Abstract
During petrophysical and petrographical analyses of the core plugs, generally, we pay close attention to the "fines migration" when we observe kaolinite minerals filling the pore space or lining the pores. The conditions leading to a drastic reduction of permeability (formation damage), at low temperature, by kaolinite have been documented in the literature: (1) to depend on the colloidal and hydrodynamic forces far from and near the well bore respectively and (2) to mechanically bridge the pore throats. And, at high temperature like in steam flooding, the formation damage caused by kaolinite depends on (1) water chemistry i.e. ionic content, (2) pH of the injection water, and (3) low salt concentration. Although these mechanisms provide a general knowledge base to control the formation damage by controlling the kaolinite particles we found no clues as to what changes occur in the kaolinite morphology or mineralogy. The case in point is a Tuscaloosa sand core from central Louisiana while being drilled with a high pH fluid i.e. pH=10-12 with caustic soda.
In order to understand and therefore to control the formation damage due to kaolinite migration, we subjected a series of core plugs prepared from a Tuscaloosa sand conventional core to a low temperature, high simulated spurt loss (flow rate of 11.1 cc/min) for a short period of fluid/rock contact time (45 minutes). After a thorough petrophysical analysis, we found that within this short period of contact time between the rock and fluid at pH=10-12 at low temperature, the permeability of cores decreased considerably. The petrographical analysis of the same cores revealed that the reason for this drastic change in permeability was the onset of the conversion of kaolinite to hallovsite and dickite under the oxidative effects of Sodium Peroxide. Also, the amphoteric nature of kaolinite similar to Al(OH), i.e. dissolution of kaolinite in both acids and bases, plays an important role in its solubility in caustic soda at pH=10-12.
On the basis of our findings we concluded that in both field and laboratory coring and/or drilling the Tuscaloosa sand or possibly any other sand with a high kaolinite content (greater than 5%) the best conditions for controlling the formation damage are to keep the pH of all injection fluids in a buffered and well controlled state of near neutral and/or to control the filtrate to near zero in such sensitive formation.
