Summary The occurrence of barite sag has been a well recognized but poorly understood phenomenon in the drilling industry resulting in problems such as lost circulation, well control and stuck pipe. The financial impact on drilling costs, usually resulting from rig-time lost while circulating and conditioning the drilling fluid system, is not trivial. Recurring barite sag problems reportedly have resulted in the loss of drilling projects. Originally thought to occur under static conditions, barite sag is recognized now to occur more readily under dynamic, low-shear-rate conditions. Industry experts have offered a variety of measuring parameters, based upon empirical data, that only partially correlate with the occurrence of barite sag. Prediction of barite sag in dynamic flow has created an engineering challenge. The effect of shear rate on dynamic barite sag, for invert-emulsion drilling fluids, has been studied and quantified using new and advanced technology. A new field viscometer capable of measuring viscosity at shear rates of 0.0017 sec–1 and an eccentric wellbore-hydraulics model were used to develop and understand this relationship. Changes in mud weight as a function of shear rate, hole angle, annular velocity (AV), and eccentricity correlate with ultralow-shear-rate viscosity. Based upon experimental results, field technology has been developed to predict the potential for barite sag of invert-emulsion drilling fluids and to provide remedial measures through ultralow-shear-rate-viscosity modification. The efficacy of using traditional rheological measurements as indicators of barite sag potential is addressed. Introduction Recent advances in drilling technology have resulted in greater numbers of directional wells being drilled as operators strive to offset ever-increasing operating costs. Deviated drilling allows operators to exploit reservoir potential by drilling multiple wells from a single site, and to increase production by penetrating the pay zone in a horizontal, rather than a vertical plane. With consideration to eliminating drilling problems such as torque and drag, stuck pipe, low rates-of-penetration and wellbore stability, these wells are being drilled increasingly with invert-emulsion drilling fluids. Despite their considerable technical merits and advantages, invert-emulsion drilling fluids are not always trouble-free. First, these fluids are generally more viscous at surface conditions than water-based drilling fluids, and efforts are made to reduce viscosity by minimizing additives used for suspending barite. Second, fluid flow in a deviated wellbore is skewed by the effects of drillpipe eccentricity, typically resulting in low shear rates under the eccentric pipe, creating conditions conducive to barite sag. As a result, the frequency of problems associated with barite sag when drilling highly deviated wells is higher with invert emulsions, compared with water-based systems. Prior Laboratory Studies In the field, barite sag is defined roughly as the change in mud weight observed when circulating bottoms-up. Several laboratory investigations of barite-sag mechanisms and potential have been undertaken over the past decade. Results from a laboratory study presented by Hanson et al.1 found that barite sag is most problematic under dynamic, not static, conditions. Results indicate that barite sedimentation and bed formation occur while drilling fluid is being circulated and that fluid-like beds can "slump" downward when circulation is stopped. An important conclusion from this work was that barite sag generally observed in the field is due primarily to barite deposition occurring under dynamic conditions. Bern et al.2 induced barite sag by circulating at low flow rates with an eccentric drillpipe. Drillpipe rotation tended to prevent bed formation and served to aid in removing beds formed on the lower side of the test section. The barite sag tendency of some fluids tested at low flow rates was so great that beds were observed "avalanching," slumping down the test section and being incorporated back within the system. The authors concluded that the combined effects of hole angle, low AV, and a stationary, eccentric drillpipe were conducive to inducing dynamic barite sag. There appear to be several "schools-of-thought" on the relationship between rheological properties and barite sag. Using laboratory devices to measure static barite sag, several researchers concluded that the API gel strength measurement is an unreliable indicator of static barite sag potential.3,4 Dynamic oscillatory techniques were used by Saasen et al.4 to measure the linear viscoelastic properties of near-static gel networks, and found to be reasonable predictors of static barite sag potential. Kenny and Hemphill5 showed that the Herschel-Bulkley yield-stress coefficient, t0, correlates with static barite-sag potential; however, they cautioned that t0 should not be the only parameter used for dynamic barite-sag predictions. The low-shear-rate-yield point (LSRYP), an extrapolated yield stress calculated from 6 and 3 rev/min readings, was deemed by Bern et al.6 to be a reasonable approximation of the true yield stress of a drilling fluid. They suggest that while the expertise exists to control static barite sag, the influence of rheological properties on dynamic barite sag is not well understood. A common theme in the published literature is that low-shear-rate viscosity is a rheological parameter of importance in determining the capacity of a drilling fluid to minimize or prevent the occurrence of barite sag, particularly dynamic barite sag.1–8 Most authors refer to "low-shear rate" as that corresponding to the 3 rev/min dial reading (~5.1 sec–1), the lowest operating speed of the 6-speed viscometer. Dye et al.9 recently concluded that the magnitude of dynamic barite sag in an eccentric annulus, using invert-emulsion drilling fluid, is highest at annular shear rates below 3 to 5 sec–1. This study demonstrated that viscosity measurements taken at ultralow shear rates (<2 sec–1) correlate with the management of dynamic barite sag. Theoretical Foundation of Study Drawing on the work of previous researchers, we postulated that dynamic barite sag can occur when:the drillpipe (or inner cylinder) is in a fixed, eccentric position, thereby ensuring a wide distribution of point velocities in an eccentric annulus;drilling fluids are circulated at constant shear-rate over an extended period of time; andviscosity levels at these shear rates are insufficient to retard barite sedimentation.

