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.

SPE and IADC Members Abstract The implementation of a new type of well profile. the designer profile, has resulted in increased recovery and production rates. The geologically complex Gullfaks Field (See fig. 1), located in the Norwegian sector of the North Sea, has seen significant change in the initial field development plan (FOP) as a result of the design technology. A new type of well profile was necessary to increase both total recovery and production rates from Gullfaks platforms A, B and C. Advances in steerable technology and directional drilling performance enabled a three dimensional horizontal I extended reach well profile, now designated as a designer well, to be utilized to penetrate multiple targets. This paper presents the concept. motivation, performance, results and conclusions from four designer wells used in the revised FDP. Introduction The Gullfaks Field, block 34/10 (See fig. 2) in the Norwegian sector, is the first license ever run by a fully Norwegian joint venture corporation. The license group consists of Statoil (operator), Norsk Hydra and Saga Petroleum. The field currently produces more than 85,000 5m /day of oil from three main reservoirs of the Jurassic age. The field produces from three separate Condeep (OBS) platforms; Gullfaks A, B and C. Gullfaks A and C are fully independent processing platforms with three separation stages. The Gullfaks B platform provides processing facilities for single stage separation only and transfers oil to both Gullfaks A and C for further processing. The Gullfaks Field has a very complex reservoir with numerous fault blocks and structures. Reverse faulting, in areas dominated by normal faults, accentuates the complexity of this reservoir. To date, approximately 70% of all GulIfaks wells have encountered small-scale faults not previously detected by seismic imaging, which again adds to the challenge presented by this field. Approximately 100 wells will be necessary to properly develop the Gullfaks Field according to the FDP. Generally, two producing wells are accompanied by one injector well. With the initial FDP approved in 1981 and an updated FDP approved in 1985 it is easy to understand its revision in light of the combination of technological advances and increasing knowledge of the reservoir with each well drilled. MOTIVATION FOR NEW PROFILE The initial FDP was based upon well profiles with minimum displacements of 3 km and maximum inclinations of 60. As the early production levels were below expectations, concern existed regarding future production levels on Gullfaks wells. Optimized multiple targets and optimized borehole placement were felt to be critical to improving the production rates and total recovery on the Gullfaks Field. To optimize both the targets and borehole placement, in this geologically complex field, would require substantial turn in the horizontal plane. The drilling department expressed concern about the ability to drill highly deviated wells with large turn in the horizontal plane. As steerable technology improved and the level of execution of the directional companies providing steerable motors improved as well, both management and the geology department were increasingly confident that this type of well profile could indeed be drilled successfully. P. 255^

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In July 2004 Statoil introduced underbalanced drilling technology to the Gullfaks Field offshore Norway. The main driver for this technology was to overcome existing pressure control problems experienced while drilling conventionally through the cap rock in order to reach the reservoir. The project represents the first application of underbalanced drilling offshore Norway. The focus of the process design was on being environmentally friendly; consequently, no hydrocarbons were released to atmosphere or flared during the operation. This paper addresses the challenges in implementing the UBO technology in Norway. There were issues related to equipment, procedures, standards and personnel. Most of the existing Norwegian requirements and guidelines have been developed for conventional drilling. The UBO surface equipment used by the project had to go through a detailed review and extensive modifications to fulfill the Statoil internal requirements as well as the external Norwegian standards and demands. Special quantitative risk assessment methods and software were developed throughout the project to define risk associated with UBO compared to conventional methods. Procedures, emergency measures and contingencies were established to ensure a safe operational environment for personnel at any time. Interfaces with existing platform production facilities had to be made in order to process produced gas and liquid hydrocarbons thereby ensuring an environmentally friendly operation. Some of the major challenges were related to communication and teams that consisted of personnel with very different backgrounds working towards a common goal, i.e. the production philosophy with automated processes vs. the drilling philosophy with manual processes. High focus was kept on open communication throughout the project. Background The Gullfaks field is located in the northern part of the North Sea. It consists of three concrete gravity based platforms and is now entering its phase of tail production. The main driver for production from the Gullfaks reservoir is seawater injection. The combination of geology and focus on maximum production has created increasing drilling problems in the Shetland formation, which is the cap-rock of the Gullfaks reservoir. The problems have originated from excessive water injection over a limited time period. This has caused pressure increase in certain parts of the reservoir and related fracturing of the cap-rock. The injected water has increased the pressure in the cap-rock in certain areas to an extent where there is no longer a window between fracturing pressure and pore pressure. Some areas of the Gullfaks field are therefore no longer drillable using conventional drilling technology. The hydrocarbon reserves left in the affected areas are substantial, and Statoil therefore introduced underbalanced technology to gain access to these additional reserves. At the same time, Statoil wanted to increase the internal competency and experience for future UBO projects both locally and internationally. The project represents the first application of underbalanced drilling offshore Norway. There were no existing rules and regulations made specifically for underbalanced drilling in Norway; therefore, the first step of the project was to approach the authorities in order to verify that the concept of underbalanced drilling was feasible. The authorities' attitude towards the project was positive, as they recognized the importance of getting UBO technology implemented in Norway, where the focus is high on tail-end production optimization. Next, Statoil's partners in the Gullfaks license had to evaluate and approve the project. Initially, they found the technology to be too expensive, but the project was approved when the need for the technology and economy of the project was proven by a detailed study. Financially, the investment cost of the whole project had to be written off on one single well, as the Gullfaks field is in the tail production phase and future wells may not generate enough income to support the introduction cost of UBO technology.

This paper descnbes strategies and techniques employed to extend the drilling reach in the Gullfaks field, offshore Norway. Field development plans were originally based upon deviated wells drilled to a maximum inclination of 60°and a maximum displacement of 3 kID. Emerging horizontal drilling techniques encouraged a reevaluation of these field development plans. These techniques are now being implemented to increase the inclination and extend the reach to 5 kID in support of the revised plan. The early success achieved has urged further consideration of extended-reach drilling to as much as 10 kID.