Ann: West Erregulla Update, page-93

Source: sciencedirect.com

5.2.2 Kick Control

A kick is defined as an unexpected and unwanted influx of reservoir fluid, oil, water, or gas, into the wellbore due to an underbalanced condition in which pressure inside the wellbore or bottom-hole pressure (BHP) is less than formation pressure. Gas kicks are riskier than fluid kicks because of their high mobility in the wellbore.

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Gas kicks are much more troublesome. The gas not only invades the wellbore but also begins to migrate upward due to the density difference between drilling fluid in the well and the gas “bubble.” In other words, it can migrate upward even if there is no further influx from the formation. As it moves upward, it retains the same pressure it had when it entered the wellbore.

Good kick control requires that some fluid at the surface be bled off to allow the gas to expand as the hydrostatic pressure on the bubble decreases (i.e., there is not as much drilling fluid above it as it moves up the hole). Without this pressure reduction and expansion, the bubble simply brings reservoir pressure along with it as it moves up the hole.

In some situations, the gas bubble is not allowed to expand as it moves up the hole. It will eventually migrate to the surface with high pressure. This assumes that some downhole feature of the well has not fractured under the pressure of the bubble at the surface plus the hydrostatic pressure from the column of mud below it. Even if the job was planned using a dead well drilling or workover procedure, this situation may require the unplanned use of a snubbing unit to prevent the pipe from being expelled from the well.



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The best way to manage a kick is to return the pipe to the bottom of the well and circulate all the “bubble” to the surface under controlled conditions. If the end of the pipe is above the kick, it must be run back down the hole. Unfortunately, for conventional rigs, surface pressure and expulsion force can create a pipe-light condition that makes it impossible to go back to the bottom.

So, in comes the snubbing unit to handle the problem. It can manage forces in both directions whether the string is pipe-light or pipe-heavy. It can safely return the pipe to the bottom for a circulating kill without risking the loss of well control. Upset end connections and collars can be managed through ram-to-ram stripping. Once the string becomes pipe-heavy, it can be stripped through an annular preventer or stripping head using the rig's hoisting equipment simply by opening the snubbing BOPs and both sets of pipe-light slips. This is one of the primary uses of a rig-assist snubbing unit.

Snubbing units have been required numerous times to push the pipe back to the bottom for kick circulation. On numerous occasions, an unexpected kick has resulted in a high surface pressure, and the string has become exceptionally pipe-light. Crews have been forced to chain the pipe string down to the rig floor to prevent it from blowing out of the well. Some tubing strings have been completely expelled from a well during high well pressure situations.Snubbing pipe back to the bottom is often preferable to bullheading mud down the well to lower the pressure. Even bullheading is better than doing nothing, which could allow the situation to escalate into a major failure including a blowout,