Experimental analysis of the effect of magnesium saltwater influx on the behaviour of drilling fluids
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This paper presents an experimental analysis of drilling fluid at elevated temperatures with and without magnesium saltwater influx in order to determine how these fluids behave when encountering the influx of salinity formation water. Salt contamination can come from drilling salt beds, or from a formation water influx. Salt water which contains magnesium chloride was added systematically to the formulated mud systems in order to evaluate its effects on the drilling fluid at elevated temperature conditions. It was observed that rheological changes in drilling fluids due to influx of magnesium salts have many effects on the degree of efficiency at which the drilling fluid performs its primary functions. From the analysis, it was observed that small quantities of magnesium saltwater can be removed with caustic soda but the large quantities are detrimental to rheological properties of drilling muds used in Niger formation.
KeywordsDrilling fluid Saltwater Weighting agent Temperature
High temperature high pressure
Electrical stability (volts)
Yield point (lb/100 sq. ft)
Drilling fluids are either water based or oil based. These fluids are made up of a base fluid, water or diesel (hydrocarbon), weighting agents and other additives that aid in removing the cuttings from the wells and keep the mud in a fluid state (Alotaibi et al. 2010). The behaviour of the drilling fluids under high temperature and high pressure is extremely important for drilling deep wells. At temperatures higher than 200 °F (94 °C), the hydroxyl-ion/clay interaction occurs at rates sufficient to change the rheological behaviour of the fluid (Darley and Generes 1956; Sydansk 1983). During the circulation downhole and back to the surface, the mud picks up contaminants (extraneous materials not present when the fluid was originally formulated). Drill solids, cement, and salts are common contaminants. At low temperatures, the mud may be able to tolerate the contaminants, but at elevated temperatures, remedial measures are often necessary. The savings in time, money and manpower are obvious to engineers, drilling managers, and laboratory personnel accustomed to waiting out the tedious weeks required for conventional bomb methods. Moreover, comparisons with conventional methods indicate two further superior features of this new circulation system: mud and mud components stabilize more completely; and laboratory muds thus produced more accurately represent good field muds produced after extended high temperature drilling (Reece 1975). Problems associated with drilling fluids normally occur downhole, so it is reasonable to be interested in the properties of drilling fluids at the conditions which exist downhole. While the general practice is to measure drilling fluid density and rheological parameters at the surface, and use these parameters to estimate pressures in the wellbore, several authors have studied the effects of pressure and temperature on the rheological and density of drilling fluids. This is because many studies have shown that estimated pressure losses using surface properties do not match the actual pressure losses measured in the fluid (Zamora 1996; White et al. 1996; Davison et al. 1999). McLean et al. (1967) showed that the rheological properties of a mud under downhole conditions are very important to cementing operations. Burkhardt (1961) showed that a knowledge of rheological properties of muds under downhole conditions is necessary to predict pressure surges. De Wolf et al. (1983) reported a close correlation of the results from their study of less toxic oils to the Herschel–Bulkley model. It was also observed that the magnitude of viscosity difference between oils tends to decrease with temperature in spite of pressure indicating that temperature was the more dominant factor. Hiller (1963) and Annis (1967) studied the effects of high temperatures (up to 150 °C) and pressures (up to 500 bar) on the rheology of water-base mud, and concluded that high temperature caused flocculation of the bentonite mud. Rommetveit and Bjørkevoll (1997)conducted laboratory measurements and concluded that rheology is pressure and temperature dependent. Sinha (1970) investigated water-based clay suspensions as well as oil-base muds using a falling bob consistometer concluding that the equivalent viscosity of WBM is not affected to the same extent by the variations of temperature and pressure. He also concluded that the temperature is the dominating variable in the case of WBM. Much has been written on how various electrolytes affect rheological proper ties at room temperature (Hauser and Reed 1937; Street 1958; Garrison and Tep Brink 1939; Browning and Perricone 1963). The solid fraction of a mud usually causes the most significant, and certainly the most unpredictable, changes in mud properties at elevated temperature. Different types of solids have different shapes, sizes and surface charges; hence, they behave differently when suspended in a liquid and subjected to elevated temperatures (Annis 1967). Improperly formulated and maintained drilling fluid systems can cause significant near-wellbore formation damage and create potential for the plugging of screens and slotted liners (Pitoni et al. 1999). Rheological changes in drilling fluids have many effects on the degree of efficiency with which a fluid performs its primary functions. Many researchers have worked on the effects of temperature and pressure on the drilling fluid but none of them has ever researched on the effect of magnesium saltwater on the drilling fluid performance. However, the major effect of magnesium is to react with hydroxyls in the mud system, thus depleting mud alkalinity and pH. This can in turn allow the undesirable carbonate and bicarbonate components of alkalinity to become dominant. Small quantities of magnesium such as those present in saltwater can be readily removed with additions of caustic soda. When large quantities of magnesium are encountered (magnesium shale, evaporates or brine flow), it is not practical to treat out the contaminant. The paper focuses on the effect of magnesium saltwater influx on the performance of drilling fluid at elevated temperature in order to know how the fluid reacts in a downhole conditions.
