Rolf Nyborg Institute for Energy Technology P.O. Box 40, N-2027 Kjeller, Norway ABSTRACT

Transcription

1 Paper No CO 2 CORROSION MODELS FOR OIL AND GAS PRODUCTION SYSTEMS Rolf Nyborg Institute for Energy Technology P.O. Box 40, N-2027 Kjeller, Norway rolf.nyborg@ife.no ABSTRACT Several CO 2 corrosion prediction models have been developed for oil and gas production systems. It can be difficult to understand the differences between the models and choose which models to use. This paper gives an overview of the different prediction models used in the oil and gas industry for evaluation of CO 2 corrosion of carbon steel. The differences between the models are explained. The models differ considerably in how they predict the effect of protective corrosion films and the effect of oil wetting on CO 2 corrosion, and these two factors account for the most pronounced differences between the various models. Keywords: CO 2 corrosion, carbon dioxide, prediction models, oil and gas INTRODUCTION Oil companies and research institutions have developed a large number of prediction models for CO 2 corrosion of carbon steel. Very different results can be obtained when the models are run for the same cases due to the different philosophies used in the development of the models. Some of the models are based little protection by corrosion product films or full water wetting. These models have a built-in conservatism and can overpredict the corrosion attack significantly for many cases, but there is little risk that they would predict low corrosion rates for situations where corrosion problems are actually encountered in the field. Other models assume protection from oil wetting or corrosion films and predict generally much lower corrosion rates. These models often rely on the company's field experience of conditions where the corrosion rates have been at an acceptably low level by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International, Publications Division, 1440 South Creek Drive, Houston, Texas The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. 1

2 Several of the models are mainly based on empirical correlations with laboratory data. Other models are to a large degree based on field data. A few models are based on mechanistic modeling of the different chemical and transport reactions involved in CO 2 corrosion of carbon steel. The mechanistic models are usually tuned against lab data to some degree, while the laboratory and field data models often have some mechanistic equations as a starting point. The differences in predicting the effects of oil wetting and corrosion product films represent the most important differences between the various CO 2 corrosion models. Some of the models have a very strong effect of oil wetting for some flow conditions, while other models do not consider oil wetting effects at all. Some models include strong effects of protective iron carbonate films especially at high ph or high temperature, some include a qualitative risk for localized corrosion attack and some do not take any account for protective corrosion films for formation water cases due to risk for localized attack. All model developers want to be able to validate their models against real field data. For CO 2 corrosion prediction models for the oil and gas industry this has proven to be a difficult exercise, as the amount of reliable corrosion field data is scarce. Much of the available uninhibited field data has been found to be either unreliable or insufficient for model validation purposes, or biased against specific field conditions. For field data cases all the necessary input parameters for the corrosion prediction models are often not known in sufficient detail in order to be able to run the models for validation purposes. If a model is validated for a set of field data of similar type from one company and maybe also from just one field, or similar or neighboring fields, a good correlation for the conditions specific for that field may be obtained, but extrapolation of the model to other fields or conditions different from the ones used in the validation may become highly uncertain. As a result of these considerations several operators decided to join forces in an effort to collect reliable corrosion field data from a number of operators into a database which can be used for sharing field experience between operators and for model validation purposes. This has been done through three joint industry projects conducted by the author. In these projects field data with actual corrosion measurements were gathered from the participating oil companies. The different available CO 2 corrosion prediction models were evaluated by performing sensitivity studies for the different models, running the different corrosion models for a set of the field cases, and comparing predicted corrosion rates with the actual measured corrosion rates. An overview of the different CO 2 corrosion prediction models based on this work has been published previously 1. This paper presents an update of this overview, including more recent models and new versions of some of the models, and gives some examples of how the field data were used for comparing the different corrosion prediction models. The process of collecting field data and using them for evaluation of corrosion prediction models have been described in detail previously 2, 3. The operators in these projects have also formulated tentative guidelines for prediction of CO 2 corrosion, emphasizing a methodology for defining the corrosion severity levels rather than corrosion rates 4. De Waard Model CO 2 CORROSION MODELS USED IN THE OIL AND GAS INDUSTRY The model developed by de Waard and coworkers (hereafter denoted Model DW) was for several years the most widely used CO 2 corrosion model. The first version was published in 1975 and was based on dependence of temperature and pco 2 only 5. The model has been revised several times since, when different correction factors have been added to the original equation 6, 7. The 1995 version 7 represents a best fit to a large number of corrosion flow loop data generated at the author's 2 2

