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TWO STAGE ARTIFICIAL LIFT SYSTEM (GARP®)

NEW IMPROVEMENTS HYDRAULIC FLUID ASSIST (NO GAS REQUIRED)

SOLIDS SEPARATION & CONTROLPACKERLESS DESIGN

FREE FLOWING PRE-ART LIFT DESIGN

Daryl Mazzanti – Executive VP Operations GARP Services LLC

A subsidiary of Evolution Petroleum Corp(EPM- NYSEMKT)

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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

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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

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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

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OPERATOR OPTIONS AND RESULTS

1. Reluctantly install conventional art lift into these regions or conditions – unsuccessful installations are high from gas interference, mechanical failures, operating costs

2. 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

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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

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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 ~100- 500 psig @ 50-150 MCFD

- Hydraulic pump requires <15 HP surface pump

with 150 – 300 BFPD of power fluid

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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

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Why Rod Pumping a High GLR Well Can Be Ineffective

Condensation raining downfrom casing wall can collect

Tbg anchor can restrict gas and stack above anchor flow in small csg sizes restricting gas and liquid flow placing back pressure on

the reservoir & causing gas Back pressureto back up under the anchor

Also gas anchors in small casing sizes have ainsufficient cross sectionalarea resulting in too high ofa velocity for gas break outi.e., gas will enter intake

Reservoir

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Stinger or On-Off tool

Dual String Connector

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2-3/8" or 1.9" tbg

Injection Gas

Gas Shroud(fiberglass or steel)

Shear Sub

Solids Shield(fiberglass or steel)

PkrVERTICAL VERTICAL

HORIZONTAL HORIZONTAL

Reservoir Top Reservoir Top

Reservoir Bottom Reservoir Bottom

Bi-Flow Tool

2-7/8" or 3-1/2" Tbg

1-1/4" tbg

Bushing

4-1/2"+ CSG

Opt:Standing Valve

Solids Separator& Collection Chamber

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Bushing used in both SBS string and concentric string designs

Bi-flow tool for concentric design

Bi-flow tool for concentric design

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Packerless Design w/ Gas Lift

Inj Gas Tubing Casing

2-7/8" or 2-3/8" Gas

Injection 2-3/8" or 1.9" Commingled Fluids

Un-anchored Pump PCP, ESP, Other

Gas

Dual Tbg

Connector Bushing

SUMP

Optional Gas Lift Valve

Optional Standing Valve

ReservoirFluids

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Packerless Design w/ Jet Pump

Inj Gas Tubing Casing

2-7/8" or 2-3/8" Power Fluid

Injection 2-3/8" or 1.9" Commingled Fluids

Un-anchored Pump PCP, ESP, Other

Gas

Dual Tbg

Connector Bushing

SUMP

Jet Pump Assembly

Reservoir

Fluids

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Packerless Slim Hole w/ Gas Lift

Pump tbg Outer Tubing

GasGas InjInj Gas

Gas

LiquidsLiquids

On-Off

SUMP

CommingledFluids

Mud Anchor

Optional Gas Lift Valve

Casing

Reservoir Fluids

Pump

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Free-Flowing Pre-Art Lift Design

Prod Tubing

Gas Gas

Casing

Bi- Gas Flow Shroud

On-Off Mud Anchor On-Off Tool

Solids

Separation & Collection

Chamber

Downcomer - Pipe or Screen

Solids Separation& Collection Chamber

Solids

Packer

ShieldReservoir Fluids

PACKER

PUMP

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

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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

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APPLICATIONS TO DATE

• Giddings Field –Central Texas

• Horizontal wells with TVD ~ 9000’ – 11,000’

• Drilled in the early 1990’s

• Extremely low BHP’s

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MORGAN KOVAR #1 RATE VS TIME

685 MMCF + 234 MBO = 348 MBOE

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MORGAN KOVAR #1 RATE VS CUM

Post GARP Reserves Est :49 MBO+145 MMCF=73 MBOEIncrease of 21%

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SELECTED LANDS #2 RATE VS TIME

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SELECTED LANDS #2 RATE VS CUM

Increase of 29%

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PHILIPS #1 RATE VS TIME

Current rate is ~4 BOPD + 240 MCFD + 45 BWPD

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PHILIPS #1 RATE VS CUM

Increase of 37%

Increase of 37%

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PHILIP DL #1 DYNO

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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)

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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

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2-3/8" or 1.9" IJ tbg Hot Inj Gas heats/insulates Injection Gas rod pump tubing to eliminate Continuous treat inject or reduce formation of paraffin chemicals with gas

Gas Shroud

Shear Sub

PkrVERTICAL VERTICAL

HORIZONTAL HORIZONTAL

Reservoir Top Reservoir Top

Reservoir Bottom Reservoir Bottom

Bi-Flow Tool

2-7/8" or 3-1/2" Tbg

Opt : Sand Screen

1-1/4" tbg

Bushing

5-1/2" CSG

-No more overwhelmingthe reservoir w/ load wtr

- Standing Valve will seatduring back-side flush

from chemical/paraffin ortrying to free a stuck pump

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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)

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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

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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

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CONTACT INFORMATION

Daryl Mazzanti – Executive VP

Operations

Email : dmazzanti@evolutionpetroleum.comAlt email : daryl@garplift.com

Office : 713-935-0122Cell : 281-796-6132

Website : http://www.garplift.com