A Successful Treatment of Formation Damage Caused by High-Density Brine

Abstract

Summary This paper presents reservoir description, treatment design and execution, and pretreatment and posttreatment analyses of a well completed in Yugoslavia. Chemical aspects of calcium sulfate (CaSO) scale dissolution by Na EDTA are also given. Introduction A major cause of formation damage, the invasion of fine particles, can be eliminated by the use of high-density brines as a completion fluid. The lack of solid filter-caking agents, however, compounds the problem of fluid invasion of producing formations. Because of the extremely high concentration of dissolved electrolytes in com-parison to typical formation waters, high-density brines cannodisturb clays and initiate their swelling and migration, and ultimately cause loss of rock permeability. Other more subtle effects of unfavorable fluid/rock interactions reported have not been proved by laboratory investigation, but high brine electrolyte concentration can cause unfavorable interactions with formation waters. The results of Morgenthaler's investigation indicate that these in-teractions are the major potential causes of formation damage with heavy brines. Field and laboratory tests show that the incompatibility between calcium-based completion fluids and formation water can cause scale precipitation, particularly if the formation water contains a significant amount of sulfate or hydrocarbon ion. The problem of scale deposition was recognized by the oil industry many years ago and reported in numerous publications. The literature deals predominantly with low-temperature oil and with disposal, water-injection, and geothermal water wells. To the best of our knowledge, no information on scale problems in high-temperature gas wells has been reported. A severe CaSO scale problem in the very-high-temperature gas-condensate well had appeared, however, and the search for the solution was initiated. The known methods for predicting CaSO scale deposition are not applicable in such conditions. A newly developed model for predicting chemical compatibilities in waterflood operations allows predicting chemical compatibilities in waterflood operations allows calculation of coprecipitation of BaSO, SrSO, and CaSO, but it requires accurate chemical analyses of formation and injection waters. Our experience with high-temperature gas-condensate wells has shown that representative water samples and their analyses are nearly impossible to obtain. Laboratory investigation of high-temperature forms of CaSO was limited to 150 deg. C [302 deg. F]. Another investigation has shown that CaSO deposition in downhole conditions is caused mainly by a pressure drop, because it has a more pronounced influence than the effect of temperature. Only chemical scale-removal techniques were applicable for removing the scale that plugged perforations and probably the flow channels of the formation rocks. CaSO is the only acid-insoluble but chemically reactive scale. Treating CaSO with certain chemical solutions converts it to an acid-soluble compound, usually CaCO or Ca(OH), after which acid is used to get the calcium into solution. The oilfield chemicals industry has accepted terminology that represents the physical appearance of chemical reactions between these solutions and CaSO (converter, decomposer, disintegrator, and dissolver), but little is known about the quantity of scale that can be removed in practice. Although a chelating agent, like EDTA, can dissolve CaSO without the need for conversion to CaCO, it has not been used extensively in the oil industry because of its high cost and low reaction rate. Very good results have been reported for using EDTA to remove CaCO scale. Application of EDTA to remove CaSO scale has also been reported; the result was as good as with the converter solution. In our case of extremely high formation temperature, the application of any acid can have a detrimental effect. Keeping in mind that high temperature has a pronounced effect on the reaction rate between EDTA and CaSO scale, we considered EDTA treatment, tested it in the laboratory, and applied it in the field. In addition to the excellent results obtained, the treatment seems to be very cost-effective. Although the well conditions are not comparable, this statement is in accordance with the results of EDTA treatment in low-temperature oil wells.