TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractBarite sag is a significant variation in mud density caused by the settlement of barite or other weight material in high-angle wells. The wide fluctuations in mud weight can lead to severe operational problems, including well-control, induced wellbore instability, downhole mud losses, and stuck pipe.A laboratory flow loop has been used to evaluate the influence of key drilling parameters on barite sag. Results show that the highest sag occurs at angles in the region 60-75°, particularly at low annular velocities. Drillpipe rotation is shown to be particularly beneficial in minimising barite settlement. Rotation also assists in re-distributing barite deposits formed on the low side of the hole. Data from the tests clearly demonstrate the interdependence of drillpipe eccentricity, rotation, and mud flow rate.Results from the study have been combined with field observations to develop guidelines to minimise barite sag and manage the associated risks. The conclusions of the study are that barite sag can be minimised by attention to detail at the planning and execution stages of drilling a well. In particular, recommendations in four key areas are addressed: well planning, mud properties and testing, operational practices, and wellsite monitoring procedures.

Variations in annular geometry, eccentricity, and pipe rotational speed strongly affect pressure loss of a fluid flowing in the narrow annulus of a slimhole well. Due to these factors, accurately calculating and controlling pressures in slimhole wellbores is difficult. Accurate pressure calculations are crucial for safely controlling formation pressures and protecting wellbore integrity. Attempts to model non-Newtonian fluid flow in narrow annuli with high-speed pipe rotation have been hampered by the lack of quality data. The results of numerous annular flow experiments presented herein partially correct this deficit. These results supplement annular pressure data from a 2500-ft slimhole test well and standpipe pressure data from a slimhole exploration well. Sensitive pressure measurements were used to characterize fluid flow in concentric narrow annuli created by a 1.25-in diameter (Dp) steel shaft inside clear acrylic tubes with 1.375-in to 1.75-in inside diameter (Dh). Similar tests were conducted in a fully eccentric annulus formed by the steel shaft inside an acrylic tube with Dh =1.50 in. Maximum shaft rotational speed was 900 rpm and maximum fluid flow rate was 12 gpm. Test fluids included water, glycerin solutions, viscosified clear brines, and several slimhole drilling muds. Models selected from the public domain were used with varying success to calculate results from the hydraulics tests. Simple models typically used by the drilling industry calculated annular pressure loss for non-rotating cases with reasonable accuracy. However, the simple models seldom calculated absolute effects of pipe rotation even though calculated trends correctly match those in measured data. For turbulent flow, annular pressure loss increased with increasing pipe rotation. For lamininar flow, annular pressure loss decreased with increasing pipe rotation. In all cases, annular pressure loss increased with increasing mud rheology and decreased with increasing eccentricity. Introduction Drilling or coring with high-speed pipe rotation requires excellent lateral stability for the pipe in order to avoid destructive vibrations. One means of providing this lateral stability is a narrow gap around the pipe. In this case, "narrows means Dp/Dh 0.80. This criteria distinguishes slimhole wells from reduced-bore or conventional wells. Small variations in annular gap, wellbore eccentricity, and pipe rotational speed strongly affect pressure loss of fluid flowing in the narrow annulus of a slimhole well . These factors, usually negligible in conventional drilling, significantly increase the difficulty of calculating and controlling pressures during slimhole drilling. Accurate calculations of pressure loss in the wellbore are necessary to control the well, optimize bit hydraulics, and avoid excessive pressure against the formation.

