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Variables affecting kill procedures

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Although variables that affect kick-killing do not necessitate a change in the basic procedural structure, they may cause unexpected behaviors that can mislead an operator into choosing the wrong procedure. The one-circulation method is used to demonstrate the effect of these variables.

Influx Type

The influx type entering the wellbore plays a key role in casing-pressure behavior. The influx can range from heavy oil to fresh water. The most common is gas or salt water; each has a pronounced casing pressure curve and different downhole effects.

Gas kicks

Gas kicks are generally more dramatic than other influx types. Reasons for this include:

  • The rate at which gas enters the wellbore
  • The high casing pressures resulting partially from the low-density fluid
  • Gas expansion as it approaches the surface
  • Fluid migration up the wellbore
  • Fluid flammability

A typical gas-kick casing-pressure curve is shown in Fig. 1.

Gas expanding from a decrease in confining pressures while the fluid is pumped up the wellbore affects the kick-killing process (Fig. 1). As the gas begins to expand, the previously decreasing casing pressure begins to increase at an accelerating rate. This higher casing pressure may give the false impression that another kick influx is entering the well. Immediately after the gas-to-surface conditions, the casing pressure decreases rapidly, which may give the impression that lost circulation has occurred. Both casing pressure changes are expected behaviors and do not indicate an additional influx or lost circulation. The possibility of lost circulation is smaller at the gas-to-surface conditions than at the initial shut-in conditions, illustrated in Figs. 6 and 7 in Well control (illustrations repeated below in Fig 2 and 3).

When gas expands, the increased gas volume displaces fluid from the well, resulting in a pit gain. Fig. 4 shows the pit gain for the problem illustrated in Fig. 4 in Well control, (illustration repeated below in Fig. 5). This pit gain is in addition to the volume increase from weight materials. Because the pit gains in volume, the flow rate exiting the well increases (Fig. 6).

Gas migration may cause special problems. There have been numerous recent studies of gravity-segregation phenomena in an effort to quantify a migration rate. Field data from one professional well-killing corporation suggests a rate of 7 to 15 ft/min in mud systems. Regardless of the rate, the migration effect must be considered, because of the potential for gas expansion. If the fluid is not allowed to expand properly during the migration period, trapped pressure will be generated at the surface. If unnecessary expansion occurs, additional formation gas will enter the well. Example 2 illustrates the gas-migration phenomenon with an actual field case.

Example 1

While drilling a development well from an offshore platform, a kick was taken. The psidp was 850 psi, and the psic was 1,100 psi. Storm conditions forced the tender (barge) to be towed away from the platform to avoid damage to the tender or platform legs. The removal of the tender caused all support services to the platform to be severed, including the mud and pumps.

The engineer on the platform knew the kick would become a problem from gas migration up the annulus. To rectify the situation, he allowed the migration to build pressure on the drillpipe, up to 900 psi, which he used as a 50-psi safety margin. Thereafter, the migration was allowed to build the psidp up to 950 psi before he bled a small volume of mud from the annulus to reduce the drillpipe pressure down to 900 psi. Because bottomhole pressure was still 50 psi more than formation pressure, no additional influx occurred. This procedure was continued until the gas reached the surface, at which time the pressures ceased to increase and remained at 900 psi. After support services were restored to the rig, the gas was pumped from the well, and kill procedures were initiated.

This example points out the manner in which gas migration can be safely controlled with the drillpipe pressure acting as a bottomhole pressure indicator.

Saltwater kicks

Saltwater-kick problems differ from gas-kick problems. Volume expansion does not occur. Because salt water is more dense than gas, casing pressures are lower than for a comparable volume of gas (Fig. 7). Shut-in pressures for the 50-bbl (7.9-m3) saltwater kick are approximately the same as those seen in Fig. 4 in Well control (illustration repeated in Fig. 5) for a 20-bbl (3.2-m3) gas kick under the same conditions.

Hole stability and pipe sticking are generally more severe with a saltwater kick than a gas kick. The saltwater fluid causes a freshwater mud-filter cake to flocculate and create pipe-sticking tendencies and unstable hole conditions. The severity increases with large kick volumes and extended waiting periods before the fluid is pumped from the hole.

Volume of influx

The fluid volume entering the well is a variable controlling the casing pressure throughout the kill process. Increased influx volumes give rise to higher initial psic, as well as greater pressure differences at the gas-to-surface conditions. Fig. 8 depicts the importance of quick closure over closure with hesitation.

Kill-weight increment variations

The original mud density must be increased in most kick situations to kill the well. The incremental density increase has some effect on casing pressure behavior. In Fig. 9, the gas-to-surface pressure conditions are higher than the original shut-in pressures for 0.5-lbm/gal (60-kg/m3) and 1.0-lbm/gal (120-kg/m3) kicks. The 2.0-lbm/gal (240-kg/m3) and 3.0-lbm/gal (360-kg/m3) mud weight increases do not show this tendency. The 3.0-lbm/gal (360-kg/m3) kick has a lower gas-to-surface pressure than at the initial closure. This is caused by suppressed gas expansion, which minimizes the associated pressures. This is generally observed in kicks requiring greater than a 2.0-lbm/gal (240-kg/m3) incremental increase.

An important mud-weight variation is the difference between the kill-mud weight necessary to balance bottomhole pressure and the mud weight actually circulated. If the circulated mud is less than the kill-mud weight, the casing pressure is higher than if kill mud had been used because it was necessary to maintain a balanced pressure at the hole bottom, illustrated in Fig. 4 and 5 in Well control (illustration repeated in Fig. 5 and Fig. 10). The equivalent mud weights will then be greater, increasing formation fracture possibility.

Circulated mud weights greater than the calculated kill mud weight do not decrease the casing pressure. The situation is synonymous with mud-weight safety factors and is termed "overkill." As the extra-heavy mud is pumped down the drillpipe, the U-tube effect (Fig. 11) causes the casing pressure to increase (Fig. 12). The U-tube principle states that the pressures on each side of the tube must be equal. These higher casing pressures have associated downhole stresses that increase formation fracture potential.

Several attempts have been made to achieve the benefits of "safety factors" while avoiding the ill effects of high casing pressures caused by the U-tube effect. The most common attempt at this effort is to subtract the hydrostatic pressure supplied by the extra mud-weight increment from the final circulating pressure, creating a net-zero effect from the added mud weight.

In a static situation, the casing pressure is reduced by an amount equal to the safety-factor hydrostatic pressure, which results in a zero net effect. From a theoretical standpoint, the approach is based on sound principles; however, field experience has shown that this procedure is not practical because of its complexity. This procedure is not necessary for proper well control, and only experienced well-control engineers should use it.

Hole geometry variations

In practical kick-killing situations, hole- and drillstring-size changes cause the kick fluid geometry to be altered. This is particularly a problem in deep tapered holes in which several pipe and hole sizes are used. The influx may occupy a large vertical space at the hole bottom, creating a high casing pressure. As the fluid is pumped into the larger annular spaces, the vertical height is decreased, thus increasing the mud column height and resulting in lower casing pressures. Figs. 13a through 13c show a typical tapered hole and the associated casing and drillpipe pressure curves.


psic = shut-in casing pressure, psi
psidp = shut-in drillpipe pressure, psi


See also

Well control



Noteworthy papers in OnePetro

External links