1. A typical lift scenario with tubing landed in the curve
Well is drilled, then Frac-ed with multiple Stages
200 ft = 90 psia
90 psi + 10 ft = 95 psia
When put on production,
Fractures and horizontal section fill with fluids such that hydrodynamic equilibrium is achieved.
Hydrostatic pressure and saturation profile restrict production and cause severe slugging.

2. An Alternative Lift Method
Tubing is pulled ….
A FLATpak ™ multi-conduit is run in the well with intake ports at the liquid accumulation points
Liquid is removed to the surface by alternately charging and bleeding down the FLATpak ™
Gas flows continuously from the liquid-free horizontal section up the casing
10 ft = 5 psia
5 psi + 1 ft = 6 psia

3. But my well isn’t loaded up!
I’d see it on
the production curves
if it was…

4. Yearly average Gas Rates (Light Blue Curve) = SMOOTH DECLINE White crosses are tubing pressure at psig
3/29/2012

5. Yearly average Gas Rates (Light Blue Curve) = SMOOTH DECLINE
Monthly allocated Gas Rates (Red Dots) = SMOOTH DECLINE with some recent random noise
3/29/2012

6. Yearly average Gas Rates (Light Blue Curve) = SMOOTH DECLINE
Monthly allocated Gas Rates (Red Dots) = SMOOTH DECLINE with some recent random noise
Daily measured Gas Rates (3 years of Yellow crosses) = complex Sawtooth pattern
3/29/2012

7. Daily measured Gas Rates (3 years of Yellow crosses)
Complex loading and unloading pattern, repeating pattern every few weeks
3/29/2012

8. So what!
A little liquid over
the producing zone
never hurt a well!

9. This well takes a year to clean-up after liquids are driven back into the formation during a Shut-in

10. This well loads, then unloads…depending on the day.
But it is clear what the long term trend is…

11. Lost production, lost revenue, higher operating costs,…

12. and lost reserves…
From CSUG/SPE