TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Jotun Field is located approximately 165 kilometers offshore Norway in 127 meters of water. Jotun development drilling was executed from a wellhead platform with a fit for purpose new build drilling rig.

The island development strategy of the giant offshore oilfield requires the use of extended reach drilling (ERD) design wells. Compared to the typical wells drilled from the wellhead towers in the same field, higher inclinations are required in both the surface hole and intermediate hole to facilitate drilling three dimensional wells of more than 35, 000 ft. While the challenges of drilling the intermediate hole at higher angles had been identified early on due to field experience, the challenges leading to stuck pipe events encountered in the surface hole were not anticipated due to limited experience drilling high angle surface holes in the region. Historically total loss of returns has been a common issue in the region when drilling the surface hole. Typically when drilling from the Jack Ups, the wells are drilled with sea water and high viscosity sweeps once total losses has been encountered. Any potential aquifer flows are diverted overboard. In order to divert the aquifer flows on the newly built Artificial Islands, the fluids must be pumped 200 or more meters to the gulf. Mud cap drilling (drilling with seawater down the drill string with heavy mud in the annulus to control well flows) was implemented to solve the issue of losses and flows on the island. The early wells with surface holes drilled at high angle experienced stuck pipe while tripping out of the hole after reaching casing point, leading to significant non-productive time (NPT) and risking project objectives and planned designs. A detailed investigation was performed, including running six arm caliper logs to better understand the mechanism for stuck pipe events. After analyzing and understanding the issue, operational practices and bottom hole assembly designs have been changed to reduce the stuck pipe risk, and specially designed stabilizers have been manufactured and used to mitigate stuck pipe events. Geologically, significant data gathering within the overburden sequence to characterize lithological, stratigraphic, and diagenetic heterogeneities, as well as structural discontinuities, has improved understanding of aspect ratio and vertical scale of features being drilled that may have caused the previous hole morphology effects. No stuck pipe events have been experienced to date in the surface hole due to the same effects after implementation of the new equipment designs and improved drilling practices.

Significant rock strength anisotropy associated with weak bedding laminations in shale can lead to wellbore instability challenges especially when drilling Extended Reach Drilling (ERD) wells that require low angles of attack relative to the formation bedding planes. Past drilling experience with water-based muds in offshore Abu Dhabi showed a high frequency of hole-cleaning and stuck-pipe events for wells deviated above approximately 40° from vertical. This was attributed to shale instability due to the invasion of the drilling fluids into micro-fractures along bedding planes as longer exposure lengths and times increased with the angle of deviation. Recently the decision to further develop a giant field with wells drilled from artificial islands has created the need for large numbers of ERD wells that will cross the shale formations at angles in the range of 40° to 85°. Pilot holes have been successfully drilled across shales at angles up to 80° by using non-aqueous drilling fluid (NADF) with mud weights predicted with an ExxonMobil proprietary model that uses previous experience and limited log data. Nevertheless, it was considered advantageous, if not essential, to better understand the mechanisms for shale instability as a function of both the angle of inclination and azimuth of the section, since it is critical to reliable prediction of the mud weight and chemistry required to avoid well-bore instability. An extensive program of tri-axial compression testing of orientated preserved core plugs was conducted in order to quantify the degree of strength anisotropy associated with both a reservoir cap, Layer A shale and intra-reservoir shales encountered while drilling offshore Abu Dhabi. This work showed that Layer A shale's compressive strength can be reduced by approximately 70 to 75% and the intra-reservoir shares by approximately 45 to 50%, when the shear plane of failure aligns with the weak laminations, compared to loading parallel, or perpendicular to the bedding planes. The inclusion of the measured strength anisotropy functions into a wellbore stability model is shown to accurately predict the observed mud weights associated with induced wellbore breakout. The non-aqueous (NADF) mud weight required for wellbore stability was incorporated in an Integrated Hole Quality and Quantitative Risk Assessment (IHQ/QRA) study to evaluate the drillability of various ERD well designs. Actual field drilling performance with NADF has also been used to validate the model. Increased understanding of this wellbore failure mechanism has the potential to reduce drilling risk and significantly increase current extended reach drilling limits for ZADCO's long term field development plan offshore Abu Dhabi.

