The Effect of Temperature in Sweet Corrosion of Horizontal Multiphase Carbon Steel Pipelines

Transcription

1 Society of Petroleum Enlneers SPE 2889 The Effect of Temperature in Sweet Corrosion of Horizontal Multiphase Carbon Steel Pipelines A.K. Vuppu and W.P. Jepson, * Ohio U. SPE Member Copyriht 1994, Society of Petroleum Enineers, Inc. This paper was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference held In Melbourne, Australia, 7-1 November This paper was selected for presentation by an SPE Proram Committee followin review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Enineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Enineers, ~s officers, or members. Papers presented at SPE meetins are subject to publication review by Editorial Committees of the Society of Petroleum Enineers. Permission to copy Is restricted to an abstract of not more than 3 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledment of where and by whom the paper Is presented. Write Librarian, SPE, P.O. Box , Richardson, TX , U.S.A. Telex SPEUT. ABSTRACT The effect of temperature on sweet corrosion in carbon steel pipelines at different liquid velocities under various oil-water concentrations was studied. Carbon steel coupons were used to study the corrosion products formed. With an increase of temperature up to 6 C, corrosion rate increases. Above 6 C, protective carbonate layers were observed. At lower temperature and pressures, the corrosion rates are similar to those predicted by de Waard and Milliams. With an increase in temperature, the corrosion rate increase is more pronounced at hiher pressures and is reater than the de Waard and Milliams. No maximum in the corrosion rate is seen for oil water mixtures for temperatures up to 8C. INTRODUCTION The sweet corrosion in carbon steel pipelines flowin multiphase mixtures of oil, water and as is a common problem faced by the oil and as industries. The corrosion rates can be very hih and lead to fractures and leaks in the pipelines. The corrosion is affected by the concentration of the various reactin species and factors such as ph, temperature, pressure and flow conditions. de Waard and Milliams (1991) produced a model that predicts corrosion rates in carbon steel pipes. The experiments were carried out earlier in stirred beakers and correction factors for the non-ideality of carbon dioxide at hih pressures and the formation of iron carbonate protective scales at hih temperature, were then added in this paper. This relation is widely used in the oil and as industry. Dusted, Lunde and Videm (1994) reported that corrosion rates were less sensitive to. an increase in CO 2 References and illustrations at end of paper 635

