Summary A large-scale study of cuttings transport in directional wells is discussed in this paper. Previous investigators used unrealistically high fluid velocities and/or short test sections where steady-state conditions had not been established. This study used a 40-ft [12.2-m] test section. Pipe rotation and eccentricity, as well as several types of drilling muds and flow regimes, were studied. Annulus angles varied from 0 to 90°, and actual drilled cuttings were used. The major factors affecting cuttings transport are drilling fluid velocity, hole inclination, and fluid rheological properties. Much higher annular velocities are required for effective hole cleaning in directional wells than in vertical wells. An increase in hole angle and/or drilling rate reduces the transport performance of drilling fluids. Hole angles of 40 to 50° are critical because of cuttings buildup and downward sliding of the bed of cuttings. High-viscosity muds were observed to provide better transport than low-viscosity muds. Introduction Since the introduction of rotary drilling, the circulation of drilling fluid has become an integral part of the drilling operation. Two primary functions of a circulating drilling fluid are (1) to remove generated cuttings from the bottomhole and bit teeth and (2) to lift those cuttings to the surface through the annular space between the drillpipe and the hole wall. The ability of the fluid to lift such cuttings is generally referred to as the carrying capacity of the drilling fluid. This study resulted from the need for accurate and realistic data to facilitate the optimum design of drilling-fluid systems for directional drilling. For vertical or near-vertical drilling, the problem appears to have been adequately contained. In directional well drilling, however, the inclined (usually eccentric) annulus poses several problems not encountered in vertical wells. Previous investigators1–7 have listed the most relevant factors affecting the carrying capacity of drilling fluids:fluid annular velocity;hole inclination;drilling fluid properties;penetration rate;pipe/hole eccentricity;hole geometry;annular velocity profile;particle density; settling velocity, size, and geometry;drillpipe rotary speed; andpipe/hole diameter ratio. It is difficult and impractical to investigate the effects of all these parameters simultaneously. Consequently, our objective was to develop field-oriented cuttings-transport models that account for the most significant factors affecting particle and fluid dynamics in directionally drilled wells. To achieve this objective, a two-pronged approach was adopted. Design and construct an apparatus for experimental investigation of the behavior of actual rock cuttings at realistic fluid velocities, hole inclination angles, pipe/hole eccentricities, drillpipe rotary speeds, and other relevant variables. Apply all theoretical considerations for the development of applicable mathematical relations based on detail analyses of relevant principles. These principles should include the dynamics of irregularly shaped particles in non-Newtonian fluids; the axial-velocity profile in inclined, eccentric annuli; and the tangential velocity produced by drillpipe rotation and pipe/hole eccentricity. This paper covers only the first phase of this study with brief comments on the second phase. The cuttings transport in vertical wells has been covered extensively by many investigators.1–5,8–24 In contrast, very little has been contributed to the problem of directional well drilling. Fujii and Sato25 conducted laboratory experiments at 0, 45, and 60° angles from the vertical with water and carboxymethyl-cellulose-polymer solutions and a 1.33-in. [34-mm] pipe inside a 2.36-in. [60-mm] casing. In our opinion, their results are of little practical significance because of the high, unrealistic velocities used (up to 10 ft/sec [3 m/s]) and because the short test section (10 ft [3 m]) did not establish steady-state conditions. Movsumov et al.26 attempted to solve the problem of drilled-cuttings transport in inclined, eccentric annuli purely from theoretical considerations. Their mathematical approach involved extensive trial and error and, therefore, is of little practical value, especially because their analysis was idealized to exclude the important phenomenon of bed formation that is discussed later. In the current work,6,7 a unique experimental facility was designed to provide flexibility for a comprehensive investigation of steady-state cuttings transport. Several angles of inclination, drillpipe rotations, pipe/hole eccentricities, and mud flow rates were investigated.

This paper describes a new model for obtaining analytical solutions to the problem of non-Newtonian fluid flow through eccentric annuli. A discussion on non-Newtonian rheology is presented, followed by the development and solution of applicable differential equations using the Ostwald de Waele power-law model and a nonrectangular slot.Results indicate that velocity values are reduced greatly in the reduced region of the eccentric annulus. This is important in directional drilling where the drill pipe tends to lie against the hole. Design of mud flow for cuttings transport on the basis of the nominal average velocity could lead to serious problems associated with cuttings buildup in the lowvelocity region of the annulus. Other practical applications of this work include the determination of velocity distribution in chemical processes involving fluid flow through eccentric annuli -e.g., heat exchangers and extruders -and more accurate velocity profiles inside journal bearings, particularly for small diameter ratios.The main advantage in the new approach is that iterative finite difference methods used by previous investigators are avoided. Previous work along present lines used a linearized model and resulted in velocity profiles of unacceptable accuracy. This study improves both the accuracy and the solution technique.

