Industry standard practices for MWD surveying consist in taken the MWD surveys at the connection; this usually will represent 30-m to 40-m interval depending of the drill pipe range used by the operator or drilling contractor. Additionally, in some occasions, the surveying sample is even larger due other drilling operation considerations such as drilling through unstable formations or simply to save rig time by removing the amount of surveys taken in the well trajectory. However, several cases studies had demonstrated that surveying the well path at these intervals is often not enough to capture the real characterization of the well, leading, in some scenarios, to significant errors in the final True Vertical Depth (TVD) placement, less refined reservoir structure interpretation as well as well engineering simulations due the unseen extra tortuosity not applied in the torque and drag analysis. A new technique, using a combination of static MWD or RSS surveys with continuous inclination, provides an engineering approach that allows describing the trajectory at 3-m (10-ft) interval thus reducing the risks aforementioned. This case study aimed to obtain further understanding of wellbore TVD placement and tortuosity characterization by qualifying the accuracy of the 3-m (10-ft) interval High-Resolution Continuous MWD surveys using statistical comparisons against micro-dogleg Continuous North-Seeking gyro listings as well as Dual Inclination analysis between MWD and Rotary Steerable Systems (RSS). TVD error analysis was also taken into account to explore how TVD error modelling can be optimized when considering survey frequency and the use of continuous inclination data in the Ellipses of Uncertainty (EOU) error terms. The results and correlations did not simply ratify the fact that High-Resolution continuous surveys enhance TVD wellbore positioning and well engineering simulations, but more importantly it was possible to demonstrate that the standard deviations between independent surveying instruments at the same sample rate were small and well within the estimate position of uncertainty predicted by the current industry standard error models. Moreover, in order to deliver a more realistic TVD position the findings also outline the need of supplementary case studies with regards TVD error modeling optimization when using continuous data in the description of the well trajectory. Furthermore, this technique represents a step forward in real time decision making process in critical well placement jobs and will also allow drilling operations to be more efficient with reduced operational and HSE risks.

This paper explores various case studies to evaluate how an innovative methodology for sending MWD surveys up hole, based on cessation of surface RPM rather than variations of mud flow rate, helps drilling operations become more cost effective, decreasing wellbore stability & HSE risks, reducing surveying time and optimizing connection procedures. Conventional surveys are taken by recycling the mud pumps. Mud flow is brought to below the MWD turn-on rate in order to switch off the tool and trigger the survey, and then the flow is increased to above the turn-on rate and the survey is sent to surface. Surveys based on RPM cessation use a different technique that allows the MWD tool to take the survey and to transmit it to the surface acquision system when it detects that the rotation has being stopped, allowing the mud flow to remain unchanged and removing the need to recycle the pumps. Various distinct applications were analyzed in terms of MWD surveying time, wellbore stability and stuck pipe risks to evaluate the impact of this new approach in drilling operations. The cases analyzed deal with the following aspects: reduction of stuck pipe events in projects with high risk wellbore stability issues, ECD and pressure management in MPD projects, anti-collision avoidance and overall reduction of rig time for projects taking MWD surveys before connection. It was concluded that more and more phases of a well construction have seen the benefit of this methodology as it has greatly contributed to the efficiency of drilling operations and in some of the cases allowing the fulfillment of the well objectives by the significant reduction of drilling risks, in comparison with the conventional way to take MWD surveys. This is a novel approach to take MWD surveys and send them up-hole; very little has been written in industry literature about how its application enhances the reduction of key drilling challenges such as reduction of stuck pipe events. This will allow operators and contractors to push the envelope even further, in scenarios where extra fluctuations in the mud flow are adding significant financial or HSE risks.

A critical requirement for directional drilling with coiled tubing (CT) is a reliable downhole means to manipulate the orientation of the mud motor bend. Alaskan operations have traditionally used hydraulically actuated ratcheting orienters, thus avoiding the complications of wireline and control lines inside the coiled tubing. With highly refined field techniques and well plans, the fundamental drawbacks to these orienters have been adeptly managed on the North Slope. Despite good success over the years, drilling and orienting have remained mutually exclusive activities. As such, orienting becomes nonproductive time (NPT) when it cannot be combined with necessary hole conditioning and wiper trips. While orienting problems and failures have been increasingly common in deep and high-build-rate applications, perhaps the most significant challenge to the standard hydraulic orienter service for coiled tubing drilling (CTD) is lost circulation. Initial steps in the development of an intelligent wireless orienter for CTD were taken in 1999 with the goal of eliminating off-bottom orientation, a significant source of NPT for Prudhoe Bay operations. Subtle computer-controlled mud pump variations are the basis for a versatile downlink command structure used to drive the downhole actions of the turbine orienter. The benefits of the prototype orienter were confirmed during a promising field trial beginning in late September 2001. As of December 2001, the novel service has been used on eight wells in Prudhoe Bay. This paper describes the turbine orienter development program, testing, a quantification of benefits, reliability figures, lessons learned, and future plans. Introduction Alaska produces primarily oil (92% of the daily hydrocarbon production) with a production decline rate of approximately 10% per year. Operators are focused on attempting to slow this decline through significant re-entry campaigns and the development of smaller satellite fields surrounding Prudhoe Bay. Logically, cost is one of the major concerns, as is the development of new technology that can lead to increased oil recovery. Coiled tubing drilling can offer a number of advantages over conventional jointed pipe rotary operations. Some of the advantages that have been demonstrated in Alaska include 1) highly efficient, modular and mobile CT drilling rigs with smaller footprints; 2) an ability to drill re-entry sidetracks without pulling and replacing production tubing; 3) faster trip times resulting from fewer connections; 4) associated cost savings. Part of the success of CTD in Prudhoe Bay can be attributed to the fact that the field has over 1,200 wells and the most common production tubing size is 4 1/2-in., enabling 3 3/4-in. sidetracks with 3 3/4-in. bottomhole assemblies. The origin of CTD on the North Slope dates back to 1993. A continuous re-entry program has been in place since 1994 and, to date, over 300 wells have been sidetracked using coil. Sixty of these wells were drilled in 2000 and, using three specialized CT drilling rigs, 72 wells were drilled during 2001. The 2002 plan is to drill 45 wells with the two active CT drilling rigs remaining. Over the years CTD has evolved to become the most efficient and economical means to drill re-entry sidetracks and Alaska has truly become the proving ground for new tools and techniques.1,2 CT Drilling Operations Time Breakdown The time distribution illustrated on Fig. 1is based on a study performed on 10 wells drilled in Alaska during 2000 using hydraulic orienters. It shows the average time distribution for the complete operation, from rig up to rig down, without considering downtime or mobilization. The figure reveals that, on average, 8% of the total time is used for orienting and 2% is spent on surveying. Technically the drilling phase is composed of drilling, tripping, orienting, circulating/mud conditioning, directional surveying, and wiper trips. On average, 60% of the total time on a sidetrack project is taken up by the drilling phase.

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