven months
Slug flow mitigation improves downhole separation, HEAL system fillage is higher and more consistent
Additional benefit of lowered BHP
Less stress on rods by avoiding erratic pump fillage
Stable fluid level allows for effective pump jack balancing

17. Case Study: Improve Production Performance Wolfcamp, Permian
Gas lift to Rod Pump transition, lower BHP.
Wolfcamp Formation is challenged by depth, high total fluid rates, high watercuts and severe high GOR gas interference
Installation in 12 Wolfcamp wells resulted in a sustained +33% increase in production
Lower OPEX and total capital with rod pumping
HEAL System Installed

18. HEAL ESP System: Two Risk Based Configurations
7” Casing or >
5.5” Casing
Features
HEAL System is below ESP
ESP is shrouded to allow ESP intake to couple directly with HEAL System
HEAL System separates gas into annulus
Separated gas travels outside the shroud past ESP
Adaptable to ALL ESP vendor equipment
Features
ESP is integral to HEAL Vortex Separator
All formation fluids flow past ESP on inside of shroud
Custom HEAL ESP Intake System (patent pending)
HEAL Separator discharges into annulus above ESP intake
Positive weight bearing sealing clamps
Adaptable to ALL ESP vendor equipment
Accommodates 5-½“, ppf wellbores and larger
Formation Fluids (Oil, Water, Gas)
Separated Gas
Oil / Water
Separated Solids

19. Case Study: Improve production ESP maximized drawdown (Permian, Wolfcamp)
Typical smaller casing configuration results in excessive ESP gas interference and poor run life
> 50% increase in production and reserves opportunity
HEAL System highly suited for such casing configurations for maximizing drawdown and run life

20. Summary
HEAL System can be installed as part of initial completion to complement existing flowback strategies.
Mitigating Slug flow from the horizontal adds value
Solids control
Efficiency as separators and pumps like smooth flow
Drawdown reliably maximized
HEAL Slickline System offers additional value of reduced CAPEX and OPEX:
Inter-wellbore communication or frac-hit risk mitigation
Extension of natural flow period
Simpler and lower cost transition to artificial lift
Simpler and lower cost transitions between artificial lift systems

21. Questions and Discussion
ROB HARI