The Role of Cores and Core Analysis in Evaluation of Formation Damage

Abstract

Four types of formation damage typically are encountered. Core tests are presented that provide data to diagnose the impairment mechanism and to aid presented that provide data to diagnose the impairment mechanism and to aid in selecting materials and procedures to minimize the damage. The conclusions form a practical checklist for identifying and/or reducing formation damage. Introduction Formation damage can occur during drilling or coring operations, well completion, production, workover, or subsequent injection of water or chemicals for enhanced recovery. Four types of formation damage typically are encountered. One type includes the blocking of pore channels by solids introduced by drilling mud or by completion, workover, or injection fluids. A second type of formation damage results from clay-water reaction that yields clay hydration and swelling, or clay particle dispersion and pore plugging by movement with produced or injected water. Although the hydration and dispersion mechanisms are different, both result in reduced productivity or injectivity. A third type of formation damage productivity or injectivity. A third type of formation damage results from a liquid block that normally is caused by extraneous water introduced into the formation at the wellbore during drilling, coring, completion, or workover. This block results from a combination of relative-permeability and capillary-retentive properties that reduces effective permeability to the hydrocarbon. A fourth type of permeability damage is related to the caving and subsequent flow of unconsolidated sands into the wellbore. This results in well sand-up with subsequent loss of well productivity. How do we know that a formation damage problem or the potential for damage exists? Warning of difficulty may be available if there is knowledge of the difficult formations in the area in which the well is to be drilled, or if cores are available from earlier wells for making definitive tests before drilling. This predrilling information often is not available and formation damage is suspected after the fact. Typical indications of damage are that the well does not respond as expected on initial production or after workover, or that an excessive pressure buildup develops in injection wells. Some formation properties that indicate likelihood of formation damage from the drilling and completion procedures can be noted as cores are recovered at the procedures can be noted as cores are recovered at the drillsite, although most of the definitive tests are performed in the laboratory. Visual examination will show vugs, fractures, and shale laminations that may react unfavorably to the drilling fluid. Spot treatment with certain dyes will indicate the presence and relative amounts of swelling clays in the core and formation. When contacting carbonate formations above certain temperatures, some types of mud form an impervious film that effectively seals against flow. Flow capability is impaired to the extent that core samples must be sandblasted or subjected to a comparable abrasion of the surface to restore permeability. Visual examination by microscope will permit permeability. Visual examination by microscope will permit qualitative evaluation of siltiness, presence of mobile fines, and presence and severity of surface sealing. Formation damage can be inferred by comparing core permeability data with pressure-buildup permeability permeability data with pressure-buildup permeability information. This comparison should be made with coreanalysis permeability data corrected for the presence of connate water and with overburden pressure applied. Comparative permeability measurements on whole-core and plug samples taken from the outer and inner circumference of a full-diameter core can illustrate damage. JPT P. 482