Page 220 - Reservoir Geomechanics

201 Compressive and tensile failures in vertical wells

similar in the two cases and, in fact, quite similar to the shape of breakouts predicted
using the elastic stress concentration predicted by the Kirsch equations (Figures 6.3 and
6.5). The similarity of these calculations might bring into question the value of using a
more complicated theory and analysis method to assess wellbore failure. This said, it is
important to recognize that the true value of this methodology is in addressing problems
such as sand production and wellbore failure when drilling in extremely weak and/or
plastic formations. In such cases, it would be inappropriate to use an elastic analysis
and the strength of materials approach in assessing wellbore failure.
The principal drawback of utilizing numerical methods with a total plastic strain
failure criterion (such as that illustrated in Figure 6.17a) is that the strain at which failure
occurs needs to be determined empirically, although it is argued that estimates of the
strain at failure can be guided by thick-walled hollow cylinder tests on core samples.
Such tests involve axially loading a rock cylinder with an axial hole until sand is noted
and assuming the strain at which sanding is noted will be approximately the same in
situ as in the lab. Nonetheless, there are 50 years of laboratory tests characterizing
failure as a function of stress in moderately strong sedimentary rocks (i.e. rocks with
cemented grains) and there is relatively little knowledge of how to express failure as a
function of strain for applications such as wellbore stability during drilling.

Chemical effects

Chemical interactions between drilling mud and clay-rich (shaley) rocks can affect
rock strength and local pore pressure and thus exacerbate wellbore failure. While the
utilization of oil-based muds can mitigate such problems, it can be very expensive to
implement or precluded by regulatory restrictions. In the context of the theory described
by Mody and Hale (1993), there are three important factors that affect wellbore stability
when chemical effects may be important: First is the relative salinity of the drilling mud
in relation to the formation pore fluid. This is expressed as the water activity A m , which
is inversely proportional to salinity. If the activity of the mud is greater than that of the
formation fluid (A w ), osmosis will cause the formation pore pressure to increase and
the wellbore to be more unstable. Simply put, osmotic pressures cause the movement of
the less saline fluid toward the more saline fluid. Second, the change in pore pressure is
limited by the membrane efficiency, which describes how easily ions can pass from the
drilling mud into the formation. The concept of osmotic pressure differentials impacting
wellbore stability is most easily understood when using water-based drilling muds. As
oil has perfect membrane efficiency, it prevents ion exchange and utilization of oil-based
mud is usually considered as a means to obviate this effect. However, Rojas, Clark et al.
(2006)have shown that if oil-based mud incorporates emulsified water, it is still impor-
tant to optimize the salinity of the drilling fluid to minimize wellbore instability. Finally,
the ion exchange capacity of the shale is important as the replacement of cations such
+
+
as Mg ++ by Ca ++ and Na by K weakens the shale. Simply stated, if A m < A p ,