In spite of the many technological advances that have accompanied the growth of coiled-tubing (CT) drilling, one significant challenge remains-effective cuttings transport, particularly in deviated wells. This paper presents a summary of cuttings-transport problems and current solutions. It is shown that, in many circumstances, hole cleaning is more efficient if a low-viscosity fluid is pumped in turbulent flow rather than a high-viscosity fluid in laminar flow. Case studies are presented that illustrate both cuttings-transport problems and routine applications without cuttingstransport difficulties. The proposed hole-cleaning models are used to interpret these data and to suggest possible alternative approaches.Two novel approaches to understanding hole cleaning are introduced. First, for laminar flow, the distance that a particle will travel (downstream) before it falls across the annulus clearance is calculated with Stokes' law and the local viscosity while flowing. This analysis may easily be applied to optimize mud selection and wiper trips. Applying this model to high low-shear-rate-viscosity (LSRV) gels shows that they may perform well inside casing but are expected to do a poor job of hole cleaning in a narrow, openhole, horizontal annulus without rotation. Second, for turbulent flow in horizontal wells, the concept of using annular velocity (AV) as a measure of hole cleaning is shown to be insufficient. A more complete term, annular velocity/root diameter (v ARD ), is introduced and should be used to compare cuttings transport in turbulent flow in horizontal wells of different cross-sectional areas.

Coiled tubing (CT) drilling has grown tremendously in the last few years. In spite of the many technological advances that have accompanied this growth, one significant remaining challenge is effective cuttings transport, particularly in deviated wells. This paper presents a summary of cuttings transport problems and current solutions (including fluid selection, flow rates, and operational techniques such as short trips and pumping viscous slugs). It is shown that in many circumstances hole cleaning is more efficient if a low-viscosity fluid is pumped in turbulent flow rather than a high-viscosity fluid in laminar flow. Several detailed case studies are presented that illustrate both severe cuttings transport problems and routine applications without cuttings transport difficulties. The proposed hole cleaning models are used to interpret these data and suggest possible alternative approaches. Hole cleaning relying on viscous fluids in laminar flow has proved to be inefficient because of the inability to rotate the string to agitate bedded cuttings. Alternatively, a high flow rate for turbulent hole cleaning is more effective, but difficult to achieve because of high friction pressures in the coiled tubing. Therefore, a cuttings bed is almost always present in CT (or any slide) drilling. This has a major operational impact resulting from required remedial activities, increased risk of stuck pipe and the inability to attain the desired reach. Two novel approaches to understanding hole cleaning are introduced. First, for laminar flow, the distance that a particle will travel (downstream) before it falls across the annulus clearance is calculated using Stokes' law and the local viscosity while flowing. This analysis may be easily applied to optimize mud selection and wiper trips. Applying this model to high low-shear-rate-viscosity (LSRV) gels shows that they may perform well inside casing but are expected to do a poor job of hole cleaning in a narrow openhole horizontal annul us without rotation. Second, for turbulent flow in horizontal wells, the concept of using annular velocity (AV) as a measure of hole cleaning is shown to be insufficient. A more complete term called AVRD is introduced, which is the product of the AV and the square root of the hydraulic diameter. This term should be used to compare cuttings transport in turbulent flow in horizontal wells of different cross sectional areas. P. 7

Gas exploration wells are being drilled in high pressure and temperature environments targeting low permeability and high fracture gradient formations that push the envelope of conventionally used technologies. Thus, conventional perforating techniques are often not sufficient to break down the formation during fracturing operations in this type of wells.A novel system, specially designed to enable hydraulic fracturing in challenging producers was successfully field-tested. The system includes an anchor, a multi-cycle incrementing and stroking tool (MCIST), and a jetting sub with multiple nozzles. The anchor is used to prevent axial motion of the jetting head while jet cutting, which overcomes the long-standing problem of tubing stretch due to pressure changes and vibration during abrasive perforating operations. With the anchor as a depth reference base, the MCIST changes length upon command from the surface and uses sequential jetting to create a series of evenly spaced perforations in the casing, with corresponding large diameter longitudinal slots in the formation, in a controlled and evenly spaced fashion. The tool design and testing process, details about the field trial experience as part of a stimulation treatment, and the excellent post-stimulation results achieved are discussed in the paper.

