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 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.

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Successful drilling, especially in very deep wells, may be driven by hydraulic limiting parameters. Two new technologies, UnderBalanced Drilling (UBD) and Managed Pressure Drilling (MPD) have emerged as solutions to specific hydraulic issues during drilling. A hydraulic parameter can be defined as any factor, mechanical, structural or fluid that impacts the exertion of hydrostatic head on the open hole. Hydraulic parameters, as a group, must be planned for and managed during all drilling operations to prevent unwanted or unsafe conditions. Many hydraulic parameters are documented thoroughly and therefore well-known in the upstream oil and gas industry. They include; Pump Rate; Drillstring and Hole Geometry; Mud Rheology (including surge effect, swab effect, standpipe pressure and hole cleaning); Surface Backpressure; and Rate of Penetration (ROP). These factors are commonplace and routinely addressed as part of a complete drilling program. Other hydraulic limiting parameters are lesser known and sometimes not addressed in the basis of design for unconventional drilling prospects. It is paramount that drillers consider all hydraulic parameters that influence UBD or MPD operations or the project can end in failure or with unsuccessful consequences. This paper discusses in general some of the lesser-known hydraulic issues that might be encountered when drilling vertical wells using UBD or MPD techniques, especially to deeper horizons. MPD / UBD Overview Hydraulic limits occur in both conventional wells and unconventional wells. The more critical wells experience limits that are unmanageable with conventional techniques; thus the emergence of UBD and MPD. MPD is defined by the International Association of Drilling Contractors (IADC) as "an adaptive drilling process used to more precisely control the annular pressure profile throughout the wellbore." Simply put, drillers are concerned with the entire pressure profile in the open hole - including the annulus pressure at the casing shoe as well as bottomhole pressure (BHP). MPD does not encourage formation influx. UBD operations involve drilling into any formation where the pressure exerted by the drilling fluid is less than the formation pressure. The technique reduces the hydrostatic pressure of the drilling fluid column so that the net pressure in the wellbore is less than the formation pressure. Consequently, the formation pressure may cause permeable zones to flow, if conditions allow flow at the surface. UBD can facilitate drilling of pressure-depleted formations and lessen formation damage for better productivity. UBD operations include formation influx in the operating plan except in the case of a hole being drilled for ROP applications in impermeable rock.

The introduction of horizontal drilling in conjunction with the "advent" (novel approach) of Flow Drilling has created a revitalized need for a Rotating Blowout Preventor "RBOP". In the 60's the original idea of an "RBOP" progressed all the way to a prototype model and then died due to other challenges facing the industry. Revitalized interest in providing a means to contain at least 1500 psi at the surface while drilling has instituted the need to produce an improved rotating blowout preventor. Both laboratory and field tests confirm. the successful preventor. Both laboratory and field tests confirm. the successful manufacture of an RBOP that can assist in well control and possibly help prevent a catastrophic failure. Introduction The industry's need for a rotating blowout preventer had. floundered in the drilling recession era from 1983 to 1989. In order for horizontal drilling applications to expand to deeper areas a better means for surface diversion of fluids needed to be developed. The use of existing equipment technology only provided for rotating heads that held up to 500 psi while rotating the drill string. Field experience in Pearsall with standard rotating heads used for surface fluid diversion was Pearsall with standard rotating heads used for surface fluid diversion was stretching pressure limits to the maximum as surface pressures of 500 to 1000 psi were encountered. To be able to expand the technique of flow drilling into higher GOR areas, the weak link at the surface needed to hold at least 1000 to 1500 psi to help in well control. The initial target area was the Pearsall Austin Chalk. Several papers have been presented about the Austin Chalk background so this paper papers have been presented about the Austin Chalk background so this paper will not address this formation other than it is a carbonate reservoir with approximately 300-400 GOR, located at a depth of 5,000' to 7,000'. The GOR appears not to change with depth in the Pearsall Field. GOR was an important parameter in understanding pressure requirements in other areas to be developed using these technologies. P. 757