Guidelines & Recommended Practices
Selection of Artificial Lift Systems
for Deliquifying Gas Wells
Prepared by Artificial Lift R&D Council
2.4o Downhole Separation and Injection
This section has been moved to the “emerging technologies” section.
This section discusses the practical limits of downhole separation and liquid
injection in terms of liquid production rate, gas production rate, depth, pressure, temperature, etc. It presents rough guidelines on the relative costs of
downhole separation and liquid injection. Obviously precise costs can not be
given as they depend on many factors. It presents rough guidelines on the
relative life expectancy of downhole separation and liquid injection. Clearly,
precise expectations can not be given as they depend on many factors.

Practical Limits
-

Cost Guidelines
-

Depth limits
Size limits
Pressure limits
Temperature limits
Rate limits
Limits with sand, corrosion, erosion, H2S, CO2, etc.
Power requirements
Operating requirements
Maintenance requirements
CAPEX
OPEX
R&M
Life Expectancy Guidelines
-
Infant mortality (early time failure)
Normal operating life

Practical Limits for Liquid Injection

Cost Guidelines for Liquid Injection
Selection of Artificial Lift Systems for Deliquifying Gas Wells
Page 2

Life Expectancy Guidelines for Liquid Injection

Information on Automation Logic that is Specific to Downhole Separation and Injection
Injection of Liquids (water) to Allow Gas Wells to Flow
Instead of producing the liquids in a gas well, why not inject them below the gas zone if
possible? This technique is used only when water is the liquid loading the well for obvious reasons.
Injection:
 Need injection zone preferable below the gas pay
 Beam-bypass seating nipple from HF works with Beam Systems
 With bypass nipple, need back pressure valve at time on surface stuffing box to
provide perhaps as much as 300 psi.
 ESP can inject water below gas pay at higher rates
 If injection zone below gas pay, gravity may be enough to inject water
Injection Example:
IPR: Pr=1000 psi, PI=1 bpd/psi
Well:
Depth = 3333 ft, 2 3/8’s tubing, Surface pressure 100,500,10000
Fluids:
100 % water, gravity of 1.0.
Selection of Artificial Lift Systems for Deliquifying Gas Wells
Page 3
Selection of Artificial Lift Systems for Deliquifying Gas Wells
Page 4
Injection of Liquids in a Gas Well, Continued:
The above injection example for liquids, is for a reflection of the reservoir PI = 1.0
bpd/psi, into the into reservoir injection deliverability curve. At 100 psi surface pressure,
the bottom hole pressure is about 1500 psi and the injection rate is about 600 bpd. At a
surface pressure of 500 and 1000 psi, the injection rates calculated are respectively
about950 and 1400 bpd. J
If injection of water is to be achieved in a gas well, some sort of injectivity relationship
needs to be established and the system must achieve the needed injection pressure for the
needed rate as shown above. The injection pressure can be below, but often is above the
fracture gradient for the reservoir. The pressure for injection can be generated by gravity
or pumping action.
There are several methods of injecting the water in a gas well. Among them is use of:
1. A bypass-seating nipple.
Selection of Artificial Lift Systems for Deliquifying Gas Wells
Page 5
This device sits under the pump. The pump raises the fluid level in the tubing and then
the hydrostatic pressure from the fluid level is allowed to pressure the injection zone below the packer and below the producing zone. When the tubing level is high enough, injection begins. If a larger pressure is required, the tubing level is pumped to the surface
and a backpressure regulator is installed on the tubing at the surface to be sure of injection. Contact Harbison Fischer, Benny J. Williams [[email protected]].
Another variation of the bypass-seating nipple is shown below where the pump is bypassed by the tube from above the pump to below the pump, allowing hydrostatic pressure to build on the underlying injection zone. The hydrostatic pressure is from the fluid
level in the tubing that is built by the pump that pumps the level to a height sufficient to
inject fluids.
ESP’s for Injection:
Selection of Artificial Lift Systems for Deliquifying Gas Wells
Page 6
Above figure shows ESP system with downhole sensor. When sensor indicates pressure
building with water accumulating, then unit turns on and injects water below a packer.
Case Histories using the ESP for Injection:
4 Inch casing
375 Series motor adapted for bottom drive
No pressure-sensing element (no casing room)
385 Series seal section
Same internal components as 400 Series
85 Series pump
Same internal components as 400 Series
Well History #1
In this case, the customer was looking for an incremental gas production rate. The unit
was sized for 120 to 180 BFPD. Disposal costs had made previous production uneconomical. An FC 320 pump stage with a 20 HP motor was used. Producing perforation was at
3200 feet and disposal was at 3600 feet. A packer was set at 3600 feet with a sheer sub
through which to produce. Installation was successfully completed June and production
and draw down were as expected. A previous production history had been established on
rods. The customer has realized an increase in production of 200 Mscf/D and no disposal
costs
Selection of Artificial Lift Systems for Deliquifying Gas Wells
Page 7
References: for Injection of Water to allow Gas to Flow:
1. Williams, R., Vahedian, S., and Lea, J. F. “Gas Well Liquids Injection using
Beam Lift Systems”, presented at the Southwestern Petroleum Course, April,
1997, Lubbock, Texas.
2. Grubb, A. D. & Duvall, D. K., “ Disposal Tool Technology Extends Gas Well
Life and Enhances Profits”, SPE 24796, presented at the 67th Annual SPE Conference in Washington, DC, October 4-7, 1992.