'\ A- ~qg1 31 ---· ' c. I ~ I SUBJECT:A CORROSION MITIGATION PROGRAM FORTHEREDWATER OIL FIELD CE1'~;.,~,·-....'-' L'l'lR" ,..., ~d " '/ 176 I.I, ,•. r. •. I ~ ', ,;' •' " L OI .., I T.A. Scott Esso Chemical Canada B. E. Fowli e Imperial Oil Limited A paper ie211@@,presented to the Canadian Region Western Confe~ence of the National Association of Corrosion Engineers ,¢February 1976 Calgary, Alberta, Canada. - A Corrosion Mitigation Program for the Redwater Oil Field Abstract Serious corrosion by hydrogen sulphide and carbon dioxide attack of the North Two-Phasegathering line, flowlines and downhole equipment, became evident in the Redwater oil field during the period 1972 through 1973. Corrosion in the North Two-Phasegathering line was successfully mitigated by the continuous injection of corrosion inhibitor. Corrosion in downhole equipment and flowlines was successfully mitigated by batching inhibitor into the annulus of each oil well while circulating the well fluids for a ten minute period. Iron counts on samples of produced water, combined with the careful observation of corrosion attack to hardware, made it possible to measure the effect of the mitigation program and to optimize the economics. Corrosion in the North Two-PhaseGathering Line Without doubt the most significant failure which clearly identi- fied the existence of a corrosion problem in the Redwater Field was the failure of a section of 8 inch diameter, 0.157 inch wall electrically re- sistance welded pipe in the North Two-Phasegathering line in June 1972. This gathering line, which is 9 miles long, begins in Opal as a 4 inch diameter line, then increases to 6 inches, 8 inches and finally 12 inches at the fieldgate and gas plant as shown in Figure 1. T. 58 2 MILES T. 57 EDMONTON HIGHWAY 28 • • OM , SOUTH R.21 R.22 W.4M . Figure 1 - Mapof the Redwater North oil field showing failure locations and inhibitor injection points on North Two-Phasegathering line. From 1956 to November1968 this line had been in gas gathering service. In Apr'il 1971 internal corrosion problems, which were attributable to the gas gathering service period, made it necessary to replace 7000 feet of 8 inch pipe. The failure which occurred in June 1972 was again within that same 7000 foot section. Nowa 3000 foot section of pipe had to be re- placed within that same area. This indicated that the corrosion was very active and very aggressive. Another internal corrosion failure occurred in the 12 inch section in August 1972. Laboratory analysis proved the failures to be the result of internal pitting on the bottom of the line. Furthermore this analysis indicated that the pitting was due to a hydrogen sulfide in water corrosion mechanism. - 3 - Figure 2 shows an exampleof the pitting. Figure 2 - An example of the pitting found in the North Two-Phaseline. A numberof items were considered to be significant to the failure analysis. Twofailures had occurred in the same section of line and the hydrogen sulfide and water content of the production was increasing with time. At the time of the June 1972 failure the line was transporting 9600 barrels/day of product and 1500 barrels/day of water. Also significant was that a compressor station was injecting gas into the North Two-Phase line at a point which was upstream of the failure locations (Figure 1). The gas/oil ratio changed from 187 standard cubic feet/barrel upstream of the compressor station to 467 standard cubic feet/barrel stream of the compressor station. 181 standard cubic feet/barrel down- The gas/oil ratio then dropped again to downstreamof the problem area as a result of the injection of quantities of dead oil into the line. - 4 - It was considered that this gas compressor provided a warming trend and a sour wet gas phase which scrubbed the pipe wall free of its natural protective films of iron-sulphide. Following the failure in the 8 inch section in June 1972, it i1T1Tiediately by injecting was decided that an inhibitor program be corT1T1enced continuously a water and oil dispersible corrosion inhibitor. The program consisted of batch treating the line at the North end of the 4 inch section and at the junction of the 8 inch and 10 inch sections at a concentration of 200 ppm. Following the bate~ treatment a continuous inhibitor injection rate of 20 ppmwas injected at the same locations. To date a corrosion failure has not occurred since the inhibition program was started. inhibition During this period of time (over three years} the rate has been maintained at 20 ppm. Since it is necessary to pig the line regularly to remove wax deposition it is not practical to install II corrosion monitoring probes. Corrosion in Oil Wells and Flowlines From 1964 through 1972.minor and infrequent corrosion of downhole equipment became apparent. initial Figure 3 shows the well locations at which the downhole corrosion problems occurred. - 5 - R 22 ·--.-· R.21 HIGHWAY 28 T.57 (.~~ ...