Drilling high-pressure high-temperature (HPHT) wells requires a special fluid formulation that is capable of controlling the high pressure and is stable under the high downhole temperature. Barite-weighted fluids are common for such purpose because of the good properties of barite, its low cost, and its availability. However, solids settlement is a major problem encountered with this type of fluids, especially at elevated downhole temperatures. This phenomenon is known as barite sag, and it is encountered in vertical and directional wells under static or dynamic conditions leading to serious well control issues. This study aims to evaluate the use of barite-ilmenite mixture as a weighting agent to prevent solids sag in oil-based muds at elevated temperatures. Sag test was conducted under static conditions (vertical and inclined) at 350 °F and under dynamic conditions at 120 °F to determine the optimum ilmenite concentration. Afterward, a complete evaluation of the drilling fluid was performed by monitoring density, electrical stability, rheological and viscoelastic properties, and filtration performance to study the impact of adding ilmenite on drilling fluid performance. The results of this study showed that adding ilmenite reduces sag tendency, and only 40 wt.% ilmenite (from the total weighting material) was adequate to eliminate barite sag under both static and dynamic conditions with a sag factor of around 0.51. Adding ilmenite enhanced the rheological and viscoelastic properties and the suspension of solid particles in the drilling fluid, which confirmed sag test results. Adding ilmenite slightly increased the density of the drilling fluid, with a slight decrease in the electrical stability within the acceptable range of field applications. Moreover, a minor improvement in the filtration performance of the drilling fluid and filter cake sealing properties was observed with the combined weighting agent. The findings of this study provide a practical solution to the barite sag issue in oil-based fluids using a combination of barite and ilmenite powder as a weighting agent to drill HPHT oil and gas wells safely and efficiently with such type of fluids.

Barite sag is a serious problem encountered while drilling high-pressure/high-temperature (HPHT) wells. It occurs when barite particles separate from the base fluid leading to variations in drilling fluid density that may cause a serious well control issue. However, it occurs in vertical and inclined wells under both static and dynamic conditions. This study introduces a combined barite–ilmenite weighting material to prevent the barite sag problem in water-based drilling fluid. Different drilling fluid samples were prepared by adding different percentages of ilmenite (25, 50, and 75 wt.% from the total weight of the weighting agent) to the base drilling fluid (barite-weighted). Sag tendency of the drilling fluid samples was evaluated under static and dynamic conditions to determine the optimum concentration of ilmenite which was required to prevent the sag issue. A static sag test was conducted under both vertical and inclined conditions. The effect of adding ilmenite to the drilling fluid was evaluated by measuring fluid density and pH at room temperature, and rheological properties at 120 °F and 250 °F. Moreover, a filtration test was performed at 250 °F to study the impact of adding ilmenite on the drilling fluid filtration performance and sealing properties of the formed filter cake. The results of this study showed that adding ilmenite to barite-weighted drilling fluid increased fluid density and slightly reduced the pH within the acceptable pH range (9–11). Ilmenite maintained the rheology of the drilling fluid with a minimal drop in rheological properties due to the HPHT conditions, while a significant drop was observed for the base fluid (without ilmenite). Adding ilmenite to the base drilling fluid significantly reduced sag factor and 50 wt.% ilmenite was adequate to prevent solids sag in both dynamic and static conditions with sag factors of 0.33 and 0.51, respectively. Moreover, HPHT filtration results showed that adding ilmenite had no impact on filtration performance of the drilling fluid. The findings of this study show that the combined barite–ilmenite weighting material can be a good solution to prevent solids sag issues in water-based fluids; thus, drilling HPHT wells with such fluids would be safe and effective.

