Steam Condensate: Formation Damage and Chemical Treatments for Injectivity Improvement

Abstract

Abstract This paper discusses the results of laboratory studies conducted to determine the potential for formation damage from alkaline condensates during steam injection in a reservoir in the San Joaquin Valley, California. The paper also reviews various remedial treatment options and recommends some optimal treatment injection sequences to sustain steam injectivity. Laboratory flow tests conducted in field core plugs with condensates at different steam qualities reveal the tendency of the condensates to dissolve the rock, destabilize the clays, and hence reduce the permeability. The alkaline condensates from once-through steam generators permeability. The alkaline condensates from once-through steam generators were also found to be incompatible with the formation water, and thus had the potential to form calcium carbonate precipitates and scales. Pretreatment of boiler feeds and/or concurrent treatment of boiler effluents with either a low concentration (<0.1% wt.%) phosphoric acid in 2% potassium/ammonium chloride solution or 2% ammonium dihydrogen phosphate reduced silica dissolution, stabilized the clays and rendered the condensates more compatible with the formation water. Introduction Steam stimulation and steam drive are proven oil recovery techniques now widely applied to heavy oil reservoirs. The San Joaquin Valley around Bakersfield, California is an area of extensive steaming activity. The majority of successful steam stimulation and steam drive projects reported in the literature have been conducted in this area. Lately, formation damage from steam injection in heavy oil reservoirs has been of concern to many steam injection operators. Recent studies conducted by some investigators on the heavy oil sands in Western Canada revealed the potential for reservoir damage during steam injection operations. Reed in an earlier laboratory study, noted the additional problems of gravel pack and formation sandstone dissolution during steam problems of gravel pack and formation sandstone dissolution during steam injection. Both investigations attributed the problems to the high alkalinity and low ionic strength of steam generator condensate effluents, which are injected along with the steam into the formation. The high pH fluids dissolve siliceous materials, along with upsetting the delicate structures of resident clay minerals. Similar problems have also been documented in a field study reported by Konopnicki et al. The above-noted authors have proposed various remedial treatments for minimizing formation damage. Reed proposed the use of calcium chloride solutions as preflush before steam injection to stabilize swelling clays and to protect them during subsequent fresh water contact. This proposed treatment, however, increases the risk of calcium carbonate and/or calcium sulfate scaling at the injection sand face. In another study, Reed proposed the use of hydroxy alumina as a pretreatment before steam proposed the use of hydroxy alumina as a pretreatment before steam injection. This author showed in both laboratory and field tests that Hydroxy-Alumina was effective in protecting clays and in minimizing steam damage. Konopnicki et al. reported that the injection of a saturated potassium chloride (KCl) slug in pilot injection wells and the continuous potassium chloride (KCl) slug in pilot injection wells and the continuous injection of KCl into generator feed water downstream of the softeners were effective in stabilizing clays and reducing condensate damage. Young et al. evaluated the potential use of commercial inorganic and organic clay stabilizers for enhancing permeability retention during steam injection. The above-prescribed treatments all rely primarily on clay stabilization without specific consideration of effects due to the dissolution of silica and other minerals, or the possible hydrothermal alteration of clay minerals. p. 245