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3 2 THE EFFECT OF TEMPERATURE IN SWEET CORROSION OF HORIZONTAL MULTIPHASE, CARBON STEEL PIPELINES SPE2889 corrosion niteswere less sensitive to an increase in CO 2 partial pressures at hiher pressures. The corrosion rates increased with increasin velocities at hiher temperatures. At a lower temperature of 2 C, the corrosion rate decreased with increase in velocity and this was more pronounced at hiher ph. Mishra et al.(1992) have summarized the work done by various researchers in understandin carbon dioxide corrosion mechanisms. They indicate that irrespective of the exact mechanisms involved in the corrosion of steel, the formation of corrosion scales is a major controllin factor. The parameters controllin the iron carbonate scale characteristics are temperature, ph, CO 2 partial pressure, iron level, water composition, material composition, flow velocity, and time. Iron carbonate layers rown below 4 C and 5 bar pressure are found to be amorphous and exhibit poor adherence. Accordin to Burke (1985), the protectiveness of the layer increases above 6 C, and at very hih temperature of 15 C, a manetite (Fe 3 4 ) layer may be formed ultimately. Kanwar and Jepson (1994) conducted experiments in a 1 cm diameter flow system operatin up to.79 MPa usin and oil and water~ He showed that at 4 C, an increase in flow velocity or an increase in carbon dioxide partial pressure increased corrosion rates substantially. He also noted that an increase in oil fraction did not decrease the corrosion rate until at least a concentration of6% oil. Vuppu and Jepson (1994) showed that the corrosion products in oivwater flows depended on the temperature, pressure and flow velocity. Thick layers of iron carbonate were not seen over the rane of variables considered. In this study, the effect of temperature on corrosion rates for full pipe flow conditions determined for.oivwater flows. The scalin temperature suested by de Waard is also examined. EXPERIMENTAL SETUP The schematic layout of the experimental setup is shown in Fiure 1. The set up consists of a closed flow loop and is made of 316 stainless steel. A predetermined oilwater mixture is stored in the 1.2 m 3 holdin tank. The liquid is circulated by a 7 lip stainless steel, centrifual pump into a 7.62 em internal diameter pipeline. The liquid flow rate in the pipeline is controlled by adjustin the ate valve on the bypass line. The flow rate of the liquids is measured by a calibrated orifice plate, connected to a pressure transducer. The liquids flow into a 1.16 cm internal diameter, 1m lon pipeline. The carbon dioxide as enters from the top of the pipe. The liquids flow throuh the test section and back into the holdin tank where the liquids and as are separated usin a de-entrainer plate. The system pressure is maintained by as from the cylinders and by adjustin the back pressure reulator. The system temperature is controlled by two 1.5 KW heaters. The test section within the 1m pipeline is outlined in Fiure 2. The corrosion rates can be measured at the top and bottom of the pipe usin at least two electrical resistance probes and also by analysis of carbon steel coupons. The coupons are also used to study the corrosion products formed. These are analyzed usin the scannin electron microscopy (SEM) and the X-ray diffraction techniques. Pressure tappins allow the pressure drop alon the test section to be monitored. A samplin tube is used to determine the distribution of the phases across the vertical diameter. This provides a check on the flowin oil and water fractions. The shear stress probe outlet was not utilized in this study. ASTM standard sea water and a liht condensate oil, Conoco LVT -2, are used for the liquids and carbon dioxide for the as. The oil has a density of 8 k/m 3 and viscosity of2 cp at 4 C. The system is filled with predetermined oil-water composition. The oxyen level in the system is maintained below 3 ppb by purin 636

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5 SPE 2889 A. K. VUPPU AND W. P. JEPSON 3 with carbon dioxide. The iron concentration is kept at below 1 ppm. The experiments are performed to study the effect of temperature on corrosion rates and to study the corrosion deposits formed on the coupon surface under various conditions. The test matrix is iven as follows: Table 1. Test matrix for the study of the temperature effects on corrosion rates. Parameters studied Values/Conditions Temperature (C) 3,4,5,6,8 Pressure (MPa).27,.79 Oil-Water Mixtures (%) -1, 2-8, 6-4, 8-2, 1- Flow Conditions RESULTS Full Pipe Flow A typical plot of the vanatlon of corrosion rate measured by electrical resistance probes aainst time is shown in Fiure 3. It can be seen that the corrosion rate decreases for several hours and eventually a constant value is attained. The corrosion process at this point have reached an equilibrium and this final corrosion rate is noted as the equilibrium corrosion rate. The corrosion rates at the different temperatures are presented in the Table 2. All the corrosion rates iven are for full pipe flow studies with a liquid velocities of 1 mls. The results from the modified de Waard and Milliams (D&M) equation, which is the most widely prediction, is used as a comparison with the results outlined in this study. In Fiure 3, the corrosion rates for salt water are plotted aainst temperature and compared to the de Waard and Milliams prediction. It can be seen that the corrosion rates for both cases show a similar trend. They increase with increasin temperature, attain a maximum, and then decrease with an increase in temperature. The predicted rates of 2.8 and 4.3 mmfyr at 3 C and 4 C respectively, at a carbon dioxide pressure of.27 MPa, are close to the experimental of values 2.1 and 3.9 mm/yr at the same conditions. For hiher temperatures, the experimental corrosion rates are much hiher than the predicted values. At.79 MPa, the measured rates are 26 and 23 mmfyr at temperatures of 6 and 8 C, whilst the respective predicted values are 17 and 13 mm/yr. An analysis of the coupons showed that the formation of protective iron carbonate scales did bein to occur above 6 C. The de Waard and Milliams equation predicts that the protective scales should be formed at a temperature of approximately 72 C at.27 MPa of carbon dioxide partial pressure and at 59 C at.79 MPa of pressure which seem to aree with this study. At each temperature, it is also seen that the corrosion rate increases substantially with increasin pressure. The corrosion rates obtained for 2% and 6% LVT- 2 oil are presented in Fiure 5. The corrosion rates are times the values predicted by de Waard. The corrosion rates for 2% oil fractions at.27 MPa is observed to increase from 3.4 mmfyr at 3 C to 14.1 mm/yr at 6 C, and continued to increase to a value of 17.4 mm/yr at 8 C. A similar trend is seen at the hiher pressure of.79 MPa and also with 6% oil fractions. The corrosion rates are also observed to increase with increasin pressure for all these conditions. This indicates that protective iron carbonate scales may not be formed at these conditions. On examination of the coupons, the corrosion products were seen to be a coarse material with carbonate crystals embedded in it. Lare cracks and voids were present in the corrosion product layer. No protective iron carbonate film was observed at these conditions. This was also substantiated by Vuppu and Jepson (1994). 637

