Lost circulation is one of the major issues that lead to unwanted non-productive time (NPT) while drilling with a narrow mud weight window and it requires engineered solutions to address the problem. In several instances in the past, wellbore strengthening was achieved by treating the drilling fluid with lost circulation material (LCM), utilizing Stress Caging or Wellbore Strengthening theory. Small fractures were propped and sealed with a proper size distribution of particles that isolates the fracture tip from fluid pressure and controls the fracture propagation, effectively increasing the near wellbore hoop stress.Laboratory data and field experience indicate limited success may occur if a single material such as sized calcium carbonate is used alone for wellbore strengthening. This is possibly due to size reduction that may occur while drilling or due to fracture closure stresses (FCS) acting on the particles. However, using calcium carbonate in conjunction with resilient graphitic carbon (RGC) material has shown to be effective in increasing the formation integrity.The effect of mechanical properties of LCMs on wellbore strengthening has been investigated using compression/crush tests at different confining pressures simulating a wide range of FCS. Crush test demonstrated compaction and significant crushing of the ground marble and ground nut shells at high confining pressure (~ 5000 Psi). Considerable improvement in the crushing resistance and resiliency of these materials was observed with small additions of RGC. Knowledge of deformation and failure behavior of different LCM materials may result in better design. In this paper recommendations are made on different combinations of LCM that may be used more effectively to provide wellbore strengthening.

Summary Lost circulation, a major complication of drilling operations, is commonly treated by adding materials of various types, shapes, and particle-size distributions to the drilling mud. Generally known as wellbore strengthening, this technique often helps the operator to drill with higher mud gradients compared with that suggested by the conventional fracture-gradient or borehole-fracture-limit analysis. The underlying mechanisms through which a wellbore is strengthened, however, are not yet fully understood. This study explores these wellbore-strengthening mechanisms through an analytical solution to the related solid-mechanics model of the wellbore and its adjacent fractures. The provided solution is generic in that it takes into account the mechanical interaction of multiple fractures between one another and the wellbore under an arbitrary state of in-situ stress anisotropy. An additional generality in this solution arises from its unification and quantification of some solid-mechanics aspects of the previous hypotheses that have been published on the subject—i.e., stress cage, as well as the tip isolation and its effect on the fracture-propagation resistance. In relation to the stress-cage theory, the study investigates the wellbore-hoop-stress enhancement upon fracturing. The findings indicate that the induced hoop stress is significant at some regions near the wellbore, especially in the general vicinity of the fracture(s). However, given the strong dependency of wellbore stress on the mechanical and geometrical parameters of the problem, generalizing these results to the entire region around the wellbore may not always be trivial. The study also examines tip isolation, a common feature of fracture-closure and propagation-resistance hypotheses, through the analysis of partially reduced fracture pressures and a breakdown criterion, defined by the critical stress-intensity factor of the formation rock.

Particulate lost circulation materials (LCM) that work for severe-to-total losses are difficult, if not impossible, to find. Solutions that are effective for lower loss rates do not perform well at higher loss rates. Many LCM formulations have been used to treat severe losses, but their design and use has been more trial and error based mostly upon successful case histories. This paper describes the development of a combination of materials that is used in conjunction with other Engineered, Composite Solutions (ECS) to further enhance their performance.A novel combination of swelling materials, retarder, and fibers with a large aspect ratio is proposed as an activator that can be deployed with ECS typically available on the rig. The activator was designed and tested under conditions that qualitatively resemble severe lost circulation scenarios (large fractures). A shale swell meter was modified to qualitatively compare the swelling behaviour of different materials under different temperatures and retarder concentrations. A polyacrylamide-based swelling material was found to be sensitive to both temperature and retarder concentration. A newly sourced, potentially reservoir-friendly swelling material was found to be sensitive to temperature only. The activator-ECS combinations were tested for plugging capability with Permeability Plugging Apparatus (PPA) test equipment using different size tapered slots. Data from these modified PPA tests were used to determine the best combination of activator and ECS for plugging a particular-sized fracture simulated by the tapered slot.Field applications of systems that led to this proposed approach are discussed along with laboratory data comparing the swelling behaviour of different materials as related to mixing and pumping times.

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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 177°C (350°F), and pressures to 690 bar (10,000 psi). Additionally, the apparatus requires only a 50-cm3 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.