Summary Offshore drilling continues to be extremely cost intensive, with U.S. $50million wells not uncommon. This paper discusses one company's experience and the lessons it learned from a comprehensive analysis of Gulf of Mexico (GOM)historical data for drilling-performance benchmarking and continuous cost reduction. Drilling operations were broken down into discrete activities, and the best times from all the wells---including trouble time---were aggregated to form the "best composite time" (BCT). The BCT, introduced in recent papers, was applied, along with learning-curve analysis and other investigative tools, to examine drilling problems and the lessons learned to capture the best practices and, thereby, challenge well-planning and construction practices. The "best composite cost" (BCC), or the monetary equivalent of the BCT, was also calculated and used for well-cost benchmarking. Correlative analyses of the wells (i.e., crossplots of drilling events alongside mud-log data, wireline logs, and geologic data) were used to elucidate major well problems and abnormal flat times that caused deviations from the BCT. Correlative analysis also helped explain why some wells were drilled relatively trouble-free, even in difficult environments. From a more detailed trouble-time analysis of company-operated wells, tool/equipment failure was seen as a significant trouble-time component. Major drilling problems were also found to be mostly well-pressure related (e.g., well control, lost circulation, and stuck pipe), supporting increased emphasis on improved planning and quantification of equivalent circulating density (ECD), deepwater geopressures, and narrow drilling margins, especially in ultradeepwater environments. Overall, the company's 2003 trouble time was 26%of the total drilling time from spud to rig release. The BCT/BCC methodology is actually one element of "The Ten-Step Process" discussed exhaustively in Refs. 1 and 2. Applications to two onshore areas, so far, have shown encouraging results in drilling-cost reduction. Applications to more-complicated offshore GOM wellbores, cost components, and narrow geopressure margins are the focus of this paper. The fields investigated are located in different parts of the GOM (Table 1). For brevity, results are shown only for the subsalt area of South Timbalier, the deepwater Green Canyon (GC) area, and the ultradeepwater eastern Gulf of Mexico(EGOM).

Riserless drilling poses numerous operational challenges that manifests itself in a number of ways, that can adversely affecting the efficiency of the drilling process. The problems include increased torque and drag, increased vibration, poor hole cleaning, tubular failures by buckling above the mud line, poor cement jobs, and associated problems during tripping operations. Drilling in deepwater and ultra-deepwater as well as extending the reach to a greater along hole depth in the riserless environment requires both improved models and comprehensive analysis, especially when the larger diameter casing pipes are run and cemented. The present calculations without proper modeling will gravely underestimate the hook load values when the casing strings are run in deepwater situations. This paper proposes a modeling approach, which uses scenarios in which the drillstring/casing strings are in open water and in openhole reservoirs under different operating conditions to arrive at appropriate hook-load values in addition to torque and drag calculations. Both combinations of soft and stiff string models are used for the tension-force estimation as well as the wellhead-side loading calculations. The research results also present the hook-load calculations for scenarios when casing and inner string are run with drilling mud inside the inner string, sea water in the outer string, and pad mud in the hole below the mud line. The study concludes that various parameters influence the results, such as wellhead offset from the rig center, wellbore inclination, curvature, wellbore torsion, angle of entry into the wellhead besides the complexity from wind, wave forces, and ocean currents. This paper documents the comparison between the predicted mathematical simulation results with the actual well data from different wells to explain the rigor of implementation.

Offshore drilling continues to be extremely cost intensive where $50-million wells are not uncommon. This paper discusses one company's experience and lessons learned from a comprehensive analysis of Gulf of Mexico (GOM) historical data for drilling performance benchmarking and continuous cost reduction. The "Best Composite Time" (BCT) introduced in recent papers (Refs. 1-3) was applied along with learningcurve analysis, and other investigative tools to examine drilling problems and lessons learned, capture best practices, and thereby challenge well planning and construction practices. Drilling operations were broken down into discreet activities and the best times were aggregated to form the BCT.The "Best Composite Cost" (BCC), the dollars equivalent, was also calculated and used for well-cost benchmarking. Correlative analyses of the wells, i.e. crossplots of drilling events alongside mud log data, wireline logs, and geologic data, were used to elucidate major well problems and abnormal flat times that caused deviations from the BCT. Correlative analysis also helped explain why some wells were drilled relatively trouble-free, even in difficult environments.From a more detailed trouble-time analysis of company-operated wells, tool/equipment failure was seen as a significant component. Major drilling problems were also found to be mostly well-pressure related (well control, lost circulation, and stuck pipe), supporting increased emphasis on improved planning and quantification of ECD, deepwater geopressures, and narrow drilling margins, especially in ultradeepwater environments. Overall, the company has been able to reduce the trouble time to only 16% of total time in 2003.The BCT/BCC methodology is actually one element of "The Ten-Step Process" discussed exhaustively in Refs. 1 and 2. Applications to two onshore areas so far have shown encouraging results in drilling cost reduction. Applications to more complicated offshore GOM wellbores, cost components, and narrow geo-pressure margins are the focus of this paper. Fields investigated are located in different parts of the GOM