Wellbore strengthening (WBS) offers enabling technology for wells that are drilled in geological environments with a narrow drilling margin. Through its deployment, costly lost circulation events may be avoided, casing setting depths may be extended, and, in optimum cases, deeper targets may be reached with a reduced or slimmed-down casing program.

The elevation of the fracture gradient offered by WBS is a complex issue that involves the growth of fractures in permeable or impermeable rocks using non-Newtonian drilling fluids that are laden with solids of varying types and sizes. Several plausible (and sometimes contradictory) models have been proposed historically to explain the WBS phenomenon, and the only way to assess the correct explanation is through dedicated experimentation. In this paper, an experimental technique to study WBS under realistic conditions is introduced, and the results of a series of larger-scale fracturing experiments using this technique are presented.

The experimental set-up described here consists of a dual flow-loop/ pressure-intensifying system to carry out high-pressure borehole fracturing tests on cylindrical rock samples while maintaining continuous circulation of the drilling fluid within the borehole. The system offers full control over pore pressure, radial confining pressure and, if desired, independent axial pressure. Several injection cycles are performed to characterize the values of the fracture initiation pressure (FIP) and fracture propagation pressure (FPP) and thereby characterize WBS effects. Typical experimental variables included: the type of base fluid (water-based, oil- or synthetic-based), the concentration, type, and particle size distribution (PSD) of lost circulation materials (LCMs) used to achieve WBS effects, and the type of rock tested (sandstone and shale, i.e. permeable and impermeable rock media). Additionally, post-fracturing techniques such as thin-section analysis were employed to study the fracture geometry and deposition structure of plugging solids on the fracture surfaces.

The experiments clearly show that for any rock with a given set of rock strength and failure parameters, there is an optimum PSD for maximizing WBS effects. Optimum PSD appears to be of primary importance, almost irrespective of LCM type. The results furthermore show that although a minimum concentration of LCM bridging agents is required for effective WBS, FPP does not increase significantly for concentrations above a certain upper threshold value. Moreover, increasing the injection volume during WBS squeeze treatments above a threshold value may actually lead to lower FPP values. All of these findings have important implications for field application of WBS treatments. In addition, petrographic imaging of the fracture after testing show that fracture plugging occurs in the proximity of the fracture tip and not close to wellbore face, in direct support of the Fracture Propagation Resistance (FPR) model of WBS, and in disagreement with Wellbore Stress Augmentation/ Stress Cage models.

The results not only confirm information from previous investigations, but also provide new insight into effective ways to strengthen wellbores in various formations. The experimental results are directly applicable to improve well construction and to minimize non-productive time on narrow drilling-margin wells such as (ultra-) deep-water wells by selecting the appropriate mud formulations, LCM materials and their concentrations, as well as application treatments.

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