1. TwO Stage Artificial Lift System (GARP®) New Improvements Hydraulic Fluid Assist (no Gas Required) Solids Separation & Control Packerless Design Free Flowing Pre-Art Lift Design
Daryl Mazzanti – Executive VP Operations
GARP Services LLC
A subsidiary of Evolution Petroleum Corp
(EPM- NYSEMKT)

2. Outline What is the problem w/ conv art lift ?
What are operator’s options?
The GARP® solution to the problem
Original Design (Big Bore) Side by Side Tbg
Slim Hole Design (Concentric Tbg)
Improvements
Criteria? When to install?
Results to date
Pros / Cons
Future

3. The Stages of LifT Intermediate – High Fluid Levels & High Rates
Greater need for a higher capacity gas separation system
Higher Rates = Higher Liquid Velocities = More Gas Being
Drawn Into Pumps = Lower Pump Efficiencies
Mid Life – Lower Reservoir Pressure = Lower Fluid Levels & Rates…..SRPs begins to dominate
Lower Reservoir Pressure = Lower Pressure Differential = Less
Production. Lowering the lift point = higher pressure
differential = higher production rate
Stripper - Fluid Levels Drop To The Pump….SRPs dominate Lowering the artificial lift point = more reserves. Any reserves that exist below the lift point are un-recoverable

4. Conventional Lift is inadequate:
Deviated Sections – High maintenance, poor gas separation (undersized gas separators & tubing anchors restricting flow, and gas slugging)
High Gas to Liquid Ratios – gas interference in pumps….worse for small csg sizes
Deep Reservoirs – impractical, limited selection & very expensive to install and operate
Long Perforated Intervals – poor separation, risk of sticking anchors/pump in the perf’d interval
Solids Production – wreaks havoc on pumps
Paraffin and Chemical Treatments - Inefficient

5. Operator Options and results
Reluctantly install conventional art lift into these regions or conditions – unsuccessful installations are high from gas interference, mechanical failures, operating costs
Opt to not install art lift or place lift equip in the vertical section many hundreds to thousands of feet above the reservoir
All the above options are inadequate and lead to lower production rates and reserves resulting in lower NPV in early life and pre-mature well abandonment in later life

6. Conventional LIFT Limitations
Gas Lift – Exerts high back pressure w/ depth
SRP/ESP- Gas & solids interference, depth limits, failures in deviated sections
PC pumps- Depth and high gravity limits, failures in deviated sections
Jet Pumps- Circulating high volumes of power fluid at the surface, depth & GLR limits, inefficient, high op costs, lots of tweaking w/ changing conditions
Piston Pumps- Inefficient, gas/solids issues
Plunger-soap strings – Very limited operating conditions, do not significantly lower BHP

7. What is GAS Assisted Rod Pump?
2 Patents + 4 Patents Pending
Two main designs –
- Slim Hole (4-1/2”+) conc tbgs w/ a single WH
- Big Bore (7” +) side by side tbgs w/ dual WH
1st stage - Gas lift or Jet pump– won’t gas
lock, solids friendly
2nd stage – Whatever pump will fit in wellbore
(only SRPs have been installed to date)
Gas lift requires ~ MCFD
Hydraulic pump requires <15 HP surface pump
with 150 – 300 BFPD of power fluid

8. The GARP® Solution
1st stage raises liquids below the pump to above the pump (not the surface)…High lift efficiencies & low back pressure on reservoir
Primary Pump remains in the vertical section above the problems regions to keep operating costs low and pump efficiencies high
Utilizes csg annulus for gas separation (no conventional tubing anchor w/ gas separator), resulting in a more efficient design
Creates a sump for the pump to ensure a supply of nearly gas free liquids for the pump resulting in higher pump fill-age and rates
Utilizes a solids collection system to trap solids before they settle on top of the packer or interfere with the primary pump
Power fluid may be used instead of gas lift if there is no gas supply
Gas lift raises liquids from deep reservoirs w/ low back pressure
Inj flow insulates and provides heat to eliminate or remove paraffin
Chemicals may be injected with the injection gas or power fluid for a more efficient and less costly placement method