6 .. 4 THE EFFECT OF TEMPERATURE IN SWEET CORROSION OF HORIZONTAL MULTIPHASE. CARBON STEEL PIPELINES SPE2889 Little previous work has been reported for multiphase flows and it seems that the use of corrosion rates obtained from sinle phase (water) systems and extrapolated to oil/water systems may lead to reat errors. Fiures 6 and 7 show plots of corrosion rates aainst oil fraction, at different temperatures. It is seen in Fiure 6, that, at a temperature of 3 C, the corrosion rate increases from a value of2.1 mm/yr at.27 MPa for salt water, to a maximum of about 5 mm/yr around 6% oil. The rates then decreases rapidly to a neliible value for oil fractions hiher than 8% oil. The same phenomena is also observed at the hiher pressure. In Fiure 7, at 6 and 8 C, the corrosion rates show similar trends. At 6 C, maximum rates of 12 and 25 mm/yr are found at.27 MPa and.79 MPa respectively, for oil fractions up to 6% oil. The rates aain become neliible at reater than 8% oil conditions. At 8 C, the maximum corrosion rates of approximately 17 and 33 mm/yr are recorded for the same two pressures studied. CONCLUSIONS A study of corrosion in multiphase pipelines has been carried out usin saltwater, oil, and carbon dioxide. It has been shown that for saltwater only, the corrosion rate increases with temperature up to approximately 6-7 C and then decreases. Evidence of protective iron carbonate layers were found. The corrosion rates predicted by de Waard are much lower than the experimental values at temperatures above 4 C. The maximum in the corrosion rate is predicted. When oil is present, the corrosion rates are times reater than those predicted by de Waard. For temperatures up to 8 C, no evidence of a maximum in the corrosion rate is seen. A study of the coupons show that no protective carbonate layer is present for these conditions. The corrosion rate increased as the oil composition is increased up to 6%. Above this, the corrosion decreased rapidly to neliible amount. This is due to the presence of a water layer at the bottom of the pipe for oil compositions up to 8%. Correlations and models developed from sinle phase systems should be used with care when extrapolatin to lare diameter multiphase pipelines. REFERENCES 1) de Waard, C., Lotz, u., and Milliams, D.E.: "Predictive model for CO 2 corrosion enineerin in wet natural as pipelines," CORROSION, 47(12), ) Dustad, Arne., Lunde, Liv., & Videm, Ketil.: "parametric study of CO 2 corrosion of carbon steel, II CORROSION/94, 14, 14/1-14/15. 3) Mishra, B. Olson, D.L., and AI-Hassan, S.: "Physical Characteristics of Iron Carbonate Scale Formation in Linepipe Steels," paper No. 13 presented at the 1992 NACE CORROSION'92 conference, Nashville. 4) Burke, P.A. Synopsis:"Recent Proress in the Understandin of CO 2 Corrosion, II Advances in C<4 Corrosion. Vol. 1, pp. 3-9, NACE, Houston, Texas (1985). 5) Kanwar, S. and Jepson, W.P.:" A Model to predict sweet corrosion of multiphase flow in horizontal pipelines," paper NO.24 presented at the 1994 NACE CORROSION'94 conference, Baltimore. 6) Vuppu, A.K. and Jepson, W.P.:"Study of Sweet Corrosion in Horizontal Multiphase, CArbon Steel Pipelines," paper OTC 7494 presented in

