BAKER HUGHES - Drilling Fluids Reference Manual

PRESSURE PREDICTION AND CONTROL
Flow rate increase – The entrance of any fluid into the wellbore will cause the flow rate to
increase. This occurs shortly after, or concurrently with, the drilling rate increase. Since the
intruding fluid is almost always lighter than the drilling fluid, a continued flow from the
reservoir tends to lighten the fluid column causing further increase in flow. The most common
flow sensor, a paddle in the flow line, allows measurement of flow increases if the flowline is
not full. A full or almost full flowline restricts paddle movement making it difficult to show an
increase in flow.
Pit volume increase – An increase in pit volume occurs as the result of two separate processes.
First, the increased flow rate increases fluid volume in the pits. In addition, if the kick contains
gas, gas expansion causes a further increase in flow rate and pit volume. Pit volume totalizers
used on the rig can be adjusted to read increases accurately, but pit levels should be monitored
visually as a back-up. The surface area of a standard fluid tank on a land rig is approximately 8
ft by 30 ft, or 240 ft 2 . This is close to 3½ barrels of fluid per inch of depth. With a normal set of
three fluid pits, a one inch change would represent a 10.7 barrel volume change.
Circulating pressure decrease – Because of the imbalance between the hydrostatic column in
the drillpipe and annulus after penetrating an abnormal zone, it may take less pump pressure to
circulate the fluid. Flow rate increase and pit volume increase would normally be observed
before a circulating pressure decrease.
Well flows with the pump off – This indicates that reservoir fluid is flowing into the wellbore.
Chlorides increase – Formation fluids may have higher chloride contents than the make-up
water being used in the fluid system. Fluid systems with chlorides above 100,000 mg/L may
not show any change when formation fluids enter the fluid system.
Gas cutting – Changes in trends of trip gas, connection gas, and background gas can be a valid
tool for detecting formation pressure changes. If gas cutting occurs, the source of the gas must
be determined. Drilling should be halted and the hole circulated for a sufficient time to remove
the cuttings from the hole. If the gas originates from cuttings, the value will decrease to a
normal level after the hole is circulated clean. If gas cutting persists, it may indicate an
underbalance. The slip velocity of cuttings can be quite high in low-density, low-viscosity
fluids, and the time required to clean the hole may be considerably greater than calculated
circulating time. It should also be borne in mind that when formations containing gas are
drilled, some gas will always show up at the surface. There is no way to prevent this from
happening, regardless of fluid weight. Normal levels of background gas will vary from one
area to another.
The degree to which gas cutting affects hydrostatic pressure is an often misunderstood factor.
Gas cutting causes only very slight reductions in hydrostatic pressure. Normally, gas cutting of
50% on the surface does not significantly reduce bottom-hole pressures (BHP), since it is less
than the normal increases due to annular pressure loss.
Referring to Figure 12-7, if an 18 lb m /gal drilling fluid is cut to 9.1 lb m /gal at the shaker, and if
the gas is evenly distributed from top to bottom of the hole, the reduction in BHP at 10,000 ft is
only 95 psi, equivalent to reducing the fluid weight by 0.2 lb m /gal.
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 12-18