A joint industry project was established to study barite sag mechanisms and to develop field guidelines to manage the consequences. A simple empirical model was developed to compare sag potential for a wide range of fluid types. In the study, physical properties of the mud, wellbore conditions, and characteristics of the weighting material were shown to have a large influence on sag behavior. The study also included direct measurements of the properties of settled weight-material beds. These results provide new insight into the mechanisms of barite sag and how best to manage problems in the field.Data from the tests clearly demonstrate that the parameters affecting sag are interrelated and seldom act in isolation. For all muds tested, the highest sag occurred at low annular velocities over angles from 60 to 75°. Drillpipe rotation was particularly beneficial in minimizing barite settlement. Rotation also assisted in re-distributing barite deposits formed on the low side of the hole.The improved understanding of the mechanisms of barite sag enabled development of practical field guidelines. Case history studies presented in the paper demonstrate how the results of the work together with better field monitoring have been successfully applied to manage the effects of barite sag in high-pressure/hightemperature and extended-reach drilling operations.Test Fluids. The 20 test fluids represented a variety of mud types, formulations, weights, suppliers, and geographical sources. One of the project goals was to select muds from active directional wells ͑Ͼ30°͒ using weighted muds ͑Ͼ12 lbm/gal͒ in order to provide immediate feedback to operations. No other stipulations were made on field muds. Some laboratory-modified and laboratory-prepared fluids were also tested. Physical properties of all test fluids are listed in Tables 1 and 2. Mechanical-Parameter Results. Fig. 3 shows results for Mud 6 using the standard protocol at four inclinations ͑45, 60, 75, and 90°͒. Circulating fluid density change ͑corrected to 120°F͒ is plotted vs. time. All fluids tested responded similarly although the magnitudes varied.Most, if not all, of the sag-bed formation occurred at low flow rates and no rotation. Initial pipe rotation to 75 rpm consistently had the greatest effect on removing the beds. Doubling the rotary speed and then the annular velocity helped as expected, but to a much lesser extent.Time-segment 3 in Fig. 3, during which the sag was greatest, most clearly demonstrates the effects of angle. For Mud 6, the order of decreasing sag severity was 60, 45, 75, and 90°. While each individual mud tested exhibited slightly different behavior, the angle at which the maximum sag occurred was consistently in the range 60 to 75°. This is consistent with previously reported data. 3Fluid-Parameter Results. Rheology, density, weight material, and chemical treatments were the key fluid parameters investigated. These parameters emerged from an earlier study as the most significant variables affecting sag that can easily be controlled in the fie...

A joint industry project was established to study barite sag mechanisms and to develop field guidelines to manage the consequences. A simple empirical model was developed to compare sag potential for a wide range of fluid types. In the study, physical properties of the mud, wellbore conditions, and characteristics of the weighting material were shown to have a large influence on sag behaviour. The study also included direct measurements of the properties of settled weight-material beds. These results provide new insight into the mechanisms of barite sag and how best to manage problems in the field. Data from the tests clearly demonstrate that the parameters affecting sag are interrelated and seldom act in isolation. For all muds tested, the highest sag occurred at low annular velocities over angles from 60-75. Drill-pipe rotation was particularly beneficial in minimising barite settlement. Rotation also assisted in re-distributing barite deposits formed on the low side of the hole. The improved understanding of the mechanisms of barite sag enabled development of practical field guidelines. Case history studies presented in the paper demonstrate how the results of the work together with better field monitoring have been successfully applied to manage the effects of barite sag in HP/HT and extended-reach drilling operations. P. 89

Drilling-fluid densities vary significantly over wide ranges of temperature and pressure, a concern that is particularly critical in deepwater, Arctic, and high-pressure/high-temperature. The variations can affect well integrity, well design, regulatory compliance, and drilling efficiency.Drilling-fluid densities depend on the compressibility and thermal expansion of the fluids (liquids) and solids used in their formulation. Suitable pressure/volume/temperature (PVT) correlations for these fluids previously have been fairly inaccessible, primarily because of continually changing base fluids and blends, and the lack of readily available test equipment.This study was conducted to measure the volumetric behavior under extreme temperatures and pressures of a broad range of the oils, synthetics, and brines currently used in industry to prepare oil-, synthetic-, and water-based drilling fluids. It follows a recent study that successfully qualified the commercially available test equipment.For the most part, tests for this study were run at temperatures from 36 to 600 F and pressures from atmospheric to 30,000 psi, ranges that generally exceed those provided in other published studies. Correlation coefficients are provided for reference and to demonstrate their use in a compositional, material-balance model to accurately predict drilling-fluid density as a function of temperature and pressure. Tests run on field drilling fluids are included to demonstrate how these data can be used in procedures and software to predict equivalent static density and hydrostatic pressure during drilling operations.