CONTROL FORMATION PRESSURE

As mentioned earlier, a basic drilling fluid function is to control formation pressures to ensure a safe drilling operation. Typically, as formation pressures increase, drilling fluid density is increased with barite to balance pressures and maintain wellbore stability. This keeps formation fluids from flowing into the wellbore and prevents pressured formation fluids from causing a blowout. The pressure exerted by the drilling fluid column while static (not circulating) is called the hydrostatic pres­sure and is a function of the density (mud weight) and True Vertical Depth (TVD) of the well. If the hydrostatic pressure of the drilling fluid column is equal to or greater than the formation pressure, formation fluids will not flow into the wellbore.

Keeping a well “under control” is often characterized as a set of conditions under which no formation fluid will flow into the wellbore. But it also includes conditions where formation

fluids are allowed to flow into the wellbore – under controlled conditions. Such conditions vary from cases where high levels of background gas are tolerated while drilling, to situations where

the well is producing commercial quantities of oil and gas while being drilled. Well control (or pressure control ) means there is no uncontrollable flow of formation fluids into the wellbore.

Hydrostatic pressure also controls stresses adjacent to the wellbore other than those exerted

by formation fluids. In geologically active regions, tectonic forces impose stresses in formations and may make wellbores unstable even when formation fluid pressure is balanced. Wellbores in tectonically stressed formations can be stabilized by balancing these stresses with hydrostatic

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pressure. Similarly, the orientation of the wellbore in high-angle and horizontal intervals can cause decreased wellbore stability, which can also be controlled with hydrostatic pressure.

Normal formation pressures vary from a pressure gradient of 0.433psi/ft (equivalent to

8.33lb/gal freshwater) in inland areas to 0.465psi/ft (equivalent to 8.95lb/gal) in marine basins.

Elevation, location, and various geological processes and histories create conditions where formation pressures depart considerably from these normal values. The density of drilling fluid may range from that of air (essentially 0psi/ft), to in excess of 20.0lb/gal(1.04psi/ft)/.

Often, formations with sub-normal pressures are drilled with air, gas, mist, stiff foam, aerated mud or special ultra-low-density fluids (usually oil-base).

The mud weight used to drill a well is limited by the minimum weight needed to control formation pressures and the maximum mud weight that will not fracture the formation. In practice, the mud weight should be limited to the minimum necessary for well control and wellbore stability.

Date: 2015-01-12; view: 892