Well control procedures are vital for ensuring drilling operations and oil and gas production are carried out safely and efficiently. Well control procedures prevent the influx of hydrocarbons into the wellbore while both drilling the well and completing the well to prepare it for production. Crews on the well site during these phases want to prevent hydrocarbons from entering the wellbore because of the risks of a blowout, an uncontrolled release of oil or gas from the well. Both mud density and casing are used to prevent the influx of fluids into the wellbore. You will learn more about the use of these techniques in the next lessons.
Well control has three general categories: primary well control, secondary well control and tertiary well control. Let’s look at primary well control in this lesson to understand the first steps used when instituting well control procedures.
Primary well control is achieved through the use of drilling mud of sufficient weight (density) to prevent an influx of formation fluids into the wellbore. If primary well control fails, secondary well control is implemented to prevent an uncontrolled loss of fluids from the well. Further failures necessitate the use of tertiary well control.
Downhole flow in typical reservoirs is governed by the basic principle that fluids flow from high pressure to low pressure, so drillers can control downhole flow around the wellbore by controlling downhole pressure. The crew maintains primary well control by making sure that the pressure of the wellbore fluids is higher than that in the formation, preventing formation fluids (such as oil and gas) from entering the well. While we want to have the wellbore pressure high enough to counteract the formation pressure, if we make the pressure inside the wellbore too high, it might fracture the surrounding rock. Let’s summarize by looking at how two undesirable scenarios could occur if wellbore and formation pressures are not properly balanced:
- Wellbore pressure < formation fluid pressure (underbalanced): If the pressure in the wellbore drops below the formation fluid pressure, formation fluids can enter the wellbore, causing what is called a kick – a flow of formation fluids into the wellbore during drilling operations. Drillers can kill a kick by increasing the wellbore pressure to equal or exceed the formation fluid pressure, usually by increasing the density of the drilling mud, which we will discuss below. If the kick is not brought under control, a blowout might ensue, which entails total loss of control of flow into the well.
- Wellbore pressure > formation fracture pressure: If the pressure in the wellbore gets too large, fractures could form within the formation at the wellbore and drilling fluids in the well could be lost to the surrounding rock. Since wellbore pressure is maintained by the hydrostatic pressure of the fluid column filling the well, losing those fluids reduces wellbore pressure, causing more flow into the wellbore which could lead to blowout if not corrected.
Rock layers or formations within the earth are all unique. They are at different depths in the earth; they are composed of different minerals; they have different fluids within the pores of the rock. In order to drill safely, engineers and geologists must estimate the mechanical conditions in these layers, namely the existing formation fluid pressure and the fracturing pressure. These pressures define the limits of what is called the mud weight window. An important condition for safe drilling, where well control is maintained, is to adjust the pressure in the wellbore to fall within the mud weight window. The reason this is called a mud weight window instead of a mud pressure window stems from the hydrostatic pressure mechanism by which the wellbore pressure is controlled. As will be described in the following section, hydrostatic pressure is set by adjusting the density of the wellbore fluid, typically referred to by drillers as the “mud weight”. Let’s look at hydrostatic pressure in more detail on the next page.