12. Stinger or On-Off tool
Dual String Connector

15. Bi-flow tool for concentric design
Bushing used in both SBS string and concentric string designs

21. When To INSTALL ? Life of Well Installation
Early life – Higher NPV through acceleration and lower costs by reducing gas interference in pump
Mid Life – Higher NPV through acceleration by lowering the flowing BHP and lower op costs
Late Life – Higher NPV by lowering the artificial lift point so the pump can recover reserves that exist below the pump. Extends life of leases

22. Predictive Methods PI/IPR Curve – If available
Analyze dyno cards % liquid fill-age on each stroke. If gas interference is noted and the pump is periodically shut-in, calculate the GARP higher pump fill-age and increased run time
Decline Curve Method – used for older wells. GARP will raise the production back on trend - before liquid loading below the pump occurred
To date the technology has proven a 10+ fold increase in rates and up to a 36% increase in reserves over the prior cumulative production

23. Applications To Date Giddings Field –Central Texas
Horizontal wells with TVD ~ 9000’ – 11,000’
Drilled in the early 1990’s
Extremely low BHP’s

24. Morgan Kovar #1 Rate vs Time
685 MMCF MBO = 348 MBOE

25. Morgan Kovar #1 Rate vs Cum
Post GARP Reserves Est :
49 MBO+145 MMCF
=73 MBOE
Increase of 21%

26. SELECTED LANDS #2 RATE VS TIME

27. Selected Lands #2 Rate VS Cum
Increase of 29%

28. Philips #1 Rate vs Time
Current rate is
~4 BOPD MCFD + 45 BWPD

29. Philips #1 Rate vs Cum
Increase of 37%
Increase of 37%

30. Philip DL #1 DYNO

34. ADVANTAGES Manpower friendly technologies – not a lot of tweaking
Lowers BHP w/o placing pump in undesirable places
Life of well installation- For early, mid, and late life
No need to over design the pump jack to place pump deeper for initial higher volumes. A smaller unit can be placed shallower & gas lift can raise liquids to pump
Very efficient continuous chem treating w/ inj gas
Reduces or eliminates paraffin
Opt SV prevents load water from entering reservoir
Loading the backside with wtr can free stuck pumps
Works for both oil wells and liquid loaded gas wells (even for oil wells without a gas supply)

35. Advantages Cont…
Can utilizes existing wellbore tubulars (depending on design)
Can accommodate wellbores with 4-1/2” or larger casings
Has applications for horizontal, deviated, and vertical wells
The tail string works a syphon string that concentrates the reservoir gas energy and may temporarily allow the well to lift to the primary pump w/o additional gas or hydraulic energy
Provides a method for solids separation and trapping to keep solids off the packer and out of the artificial lift equipment
Optional packerless design utilizes a down hole sump that traps liquids to provide a supply of liquids for the 2nd stage lift
Excellent method for cyclical steam floods. No need to pull pump in order to inject steam

37. Disadvantages No obstructions to desired artificial lift point
Does not overcome inherent limitations of the 2nd stage lift pump - production rate limitations, fines plugging, maintenance, workover costs, etc
Costs more than a conventional SRP installation depending on depth, desired BBLS/D (incr costs – 2 days rig time, tbg string (s), additional 1st stage lift equipment, dual wellhead, surface equipment, pkr. May be as low as ~$75K ~75% of $$ re-useable equip
Low pressured reservoirs require injection gas or power fluid (small compressor or pump)

38. Well Criteria
All wells that have pumps set high above the reservoir ( for whatever reason)
Wells that are currently on other forms of artificial lift and not meeting production expectations
Wells that currently have high op costs from placement of the pump in undesirable locations
4-1/2” casing size or larger
4” + liners…No obstructions in the well

39. Future Applications for GARP
Early Life Rate Acceleration
Deep Reservoirs
Vertical wells with long perforated intervals
Future Designs Incorporate down-hole pumps that do not use rods - for wells w/ near surface deviations (Crooked or Pad wells)
Cyclical Steam Floods – Steam is used as the injection fluid

40. Daryl Mazzanti – Executive VP Operations
Contact Information
Daryl Mazzanti – Executive VP Operations
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