Formation Damage
1. Whether the fraction of authigenic clays that grow on the solid grain surfaces of reservoir rock over geological times; and the fraction of detrital clays that gets broken off the solid grains by local stresses play a crucial role associated with the formation damage (fines migration) of a sandstone reservoir?
If DLVO theory fails to predict the trend of detached particle concentration; then, whether the diffusive flux of authigenic and detrital particles in the reservoir considered to be insignificant?
How important would be the compressibility of the suspended particles and those of the retained particles in the oil/water system during its migration towards production well considering the drag forces?
Can we characterize the transportation of suspended particle fluid to be described by single-phase Darcy’s law despite its mobility along with oil and water?
If so, how do we take into account contact-bond radius; pore-radius; particle-size; lever-arm ratio; tensile strength; pH; salinity and aspect ratio?
If both particle sizes as well as pore sizes remain to be lesser than 10 microns; then, would it remain feasible to deduce the maximum detachment of detrital particle and the maximum amount of authigenic particle’s mobilization?
How exactly to capture the rate at which the particles get strained in the vicinity of a wellbore in terms of fluid shear rate; and in turn, the way, the permeability keeps changing?
2. How easy would it remain to distinguish between fines migration and the external solid entrainment (when, particles from injected fluids as well as variety of suspended solids enter and clog the pores surrounding the wellbore)?
3. When wellbore fluids try to contact the nearby formation; and if it causes a significant reduction in water saturation; then, to what extent the coupled negative effect of capillary pressure and relative permeability effects would be aiding formation damage by means of phase-trapping and blocking?
4. To what extent, the detonation of perforation charges (leading to crushed zones and generating mobile rock grains; and thereby mitigating permeability and eventually, creating perforating over-balanced) and gazing (direct damage to the wellbore face caused by drill bit interactions resulting in cutting of fines particles into the formation face) contribute to formation damage below and above bubble point pressure?
5. Could clay swelling and formation dissolution be easily avoided?
6. To what extent, the enhanced viscosity of produced water either in the form of water-in-oil emulsion or in the form of oil-in-water emulsion tend to result in blockages of pores near wellbore?
7. Whether the formation damage by bacteria (viscous polysaccharide polymer) could significantly plug the formation?
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