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Well abandonment is one of the biggest challenges in the oil and gas industry, both in terms of cost and effort as well as the technical hurdles associated with wellbore isolation for an indefinite term. A mechanism that may be exploited to simplify well abandonments is using natural shale formations for the creation of annular barriers. Currently, uncemented annuli often require casing milling and pulling before abandonment plugs can be set, which necessitates the use of a drilling rig. This is an expensive, time- and labor-intensive process, particularly offshore. However, shale creep may naturally form a barrier behind uncemented casing sections. With a qualified annular shale barrier in place, the well may only require the setting of abandonment plugs within the existing casing string(s), a task that can often be done rigless and with significantly less effort. The work described in this paper presents the results of a rock mechanical investigation into the creep behavior of North Sea shales and their ability to form effective annular barriers. Field core from the Lark-Horda shale was used to conduct dedicated, customized experiments that simulated the behavior of shale confined under downhole effective stress, pressure and temperature conditions to fill in an annular space behind a simulated casing string. Full scale tri-axial rock mechanics equipment was used for testing cylindrical shale samples obtained from well-preserved field core in a set-up that mimicked an uncemented casing section of a well. The deformation behavior of the shale was monitored for days to weeks, and the formation of the annular barrier was characterized using dedicated strain measurements and pressure pulse decay probing of the annular space. The large-scale lab results clearly show that the Lark-Horda shales will form competent low permeability annular barriers when left uncemented, as confirmed using pressure-pulse decay measurements. They also show that experimental conditions influence the rate of barrier formation: higher effective stress, higher temperature and beneficial manipulation of the annular fluid chemistry all have a significant effect. This then opens up the possibility of activating shale formations that do not naturally create barriers by themselves into forming them, e.g. by exposing them to low annular pressure, elevated temperature, different annular fluid chemistry, or a combination. The results are in very good agreement with field observations reported earlier by several North Sea operators.

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 mode...

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