Petroleum Reservoir Geo-mechanics
1. To what extent, whether the common assumption of principal stress falling in the vertical plane - with other two stresses falling in the horizontal plane – would remain to be justified - in a reservoir - that has undergone – ‘strong structural deformation’ such as folding/salt-diapirism?
Feasible to capture ‘stress arching’ (non-homogeneous stress distributions) in such circumstances?
Do we still require a relatively complex tectonic fabric and stress history analysis (folds, lateral deformation history, faults) in order to determine the principal stress directions and their relative magnitudes?
OR
ML/AI has a role to play with in deducing the magnitude and directions of stresses?
OR
Do we have a well-developed ‘stress measurement methods’ that could be used repeatedly during ‘reservoir development’?
OR
Whether the deconvolution of changes in velocities and amplitudes over time in cases with changes in pressure or temperature – have really been useful – so far – in ‘successfully’ estimating stress changes or fabric changes (dilation and de-cementation) – towards calibrating THM models?
2. Although, reservoirs such as ‘North Sea Chalk’ and ‘California Diatomite’ with high-porosity materials; and ‘rocks such as intensely fractured granites or vesicular basalts’ – represent only a small fraction of world’s petroleum resources; whether ‘reservoir geo-mechanics’ is given due weightage - ‘every time, explicitly’ - during characterization
(apart from the focus on stress evolution; sand production management; hydraulic fracturing; borehole stability; casing shear; subsidence; & thermal stimulation – involving THMC coupling)
of either ‘unconsolidated sandstones’; or, ‘naturally fractured carbonate reservoirs’, which correspond to over 70% of world’s liquid petroleum reservoirs (including conventional oil), which essentially remain associated with
(a) viscous or immobile oils;
(b) higher temperatures, pressures and depth; and
(c) ‘reservoir materials that are weak, intensely fractured, or highly compressible’?
3. To what extent, the “passive or indirect” inference of ‘scalar state properties’ (pressure, temperature, porosity); and ‘material properties’ (transport properties, strength & deformability) using correlations to ‘strain wave properties’; ‘geophysical log responses’; ‘index tests’; and ‘responses to in-situ flow or fracture tests’ – as against the direct ‘in-situ measurements’ or ‘core measurements’ – really dilute the geo-mechanical behavior of a petroleum reservoir?
4. While coring a specimen from increased depths (3 – 5 km) and stresses (40 – 70 MPa), there will be unavoidable micro-damage resulting from differential strains either @ grain- or @ crystal-scale, which damage the core ‘irreversibly’ and subsequently affecting the mechanical properties.
Is there an improved way to address the quality of core sample considering the issues of heterogeneity, scale and representativeness?
In active compressional and strike/ slip tectonic regimes the assumption that the vertical stress is Sigma 1 is not valid. In an active compressional regime Sigma 3 is vertical and in an active strike/slip regime Sigma 2 is vertical.
With respect to measuring the stress magnitude: in the oil industry Sigma 3 is measured on a routine basis when during the drilling of a well the casing shoe strength is measured with a Leak-off test. Vertical stress is calculated by integrating density log values from the surface to TD of a well.