Wellbore Stability Modelling

When a well is drilled in a formation, stressed solid material is removed and replaced with a fluid under pressure. Whilst rock can support shear and normal stresses, the mud is unable to support shear stress, which leads to a redistribution of the in situ stresses and an alteration in the stress state of the formation around the well. Elastic theory is used to evaluate the well pressure at which shear failure (collapse/breakout) will initiate at the borehole wall. Initial shear failure within a layer occurs when a low mud pressure creates a large enough stress differential between the maximum principal stress and the minimum principal stress to exceed the failure criterion for that layer.

A simplified approach to wellbore stability involves using poro-elastic analysis to compute stress states around the wellbore. These stresses are then compared with a failure criterion. In many instances (but not all) results are found to be somewhat pessimistic in predicting the onset of shear failure (collapse/breakout) around a well, particularly when considering stability and minimum mud weights during overbalanced drilling. Under such situations, the presence of a mud cake can maintain hole stability, so that although the borehole wall may have undergone limited yield there may not be any significant or observable instability. Similarly, the non-linear nature of rocks means that the stresses at the wellbore, computed using linear elasticity, may slightly exceed those which occur in reality.

The concept of the “safe” mud window is illustrated below:

The lower limit of the mud weight window is defined by the pore pressure gradient. The mud weight must be higher than the pore pressure to avoid a “kick”. When the mud weight is too low to balance the effective stress acting on the formation, shear failure will occur, which manifests as wellbore breakout. If the mud weight is raised too high, mud “losses” will occur. In intact formations the upper limit of the mud weight window is defined by the fracture gradient.

The fracture gradient is calculated by evaluating the stress concentration at the wellbore wall and evaluating when it will overcome the formation tensile strength. It will generally be significantly higher than the minimum in-situ stress. Should the mud weight be raised above the fracture gradient, fractures will be initiated and the formation will take losses. The safe mud weight window for a particular formation will depend on the rock mechanical properties, the stress, pore pressure and the well trajectory.

To discuss any requirement for wellbore stability modelling, please contact lynne@rockmohr.com

Determining Rock Strength

In geomechanical modelling, rock strength refers to the ability of the rock to withstand the in-situ stress environment around the wellbore or perforation cavity. A rock strength model is developed using log based models calibrated with core data where available.  This allows a continuous, foot-by-foot, rock strength prediction model to be developed.

Core Data:

The following rock property data are typically required to populate geomechanical and sanding evaluation models:

  • Unconfined Compressive Strength (UCS)
  • Thick Wall Cylinder Strength (TWC)
  • Cohesive strength
  • Friction angle
  • Static Young’s modulus
  • Static Poisson’s ratio
  • Biot poro-elastic factor

Definitive data are only available from rock mechanics tests on core.  However, core is discontinuous and rock strength data coverage is inherently limited, hence rock strength evaluation is normally based on log indicators calibrated where possible against viable core data. Where core is not available, reliance is placed on uncalibrated log based strength models which increases uncertainty in the analysis.

Log Strength Modelling:

There are a number of published log-core strength correlations that can be used to develop a continuous rock strength model.  These tend to be constrained by log data availability.  Most log models involve correlations between unconfined compressive strength (UCS) and logs which are sensitive to rock strength variations, particularly sonic (DTC and/or DTS), density (RHOB) and porosity (PHIT and PHIE). 

The principal requirement for a log-derived model is that it should provide an accurate description of rock strength in uncored (or unsampled) intervals and wells.

RockMohr Ltd will design a rock test specification document and work with the selected laboratory to ensure fit-for-purpose data for geomechanical modelling.  Strength models can then be built for use in sand failure analysis, wellbore stability or for other geomechanical analysis.

An Introduction to Log Based Pore Pressure Modelling

As sediments are buried to greater and greater depth, the weight of the overlying rocks increases and the increasing stress acting at the grain contacts leads to rearrangement of the grains, resulting in lower porosity. If the rate of sedimentation exceeds the rate at which fluid can be expelled from the pore space, or if dewatering is inhibited by the formation of seals during burial, the pore fluid becomes overpressured and thus supports part of the overburden load. Overpressure generated in this way is said to result from disequilibrium compaction or undercompaction, this being the most common mechanism for generating overpressure in deepwater sediments. 

Log based methodologies for pore pressure estimation are only relevant where overpressure has developed through disequilibrium compaction in shale/clay sequences. Compaction represents a reduction in porosity with increasing depth, and will produce a linear relationship on a logarithmic plot of porosity versus depth. Under normal compaction, porosity is reduced at the same time as pore fluid is expelled.

The workflow to perform log based pore pressure analysis includes: determination of the overburden gradient (OBG), discrimination of shale intervals, definition of a normal compaction trend to allow identification of compaction anomalies, pore pressure analysis calibrated where possible to measured data or well response, fracture gradient (FG) analysis.

For any PPFG enquiries, please contact me at lynne@rockmohr.com