For efficient and safe well operations it is important to understand the behaviour of gas influx in petroleum fluids and the impact of relevant temperature and pressure changes in the well. Drilling simulators are tools for analysing gas kick detection limits, designing well control procedures, planning the chemicals and equipment needed on the rig, and generally for planning the well design. A major weakness in current models of kick detection is the lack of experimentally verified data in the HPHT region. The data from this study will be analysed and used as an input in a computational model of two phase gas-drilling fluid flow in the well, allowing better prediction of gas absorption.This study will provide experimental measurements under HPHT conditions for oil based drilling fluids (OBDFs) and base oils mixed with methane. As a part of the DrillWell centre program, SINTEF has developed an experimental setup for studying the effects of natural gas dissolved in drilling fluids under conditions relevant for HPHT drilling operations. In this setup we are able to measure density and rheological properties of drilling fluids with different degrees of methane saturation at pressures and temperatures of up to 1000 bar and 200°C.Base oils, the major constituent of OBDFs, contribute to the mud properties. Knowing the properties of the base oils at different pressure and temperature conditions enables assessment of the influence of the other components in the drilling fluid. In this paper we present measurements of a refined mineral base oil, especially designed for deepwater operations, and a linear paraffin oil. These base oils were tested for gas absorption capacity at various pressures and temperatures, and the effect of dissolved gas on the density of the base oils was measured. Experimentally determined saturation pressures show good correlation with predictions made with PVTsim for low gas-oil-ratios (GORs), however, at higher GOR-values the deviation is significant. The temperature influence on the saturation pressure is underestimated by PVTsim, demonstrating the need for more experimental data of drilling fluid behaviour at HPHT conditions. Furthermore, there was a clear difference in the maximum saturation pressure of the two base oils, which may be of high importance for the choice of drilling fluid at high reservoir pressures.In the continuation of this study we will perform measurements of methane solubility in two OBDFs composed of the two base oils studied in this work, respectively. Density and viscosity of mixtures of OBDF/CH 4 will be measured for various amounts of methane at pressures and temperatures ranging from standard ambient to HPHT. The resulting HPHT data will be highly important for improved calculation of bottom hole pressure and prediction of gas kicks.

Incidences with sag of solid weighting agents in drilling fluids can lead to potential drilling impediments including; loss of wellbore control, lost circulation, stuck pipe and high torque. 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. Separation of weighting materials in a non-moving fluid column is referred to as static sag while sag in a flowing fluid is normally referred to as dynamic sag. An approach to obtain static and dynamic barite sag measurement protocols is presented to examine the effects of rheological and viscoelastic properties of typical field oil-based drilling fluids on barite sag performance. Static sag results are computed based on modified Stokes settling theory while dynamic sag results are compared for rotational and oscillatory ultra-low to low shear conditions. For static sag measurements, an optical scanning analyzer, which is based on the principle of multiple light scattering was used to characterize the stability and particles settling speed of the drilling fluid samples. A cylindrical glass cell containing 20 mL of drilling fluid sample was scanned at the entire height of the sample for 7 days at 1-hour interval to acquire transmission and backscattering data every 40 μm. Under the dynamic sag measurements, a rheometer with a measuring system applying a cup and grooved bob was used to conduct rheological and viscoelastic measurements such as flow curves, oscillatory amplitude sweep, oscillatory frequency sweep, rotational and oscillatory time tests on the drilling fluid samples. The drilling fluid properties were characterized under atmospheric conditions before and after dynamic aging. The aging temperature and pressure conditions in the roller oven were 120°C and 100 psi respectively for a period of 2-1/2 days. A high precision density meter was used to measure the density of the drilling fluid samples before and after each test. Dynamic sag index (DSI) results were compared between time-dependent rotational shear test with shear rates from 10.22 to 0.001 s−1 and time-dependent oscillatory shear test with angular frequencies from 10.22 to 0.001 rad/s at constant strain amplitudes of 0.05% within linear viscoelastic (LVE) range and 100%, over a period of 10,800 s to closely compare to sag-prone conditions during drilling operations. We observed that heat-activated chemicals in the hot-rolled fluid sample increased the viscosity and elasticity which contributed to lower barite sag and longer suspension of particles than before hot rolling. Moreover, rotational shear test increased barite sag in the fluid sample more than oscillatory shear test, particularly for shear rates exceeding 1.0 s−1. Within the LVE range, oscillatory shear test did not disturb the position of the particles enough to promote sag in the fluid samples. The time-dependent oscillatory shear test can provide new insight on the structural character of drilling fluids to predict barite sag tendencies during the fluid design phase.

