news from canada, page-2

Some info for the ones new to gas drilling..........
A kick can be the result of improper mud density control, an unexpected overpressured (shallow) gas pocket, or may be a result of the loss of drilling fluids to a formation called a thief zone. If the well is a development well (and not a wildcat), these thief zones should already be known to the driller and the proper loss control materials would have been used. However, unexpected fluid losses can occur if a formation is fractured somewhere in the open-hole section, causing rapid loss of hydrostatic pressure and possibly allowing flow of formation fluids into the wellbore. (See "Underground Blowout" discussion in next section.) Shallow overpressured gas pockets are generally unpredictable and usually cause the more violent kicks because of rapid gas expansion almost immediately.
The primary means of detecting a kick is a relative change in the circulation rate back up to the surface into the mud pits. The drilling crew or mud engineer keeps track of the level in the mud pits, and a increase in this level would indicate that a higher pressure zone has been encountered at the bit. Conversely, a drop in this level would indicate lost circulation to a formation (which might allow influx of formation fluids from other zones if the hydrostatic head at depth is reduced from less than a full column of mud). The rate of mud returns also can be closely monitored to match the rate that it is being pumped down the drill pipe. If the rate of returns is slower than expected, it means that a certain amount of the mud is being lost to a thief zone, but this is not necessarily yet a kick (and may never become one). In the case of a higher pressure zone, an increase in mud returns would be noticed as the formation influx pushes the drilling mud toward the surface at a higher rate.

The first response to detecting a kick would be to isolate the wellbore from the surface by activating the BOPs and closing in the well. Then the drilling crew would attempt to circulate in a heavier kill fluid to increase the hydrostatic pressure (sometimes with the assistance of a well control company). In the process, the influx fluids will be slowly circulated out in a controlled manner, taking care not to allow any gas to accelerate up the wellbore too quickly by controlling casing pressure with chokes on a predetermined schedule. In a simple kill, once the kill-weight mud has reached the bit the casing pressure is manipulated to keep drill pipe pressure constant (assuming a constant pumping rate); this will ensure holding a constant adequate bottomhole pressure. The casing pressure will gradually increase as the contaminant slug approaches the surface if the influx is gas, which will be expanding as it moves up the annulus and overall pressure at its depth is gradually decreasing. This effect will be minor if the influx fluid is mainly salt water. And with an oil-based drilling fluid it can be masked in the early stages of controlling a kick because gas influx may dissolve into the oil under pressure at depth, only to come out of solution and expand rather rapidly as the influx nears the surface. Once all the contaminant has been circulated out, the casing pressure should have reached zero.
Sometimes, however, companies drill underbalanced for better, faster penetration rates and thus they "drill for kicks" as it is economically sounder to take time to kill a kick than to drill overbalanced (which causes slower penetration rates). Under these circumstances, always with qualified personnel on the rig, calling in a "well control" specialist may not be necessary.