Rheology assessment and barite sag in a typical North Sea oil-based drilling fluid at HPHT conditions

The occurrence of barite sag in drilling fluids has relatively often been the cause for gas kicks in oilwell drilling. The subsequent absorption of gas into drilling fluid could lower the density and reduce the viscosity of the drilling fluid, thereby aggravating both pressure control and hole cleaning. In this paper, we present experimental measurements of rheological properties and barite sag in a typical North Sea oil-based drilling fluid at downhole pressure and temperature conditions. A new experimental apparatus was setup for barite sag measurements at static condition with operational temperature and pressure capabilities up to 200 °C (392°F) and 1000 bar (14,503.8 psi), respectively. Rheometry measurements were conducted on fluid samples with and without barite particles at operating conditions up to 90 °C and 100 bar. We observed that at a typical shear rate of 250 s−1, which is experienced in 8.5″ hole annulus, the viscosity of fluid sample with barite increased nearly three times as that of the fluid sample without barite as the temperature and pressure increased. However, temperature effect on viscosity dominates at high shear rates compared to pressure effect. Furthermore, the fluid samples showed more shear-thinning effect with increasing yield stress as the temperature increased. On the other hand, barite sag measurements revealed that whereas fluid samples under high pressure are less prone to sag, high temperature fluid samples, however, promote sag significantly. The data from this study are useful to validate extrapolations used in computational models and to improve understanding and operational safety of sag phenomena at downhole conditions. We also discuss the importance of this study in optimizing drilling operations.publishedVersio

Modelling of Fluid Flow and Cuttings Transport in Horizontal Narrow Annulus

The motivation for this research originated from the little understanding on the phenomenon of cuttings and liquid flow in narrow horizontal wellbore. The study was aimed at modelling single-phase yield power law (YPL) fluid flow and two-phase (cuttings-water, cuttings-power law, and cuttings-YPL) flow through narrow horizontal annulus. The effects of drillpipe rotation speed, eccentricity, diameter ratio, and fluid rheological properties were investigated on the flow velocity and viscosity profile distributions, annular pressure losses, and cuttings concentration. The modelling was performed using a computational fluid dynamics (CFD) software, ANSYS CFX-14. The slot approximation technique was adopted to formulate a new approximate pressure loss model for YPL fluid with drillpipe rotation. The Buckingham

Eulerian-Eulerian Simulation of Particle-Liquid Slurry Flow in Horizontal Pipe

In this study, a computational fluid dynamics (CFD) simulation which adopts the inhomogeneous Eulerian-Eulerian two-fluid model in ANSYS CFX-15 was used to examine the influence of particle size (90 μm to 270 μm) and in situ particle volume fraction (10% to 40%) on the radial distribution of particle concentration and velocity and frictional pressure loss. The robustness of various turbulence models such as the k-epsilon (k-ε), k-omega (k-ω), SSG Reynolds stress, shear stress transport, and eddy viscosity transport was tested in predicting experimental data of particle concentration profiles. The k-epsilon model closely matched the experimental data better than the other turbulence models. Results showed a decrease in frictional pressure loss as particle size increased at constant particle volume fraction. Furthermore, for a constant particle volume fraction, the radial distribution of particle concentration increased with increasing particle size, where high concentration of particles occurred at the bottom of the pipe. Particles of size 90 μm were nearly buoyant especially for high particle volume fraction of 40%. The CFD study shows that knowledge of the variation of these parameters with pipe position is very crucial if the understanding of pipeline wear, particle attrition, or agglomeration is to be advanced