7 Table 2. Corrosion Rates (mm1yr) for different experimental conditions K \ Corrosion Rates (mm1yr) Brine Synthetie sea watej Conoco LVT2/Sea Water mix Temp De Waard '" MiDi.IDS (SW) 2%iI-8O"/oSW 6%Oil-4O"/oSW C.27 MPlI.79MPl1.27MPl1.79 MPlI.27MPl1.79 MPlI.27 MPlI.79 MPlI NA NA \ E,~ NA NA \ NA NA NA NA \ ana Not Available. Experiments were not performed under these conditions. A. Liquid Tank B. Liquid Recycle C. Valve on Liquid Recycle D. Valve on Liquid Feed E. 7.6 em IDStainless Steel Liquid Feed F. Orifice plate. to pressure transducer G. Aow Heiht Control Gate H. Carbon dioxide Feed Line I. Test Section-IO em ID Stainless Steel pipe J. 1 em IDStainless Steel Section K. Pressure Gaues & Back Pressure Reulator L. Safety valve M. Heater N. Pump Fiure. I Layout of The Experimental System 1Il '" co 5 SOC..79 MPa 4 'i:" >. I 3 ~ e c 'ill U 2 corrosion rate = 22 mm1yr ToAuidTank E - ER Probe or LPR Probe C -Coupon P - Pressure Tappins S - Shear Stress Probe ST - Samplin Tube T - Taos on void fraction Tube Sf 1 em 1D Test Section IP Time (hrs) Fiure 3. Plot of corrosion rate vs time for full pipe flow of salt water at SOC..79 MPa and I mls 2 25 T T Fiure 2 Test section E C

8 3 - de Waard,.27 MPa ~de Waard,.79 MPa 2511-_ this study,.27 MPa I~-e-this study,.79 MPa 'i:' >. E 2 ~ 15 6 'r;; 1 U 'i:' >. E 35 L _ 2% LVT2..27 MFa ~ 2% LVT2..79MPa 3 f : 6% L VT2,.27 MPa -e- 6% LVT2,.79 MPa 25 2 ~ 6 15 'r;; U * I 'i:' >. I ~ 1 E = 'r;; U 5 Temperature Fiure 4. Plot of corrosion rate vs temperature for full pipe flow of salt water at 1 mls C 3OC,.27 MPa 3OC,.79 MPa 4OC,.27 MPa /' I 4OC,.79 MPa 'i:' j 2 ~ = 15 'r;; 1 U Temperature Fiure 5. Plot of corrosion rate vs temperature for full pipe flow of conoco LVT2 oil/water mix at 1 mls / " /~ "'-,. ~ () \ ---,\. -~~'\\ ", \..~ ' ~~ C o <> 6OC,.27 MPa 6OC,.79 MPa SOC,.27 MPa SOC,.79 MPa 5 ~ o o %Conoco LVT2 Fiure 6. Plot of corrosion rate vs % oil fraction for full pipe flow at 3C and 4C and 1 mls % Conoco LVT2 Fiure 7. Plot of corrosion rate vs % oil fraction for full pipe flow at 6C and SOCand 1 mls 1 1~\ l' i j(