Summary In this paper, we present the results of barite sag measurements before and after hot-rolledoil-based drilling fluids (OBDFs) using different approaches for characterization. We characterized the barite sag of a liquid column under static condition using light-scattering (LS) measurements, hydrostatic pressure measurements, and gamma densitometry. Under the dynamic condition, we used a rheometer with a grooved bob-in-cup measuring system to characterize barite sag in rotational and oscillatory shear conditions. Extensive rheological characterization of the drilling fluid samples, before hot rolling (BHR) and after hot rolling (AHR), is carried out. It is found that barite sag decreased in hot-rolled fluid samples from the LS, rotational, and oscillatory shear measurements. The rheological characterization of the fluid samples showed that heat-activated chemicals in the hot-rolled fluid sample increased the viscosity and elasticity, which contributed to lower barite sag and longer suspension of particles than BHR. Both hydrostatic and gamma densitometry measurements reveal more or less uniform compaction of barite particles in the fluid sample below the liquid layer. Time-dependent oscillatory shear measurements provide new insights on the structural character of drilling fluids to predict barite sag tendencies during the fluid design phase.

In the present research paper modelling principles for the oil-water separation with special emphasis on the modelling of dense packed layer (DPL) is presented. Formation of the DPL is attributed to the difference between sedimentation rate and interfacial coalescence rate. Different sub-models resolving for the free sedimentation zone, the DPL, the binary coalescence and the interfacial coalescence are described. These submodels are implemented in commercial CFD software. Adequate validation and calibration of these submodels are necessary to be used for understanding the separation processes in industrial separators. Experiments for understanding the water in oil separation processes in a horizontal continuous separator were designed and carried out.Results from bottle and decay tests were used only for calibrating the model. CFD simulations using the calibrated model have served to understand the flow phenomena occurring inside the horizontal separator. The prediction of the model seems to be satisfactory except at higher emulsion flow rate and lower water cuts.

Details of the interaction between natural gas and oil in drilling fluids currently not taken into account, will in extreme cases be significant for the safety of drilling and well control operations. The paper describes such effects, in particular time dependence (kinetics) and compositional PVT with dense phase included. The importance of validation and tuning of PVT calculations, even when using state-of-art tools, is demonstrated by integrating new methods in a well control simulator. We consider sub-models for kinetics (time dependence of gas dissolution and boiling) and compositional PVT for the drilling fluid-natural gas mixture, and study different effects and assumptions numerically by integration in a well control simulator. Available laboratory data are used for model development and tuning of existing software. The dense phase may be important to consider in HPHT wells, where the conditions allow for the drilling fluid-gas mixture to exceed the critical point. This influences the gas absorption capability of the drilling fluid, as well as the density. The paper illustrates the impact of kinetics and improved PVT calculations through a sensitivity analysis using realistic well and fluid data. Two specific base-oils, a refined mineral oil and a linear paraffin, are used in combination with methane gas. The simulations show how kinetic effects can be important in some cases, both for early interpretation of a kick and for the response seen at surface as gas approaches and enters topside equipment. Furthermore, it demonstrates that dense phase effects can be significant, and that even state-of-art PVT software requires tuning when used with new combinations of oil-base fluids and hydrocarbon gases. Although the effects discussed are small compared to safety margins for many wells, ignorance may cause drilling teams to run into severe risks without knowing in advance for other wells. Combining advanced PVT models capable of representing dense phase behavior and a kinetics model with hydraulic flow modelling represents a leap forward in simulation of well control events. In addition, the importance of tuning adds valuable knowledge. These elements enable earlier detection and safer handling, thus increasing the safety on the rig.