The Jotun Field is located approximately 165 kilometers offshore Norway in 127 meters of water. Jotun development drilling was executed from a wellhead platform with a fit for purpose new build drilling rig. All production wells were planned as complex directional, horizontal producers in Paleocene, Heimdal sandstones at a depth of approximately 2050 meters TVD SS. Reservoir target complexity dictated tortuous directional well paths often resulting in azimuth changes in excess of 90 degrees at high angle, horizontal inclinations. Target tolerance ±1m was common place at measured depths out to 6000 meters. Directional control and well tortuousity were critical well design considerations. An agreement was reached between Esso Norge AS and Baker Hughes Inteq to utilise AutoTrak™ steering technology on all 12 1/4 inch intermediate and 8 1/2 inch horizontal hole sections on the Jotun B Platform. Drilling commenced in April 1999. This was the first field to be developed using rotary steering technology. To date, 1 water injection well and 14 horizontal production wells have been drilled on Jotun B. This paper provides a history of drilling performance utilising rotary steerable technology on the Jotun B Platform. The following topics are discussed:Well design considerations and complex 3- dimensional well pathsDrilling performanceAutoTrak™ tool performance and reliabilityRotary steering hole conditioning benefits Introduction Directional drilling is necessary to allow wellbores to be optimally placed to meet reservoir access objectives. The amount of directional drilling required has a significant impact on the drilling rate of penetration (ROP) that can be achieved over a hole section. Conventional directional drilling techniques do not allow the drill string to be rotated while the well path is being oriented. The drill string must slide in the wellbore until the desired direction and/or inclination is achieved. New rotary steerable technologies allow the drill string to be rotated while the wellbore is being directionally drilled. The ability to directionally drill while rotating the drill string greatly improves the effective penetration rate, particularly on longer extended reach wells where friction between the wellbore and drill string makes sliding difficult. Rotary steerable technologies are available from several service suppliers. All of the technologies provide the capability to rotate and directionally drill, thereby increasing effective penetration rate. The decision to utilize a rotary steerable system for the Jotun development was based on achieving a lower cost well through reduced drilling times. Drilling Objectives A total of 15 wells were drilled as a part of the Jotun development. Fourteen horizontal oil producers and one water injector. All fourteen of the oil producers were drilled to access oil reserves in the Heimdal reservoir. All wells were drilled from the Jotun wellhead platform with oil production to a Floating Production Storage and Off-loading facility. The Jotun B platform was positioned to be able to access each of the three Jotun reservoirs within a horizontal distance of 6000 meters. To be able to place each of the horizontal wellbore sections in the reservoirs at the required orientations, complex three dimensional well paths were required. Achieving the specified orientation was critical to minimizing the number of wells needed for reservoir drainage (Fig. 1).

The Hibernia field is located in the Jeanne d'Arc Basin on the Grand Banks of Newfoundland, approximately 315 km east southeast of St. John's (Fig. 1). The Hibernia Gravity Based Structure (GBS) platform has a total of 64 slots available for well construction and currently only a limited number of well slots remain. Since production began in 1997, it has become apparent more than 64 wells will be required to develop the resources adequately. As such, it was recognized a platform slot constraint issue could become a limiting factor for the timing of development of the remaining resources. To optimize the use of the remaining slots, a unique technical solution was developed. The design concept was to drill a well through the upper Ben Nevis - Avalon (BNA) reservoir (G Block) and into the Hibernia reservoir (DD Block). This well (WIDD1/AWIG1) was the first Hibernia dual concentric water injection well. To realize this design concept, the world's first annular safety valve for dual concentric water injection was designed, manufactured, fully tested, and qualified in a fast track manner to enable injection into the annulus for the upper BNA target and through the tubing for the lower Hibernia target. The WIDD1/AWIG1 well was successfully drilled and completed allowing dual concentric injection as envisioned in the original well proposal. To date, one additional dual concentric injector well has been drilled and other dual concentric well concepts are actively being pursued. Introduction The Grand Banks of Newfoundland is one of the harshest environments in the world with extremely cold temperatures, significant wind and wave forces, and seasonal ice and iceberg presence. The area is also known as one of the foggiest areas in the world. This environment increases the challenges faced by offshore industry, especially subsea drilling projects. Glory holes, excavated basins, are used to protect subsea Christmas trees and exposed flowlines from the presence of scouring icebergs. This requirement adds significant cost and complexity to a project. The Hibernia GBS platform has two drilling rigs, M71 East and M72 West, paired with two drilling shafts with a total of 64 slots. The field development since the platform was constructed has clearly indicated that more than 64 wells will be required. Therefore, slot constraint will be an obstacle that will need to be overcome to develop the total resources available. The resources could be developed by augmenting a subsea portion to the current platform project. This, however, would be a costly endeavor. Therefore, the focus was placed on extending the capabilities of the current structure. One of the proposed solutions to the constraint is the dual concentric water injection well design. The WIDD1/AWIG1 well that was drilled and completed in 2005 was the first Hibernia well to apply this design concept. The well was drilled through the "G" Block of the BNA reservoir and then into the "DD" Block of the Hibernia reservoir. The concept was to inject through the annulus into the upper BNA reservoir block and through the tubing into the lower Hibernia reservoir block. To achieve this goal, various challenges had to be addressed. Therefore, the following objectives were developed: Challenge As this was the first dual concentric water injector well at Hibernia, the most significant challenge was to deliver an ASV within a very limited timeframe. ASVs are not new to the oil and gas industry, however, to date they have been mainly used as an annulus barrier for gas lift applications in the North Sea.