Formation Damage resulting from the migration of small, mobile mineral particles within hydrocarbon producing formations has been, and continues to be a major concern of drilling and production engineers. The flow rate at which these small, usually colloidal, particles begin to dislodge and move within a formation is referred to as the critical flow rate.
Many factors can influence the migration of fines within a producing formation: mineral composition, size and shape; pore throat size and distribution; relative fluid saturations; particle wettability; viscosity of the mobile fluid phase; fluid interfacial tension; production rate; and chemical alteration by drilling and completion fluids can affect the mobility of mineral species responsible for formation damage from in situ fines migration. A novel approach for the analysis and quantification of formation damage resulting from fines migration is described in this paper. The analysis is routinely performed on core plugs from whole core, rotary sidewall cores, and percussion sidewall cores. The technique described employs industry accepted practices for the measurement of single and multiphase permeability of core samples at reservoir conditions, as well as a novel experimental methodology and data processing technique for critical rate determination. A baseline permeability is established at a very low production rate. The rate is subsequently increased in a step wise fashion, returning to the established base rate after every consecutive rate increase. Experimentally derived flow rate and permeability data are converted to bottom hole and wellhead production rates using completion data and well geometry.
The technique described in this paper is used successfully to augment production efforts in several producing formations by integrating the data obtained from flow studies with X-ray diffraction, scanning electron microscopy, and petrographic analysis.
By imparting the ability to vary drilling and completion procedures while under simulated reservoir conditions in the laboratory, this analytical technique can reduce the risk of formation damage at all stages of well operations.
The problem of permeability reduction resulting from the migration of in situ colloidal and detrital fines in petroleum reservoirs is a well documented phenomenon.
Small, uncemented mineral particles, normally referred to as formation fines, exist in the pore networks of nearly all naturally permeable rock formations. These mineral particles vary considerably in composition and morphology. Fibrous or platy clay minerals often line the surfaces of pore cavities or bridge across the pore throats of sandstone and siltstone formations. These minerals are usually authigenic in nature, often forming in situ as a result of diagenetic alteration reactions of feldspathic and micaceous minerals within the rock. Small uncemented particles of quartz or calcite are usually also present in the pore spaces of most grainstone formations.
When flow is initiated in a pore network containing loose or poorly attached solid particles, hydrodynamic conditions may reach a level at which these uncemented particles are subjected to forces large enough to dislodge and transport them through the porous medium. The flow rate at which fines migration begins is unique for every flow unit within a formation and, indeed, for every well and is referred to in this paper as the critical flow rate or critical production rate.