Horizontal wells have shown such gains in productivity in many applications that the damage associated with longtime exposure to drilling fluid was, in many cases, accepted. In addition, the difficulty of removing formation damage in a horizontal well has compounded the problem. With many horizontal wells now being left in an openhole status, formation damage becomes even more important. Coiled tubing (CT) drilling has grown from four jobs in 1991 to over 120 (estimated) jobs in 1994. The primary motivations for this growth have been:The ability of CT drilling to finish drilling a well in soft formations faster than a rotary rig, andSafe, rigless underbalanced drilling to greatly reduce formation damage in horizontal wells. This paper reviews the causes of formation damage, both from fluid/solids invasion and stimulation techniques to remove damage. An analytical model is used to estimate the productivity index (PI) for various horizontal and vertical permeabilities, well lengths, and reservoir thicknesses for comparison with results from several case studies. Options for underbalanced drilling including fluid selection, gas lift, and seal technology are discussed. Candidate selection criteria for those evaluating the possibility of underbalanced horizontal drilling are presented. INTRODUCTION Horizontal wells are particularly vulnerable to formation damage due to long drilling mud exposure time relative to vertical wells (easily 30 times) and reduced cleanup velocity (easily 1/5) with production spread over the long horizontal. In spite of this, horizontal wells are the most important success story in the oil business in the last 10 years. Average gains in productivity1,2,3,4 of two to seven times the vertical wells in reservoirs with matrix permeability have fueled the growth of horizontal drilling. In reservoirs with natural fracture, productivity indices of 20 to 30 times the vertical have been observed with ultimate recovery several times greater than for vertical wells.5 Ultimate recovery improvement with matrix permeability is not widely reported, although 1.5 to 2 times vertical ultimate recovery is expected in two Canadian reservoirs. Although the ultimate recovery may not be improved, the accelerated production often makes horizontal wells more economically attractive in spite of the higher cost of the average horizontal well which is 1.2 to 2 times the vertica.3

Summary In the 1980's, a "coiled-tubing revolution" began when coiled-tubing services were expanded to include most workover services. In 1991, this revolution expanded to include openhole drilling with a coiled-tubing unit (CTU) in place of a drilling rig. This paper discusses the design process and the limits associated with the use of coiled tubing (CT) to drill new wells and horizontal re-entry wells. Introduction For several years, CT has been used to drill scale and cement in cased wells. Recently, CT has been used (in place of a rotary drilling rig) to drill vertical and horizontal open holes. At this time, <30 openhole CT drilling (CTD) jobs have been performed. However, there is a tremendous interest in this technique in the oil industry; many companies are actively involved in developing CTD technology. This paper discusses CTD applications and presents an engineering analysis of CTD. This analysis attempts to define the limits of what can and cannot be done with CTD. These limits are calculated with CT and drilling models used for other applications. The basic limits associated with CTD are weight and size, CT force and life, and hydraulic limits. Each limit is discussed separately. For a specific application, each limit must be considered. CTD Applications Table 1 divides CTD applications into four main categories. First, re-entry drilling in existing wells and new well drilling are considered. Second, vertical and deviated wells are considered. Table 2 is a list of CTD attempts to date that we are aware of. Any errors or omissions from this table are unintentional. Table 2 highlights the applications attempted, CT size, and hole size. It is not surprising that most of these attempts are re-entries because CT services were developed for the workover market. When working in an existing well, there is no need to spud the well or to set surface casing, neither of which can be done with most existing CTU's. Vertical deepening with a pendular assembly to keep the hole vertical is probably the most straightforward CTD application. A long bottomhole assembly (BHA) is used to provide weight on bit (WOB) without buckling the CT. The neutral point is in the BHA so that the CT is always in tension. Lateral drainhole drilling (Fig. 1) requires milling a window in the casing. A lateral then is drilled through the window with a directional measurement and control system.