Presence of natural fractures in sub-surface makes an oil well drilling operation very challenging. As one of the major functions of drilling mud is to maintain bottomhole pressure inside a wellbore to avoid any invasion of unwanted high-pressure influx (oil/gas/water), drilling a well through these fractures can cause severe mud loss into the formation and subsequent danger of compromising the wellbore pressure integrity. The aim of this paper is to carry out a Computational Fluid Dynamics (CFD) study of drilling fluid flow through natural fractures to improve comprehensive understanding of the flow in fractured media. The study was carried out by creating a three-dimensional steady-state CFD model using ANSYS (Fluent). For simplicity and validation purpose, the model defines fracture as an empty space between two circular disks. Moreover, it is considered that single-phase fluid is flowing through fractures. By solving the flow equations in the model, correlations to determine the fracture width and invasion radius have been developed for specific mud rheological properties. Prior to onset of drilling and at the end of lost circulation, similar correlations can be developed by knowing rheological properties of drilling fluid which will be very much helpful to take an instantaneous action during lost circulation, i.e., determining lost circulation material particle size and also be useful in the well development stage to determine the damaged area to be treated.

In the lubricated pipe flow (LPF) of heavy oils, a water annulus acts as a lubricant and separates the viscous oil from the pipe wall. The steady state position of the annular water layer is in the high shear region. Significantly, lower pumping energy input is required than if the viscous oil was transported alone. An important challenge to the general application of LPF technology is the lack of a reliable model to predict frictional pressure losses. Although a number of models have been proposed to date, most of these models are highly system specific. Developing a reliable model to predict pressure losses in LPF is an open challenge to the research community. The current chapter introduces the concept of water lubrication in transporting heavy oils and discusses the methodologies available for modeling the pressure drops. It also includes brief descriptions of most important pressure loss models, their limitations, and the scope of future works.

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Water-lubricated flow technology is an environmentally friendly and economically beneficial means of transporting unconventional viscous crudes. The current research was initiated to investigate an engineering model suitable to estimate the frictional pressure losses in water-lubricated pipelines as a function of design/operating parameters such as flow rates, water content, pipe size, and liquid properties. The available models were reviewed and critically assessed for this purpose. As the reliability of the existing models was not found to be satisfactory, a new two-parameter model was developed based on a phenomenological analysis of the dataset available in the open literature. The experimental conditions for these data included pipe sizes and oil viscosities in the ranges of 25–260 mm and 1220–26,500 mPa·s, respectively. A similar range of water equivalent Reynolds numbers corresponding to the investigated flow conditions was 103–106. The predictions of the new model agreed well with the experimental results. The respective values of the coefficient of determination (R2) and the root mean square error (RMSE) were 0.90 and 0.46. The current model is more refined, easy-to-use, and adaptable compared to other existing models.

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Absorption mass transfer coefficients (k_l a) of methane into two widely used drilling fluids base oils-internal olefins and diesel were determined. A laboratory-scale bubble column (0.0254m diameter and 0.71m static liquid height) was used to perform the experiments. Ranges of superficial gas velocity (0.0045-0.0491 m/s) and system pressure (100-300 psig) were covered. Based on the results, the effects of the varying parameters on k_l a have been discussed. Based on the observations, an empirical model for volumetric mass transfer coefficient as a function of superficial gas velocity and gas density was developed. This correlation fitted well (R² >0.98) with the measured k_L a values for the investigated range of operating conditions. This study gives new quantitative insights into the absorption kinetics of methane into two drilling fluid base oils, which are important for improving gas influx management with non-aqueous drilling fluids.

During the past decade, the increased use of Managed Pressure Drilling (MPD) equipment has significantly improved the safety and efficiency of gas influx management. However, it is still not clear to the industry what should be the safest and most effective pressure control method for removing gas influxes out of a riser. The objective of this study is to perform a systematic evaluation of different pressure control methods for riser gas handling, including the constant surface backpressure method, the constant riser bottom pressure method, and the fixed choke and constant outflow method. A transient multiphase flow simulator based on a Drift Flux Model was developed to simulate riser gas handling events in a Water Based Mud (WBM) system. Multiple sets of full-scale experimental data were used for the calibration and validation of the simulator. In the full-scale experiments, riser gas events were simulated by injecting gas into the bottom of an experimental well, followed by applying different pressure control methods. Besides conventional downhole and surface pressure and flow measurement instrumentations, a Distributed Fiber Optic Sensing (DFOS) system was used for the high-resolution monitoring of gas influxes in the annulus. The performance of different pressure control methods was evaluated based on the simulation results, including the behaviors of surface and riser bottom pressures, peak surface outflow rates, and the time required for riser gas handling. The numerical simulations carried out in this study can help better understand the different pressure control methods and improve the design of riser gas handling strategies.

During oil and gas drilling operations, formation gas (mostly methane) may enter the wellbore annulus or the drilling riser. This gas influx may get absorbed into the surrounding mud causing complexity for kick detection. Absorption mass transfer experiments of methane into four different fluid systems were performed. The continuous phase for all these fluids was Internal olefins (IO) which is widely used within the drilling industry as a base fluid. Two of the fluids were emulsions (Water as the second phase) and the other fluid comprised of Internal Olefins with Suspentone. Ultrahigh purity methane was used as the absorbing gas phase. The system pressure was kept at 100psi (0.689MPa) with a superficial velocity of 0.009 m/s. Volumetric mass transfer coefficients (kLa) from these experiments were individually determined using a bubble column with an internal diameter of 0.0381m. The volume of the liquid was kept constant during each of the tests. It was observed that methane in pure IO has the highest kLa value while its value is the lowest when it was flown through the IO/Water/suspentone fluid system. The reduction of kLa values was attributed to the increase of viscosity of the fluid and reduction of interfacial area of the IO due to the addition of water.