Laboratory mud formulation
The main objective in testing the laboratory-formulated drilling fluids was to compare oil mixed with water, emulsifier, viscosifiers and other additives with different weighting agents, barite (Barium Sulphate) which has density of 4.5 and SG of 35 ppg, and hematite (Iron Oxide) which has density of 5.3 and SG of 44.15 ppg and ferrobar (combination of barite and hematite) in order to evaluate their performance in a downhole condition. The formulated muds in this study consist of diesel oil and water at a ratio of 75/25. OBM are composed of brine droplet in an organic phase (base oil). The continuous phase and suspending medium for solids (or liquid) is a water immiscible fluid that is oil-based. The presence of emulsifier and co-emulsifier such as VERSAMUL and VERSACOAT is necessary to ensure a good stability of the emulsion, HPHT filtration control and also to reduce the effects of water contamination. Depending on the formulation, different additives that may be present among them are viscosifying agents such as VERSAGEL HT (amine-treated, pure hectorite clay used as the primary viscosifier in invert emulsion drilling fluid systems), lime in order to control mud alkalinity, filtrate reducers, wetting agent to ensure mud homogeneity. Rheological properties of the base oil were measured and correlated with the mud properties. This was used to determine the influence of the nature of the based oil and of the type of additives present in the formulation. Three samples of formulated mud were used as Sample A containing all the above-listed composition with ferrobar as weighting agent, Sample B containing barite and Sample C containing hematite to regulate mud density. Mud mixer was used to mix the three portions of mud samples to ensure homogeneous mixture. For the purpose of the following tests, a high-temperature/high-pressure rotational viscometer was used. This viscometer was capable of measuring drilling fluids properties from ambient to 500 °F at gauge pressures from 0 to 12,000 psi. The mud properties were measured before aging at 120 °F at a pressure of 500 psi and aged at 400 and 500 °F at 10,000 and 12,000 psi for 16 h at dynamic condition and the rheological properties were taken at 120 °F after aging. The filtrates were run for 30 min upon which the volume of filtrate was recorded and the filter cake thickness was measured. These viscometers have rotation speeds (600, 300, 200, 100, 60, 30 and 3 rpm) as recommended by API to measure the rheological properties of drilling mud samples. The laboratory experiment was carried out in phases with the mud volume of 350 cm3. In the first phase of testing, no salt water was introduced and temperature was taken at 120 °F and aged at 400 and 500 °F and the rheological properties of these fluids were determined at 120 °F for the three different mud formulations. The second phase was carried out in similar manner but with the addition of 30 ml of salt water (which contains magnesium salt water, MgCl2) to the same volume specified above to evaluate its effects on the rheological properties of these fluids.
To study which of the drilling fluids will perform best when there is magnesium saltwater influx.
To study drilling fluid flow behaviour at low and high temperatures.
To study the effect of magnesium saltwater influx on commonly used drilling fluid at elevated temperatures.
To determine effectiveness, temperature stability and overall characteristics of mud components to mimic downhole conditions.
Analysis of results
Effect of temperature on the drilling mud
Effect of salt on drilling mud
It is very important to know precisely the temperature evolution of the drilling mud during the different drilling and circulation stop.
From the research carried out, it was observed that increase in temperature reduces the stability and viability of drilling fluid.
It is revealed that at temperature above 400 °F, ferrobar, barite and hematite fluids lack important rheological properties.
Considering the thermal degradation effect on the three muds, we can conclude that ferrobar maintains its effectiveness to flow at temperature above 500 °F.
The authors would like to thank all the staff of Mi-SWACO, Port Harcourt Nigeria for their technical support and the resources made available during the experimental work of this research.
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