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Abstract In the last years the quest for hydrocarbons findings moved into extreme drilling condition, such as ultra-deep waters, ultra-high temperatures and drilling fluids densities. Adding to these the very narrow density windows (reservoirs with very low differential fracture pressure - pore pressure), both operators and drilling fluids service companies faces increased challenges to deliver the well for production. It is common that for such applications the bottom-hole static temperature is over 180°C/356°F, even reaching temperatures in excess of 250°C/482°F in some fields, acid gases (CO2, H2S) are also present, so the list of challenges is formidable. In this paper, the authors details the common challenges for such extreme conditions wells and best practices, present a new generation synthetic-based fluid capable to withstand temperatures in excess of 500°F/260°C, as well as a unique hydraulics engineering calculations software which enable real time equivalent-circulation density (ECD) calculations. The design and development of the mew ultra-high temperature mud system is presented and its components. At the core of the system it is a new amine-free emulsifier, which is stable to temperature above 300°C/572°F. In addition, the authors will present the extensive lab work required to optimize the formulation for high densities and extreme high temperatures, detailing also the critical fluids engineering guidelines for drilling in such harsh conditions. Using laboratory, field, and computer data, the authors will demonstrate the effectiveness of the new fluid in delivering optimum drilling in extreme HTHP conditions. Also, it is illustrated how the rheology is maintained at minimum level with a micron-size weighting material, and the engineering software used for pre-planning and while drilling to accurately calculate the ECD and maintain it within the required range.
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 177°C (350°F), 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 45° 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.
Abstract Weight material sag occurs during drilling operations when drilling fluids remain idle in the wellbore for time periods ranging from hours to several days at static or low-shear conditions. This paper presents a novel method of predicting real-time sag behavior in the wellbore. The method also accurately predicts the fluid mud weight collected at the surface as it is circulated out after a sag event, providing a significant advancement in drilling fluids engineering. Weight material sag is broadly viewed as the settling of barite particles in drilling fluids (primarily oil-based) under various mechanisms. Fluid composition (barite size/concentration and oil/water ratio) and fluid properties (i.e., rheology) influence the barite settling rate. The well geometry (i.e., inclination and diameter) also affects sag behavior. In addition, well operating conditions (i.e., temperature, pressure, and time for which fluid is uncirculated) also influence sag severity. A comprehensive computational approach was developed to model the sag behavior in wellbores using fluids composition/properties and wellbore geometry/conditions information. The wellbore sag model predicts information about the changing fluid composition along the wellbore depth as affected by sag, when the fluid in the well is under idle conditions (static or low shear). Specifically, for a wellbore section of a given inclination, the model provides quantitative density/rheology estimates of the barite-depleted zone at the top of the section and the barite-accumulated zone at the bottom. As the sag-affected fluid is circulated out after an idle period, the model also predicts the varied mud weight of the fluid collected at the surface and the corresponding transient bottomhole equivalent circulating density (ECD) as the circulation begins. The wellbore sag model predictions, especially the variation in the mud weight of the fluid collected at the surface after the sag event, were tested on several wells and fluid systems. The model provided good correlations between measured and predicted fluid density, typically less than 0.1 lbm/gal. The model accurately demonstrates how certain fluids show good sag resistance in some wells yet fail in some complex wells. The model also shows excellent sag resistance of certain specialized fluids in complex wells, which is in agreement with the field observation. A method to accurately determine real-time sag in the field has been a long-standing need. The successfully validated wellbore sag model, which captures the combined effect of fluids composition/properties and wellbore geometry/conditions, could serve as a useful tool for mud engineers to evaluate the sag behavior. It could also enable fast decision making at the rig site to optimize fluid formulations and operating conditions for sag management.