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Gas Separation • Solids • Low Liquid Lift Efficiency • Reservoir Sensitivity

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Why GARP is better

GARP® increases production by:

Increasing the liquid pump efficiency per stroke by decreasing the amount of gas that enters the pump – this is accomplished by utilizing the relatively large cross-sectional area of the casing annulus to separate the gas from the liquids instead of the relatively small cross-sectional area of a conventional gas anchor. This large area substantially reduces the fluid velocities which prevents the gas bubbles from being drawn down into the pump intake.
GARP® Lite increases the lift efficiency of liquids from below to above the pump by forcing the gas and liquids into a smaller inner diameter tubing string (called a velocity string). The gas more efficiently lifts the liquids up the smaller ID tubing than it would a larger ID tubing. A packer placed in the vertical section (NOT THE LATERAL SECTION) prevents the lifted liquid from falling back down-hole to give time for the pump to lift the liquids to the surface. As little as 25 MCF/D is all that is needed to lift these liquids up to the pump

GARP® lowers pulling costs by:

Allowing the wellbore to be loaded with liquids and removing the differential pressure that is sticking the pump on seat. Also, the well can now be circulated down the back-side and up through the pump and production tubing to flush solids out of the pump to increase pump efficiency and to free stuck pump plungers. Down-hole screens can be back-washed as well.

What is the problem with conventional artificial lift?

Conventional gas separators do not have sufficient cross-sectional areas and thus have very poor efficiencies at higher rates. Small casing sizes, high fluid levels, and foamy oils tend to exacerbate this problem
Liquid loading below conventional down-hole pumps is a problem in wells with horizontal or deviated sections, deep reservoirs, long perforated intervals or small liner, dog legs, or obstructions. Operators generally prefer to install down-hole pumps in a well’s vertical section, above any perforations or deviations, to prevent high maintenance costs and inefficiencies resulting from frictional wear on tubulars, solids sticking the down-hole pumps, and gas interference in the pump. In many instances, the pump is placed many hundreds to thousands of feet above the reservoir. Since down-hole pumps cannot recover liquids that exist below them, liquids build up above the reservoir and causes significant back pressure, reducing or even ceasing the production, resulting in a lower eventual ultimate recovery (EUR) and premature abandonment of the well
Other forms of artificial lift fair no better. The back pressure from gas lift operations will eventually over power the reservoir pressure in depletion drive reservoirs. Plunger lift and soap strings only operate in a narrow range of well conditions and do not effectively lower the bottom hole pressure. ESP’s can have very high failure rates and become uneconomical at lower production rates. Jet pumps are difficult to operate, have environmental concerns with power fluid, and are very inefficient with low BHP reservoirs and high GLR’s. Hydraulic piston pumps also have environmental issues with power fluid and are inefficient at high GLRs
Conventional lift designs require expensive pulling jobs to free stuck pumps/plungers and to clean solids out of pumps and screens

How GARP® reduces operating costs

GARP® reduces operating costs by:

Placing the rods and pump in the “pump friendly” vertical section (versus lowering the pump into the curve or lateral) to reduce maintenance and repair costs
Utilizing a standing valve below the pump which allows the wellbore to be loaded with fluid which reduces the differential pressure that may be sticking the pump on seat
Utilizing the same standing valve to allow the wellbore to be circulated (even for low bottom hole pressure wells) to flush the pump from solids which increase the pump efficiency and may free a stuck plunger
Inclusion of an optional solids separation and containment system that lessens the risk of solids interfering with the pump or packer
Inclusion of an optional on-off tool and safety shear sub that greatly lessens the risk of a fishing job or having to pull the entire assembly out of the well in case of a stuck pump

Operations

We design, provide the necessary parts, and will deliver the necessary parts and assemblies with a well diagram showing placement in the well string. We will also provide consultation to ensure it is installed properly and is functioning properly after installation. The operator maintains operation of the well which is no different than the normal operations.

Advantages of GARP®

ALL DESIGNS

Enhances gas separation
Accelerates &/or increases production & reserves by lowering flowing bottom hole pressures
Extends the life of marginal wells and thus the associated lease(s)
Superior gas separation design allows high GLR wells to be pumped
Very user friendly.. utilizes off the shelf conventional lift equipment that is well understood, proven, and has readily available replacement parts
Does not place down-hole moving parts in a section of the wellbore that would generate maintenance, inefficiency, or failure problems and increasing LOE/BOE
Provides a solids containment system option that protects the packer from becoming stuck
Optional sand screen installation to protect the pump from solids – screen can be un-plugged by back-washing in situ
Incorporates a one-way check valve on bottom to allow loading the casing with water to free stuck pumps and to circulate the well to remove trash from the pump
Incorporates a drain sub above the check valve to prevent pulling a wet string

GARP Bi-Flow Sump Separator

Low cost separator that can be used with a tubing anchor or packer
Creates a “True Sump for the Pump” for increased gas separation
Design available for high fluid level wells and foamy oils

GARP LITE SUMP Advantages

Aids in lifting liquids from below to above the pump without gas injection
Optional equipment can provide solids control, freeing stuck pumps, and circulating solids out of the pump barrel
In-situ back-washable sand screens may be installed to prevent solids entry into the pump

GARP with gas lift – Advantages

Gas lift raises liquids just above the pump (not the surface), therefore, it does not add significant back pressure on the reservoir
Provides a more efficient chemical placement technique by allowing chemical injection with the gas injection stream
Since the production tubing is surrounded by hot injection gas in the annulus between the concentric tubing strings, paraffin treatments may be eliminated or extended depending on the cloud point temperature of the paraffin.

