Abstract

Selecting a drilling fluid from the learnings from conventional reservoirs can be a wrong choice when it is used for unconventional formations. Drilling fluid has a chemo-mechanical effect on the reservoir rock during exposure time; this interaction can be abrupt or imperceptible depending on minerals comprising the rock matrix and their chemical sensitivity to the fluid composition. Improper selection of drilling fluid may cause strong shale-fluid interaction and thus result in wellbore instability. This paper presents a comprehensive experimental study examining the effect of various drilling fluids on the mechanical properties of conventional and unconventional rock samples.

Four drilling fluids with varying additives are selected to contact and saturate rock samples at the temperature of 230°F for 16 or 24 hours: Three of them are water-based muds (WBM) and the other one is an oil-based mud (OBM). Rock samples used are from the Berea sandstone, Mancos and Eagle Ford shale formations. For each type of rock, one plug is tested without contacting any drilling fluid and is used as a reference of geomechanical properties. Other samples are contacted and saturated with other drilling fluids before their geomechanical testing. A fluid-saturating process is conducted at a pressurized aging cell. Mechanical testing is performed in a servo-controlled triaxial apparatus in which samples are deformed at a constant confining pressure of 10 MPa and the drained condition.

Experimental results show that drilling fluids have a negligible effect on the peak strength and Young's moduli of Berea sandstone. However, the peak strength of Mancos shales decreases dramatically while their Young's moduli change randomly. For Eagle Ford shales, fluids reduce both peak strength and Young's moduli. For all samples tested, their Poisson's ratios increase after samples are saturated with fluids. Compared to WBM, it is observed that OBM preserves the mechanical properties of Mancos shales much better. After optimizing the design of one high-performance water-based mud (HPWBM1), the new fluid (HPWBM2) has an improved performance (similar to OBM) in preserving shale geomechanical properties.

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