Within the context of broad industry recognition of two drilling technologies, Underbalanced Drilling predates Managed Pressure Drilling (MPD) by at least a decade. While there are some similarities in some of the equipment and possibly in some of the techniques, the applications are different in their intent. This paper will discuss methodologies comparing Conventional, Underbalanced, and Managed Pressure Drilling Operations with respect to objectives, planning, drilling equipment and operations, and well control. The application of Managed Pressure Drilling was specifically created to give it an identity apart from Conventional Drilling and apart from Underbalanced Drilling. There appears to be some confusion with respect to methodology for Managed Pressure Drilling. What constitutes a Managed Pressure Drilling Operation? What constitutes an Underbalanced Drilling Operation? Are they actually the same? Does it matter?
Figure 1 illustrates the general domains of Conventional Drilling Operations, Managed Pressure Drilling Operations, and Underbalanced Drilling Operations.
Conventional drilling by most accounts had its beginnings at Spindletop, near Beaumont Texas in 1900. Three key technologies contributed to the success of the well and later the drilling industry. They were rotary drive, roller cone bits, and drilling mud. There have been some improvements over the years. Today, the conventional drilling circulation flow path begins in the mud pit, drilling fluid (mud) is pumped downhole through the drill string, through the drill bit, up the annulus, exits the top of the wellbore open to the atmosphere via a bell nipple, then through a flowline to mud-gas separation and solids control equipment, then back to the mud pit. All this is done in an open vessel (wellbore and mud pit) that is open to the atmosphere. Drilling in an open vessel presents a number of difficulties that frustrate every drilling engineer.
Conventional wells are most often drilled overbalanced. We can define overbalanced as the condition where the pressure exerted in the wellbore is greater than the pore pressure in any part of the exposed formations. Annular pressure management is primarily controlled by mud density and mud pump flowrates. In the static condition, bottomhole pressure (PBH) is a function of the hydrostatic column's pressure (PHyd) (Figure 2), where…
PHyd = PBH
In the dynamic condition, when the mud pumps are circulating the hole, PBH is a function of PHyd and annular friction pressure (PAF) (Figure 2), where…
PBH = PHyd + PAF
In an open-vessel environment, drilling operations are often subjected to kick-stuck-kick-stuck scenarios that significantly contribute to Non-Productive Time (NPT), adding expense for many drilling AFEs. Because the vessel is open, increased flow, not pressure, from the wellbore is often an indicator of an imminent well control incident. Often, the inner bushings are pulled to check for flow. In that short span of time, a tiny influx has the potential to grow into a large volume kick. Pressures cannot be adequately monitored until the well is shut-in and becomes a closed vessel.