Well Candidate Criteria

Any rod pumped well that has issues with gas separation, solids, reservoir sensitivity or has the pump installed high to the reservoir

Life of well application
– At initial rod up for rate acceleration due to GARP’s more efficient gas separation
– Mid-Life to raise liquids to help maximize pump fill-age on each stroke
– Stripper Stage to raise liquids to the pump to recover additional reserves
wells that have issues with stuck pumps, plungers, solids in the pump
casing sizes or liner sizes of 4-1/2” or larger
wells with dog-legs that prevent a deeper pump setting due to rod wear
wells with restrictions or high set liners that prevent a deeper pump setting
horizontal, deviated or vertical wells
long perforated intervals
reservoirs that are too deep for conventional lift
high gas to liquid ratio wells in which conventional lift equipment is ineffective

Expected Costs

The cost to install the equipment depends on numerous factors such as depth, casing size, and existing production equipment and facilities. The down-hole equipment costs for the Bi-Flow Sump Gas Separator Assembly can be as low as $6000 and a GARP® Lite installation can be as low as $15K. Call your GARP Services representative for a quote.

GARP Designs®

There are four main designs that increase rod pump production:

GARP® Bi-Flow Sump Separator

Least expensive option
Installed in an operator’s production tubing in conjunction with the existing tubing anchor
Provides gas separation as follows:
- 4-1/2” casing up to 450 BLPD
- 5-1/2” casing up to 800 BLPD
- 7” casing up to 1500 BLPD
Optional Equipment – Solids Shield, On-Off Tool, Safety Shear Sub

GARP® Lite

Same gas separation benefits as above
Uses a velocity string to lift liquids from below the pump to above the pump. No gas injection is necessary.
Allows the sump height to be any desired length for retention time to break gas out of foamy oils

Optional Equipment – Standing Valve, Mechanical Drain Sub, Solids Shield, On-Off Tool, Safety Shear Sub and an optional solids screen that may be back-washed in situ with the solids circulated to the surface

Full GARP® with gas lift assist

Utilizes a concentric tubing arrangement to provides a pathway for the lift gas and for production in casing sizes as small as 5-1/2”

Two Step GARP® Lite to Full GARP®

If it is uncertain whether to install GARP® Lite or Full GARP®, the operator can start out with the less expensive GARP® Lite design and then add Full GARP® (with injection) in the future without having to pull the entire assembly from the well

Optional Equipment – Standing Valve, Mechanical Drain Sub, Solids Shield, On-Off Tool, Safety Shear Sub and an optional solids screen that may be back-washed in situ with the solids circulated to the surface

New Seating Nipple By-Pass Technology

This new technology allows fluids to be pumped down the production tubing with a rod pump installed in a seating nipple. This is accomplished by placing a pressure actuated valve in a mandrel above the seating nipple. Applications include a more efficient paraffin and chemical treating system, and a method to circulate down-hole solids to the surface. We are currently looking for test wells to prove up the technology for no charge. Contact us if you are interested.

New Plunger Lift Technology

This new technology reduces the volume of the casing annular liquids by ~ 2/3 which results in a faster contact of annular gas with the plunger, faster plunger travel times, no stalls, more trips per day and thus higher production per day. It can also allow plunger lift installations on wells that were thought not to be plunger lift candidates. The larger outer diameter tubing is achieved by securing a material to the outside of standard tubulars that is corrosion resistant and can withstand 1000 deg F. We are currently looking for test wells to prove up the technology for no charge for the larger OD material. Contact us if you are interested.

How does GARP work?

GARP contains two main methods which significantly increases the capacity of down-hole gas separation and also raise liquids from below the pump to above the pump.

GARP LITE – utilizes a velocity string to lift liquids above the pump using the natural energy from the reservoir
FULL GARP – utilizes injection fluids to aid in lifting the liquids above the pump

Both methods increase the gas separation capacity dramatically over conventional down-hole gas separators by utilizing packer type separation system instead of a conventional tubing anchor/gas anchor system.

Both methods combine a sucker rod pump (or other applicable pump) with a concentric tubing arrangement to allow the pump to be placed in a “pump friendly environment” to keep operating costs low.

Expected Production/Reserves Increases

GARP will increase production from the wellbore, but only up to the limit of the down-hole pump. Therefore, the ability to separate out gas from the liquids often is over the capacity of the pump to lift the liquids from the well. Call a GARP Services representative for an analysis of your well. Every well is different. Send us your PI/IPR curve or historic production data (oil, water, gas) for each well and we will analyze the data to determine if GARP can help. We have seen rate increases up to 20 fold and reserve increases over 35% of the cumulative oil and gas produced to date.

Rate vs. Time with Liquid Loading

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