Hydrostatic pressure and saturation profile restrict production and cause severe slugging.

A typical lift scenario with tubing landed in the curve Well is drilled, then Frac-ed with multiple Stages 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. 200 ft = 90 psia 90 psi + 10 ft = 95 psia

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 5 psi + 1 ft = 6 psia 10 ft = 5 psia

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

Yearly average Gas Rates (Light Blue Curve) = SMOOTH DECLINEWhite crosses are tubing pressure at 10-30 psig

Yearly average Gas Rates (Light Blue Curve) = SMOOTH DECLINE Monthly allocated Gas Rates (Red Dots) = SMOOTH DECLINE with some recent random noise

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

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

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

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

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

Lost production, lost revenue, higher operating costs,…

and lost reserves… From CSUG/SPE 149477

Hydrostatic pressure and saturation profile restrict production and cause severe slugging.