Xanthan gum and other naturally obtained polymers have been used extensively in the petroleum industry as a "viscosifier" in drilling, completion, workover and hydraulic fracturing fluids. Other than the effects of shear rate, pH and temperature, the performance of various polymers can be greatly affected by salinity, due to their sensitivity to metal ions of different salts contained in the commonly used solvents. In today's oilfield operations, it is not uncommon to combine polymers with sea water or brine of a known salt concentration in order to generate certain desired fluid properties. Consequently, the importance of understanding the compatibility and shear properties of polymer fluids in brine solvents for coiled tubing operations cannot be underemphasized.However, while there are several existing literatures on the various methods of viscosifying brine solutions with polymers, only a handful have attempted to describe the flow properties of viscosified brine. In order to bridge this knowledge gap, the present experimental study examines the compatibility and flow characteristics of Xanthan gum at various polymer loadings with different concentrations of Calcium Chloride (CaCl 2 ) brine. An unprecedented set of flow data was acquired using an experimental flow-loop comprising of ½ in. straight and coiled tubing sections. The data demonstrated a continual decrease in drag reduction and increased friction pressure loss with increasing brine density. A comparison of those data with predicted data show that the hydraulic properties of viscosified brine can be fairly estimated using existing friction factor correlations. Nevertheless, additional flow data must be acquired with various brines and polymers to develop correlations with better accuracy.
In the last few decades, coiled tubing has been widely employed for post-stimulation drillout of composite or cast-iron bridge plugs and isolation sleeves used in multi-stage hydraulic fracture stimulation in horizontal wells. Due to its inherent capability of continual deployment, coiled tubing technology has increased in popularity for this application over conventional jointed-pipe snubbing with rig-assist snubbing units. Despite the increasing use of coiled tubing units, drillout practices have typically been based on "art" rather than science, often resulting in drilling problems such as poor fluid efficiency and hole cleaning issues, lost circulation, stuck pipe, lost-in-hole tools, and parted pipe. Unfortunately, a greater percentage of stuck pipe incidents are directly related to poor hole cleaning, and it is not surprising that the causes of these problems are often not well understood. Thus, various approaches have been utilized to prevent recurrence based on incorrect assumptions. While some of these problems have been adequately dealt with in several publications, the determination of optimum fluid properties for efficient hole cleaning as well as the effectiveness of short tripping have been given minimal attention. To a large extent, fresh water, or brine, is mixed with various additives such as friction reducer for pressure loss and pipe friction, hydrogen sulfide scavenger and inhibitor, biocide, scale inhibitor, and polymer gel while drilling plugs. A common hole cleaning practice is the use of intermittent high-viscosity gel sweeps, wiper tripping to kick-off point after drilling a predefined number of plugs, and flowing back the well in an underbalanced condition while drilling and short tripping. The effectiveness of these practices is worth questioning based on the occasional drag and stuck pipe encountered while tripping out of hole. This paper addresses the misconceptions related to coiled tubing hydraulics and hole cleaning, as well as reviews the common drillout practices and their cost implications including coiled tubing rig up, coil size selection, bottomhole assembly, fluids efficiency, and short tripping. Various best practices are recommended for improving post-stimulation drillout, with specific emphasis on how to minimize drillout cost.
Over the last few decades, coiled tubing technology has found increasing applicability in oilfield operations, including well intervention, well logging, coiled tubing drilling, perforation and fishing operations. Significant attention has been given to the prediction of friction pressure loss of various fluids pumped through coiled tubing and the annular space between the tubing and the wellbore. The importance of such prediction cannot be underemphasized, as adequate knowledge of the anticipated friction pressure is useful for determining the required pump horsepower and developing hydraulic programs during the operational planning stage.However, a coiled tubing string can buckle under its own weight when the axial compressive load acting on the string exceeds a certain threshold, known as critical buckling load. In long extended reach wells, the extent of buckling, as well as its effect on fluid flow hydraulics can be significant, especially in the annulus between the tubing string and the wellbore. Despite the frequent occurrence of tubular buckling in many oilfield operations, previous publications on annular flow have traditionally considered flow in concentric and eccentric annuli, mainly discussing the effects of diameter ratio, fluid rheology and eccentricity on the friction pressure loss observed in such conduits.The present numerical and experimental study examines the characteristics of steady-state isothermal laminar flow of non-Newtonian (Power-law) fluids and turbulent flow of Newtonian fluids in annulus with a non-rotating buckled inner tubing string. Numerical modeling results of fluid flow in various three-dimensional annular geometries using Computational Fluid Dynamics (CFD) are presented, ranging from a uniformly eccentric annulus to an annulus consisting of "corkscrewed" inner tubing -a helical buckling state, whereby the coiled tubing is permanently deformed when the prevailing bending stresses exceed the yield stress of the tubing. In addition, extreme cases of "arbitrarily" buckled coiled tubing annulus were evaluated for each size of coiled tubing considered. An interesting observation is the increase in annular friction pressure loss with increasing buckling extent. The CFD simulation results have been verified experimentally using a field-scale flow loop comprising of a helically buckled tubing annulus and an equivalent uniformly eccentric annulus. Practical empirical correlations have been developed, taking into account certain buckling parameter, to improve the accuracy of annular friction pressure loss predictions in coiled tubing operations involving a considerable level of buckling.
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