Steamflood Heater Scale and Corrosion
- Bryant W. Bradley (Shell Oil Co.) | Lavigne K. Gatzke (Shell Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- February 1975
- Document Type
- Journal Paper
- 171 - 178
- 1975. Society of Petroleum Engineers
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- 202 since 2007
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Field studies to evaluate scale and corrosion in steamflood heater tubes indicate that series-softened sodium ion-exchange water (0.5 ppm total hardness as CaCO3), containing less than 0.2 ppm iron, causes very little deposition and few tube failures. Caustic treatment reduces iron dissolved from bare soft-water distribution lines and iron scale deposition in heater tubes.
When Shell Oil Co. began commercial steamflooding, the water-treating program consisted of catalyzed sodium sulfite, to remove dissolved oxygen, and conventional sodium ion-exchange softening, followed by chelation of hardness leakage with ethylenediaminetetraacetic acid (EDTA). Within 8 months the once-through steam generators (field heaters) began to experience leaks from internal thinning of the 3-in., 180 degrees return beads. Iron material balance calculations revealed a correlation between excess EDTA and iron removal rate, as shown in Fig. 1. Laboratory studies by P. J. Raifsnider, Shell Development Co., determined the leaks were most likely caused by erosion-corrosion in the presence of EDTA. Fig. 2 summarizes Raifsnider's presence of EDTA. Fig. 2 summarizes Raifsnider's experiments using carbon steel coupons in a stirred autoclave. The high concentration of EDTA used in these studies was employed to obtain a measurable effect of the treatment. Laboratory and field tests seeking alternate water-softening schemes demonstrated that series sodium ion-exchange produced water of zero hardness to the standard EDTA analytical test method. Actually, this water contained about 0.4 ppm total hardness using more sophisticated analytical techniques. Accordingly, Shell later added a second stage softener in their steamflood projects. It was noted that on cessation of EDTA treatment the iron material balance calculations began to show small amounts of iron deposition in the heater. Small deposits of calcium and magnesium compounds were also indicated. Within a year another type of tube failure manifested itself. This failure occurred in the body of the tube and consisted of slight swelling and, finally, longitudinal splitting. Analyses of scale samples from two failures and two imminent failures are shown in Tables 1 and 2, respectively. The scale in the swollen but unfailed tubes was less than 1 mm in thickness.
Problem Problem The problem was tube failure because of water-side scale deposits. The purpose of this study was to determine the concentration of scale-forming ions required to form deposits. Our data indicate that the concentration of calcium, magnesium, and iron should be kept as near zero as possible to minimize scale formation.
The source of calcium, magnesium, sodium, and silica was obviously the heater feedwater. However, the major constituent, iron, could have been from tube corrosion or iron picked up by the feedwater from steel distribution piping between the softening plant and heaters. The latter was suspected to be the most important. The power-generating industry has experienced a similar problem with boiler tube failures caused by scales found to be predominantly iron oxides.
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