Weighting agents are mixed with the drilling mud to provide the high density required to control high-pressure high-temperature (HPHT) wells throughout the drilling operation. Solids sag occurs when the weighting agent separates from the liquid phase and settles down, causing variations in the drilling fluid density. This study evaluates barite–manganese tetroxide (Micromax) mixture to eliminate solids sag issue encountered with weighted invert emulsion drilling fluids at HPHT conditions. Micromax additive was added to barite-weighted fluids in different concentrations, 0, 15, and 30 wt% of the total weighting agent. Static and dynamic sag tests were used to evaluate the sag tendency of the new formulation under static and dynamic conditions. The performance of the new formulation was evaluated by measuring the electrical stability, density, rheological, viscoelastic, and filtration properties of the drilling fluid. The obtained results showed that Micromax additive improves drilling fluid stability by reducing the sag tendency. Adding only 30 wt% of Micromax additive eliminated barite sag issue in both dynamic and static conditions at 350 °F. 30 wt% Micromax increased the base fluid density by 5.4% and the yield point by 115% and maintained the gel strength value at 12 lb/100 ft², while it reduced the plastic viscosity by 30%. The addition of Micromax additive improved the viscoelastic properties of the drilling fluid by maintaining a higher storage modulus to the loss modulus ratio when compared with the barite sample (in the range 4–4.5). Furthermore, 30 wt% Micromax improved the filtration performance by reducing the filtrate volume, filter cake weight, and filter cake thickness by 50%.

Barite sag is a challenging phenomenon encountered in deep drilling with barite-weighted fluids and associated with fluid stability. It can take place in vertical and directional wells, whether in dynamic or static conditions. In this study, an anti-sagging urea-based additive was evaluated to enhance fluid stability and prevent solids sag in water-based fluids to be used in drilling, completion, and workover operations. A barite-weighted drilling fluid, with a density of 15 ppg, was used with the main drilling fluid additives. The ratio of the urea-based additive was varied in the range 0.25–3.0 vol.% of the total base fluid. The impact of this anti-sagging agent on the sag tendency was evaluated at 250 °F using vertical and inclined sag tests. The optimum concentration of the anti-sagging agent was determined for both vertical and inclined wells. The effect of the urea-additive on the drilling fluid rheology was investigated at low and high temperatures (80 °F and 250 °F). Furthermore, the impact of the urea-additive on the filtration performance of the drilling fluid was studied at 250 °F. Adding the urea-additive to the drilling fluid improved the stability of the drilling fluid, as indicated by a reduction in the sag factor. The optimum concentration of this additive was found to be 0.5–1.0 vol.% of the base fluid. This concentration was enough to prevent barite sag in both vertical and inclined conditions at 250 °F, with a sag factor of around 0.5. For the optimum concentration, the yield point and gel strength (after 10 s) were improved by around 50% and 45%, respectively, while both the plastic viscosity and gel strength (after 10 min) were maintained at the desired levels. Moreover, the anti-sagging agent has no impact on drilling fluid density, pH, or filtration performance.

Fine, small-size, drilled cuttings, if not properly separated using mud conditioning equipment at the surface, are circulated with the drilling fluid from the surface to the bottom hole. These drilled cuttings have a significant effect on the drilling fluid properties and filter cake structure. During drilling long lateral sandstone formations, different cuttings with varied properties will be generated due to sandstone formations being heterogeneous and having different mineralogical compositions. Thus, the impact of these cuttings on the drilling fluid and filter cake properties will be different based on their mineralogy. In this paper, the effect of different sandstone formation cuttings, including arenite (quartz rich), calcareous (calcite rich), argillaceous (clay rich), and ferruginous (iron rich) sandstones, on the filter cake and drilling fluid properties was investigated. Cuttings of the mentioned sandstone formations were mixed with the drilling fluid to address the effect of these minerals on the filter cake thickness, porosity, and permeability. In addition, the effect of different sandstone formation cuttings on drilling fluid density and rheology, apparent viscosity (AV), plastic viscosity PV), and yield point (YP) was investigated. High-pressure high-temperature (HPHT) fluid loss test was conducted to form the filter cake. The core sample’s petrophysical properties were determined using X-ray fluorescence (XRF) and X-ray diffraction (XRD) techniques and scanning electron microscopy (SEM). The results of this work indicated that all cutting types increased the rheological properties when added to the drilling fluid at the same loadings but the argillaceous sandstone (clay rich) has a dominant effect compared to the other types because the higher clay content enhanced the rheology. From the filter cake point of view, the ferruginous sandstone improved the filter cake sealing properties and reduced its thickness, while the argillaceous cuttings degraded the filter cake porosity and permeability and allowed the finer cuttings to penetrate deeply in the filter medium.