Since 1994 Coiled Tubing Drilling (CTD) has completed over 650 sidetracks on the North Slope of Alaska. In many aspects the window milling and drilling phase can be considered a mature technology. However, recent developments in the completion phase namely with the generation II side exhaust liner running tool (Gen II SELRT) have further increased job reliability, safety, and efficiency for the liner cementing completion phase. This paper will begin with a brief update on the status of CTD on the North Slope (3 rigs drilling on a daily basis) and discuss how many of the challenges with drilling through/below the production tubing have been dealt with. The cost for a CTD sidetrack with an equivalent amount of reservoir exposure and zonal isolation is about one half that of a rotary sidetrack on the North Slope. This is due to efficiencies in leaving the production tubing in place (dominant savings) and less consumables. In addition, CTD’s enhanced capability for underbalanced drilling (UBD) and managed pressure drilling (MPD) make it attractive for some North Slope fields. While the electronically controlled drilling bottomhole assembly (BHA) has improved drilling performance, the electric line (EL) inside the CT has challenged the completion phase. CT wiper darts for separating cement from displacement fluid can no longer be used. The CT wiper dart would be damaged by the EL and visa versa. Instead, the new liner running tool discussed in this paper exhausts the contaminated cement/mud interface to the annulus at top of liner before launching the liner wiper plug (LWP). Over 76 liners have been cemented with the side exhaust technique. The last 34 jobs have been done with the Gen II SELRT that uses mechanical dogs to close the path through the LWP, side exhaust, and launch the LWP when desired. This new tool increases job efficiency over the first generation tool and continues to provide reliable liner cementing with EL in the coil.

A new system for running and cementing liners using Electric line coiled tubing has been proven on the North Slope of Alaska. The SELRT, the Side Exhaust Liner Running Tool, gives the functionality to run and release a liner while utilizing a liner wiper plug system to ensure good cement quality. A jointed pipe liner is conveyed and cemented with the coiled tubing containing an electric umbilical.This innovative equipment has proven to be a substantial HSE benefit and savings in rig time when compared to a more conventional liner running system. Older systems used in Alaska required switching to an electric line free coiled tubing reel prior to running and cementing liner. Jointed pipe liners up to 3,700' long have been successfully run and cemented with electric line coil using the SELRT system, saving an average of 19 hours of rig time per well. This paper will describe the system development including pumping test slurries of cement through electric line coiled tubing, confirming that dropping balls is possible through electric line coiled tubing and the development and use of the new liner running equipment. Several successful liner running and cementing jobs will be reviewed. This is now the standard liner running equipment used for wells drilled with coiled tubing in the Prudhoe Bay field. IntroductionThere has been a continuous coiled tubing drilling campaign on the North Slope of Alaska since 1994. This program reenters existing vertical wells and drills horizontal sidetracks in the Prudhoe Bay, Kuparuk, Endicott and Milne Point fields. These sidetracks are typically drilled thru 4-1/2" production tubing without pulling the tubing or removing the existing production tree. (See Figure #1). Over 575 new sidetrack wells have been drilled in these fields since 1994. Prior to 2001 conventional 2-3/8" OD coiled tubing (electric line umbilical free) was in use. When a well reached TD the typical completion was a solid/cemented liner followed by coiled tubing conveyed perforating guns. The liner running tool used a ball drop system to release the liner and a coil dart/liner wiper plug system to ensure that uncontaminated cement was accurately placed behind the liner. This system proved quite reliable and robust and accounted for the majority of wells drilled up to 2001. In 2001 a new MWD BHA was tested. This BHA required an electrical umbilical inside the coiled tubing to operate. There were significant advantages to this drilling system. It provided higher data telemetry rates, more real time downhole information and better directional control using an electrical downhole orienter instead of a mechanical orienter. This system proved to be especially beneficial in managed pressure and under balanced drilling applications. The electric orienter minimized shale damage by eliminating the pump cycles needed to operate a mechanical orienter. This new equipment provided enough time savings to enable a 30% increase in effective ROP.Unfortunately, some of the productivity gains realized from using the e-line coil BHA wer...