Accurate knowledge of drilling fluid behavior under actual conditions is required to maximize operational efficiency and to minimize cost and drilling fluid related risks on extreme high-pressure / high-temperature (HP/HT) wells. This paper identifies and discusses the major HP/HT drilling fluid challenges, recent innovations in fluid viscosity measurements under HP/HT conditions, drilling fluid designs stable to extreme HP/HT conditions, and other considerations in HP/HT drilling. Introduction Worldwide demand for energy continues to increase and is projected to average 2.0% per year out to 2030. Demand is widespread geographically but the most rapid growth is projected for nations outside the Organization for Economic Cooperation and Development (non-OECD nations) averaging 3.7% per year for non-OECD Asia.1 Providing adequate supply is driving the industry to explore areas previously unexplored, or minimally explored. A subset of this activity is HP/HT drilling. HP/HT drilling is not rigorously pursued during times of price uncertainty or low commodity pricing due to the relatively high lifting cost. The resurgence in HP/HT drilling stretches globally and encompasses areas such as the deep Gulf of Mexico Continental Shelf, northern India, Saudi Arabia, and Brunei. Historical HP/HT basins such as Indonesia, Thailand and northern Malaysia have also seen a selective increase in HP/HT activity. Several factors have combined to make deep gas increasingly attractive worldwide:Abundant infrastructure in the way of platforms, producing facilities, and pipelines that would allow new production to flow quickly to market.New technology such as 3D seismic and faster computers to locate potential formations. Drilling and Drilling Fluid Challenges Developing HP/HT prospects can require overcoming some formidable drilling challenges. Rigs capable of HP/HT drilling are larger due to requirements such as hook load, mud pumps, drill pipe and surface mud capacity to name a few. Due to these requirements, these rigs are more expensive. HP/HT wells, by definition, require a higher density fluid which typically requires high solids loading. High solids loading, the resulting higher pressures, combined with the competency of rock at depth, lead to low penetration rates, extending time on location and added drilling costs. In extreme cases, pressure, temperature, and acid gas levels can limit the selection and function of down-hole tools and fluid selection. These limitations can be so severe that MWD/LWD tools become unusable, rendering down-hole annular pressure measurements used for pressure management, unavailable. This places additional demands on the drilling fluid and temperature/hydraulic models as they become our best, if not our only source for down-hole pressure information. These models are based on surface inputs and laboratory measured fluid properties under down-hole conditions. During the planning stage for several potential record depth deep gas wells currently drilling or recently TD'd, not only did this information not exist, laboratory equipment capable of operation at the required temperatures and pressures didn't exist. Pressure/Volume/Temperature (PVT) Down-hole pressures are commonly calculated using TVD (true vertical depth) and surface measured mud weight reported from the rig. While this approach is adequate for less demanding wells, critical applications such as HP/HT and deepwater wells require adjustments for the pressure and temperature driven compression and expansion characteristics of the whole drilling fluid. These compression and expansion effects are quantified in fluid PVT measurement under expected down-hole conditions which, until recently, ranged from 15 psi/75°F to about 20,000 psi/350°F which covered industry needs. HP/HT drilling pressures and temperatures, however, can far exceed this envelope. Figure 1 illustrates isobaric PVT results on a commonly used base-fluid.

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractBarite sag is a well recognized, but poorly understood phenomenon in the drilling industry. Historically it has been associated with a static well environment; consequently test devices and rheological measurements were originally based on static conditions. Dynamic barite sag is now recognized as the major contributor to sag-related drilling problems. There are two prominent variables conducive to creating dynamic sag; 1) low shear rate conditions (drilling process-related) and 2) insufficient ultra-low shear rate viscosity (drilling fluidrelated). Dynamic sag is not entirely a mud-related problem and, under certain conditions, will occur despite appropriate control of drilling fluid viscosity.Barite sag is typically attributed to the mud system and the traditional approach to manage barite sag is to modify (increase) certain rheological properties of the mud system. These efforts are often frustrating because; 1) the proposed solution is ineffective, 2) the solution creates a new problem such as ECD management and 3) expectations are not met. This paper proposes that dynamic sag is related to both the drilling process and drilling fluid, and that these two variables cannot be treated independently from one another.

The occurrence of barite sag is a well recognized but poorly understood phenomenon in the drilling industry. Industry experts have offered a variety of measuring parameters, based upon empirical data, that only partially correlate with the occurrence of barite sag. The industry’s lack of understanding of the mechanisms and types of barite sag generally result in a poor correlation between laboratory results and field observations of barite sag. The financial impact of barite sag on drilling costs, usually resulting from rig-time lost while circulating and conditioning the mud system, is not trivial. There are reported incidences where recurring barite sag problems have resulted in the loss of drilling projects. The accuracy and relevance of technology utilized to manage barite sag can help reduce drilling costs. In the field barite sag frequently occurs in deviated wells where pipe eccentricity creates conditions conducive to dynamic sag. With the exception of a flow loop, laboratory tests do not simulate field conditions. Historically, laboratory tests characterize density variations arising from a vertical fluid column as static or dynamic sag without proper consideration to angle, pipe eccentricity, annular shear rates and annular flow. This paper reviews traditional and newly-emerging barite sag technology and compares their ability to predict barite sag potential. This potential will be determined under dynamic and static conditions in a sophisticated flow loop configured to match certain field conditions.