Barium and Strontium Sulfate Scale Formation Due to Incompatible Water in the Namorado Fields Campos Basin, Brazil

Abstract

Abstract The chemical incompatibility of infected seawater and formation water has prompted deposition of barium and strontium sulphate scales in producing wells of the Namorado field. The precipitation Squeeze process was chosen as a means of preventing scale formation in this field. The present paper describes tests conducted to select the inhibitor, improve inhibitor precipitation and simulate treatment in the porous media. It also presents the results of the first squeeze operation conducted in the field. Introduction Located in the Campos basin in southeastern Brazil. the Namorado field produces 10 000 m3 of oil per day from produces 10 000 m3 of oil per day from sandstone reservoirs displaying excellent permo-porosity properties. This level of permo-porosity properties. This level of production is-maintained by infecting 10 000 m3 production is-maintained by infecting 10 000 m3 of seawater per day. When seawater containing a high SO4- content is mixed with Ba- and Sr- rich formation water (Table l), the result may be the precipitation of predictable quantities of BaSO4 and SrSO4. predictable quantities of BaSO4 and SrSO4. Barium sulphate and strontium scale formation has of ten been noted. mainly in the tubing of producing wells, where this scale Ny producing wells, where this scale Ny seriously jeopardize oil production. Precipitation squeeze as a means of preventing scale formation has been used and preventing scale formation has been used and reported on by other authors. In the case of the Namorado field. the type of rock (sandstone); the high barium and strontium contents (229 and 415 mg/l) displayed by the formation water; and the high basic sediments and water(BS and W) accompanied by a high production rate made it necessary to conduct a production rate made it necessary to conduct a thorough experimental study to select an inhibitor. improve its precipitation. and simulator treatment in the porous media. HISTORY Following four years of seawater infection operations, scale formation was observed in the perforations, wellbore, and subsurface perforations, wellbore, and subsurface equipment of wells located near the infection front. Producing oil well 7-NA-16D-RJS was selected for detailed monitoring, with the aim of linking the history of production over the last three years with the occurrence of scale. Worked over in September 1994 at 3545 to 3554m, the well initially presented a damage ratio of 0.69, a gross flop rated of 800 m3/day of dry oil, and a wellhead, flowing pressure of 240 KPa of 26deg. API oil. In January pressure of 240 KPa of 26deg. API oil. In January 1987, the produced oil displayed 5% BS and W and water salinity equivalent to that of the formation water. In July 1988 an increase in BS and W and drop in salinity provided the first indications of scale in the production column, and a wireline caliper was dropped in. Scale formation was indeed verified and it was necessary to pull out the tubing. The scale was located in the tubing and was thicker on the tubes and equipment located below the packer. X-ray fluorescence and diffractometry analyses indicated that the deposit consisted predominantly of BaSO4, with low-SrSO4 and predominantly of BaSO4, with low-SrSO4 and CaSO4 contents. LABORATORY TESTS Screen Test for Scale Inhibitor A static precipitation test was used to ascertain the efficiency of polymer and phosphonate scale inhibitors. The quantity and phosphonate scale inhibitors. The quantity and type of precipitate formed by the mixture of injector. and formation water were compared with the quantity and type of precipitate formed by the same mixture under the same time and temperature conditions, but without the inhibitor.