Effect of Salinity on the Viscosity of Water Based Drilling Fluids at Elevated Pressures and Temperatures
Authors: Amani Mahmood , Khorasani Mohammad Hassan Mohammad , Ghamary Mohammad Hossein 
Published: July 2019

Due to the continued growth in hydrocarbon demand, operators in the oil and gas industry are always looking to drill deeper wells in order to access previously unattainable hydrocarbons. High-Pressure High-Temperature (HPHT) wells are now broadly present in places like the Gulf of Mexico, the North Sea, and the Middle East. At such conditions, the effect of salts on the properties and performance of water-based drilling fluids cannot be reliably extrapolated from moderate conditions.

Oil and gas wells are referred to as HPHT wells if their bottomhole conditions are greater than 300°F (150°C) or 10,000 psi (69 MPa). As drillers get into HPHT formations, a number of unique problems are introduced. Well control, for example, becomes more complicated due to narrow pressure margins and higher bottomhole pressures and temperatures.

As a result, this research aimed to test and investigate the rheological behavior of various water-based drilling fluids with a variety of different salinities at HPHT conditions using a state-of-the-art HPHT viscometer. The main equipment for these experiments is CHANDLER Model 7600 High Pressure High Temperature Viscometer. There are only 8 such equipment that exists in the whole world and our university in Qatar has one of them. Working on this experimental research will train the participating students to use one-of-a-kind high end viscometers in the world. The parameters that are gauged in this experiment are viscosity, yield point and gel strength of the drilling fluid when subjected to these conditions. To model this experiment, water based muds of varying salinity were experimented with two different types of salts – NaCl and CaCl2. Also, two percentages, 15 and 25, of each of these two salts are proposed to be used in formulating the water-based fluid samples which corresponds to approximately 9.3 and 10.0 ppg. 25? concentration of NaCl will result in full saturation of the water-based fluid system and thus this percentage represents a maximum value. 15? concentration, however, can represent a middle value between the maximum concentration (25?) and the minimum (0?). Overall, the results attained in this experiment were useful in coming to several conclusions regarding the effects of salinity on the rheological properties of water-based mud. As shown in Fig. 4, the average dial reading increases with the set pressure. It levels off at a maximum pressure of 18,000 psi and then decreases. This was the case for all the samples apart from the CaCl2 at 25?. Salinity is the total of all non- carbonate salts dissolve in water, unlike chloride concentration that represented only by its content. Therefore, the summation of all the salts in the mud can be expressed by salinity. Amani and Hassiba (2012) performed HPHT tests on water-based drilling fluids containing different concentrations of Sodium and Potassium Chloride (NaCl and KCl). They showed that the fluids with these salts followed the Power Law model up to pressures of 20,000 psi. Above that pressure, the shear rate started to vary linearly with shear stress (best modeled by the Bingham Plastic equation). In the presence of different kinds of salt additives to initially increase the weight of the mud, the junction to the point of separation between water and other solids creates and breaks the stable suspension and produces flocculation.

Therefore, at the end it will decrease the viscosity of the mud. Up to some extent, modified starches becomes anionic and free in hydrated water. The flow properties of the drilling fluid must be controlled so that the fluid can function properly. Properties of the fluid such as the plastic viscosity and the yield stress are very important for the success of the rotary-drilling operations and are therefore constantly measured. Viscosity is the measure of a fluid's resistance to flow and is defined as the ratio of shear stress to shear rate. Newtonian fluids are fluids where the proportionality between the shear stress and the shear rate is independent of the shear rate. Newtonian fluids are usually water or fluids with low molecular weight material. However, most drilling fluids are non-Newtonian and experience shear thinning with increased shear rate as shown in Fig. 20. The Bingham plastic and the power law rheological models are non-Newtonian models that were used in the past and are still used today to approximate the behavior of drilling fluids and cement slurries. The majority of the behavioral models for drilling fluids and cement slurries used today include a yield stress. One of these rheological models that fits this kind of behavior at both high and low shear rates is the Herschel-Bulkley model.

The mud was found to start losing its intrinsic properties at 24,000 psi and the concentration of Calcium Chloride was found to have a more profound impact on the rheology than Sodium Chloride. Out of the used rheological models, Herschel-Bulkley had the best fit and could be used to predict the viscosity. Although the cost of calcium chloride is more than sodium chloride per unit, it is still feasible to use this salt as it has a profound effect on the shear stress and other rheological properties of the fluids. In future iterations of this experiment it would perhaps be more useful to record more data points for the salinity level. Observing the results for more salt concentration levels will give a clearer picture of the effect of salinity on the rheological properties of the fluids. Acknowledgement: “This report was made possible by a UREP award [UREP 13-031-2-014] from the Qatar National Research Fund (a member of The Qatar Foundation). The statements made herein are solely the responsibility of the author.”