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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TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractKick detection in oil and synthetic-based fluids has been a major concern for the industry for decades. Due to solubility issues, kick detection may be delayed and resulting well control operations may be problematic. Use of the Micro-Flux Control (MFC) method potentially offers a better way to address this problem in the same way it has been successfully demonstrated to work using water-based fluids (WBM).To check the performance of the MFC method while using oil-based mud (OBM), a series of full-scale tests were conducted at Louisiana State University PERTT Laboratory using natural gas injected into test wells containing an 11-ppg 70/30 diesel/water OBM. Performance results were compared with results previously obtained with WBM gathered at the same facility.The excellent and consistent character of the test results obtained encouraged the use of the MFC on a well to be drilled in Texas for Chevron. The well plan called for using OBM with mud density up to 17.4 ppg, at an anticipated depth of 13,000-ft. This would be the second well drilled with the MFC method, following one drilled in Brazil for Petrobras using WBM.The paper presents the results obtained during the oneweek long live well testing at LSU as well as details of the first field test of the MFC system on the actual well drilled with OBM in Texas. The results confirmed the ability of the MFC system to detect very small influxes of natural gas into OBM with subsequent control of the influx accomplished in a way very similar to that used with WBM. Several other tests were also performed in both wells to explore possible additional uses of the MFC system. These included dynamic leak-off and formation integrity tests, behavior with multiple kicks inside the wellbore simultaneously, identification of ballooning or "breathing" during connections, and early detection of loss of circulation. All of the results obtained in both test scenarios confirmed the potential value of the MFC system for identifying and dealing with the above listed issues when conducting drilling operations utilizing OBM.

Kick detection in oil and synthetic-based fluids has been a major concern for the industry for decades. Due to solubility issues, kick detection may be delayed and resulting well control operations may be problematic. Use of the Micro-Flux Control (MFC) method potentially offers a better way to address this problem in the same way it has been successfully demonstrated to work using water-based fluids (WBM). To check the performance of the MFC method while using oil-based mud (OBM), a series of full-scale tests were conducted at Louisiana State University PERTT Laboratory using natural gas injected into test wells containing an 11-ppg 70/30 diesel/water OBM. Performance results were compared with results previously obtained with WBM gathered at the same facility. The excellent and consistent character of the test results obtained encouraged the use of the MFC on a well to be drilled in Texas for Chevron. The well plan called for using OBM with mud density up to 17.4 ppg, at an anticipated depth of 13,000-ft. This would be the second well drilled with the MFC method, following one drilled in Brazil for Petrobras using WBM. The paper presents the results obtained during the one -week long live well testing at LSU as well as details of the first field test of the MFC system on the actual well drilled with OBM in Texas. The results confirmed the ability of the MFC system to detect very small influxes of natural gas into OBM with subsequent control of the influx accomplished in a way very similar to that used with WBM. Several other tests were also performed in both wells to explore possible additional uses of the MFC system. These included dynamic leak-off and formation integrity tests, behavior with multiple kicks inside the wellbore simultaneously, identification of ballooning or "breathing" during connections, and early detection of loss of circulation. All of the results obtained in both test scenarios confirmed the potential value of the MFC system for identifying and dealing with the above listed issues when conducting drilling operations utilizing OBM. Introduction Despite several challenges the industry faces when employing OBM, its use is still common. Environmental considerations are probably the biggest issue, but the technical advantanges offered by OBM in difficult drilling conditions often compensate for its choice. Today, OBM is the preferred choice for many wells located in deepwater, for HPHT applications, and for wells with chemical related wellbore instability. These challenging drilling scenarios have previously raised significant concerns related to detection of kicks and subsequent well control operations because of the solubility of natural gases in the hydrocarbon fraction of the fluid. Pit gain and increase in return flow rates are widely used as primary kick indicators. However, the roll and heave movements on floater drilling vessels and the relative inaccuracy of today's measurement methods may often result in high kick volumes in the wellbore. Gas solubility has been blamed for causing problems in early detection of the kick when using OBM. Previous studies done by O'Brien1, Thomas et al2, O'Bryan3 and O'Bryan and Bourgoyne4 have shown that there will be very little or no increase in pit level as the gas dissolves in the OBM over time and the detection of kicks is indeed more of a problem than in WBM. Cockburn5 added that "oil based muds with gas in solution, reduce the time the driller has to react to this potentially dangerous situation." Recognizing the criticality of well kick volume, or kick tolerance, early detection could result in a significant increase in drilling operation safety and efficiency. Orban et al6 stated that "The danger of undetected influxes grows with the increase of average well depth, drilling through deep water and the tendency to drill with lighter mud. The detection of influx is still commonly based on unreliable and/or inaccurate methods." However, using a closed-loop system and accurate flow measurements brings the possibility and potential for early gas kick detection in OBM before the gas has time to go into solution. In addition, coupling early detection with a computer controlled hydraulic choke, the MFC method minimizes the total volume of gas in the wellbore.