-R.20 W.AM. 3 MIUS T.56 Figure 3 - MapoftheRedwater oil field showing location of wells where downholecorrosion occurred prior to 1973. Beginning in 1973 the frequency of corrosion related damageof downhole pumpsand sucker rods in the Northern section of the field where produced fluids contain 90%water began to increase at an alarming rate. Within twelve months the downhole corrosion spread across the complete field inclusive of those areas where the produced fluid contained less than 1% water. Figure 4 shows the location of those additional problem wells. - 6 - R.21 HIGHWAY 28 • T.57 • R.20 W ,M . • l Mllfl T.56 • ••• • Figure4 - MapoftheRedwateroil field showing location of wells having downholecorrosion by the end of 1973. Problem Analysis An extensive investigation of the corrosion problem revealed the following: 1. The initial metallurgical analysis of corroded downhole hardware indicated that the corrosion was characteristic of hydrogen sulfide pitting attack (as in the Two-Phaseline). Figure 5 shows a typical sucker rod corrosion pit. - 8 - TABLEI COMPOSITION OF GASSAMPLES FROM GASSEPARATORS Sample Location Mole% H2S Mole %CO2 H2S/C02 Mole Ratio Total Acid Gas Mole% H2S &CO2 Separator No. 1 1. 7 5.9 0.29 7.6 Separator No. 2 1.3 6.0 0.22 7.3 Separator No. 3 1.3 4.7 0.28 6.0 Separator No. 4 1.1 3.9 0.28 5.0 Separator No. 5 1.1 4.9 0.22 6.0 Separator No. 6 1.4 4.3 0.33 5.7 Separator No. 7 1.8 4.4 0.41 6.2 Separator No. 8 1.8 4.3 0.42 6.1 Separator No. 9 1. 5 3.1 0.48 4.6 Separator No. 10 1.5 3.3 0.45 4.8 Separator No. 11 0.8 2.7 0.30 3.5 Separator No. 12 1. 5 3.3 0.45 4.8 Separator No. 13 0.8 2.6 0.31 3.4 Separator No. 14 1.1 3.4 0.32 4.5 Separator No. 15 1.3 3.5 0.37 4.8 Separator No. 16 1.2 2.6 0.46 3.8 Separator No. 17 1.3 4.6 0.28 5.9 Separator No. 18 1.3 4.9 0.27 6.2 Separator No. 19 1. 5 4.3 0.35 5.8 Separator No. 20 1.4 4.8 0.29 6.2 Separator No. 21 1.2 3.7 0.32 4.9 / - 9 - Contour plots of the gas composition revealed that 32 of the 40 wells with the most serious corrosion problems fell within areas bordered by either hydrogen sulfide/carbon dioxide mole ratios of 0.48 or total acid gas contents of 6.0 or greater mole percentage. Previous studies conducted by Imperial Oil's Production Research and Technical Service Laboratory showed that hydrogen sulfide/carbon dioxide mole ratios of 0.4 to 1.2 caused the most extreme corrosion rates. 180 -- 00 INFLUENCE OF GAS COMPOSITION ON CORROSION RATE --r-- ---r 200 160 -· --- - -- (See figure 6) ··- COUPONS - J55 COUPON TEMPERATURE-100 ° F GAS TEMPERATURE-140° F -----1 GAS PRESSURE-1200 PSI '--~-.-~-.-~~~ 1~---~~~---1 ~ -+ - - 140 - - --+---+--- ~ LLI I- er o: 120, I z 0 u, IOOV)-- ---- ----"----"'< 0 0: 0: 8 80 60 0 1- o - - 0.4 0 .8 1.2 1.6 2 .0 2 .4 2.8 3.6 4.0 4 .4 4 .8 Figure 6 - Influence of gas composition on corrosion rate. It was concluded that the corrosion failures pitting were caused by a attack from a hydrogen sulfide/carbon dioxide in water mechanism which was most severe in areas bordered by a hydrogen sulfide/carbon dioxide mole ratio of 0.48 or total acid gas concentration of 6.0 or greater mole percentage in the produced gas. Corrective Action / It was decided initially problem by giving an inhibitor to obtain control of the downhole corrosion treatment to all wells within the recognized problem area that were producing fltiids containing in excess of 35%water. It was further decided to inhibit all wells that were producing fluids containing in excess of 10%water with flowlines crossing the river. this criterion lost its significance However, very quickly when it became evident that the corrosion attack was also occurring in wells producing fluid containing as low as 1%water. An analysis of well service reports of 75 wells which showed evidence of corrosion attack revealed that there was no recognizable correlation the percentage of water in the produced fluids and corrosion attack. between (See Table TABLEII Corrosion Attack versus Water Content of the Produced Fluid Percentage of Water Numberof Wells Showing Corrosion Attack less than 5 5 to 20 20 to 40 40 to 60 60 to 80 80 to 100 15 15 9 12 9 15 Therefore, the inhibition defined problem area irrespective fluid. In addition, of the percentage of water in the produced also wells outside of the problem area were included in the corrosion inhibition rods or pumpparts. program was expanded to all wells in the program when relatively minor corrosion occurred on A water and oil dispersible inhibitor was applied as follows: itial treatment each well selected for inhibition received a 10tch of inhibitor followed by complete circulation of the well fluid. Jn, the flowline was pigged where possible and then batched with of inhibitor. In order to ensure maintenance of the initial e film, each well received in subsequent treatments a 5-gallon batch tor injected into the annulus weekly. During these subsequent treatwell fluids were circulated only while injecting the 5-gallon batch tor. Each injection takes approximately ten minutes. The corrosion inhibitor is injected by means of a self-contained .sure pumptruck as shownin Figures 7 and 8. J I. ,,, .,. ..~' ~_.......,.__~...... ~ .!. ,1 - l-··· • 1, . .. ,... - - ...... ~-- • .....,.!If ...,-. -~ •• .,-- 'J.! D :18 ~ ~ ( .,.