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Summary Weighting-material sag is a reoccurring problem with many oil-based drilling fluids. Attempts to correlate sag tendencies to various rheological properties commonly used to benchmark drilling fluids have had limited success in prevention and anticipation of sag problems in the field. This paper presents a new testing apparatus for dynamic and static settling-rate (sag) measurements, which has proved to provide a better understanding of the sag phenomena and a better means to characterize fluid performance. This apparatus greatly expands the precision of sag measurements over previous techniques and allows testing conditions similar to those experienced downhole. Good correlation has been found between settling-rate measurements and performance of drilling fluids in the field. Introduction Sag is a variation in density of a drilling fluid caused by settling of suspended particles or weighting material in a wellbore. Laboratory and field experience suggests that sag is often worse in dynamic situations caused by pumping, pipe rotation, and tripping. However, sag can occur in either static or dynamic conditions. In the presented apparatus, measurements are performed at prescribed shear rates, elevated temperatures to 177ยฐC (350ยฐF), and pressures to 690 bar (10,000 psi). Additionally, the apparatus requires only a 50-cm sample for complete analysis. The settling-rate measurements obtained are useful in planning and as a diagnostic tool for sag performance in active drilling-fluid systems. Preliminary Laboratory Studies A typical way to control the shear of a non-Newtonian drilling fluid is to use a concentric-cylinder configuration with the sample fluid occupying the annulus. If either the outer or inner cylinder is rotated relative to the other, the annular fluid is subjected to an approximately uniform shear field that can be modeled easily. The configuration is comparable to the common oilfield viscometer and is commonly referred to as "Searle geometry" if the inner cylinder rotates relative to a stationary outer cylinder or as "Couette geometry" if the outer cylinder rotates relative to a stationary inner cylinder. Cylinder rotation combined with axial flow of the annular fluid would more closely resemble the borehole configuration, but would greatly complicate the computational modeling and control. Flow loops usually expose the sample to a range of shear rates in contrast to the constant shear rates possible in the simpler system. A flow loop also would require a high-pressure pumping system, as well as added unnecessary bulk, sample volume, and system complexity. A preliminary study apparatus was assembled (Fig. 1), which consisted of a clear-plastic outer cylinder approximately 2 m (6 ft) long and 7.62 cm (3 in.) internal diameter (ID), with sealing caps closing the ends. Bushings in the caps supported a rotatable concentric inner stainless-steel tube of 3.81-cm (1.5-in.) outside diameter. This gave a diameter ratio of 0.50. In later studies, another clear tube was centered in the original outer tube with an internal diameter of 5.08 cm (2 in.), giving a diameter ratio of 0.75. The narrower annular gap more closely approximates ideal Searle flow. The entire apparatus was pivoted on a bench-mounted knife edge, near the center, and tilted at 45ยฐ from vertical. A pivoted strut from the top end of the tube rested on a electronic laboratory digital scale, setting the angle of tilt and allowing the measurement of the imbalance force. A gear motor mounted on the upper end of the outer tube was arranged to belt drive the inner cylinder. The motor speed was adjustable by an electronic drive. A temperature-controlled bath was connected to the inner rotating tube in a way that allowed the tube to rotate while fluid from the temperature controlled bath circulated through it. When the annulus of the tubes was filled with a sample of drilling fluid, changes in the center of gravity could be tracked by monitoring the scale readings. Sample taps at intervals along the bottom side of the sloped outer tube allowed measurements of the density of the fluid at that those points.