After a series of successful tests conducted at a research facility for a vertical well using full scale equipment, the Micro-Flux Control (MFC) equipment was taken to its first field applications to begin exploring the performance of the system under actual drilling conditions. These conditions include the presence of cuttings in the return fluid and effects of pipe movement; neither of which could be tested at the research facility. The accuracy of the MFC had been demonstrated for both WBM and OBM at the research facility, detecting influxes and losses at very low volumes. The first two field wells drilled confirmed the accurate measurement capabilities and showed additional and unique information in terms of flow and pressure. This paper describes the first two wells drilled with the system. The first was a shallow exploratory well for Petrobras in Brazil using WBM (1824 ft drilled and 3018 ft TD). The second well, drilled for Chevron in Texas using OBM was a development well in a challenging area with ROP approaching 300 ft/hr (2587 ft drilled and 13,000 ft TD). The system proved to be capable of being used on a wide variety of rigs; whether conventional, without any automation or sophisticated controls and employing a kelly; or latest generations, with fully automated controls and employing a top drive. The results to be presented include the summary of the planning, the challenges and problems targeted, preparation of the wells, rig up of the equipment, and the results. Among data disclosed is the influence of pipe movement, accuracy of the flow measurements under various conditions, and identification of drilling related problems using the various parameters collected. Several influxes were detected along the well and positively confirmed when gas reached surface. The influx detection data was analogous to the mud logging data. Introduction The Microflux Control (MFC) method is a new managed pressure drilling (MPD) technology that was designed to improve drilling in most conditions, from simple wells all the way to high pressure, narrow margin, offshore and other challenging wells and to significantly increase safety through automated kick detection and control. The system has been described in several publications and only a brief description is herein made 1–5. The system operates using a closed loop drilling process that allows for real-time identification of micro influxes and losses and the control and management of downhole pressures through an automated data acquisition and computerized pressure control system. After the successful tests conducted with water and oil based mud at the Louisiana State University Well Control Facility in 2005 and early 2006, the system was taken to its first wells in the summer and fall of 2006 with Petrobras and Chevron. MPD wells can be divided in basically two categories (suggestions made by the authors):–Standard, where the well is statically overbalanced;–Special, where the well is statically underbalanced for at least a portion of it. The MFC can be used with either options, but the first two wells drilled and herein described used the Standard option. As the well is drilled statically overbalanced, all operational procedures, including safety and well control, remain the same. There is no need to change well design criteria or safety, and the main goal is to provide a way of safely reducing the mud weight towards the pore pressure. Very little training is required, and can be provided at the well site for the rig crew in less than one hour. The Special mode, on the other hand, requires much more elaboration in terms of well design. There is a need to review the operational procedures, including connections, tripping, casing, logging, cementing, and especially safety and well control. Training is extensive and there is a need for expert personnel at the location during drilling. And additional equipment is also another item that needs to be considered, making it more difficult in some cases due to footprint restrictions of some rigs. Not to mention the higher cost associated to it.