Evaluating the Performance of Fluid Placement Approaches on Well Stimulation Results

Abstract

Oil and gas production or water injection is sometimes hampered by wellbore scales and fills (i.e., inner well flow impediments) as well as formation damage (skin) that impedes flow. Formation damage may reside in the near wellbore region but could also extend deep into the formation. While the severity of the skin may vary from well to well the mechanisms of damage are generally mechanical, chemical, biological, or thermal in nature. Whereas a formation with no damage would have a skin factor of zero a well with serious damage may have a skin factor of 20 or greater. Formation damage impairs rock permeability which directly impacts oil and gas production or water injection operations hence the economics of the oil and gas field. Well stimulations to address formation damage are accomplished through a variety of techniques but most commonly through chemical (acid) treatments to restore a wells productivity or injectivity. Often, due to permeability heterogeneity, common stimulation approaches do not provide maximum volumetric contact of treatment fluids with the formation. To maximize volumetric contact of the treatment fluid with the formation and across the entire completed interval, it is of utmost importance to employ a technique that can overcome the challenges of permeability heterogeneity to improve post-stimulation outcomes.