Modernization of the API Recommended Practice on Rheology and Hydraulics: Creating Easy Access to Integrated Wellbore Fluids Engineering
Bern, Peter A. (BP Research) | Morton, Keith (Chevron ETC) | Zamora, Mario (M-I SWACO) | May, Roland (INTEQ) | Moran, David P. (Smith International) | Hemphill, Terry (Halliburton Energy Services Group) | Robinson, Leon H. (Consultant) | Cooper, Iain (Schlumberger) | Shah, Subhash N. (University of Oklahoma) | Flores, Daniel (Exxon Mobil)
Summary Tailoring drilling-fluid hydraulics is one important key to the success of a drilling operation. Failure to do so, can result in costly problems, negatively impact equipment longevity and performance, as well as ultimately jeopardize overall well objectives. In recent years, the industry methods have deviated from American Petroleum Institute (API) RP13D standard practice (2003, 2006). This departure has been driven primarily by the increasingly onerous demands of critical wells, coupled with readily accessible computer power. In 2003, a task group was formed to modernize the existing API recommended practice (RP) bulletin on rheology and hydraulics. It comprised a cross-functional team of operators, suppliers, and academics that set an aggressive target to modernize the existing standard within 2 years. The focus was to develop simple, yet accurate, methods that could be implemented readily with basic spread-sheeting skills. This paper describes improvements made to the existing procedures and provides an illustration of how these methods can be applied to complex well designs. The paper also serves to introduce the industry to a modernized API standard that offers an ideal foundation to inform new engineers of the fundamental concepts of hydraulic design and optimization. Introduction Rheology and hydraulics are central to successful well planning and execution of drilling operations, and there has been an API RP in place since the mid-1980s. API RP13D(2003) has served the industry well as a guide to support these important issues. However, it was widely recognized that the most recent version of this recommended practice required modernization. The primary drivers for this includedIncreased well complexity beyond the scope of the current document Extensive use of drilling fluids with physical properties sensitive to high-pressure/high-temperature (HP/HT) environments. The need to integrate wellbore engineering technologies to give a holistic approach. In addition, a recently published paper(Zamora and Power 2002) concluded that the timing was right to effectively bridge the widening gap between field practices and the technology being introduced into advanced hydraulics software. By incorporating the fundamentals, it is believed that the revised standard will serve both as a practical reference and as a training guide. The intended audience includes the office-based planning engineer and the wellsite operational staff (drilling engineer and drilling-fluids engineer). A review of the existing RP13D identified the following areas as the primary focus for attention in enhancing the document: downhole behavior (rheology and density), pressure-loss modeling, hole cleaning; drilling optimization; swab/surge pressures; wellsite monitoring and rheological testing. A full listing of the revised sections is shown in Table 1. This paper introduces the modernized recommended practice that was published recently (RP13D 2006). Also presented are revision improvements and their application to complex well designs, together with the project planning and management methods used to complete the new document to meet an aggressive time line.
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.97)
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 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. 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. 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. Dynamic oscillatory techniques were used by Saasen et al. to measure the linear viscoelastic properties of near-static gel networks, and found to be reasonable predictors of static barite sag potential. Kenny and Hemphill 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. 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. Most authors refer to "low-shear rate" as that corresponding to the 3 rev/min dial reading (~5.1 sec), the lowest operating speed of the 6-speed viscometer. Dye et al. 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. This study demonstrated that viscosity measurements taken at ultralow shear rates (<2 sec) 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; and viscosity levels at these shear rates are insufficient to retard barite sedimentation.
Summary Many laboratory studies evaluating the cuttings transport capabilities of water-based and oil-based drilling fluids have been published. Few attempts have been made to investigate both fluid types under identical, controlled conditions. Those that considered both fluid types measured cuttings accumulation in the annulus and not fluid velocity. In this comparative study, the efficiency of water-based and oil-based muds in cleaning the inclined annulus at varying fluid velocities was investigated. Introduction A major problem for drilling operations on high angle/horizontal wells around the world is inadequate cuttings transport. Increasing environmental concerns and economic restraints are forcing operators to consider application of extended-reach drilling techniques to even greater depths and lateral displacements, thereby increasing the magnitude and severity of the cuttings transport problem. Many researchers have identified fluid velocity as the key parameter affecting hole cleaning in high angle situations. Previously published studies that have considered water-based muds (WBM) and oil-based muds (OBM) together were principally concerned with cuttings accumulation in the annulus and not with fluid velocities. In this paper, cuttings transport capabilities of WBM and OBM are evaluated under conditions of critical and subcritical flow. The effect of fluid rheological properties on cuttings transport is also addressed. In addition to the Bingham Plastic and Power Law rheological models, this paper applies the more accurate Yield-Power Law [Herschel-Bulkley] model to better understand the problem of cuttings transport from a rigorous fluid flow perspective. Recent advances in the modeling of fluid flow in eccentric annuli are employed to document the effect of fluid rheological properties on flow velocities.
- Research Report > New Finding (0.82)
- Research Report > Experimental Study (0.64)