CTD (Coil Tubing Drilling) has become a mature and successful technology in the continued development of the northern Alaska oilfields. Driven by advancing existing product limits and embracing new technologies, this paper details the development of a new completion technology that allows the operator to plan for and place pre-determined casing exit points within the wellbore to be accessed in the future as the well matures. This new technology addresses many of the typical limiting factors faced by operators when identifying future CTD candidates by reducing the typical preparation time, costs, and equipment limitations currently available to them. The paper will show the viability and flexibility the operator gains by incorporating the use of pre-determined and spaced outer wedge assemblies affixed to the outside of the production tubing joints and run during the completion phase. The operator has the flexibility to run as many outer wedge assemblies as needed, based on their future field development strategy without imposing limitations on primary completion access or drainage capabilities. When required, an inner wedge assembly is then run and positioned within the outer wedge assembly, using a common wireline set tubing plug as a false bottom no-go. Orientation of the inner wedge is at the operators' discretion. The milling assembly will first mill through the production tubing before being deflected by the outer wedge assembly to then mill through the production casing. Details of the design, testing, and implementation of the system and components will be detailed within the paper. This technology allows operators to plan for the life of the well at the completion phase. This reduces CTD preparation costs, provides simplified zonal isolation flexibility, and allows upper zones to be exited first if required. The technology reduces the risks and cost of dual string exits, while removing the need to leave an exposed large bore casing/liner at the exit point that could create difficulties during CTD drilling. Future advances and optimization of completion designs are expected to provide a cementless CTD liner completion while retaining zonal isolation capabilities within the wellbore.

This is a case study for a well intervention job that was conducted in the Prudhoe Bay Unit field, Alaska. It describes the successful use of an electric line milling system to remove a protective frac sleeve that was stuck in a subsurface safety valve (SSSV) landing nipple.Past attempts to remove the sleeve with conventional methods were unsuccessful. Those attempts included slickline, coiled tubing (CT), and pulling 110,000 lbf with a workover rig using a through-tubing work string. At the time, the sleeve did not interfere with production, so it was left in the well.However, an unrelated tubing leak developed below the stuck frac sleeve. The well had to be shut in until the frac sleeve could be pulled to allow installation of a tubing patch.Milling the frac sleeve with coiled tubing or replacing the entire tubing string with a workover rig was considered. However, cost and time could be reduced if the frac sleeve could be milled with an electric-line (e-line) conveyed bottomhole assembly (BHA).The e-line tool string included a wireline release device, an electric-over-hydraulic tractor with stroking tool, electric milling motor, and burning shoe with integral centralizer and no-go. The burning shoe was designed to reduce the outside diameter (OD) of the frac sleeve but preserve the packing bore inside diameter (ID) of the SSSV landing nipple. The tractorstroker-miller tool string was run in the well and tagged the sleeve at 2,119 ft measured depth (MD) where milling continued for approximately 4 ½ hours. After E-line milling was completed, slickline was rigged up for fishing operations and successfully pulled the frac sleeve. The tubing repair was completed and the well was returned to production.This intervention technology can be used in other wellbores requiring precision milling. The solution proved successful and is a cost-effective alternative to conventional methods for milling obstructions.

Coiled Tubing Drilling (CTD) has been used on the North Slope of Alaska (Fig. 1) since 1994 for drilling sidetracks or laterals. Technology and techniques developed in Alaska have been transferred globally including the process and best practices to mill windows off whipstocks. A majority of the through tubing sidetracks have been drilled using conventional monobore or through-tubing whipstocks in multiple configurations. CTD has been limited to the size of the tubing or minimum internal diameter (ID) that a whipstock can pass-through and the ID of the tubing, liner, or casing that the whipstock will be set in. A 3-1/2" Thru-Tubing whipstock has a running outer diameter (OD) of 2.625" and could only be set in liner or casing up to 5-1/2". The problem with installing a 3-1/2" Thru-Tubing whipstock in larger liner or casing than 5-1/2" has always been the ability to properly anchor the whipstock and keep the window milling bottom hole assembly (BHA) on the tray of the whipstock. That is no longer an issue with the development of the High Expansion Wedge (HEW). The HEW has a 2.625" OD and is capable of anchoring inside 7" liner or casing. This type of whipstock will open a new set of CTD candidates that have previously been inaccessible. The goal of this paper will be to describe the design, testing, and field trials that were used to develop the HEW.