A well kill is the operation of placing a column of special fluids of the required density into a well bore in order to prevent the flow of reservoir fluids without the need for pressure control equipment at the surface. It works on the principle that the hydrostatic head of the "kill fluid" or "kill mud" will be enough to suppress the pressure of the formation fluids. Well kills may be planned in the case of advanced interventions such as workovers, or be contingency operations. The situation calling for a well kill will dictate the method taken.
Not all well kills are deliberate. On occasion, the unintended accumulation of fluids, either from injection of chemicals like methanol from the surface, or from liquids produced from the reservoir, can be enough to kill the well, particularly gas wells, which are notoriously easy to kill.
Well control in general is an extremely expensive and dangerous operation. Extensive training, testing, proof of competence, and experience are prerequisites for planning and performing a well kill, even a seemingly simple one. Many people have died through incorrectly performed well kills.
Principles
The principle of a well kill revolves around the influence of the weight of a fluid column and hence the pressure exerted at the wellbore's bottom.
Where P is the pressure at a specific depth, h, within the column, g is the acceleration of gravity and ρ is the density of the fluid. It is common in the oil industry to use weight density, which is the product of mass density and the acceleration of gravity. This reduces the equation to:
Where γ is the weight density. Weight density may also be described as the pressure gradient because it directly determines how much extra pressure will be added by increasing depth of the column of fluid.
The objective of a well kill operation is to make the pressure at the bottom of the kill fluid equal (or slightly higher) compared to the pressure of the reservoir fluids.
Example
The pressure of the reservoir fluids at the bottom of the hole is 38 MPa. We have a kill fluid with a weight density of 16 kN.m−3. What will need to be the height of the hydrostatic head in order to kill the well?
From the equation:
Therefore, a column of 2375 m of this fluid is needed. This refers to the true vertical depth of the column, not the measured depth, which is always larger than true vertical depth due to deviations from vertical.
Math in the oil field
In the oil industry, a pure SI system is extremely rare. Weight densities are commonly either given as specific gravity or in pounds per gallon. Simple conversion factors (0.433 for specific gravity and 0.052 for ppg) convert these values to a pressure gradient in psi per foot. Multiplying by the depth in feet gives the pressure at the bottom of the column.
Of course, when the well is being drilled in metres as the depth unit, the maths gets more complicated. Since well-kill certification is normally (in the US/ UK) done in "oil field units" (feet for length, inches for diameters, oilfield barrels for volume-pumped, psi for pressures), complex workarounds are often performed to keep the planned calculations in line with local regulations and industry "best practice".
Methods of well kill
During all well kills, careful attention must be paid to not exceeding the formation strength at the weakest point of the wellbore (or casing/ liner pipes, as appropriate), the "fracture pressure", otherwise fluid will be lost from the wellbore to the formation. Since this lost volume is unknown, it becomes very hard to tell how the kill is proceeding, especially if gas is involved with its large volume change through different parts of the wellbore. Combining a well kill with such a "lost circulation" situation is a serious problem.
Lost circulation situations can, of course, also lead to well kill situations.
Reverse circulation
This is often the tidiest way of making a planned well kill. It involves pumping kill fluid down the 'A' annulus of the well, through a point of communication between it and the production tubing just above the production packer and up the tubing, displacing the lighter well bore fluids, which are allowed to flow to production.