Horizontal stress magnitudes are determined from dynamic elastic moduli, effective vertical stress and a wellbore stress model using nonlinear elasticity in rock formations with medium to high porosity (15 to 40%). Full-waveform borehole acoustic waves (flexural and Stoneley) and the near-wellbore stress distribution are used to estimate the third-order elastic constants required to relate changes in the far-field shear moduli to changes in stress magnitudes. A case study from offshore Malaysia has been completed in which the results indicated a normal stress regime and horizontal stress anisotropy of 8 to 12%. Estimates of the σh are consistent with the LOT data and the formations did not show any borehole breakout, yet σHwas found to be greater than σh min. The third-order elastic constants c144 and c155 were found to be consistent with laboratory values in the published literature. Stress-velocity relationships using these results are shown to be suitable for analysis of stress path effects for time-lapse seismic surveys.
It has become a standard practice within the petroleum industry to construct wellbore geomechanical models for applications such as designing safe mud windows for drilling, predicting sand production and designing stimulation treatments in the form of hydraulic fracturing. A particular need is better quantifying of geomechanical properties, i.e. the in-situ stress field, pore pressure, material properties (elastic, yield or quasibrittle failure, hardness, rock-fluid sensitivity), their anisotropic nature and their spatial heterogeneities, as well as the presence of discontinuities (such as natural fractures or geological layering). With the evolution of the unconventional resource market, much advancement has been made to quantify the impact of layering anisotropy within shale rocks for stimulation design (Higgins et al. 2008, Prioul et al. 2011).
It is known that in many offshore environments where deepwater exploration is increasing, linear elasticity is not always sufficient as a constitutive law (e.g. stress-sensitive high porosity rocks), yet simple empirical stress models (Eaton 1969, Matthews & Kelley 1967) are still being used today. Even though these models are robust and require only limited input data, they do not account for unbalanced tectonic stress or formation anisotropy. Case studies have shown that these two factors should be considered; otherwise, well integrity issues may arise (Kozlowski et al. 2011). The minimum horizontal stress can be determined through extended leak-off tests or mini-fracs. In deepwellbores the maximum horizontal stress is difficult to measure directly, and therefore borehole failure models have been traditionally employed to determine its magnitude. However, within most offshore wells, synthetic oil-based mud systems are commonly used, resulting in fewer observations of wellbore failure. Furthermore, in formations that are considered nonelastic, these failure models are not applicable (Zoback et al. 1985).