On the Stability of Oil-Based Drilling Fluid: Effect of Oil-Water Ratio

Drilling fluids are complex mixtures of natural and synthetic chemical compounds used to cool and lubricate the drill bit, clean the wellbore, carry drilled cuttings to the surface, control formation pressure, and improve the function of the drill string and tools in the hole. The two main types of drilling fluids are water-based and oil-based drilling fluids, where the oil-based also include synthetic-based drilling fluids. Many rheological properties of drilling fluids are key parameters that must be controlled during design and operations. The base fluid properties are constructed by the interaction of the emulsified water droplets in combination with organophilic clay particles. The rheological properties resulted from this combination, along with the particle size distribution of weight materials are vital in controlling the physical stability of the microstructure in the drilling fluid. A weak fluid microstructure induces settling and sagging of weight material particles. The presence of sag has relatively often been the cause for gas kicks and oil-based drilling fluids are known to be more vulnerable for sag than water-based drilling fluids. Hence, the shear-dependent viscosity and elasticity of drilling fluids are central properties for the engineers to control the stability of weight material particles in suspension. In this study, we examined the stability of typical oil-based drilling fluids made for North Sea oilfield drilling application with oil-water-ratios (OWR) of 80/20 and 60/40. The structural character of the fluid samples was analyzed both at rest and dynamic conditions via flow and viscosity curves, amplitude sweep, frequency sweep, and time-dependent oscillatory sweep tests using a rheometer with a measuring system applying a grooved bob at atmospheric conditions. A high precision density meter was used to measure the density of the drilling fluid samples before and after each test. The measurement criteria used to rank the fluids stability include the yield stress as measured from flow curves and oscillatory tests, flow transition index, mechanical storage stability index, and dynamic sag index. We observed that between the two drilling fluids, the sample with OWR = 60/40 showed a stable dispersion with stronger network structure as evidenced by higher yield stress and flow transition index values, while the mechanical storage stability index and dynamic sag index recorded lower values. The results of this study enable drilling fluid engineers to design realistic oil-based drilling fluids with stable microstructure to mitigate settling and sagging of weight material particles for North Sea drilling operation

Leak Detection in Gas Mixture Pipelines under Transient Conditions Using Hammerstein Model and Adaptive Thresholds

Conventional leak detection techniques require improvements to detect small leakage (<10%) in gas mixture pipelines under transient conditions. The current study is aimed to detect leakage in gas mixture pipelines under pseudo-random boundary conditions with a zero percent false alarm rate (FAR). Pressure and mass flow rate signals at the pipeline inlet were used to estimate mass flow rate at the outlet under leak free conditions using Hammerstein model. These signals were further used to define adaptive thresholds to separate leakage from normal conditions. Unlike past studies, this work successfully detected leakage under transient conditions in an 80-km pipeline. The leakage detection performance of the proposed methodology was evaluated for several leak locations, varying leak sizes and, various signal to noise ratios (SNR). Leakage of 0.15 kg/s—3% of the nominal flow—was successfully detected under transient boundary conditions with a F-score of 99.7%. Hence, it can be concluded that the proposed methodology possesses a high potential to avoid false alarms and detect small leaks under transient conditions. In the future, the current methodology may be extended to locate and estimate the leakage point and size

Leak Detection in Gas Mixture Pipelines under Transient Conditions Using Hammerstein Model and Adaptive Thresholds

Conventional leak detection techniques require improvements to detect small leakage (&lt;10%) in gas mixture pipelines under transient conditions. The current study is aimed to detect leakage in gas mixture pipelines under pseudo-random boundary conditions with a zero percent false alarm rate (FAR). Pressure and mass flow rate signals at the pipeline inlet were used to estimate mass flow rate at the outlet under leak free conditions using Hammerstein model. These signals were further used to define adaptive thresholds to separate leakage from normal conditions. Unlike past studies, this work successfully detected leakage under transient conditions in an 80-km pipeline. The leakage detection performance of the proposed methodology was evaluated for several leak locations, varying leak sizes and, various signal to noise ratios (SNR). Leakage of 0.15 kg/s&mdash;3% of the nominal flow&mdash;was successfully detected under transient boundary conditions with a F-score of 99.7%. Hence, it can be concluded that the proposed methodology possesses a high potential to avoid false alarms and detect small leaks under transient conditions. In the future, the current methodology may be extended to locate and estimate the leakage point and size