3 laboratory 8. The model uses a scale factor to take account for corrosion product scales, but this gives only a minimum estimate of scale protectiveness. The model takes relatively little account for the effect of protective corrosion scales, especially at high temperature or high ph. The model was calibrated against laboratory data up to C, and the model does not give much account for formation of corrosion films with good protective properties above this temperature. The scale factor was meant to be used only when formation water is not present, due to the risk for breakdown of the corrosion film in the presence of formation water 6. The model includes an on/off factor for oil wetting in crude oil systems. Oil wetting and no corrosion is assumed when the water cut is below 30 % and the liquid velocity is above 1 m/s. This on/off oil wetting factor is used for crude oil only and not for condensate, as water is considered to separate out much more easily in condensate systems 6. For oil pipelines the scale and oil wetting factors result typically in either quite high corrosion rate (water wetting and no effect of protective films) or no corrosion at all (oil wetting). The model includes ph calculation only for pure condensed water or condensed water saturated with corrosion products, and requires ph as a separate input when a formation water chemistry is specified. However, due to the moderate account for protective films the model has relatively little sensitivity to variation in ph. Norsok M-506 Model This model ( 1 ) (hereafter denoted Model NO) is an empirical model developed by the Norwegian oil companies Statoil, Norsk Hydro and Saga Petroleum 9, 10. The model is fitted to much of the same lab data 8 as Model DW, but includes in addition more recent experiments 11 at 100 to 150 C. The model takes larger account for the effect of protective corrosion films at high temperature and high ph than DW and several of the other models. The model is considerably more sensitive to variation in ph than DW. In the second revision of the model the lower temperature limit for the model was extended from 20 to 5 C and a lower limit of 0.1 bar CO 2 partial pressure was introduced 10, 12. The model has been issued as a standard for the Norwegian oil industry and is openly available 10. The model contains modules for calculating ph and wall shear stress. Three options for calculating ph are available. For condensed water without corrosion products the ph is given by the temperature and CO 2 partial pressure. The ph in condensed water saturated with iron carbonate produced by corrosion can also be calculated. For formation water the ph calculation is based on the bicarbonate content and the ionic strength. Wall shear stress can be calculated from production rates and pipe diameter. The model does not account for any effect of oil wetting. The model is not intended for corrosion prediction in systems where ph stabilization is used for corrosion control. Practical guidelines for application of this model have been given by Olsen et al 12. Hydrocor This model ( 2 ) (denoted Model HY) was developed by Shell to combine corrosion and fluid flow modeling. Different CO 2 corrosion models are coupled to models for multiphase flow, ph calculation and iron carbonate precipitation 13, 14, 15. An oil wetting factor is used for crude oil systems, but not for gas condensate, which is not regarded as giving any protection by oil wetting, as water separation is likely to occur. Oil wetting and no corrosion is assumed when the water cut is below 40 % and the liquid velocity is above 1.5 m/s 14. The scale factor is applied for condensed water cases, but not for ( ) 1 NORSOK standard No. M-506: Standards Norway, Oslo, Norway 2 HYDROCOR: Shell Global Solutions, Amsterdam, The Netherlands ( ) 3 3

4 formation water cases, as porous mixture scales may form with little protection 14. The scale factor gives relatively weak protection from corrosion product films. Prediction of top-of-line corrosion is also included 16 as well as simplified models for H 2 S corrosion and organic acid corrosion 14, 15. The program includes a fluid flow model which calculates pressure, temperature and flow profiles along a pipeline. This is then used for predictions of corrosion rate along the pipeline. The ph calculation takes account for production of iron and bicarbonate due to corrosion and to iron carbonate precipitation, giving an increase in ph along the pipeline. Corplus This model ( 3 ) (denoted Model CO) is developed by Total and is a result of a merger of the Cormed tool (CM) developed by Elf 17, 18 and the Lipucor model (LI) developed by Total 19. CM and LI are no longer used by Total and have been replaced by Model CO. The model is based on detailed analysis of the water chemistry including effects of CO 2, organic acids and calcium, and a large amount of corrosion field data, particularly for wells. Free acetic acid and ph are identified as key parameters for corrosion prediction. The ph calculation method is the same as in the previous CM tool. Model CO gives a potential corrosivity without any protection from corrosion films or oil wetting. This is the same as in CM. It then uses the fluid flow calculations from LI, and gives a predicted corrosion rate as the potential corrosivity with no effect of protective corrosion film (from CM) times a water wetting factor (from LI), typically giving low corrosion rates for liquid velocities above a critical velocity which is often calculated to around 0.5 m/s. s. A possible reduction in corrosion decrease due to oil wetting is also calculated In addition to the numerical values for corrosion rate the model gives a CO 2 corrosiveness in categories from Very low to Very high. This includes additional qualitative criteria determined from an extensive review of Total field experience. A Very High Corrosiveness means that early failures have been reported in the field in less than 3 to 5 years, corresponding to corrosion rates above about 3 mm/yr. Very Low Corrosiveness means that there is good field experience without any corrosion indication after more than years service life, i.e. corrosion rates < 0.1 mm/yr. The CO 2 corrosiveness does not include any possible beneficial effect of oil wetting. The combination of the predicted corrosion rate and the CO 2 corrosiveness category then gives the most complete picture of the actual case. Model CO gives recommendations on how to adjust the water chemistry if it is not evaluated as consistent with respect to calcium carbonate saturation. If the specified water chemistry, temperature and CO 2 partial pressure shows supersaturation of CaCO 3 it is recommended to check for the most likely cause and correct it until the saturation is evaluated as consistent. The most likely cause is often an over-estimate of the bicarbonate content. If the user ignores this recommendation Model CO will in the ph calculation reduce the bicarbonate level until CaCO 3 saturation is reached, giving a lower calculated ph for CaCO 3 supersaturated waters than most of the other prediction programs which do not correct for CaCO 3 supersaturation. Cassandra This model ( 4 ) (denoted Model CA) is BP s implementation of Model DW, including company experience in using this model 20. In this model a ph calculation module is included, where the ph value is calculated from the CO 2 content, temperature and full water chemistry. The effect of protective corrosion films can be included or excluded by the user by choosing the scaling temperature. Above ( ) 3 CORPLUS: Total, Pau, France 4 Cassandra: BP Exploration, Sunbury, United Kingdom ( ) 4 4

5 the scaling temperature the corrosion rate is considered constant instead of reduced with increasing temperature as in Model DW. The model thereby gives less credit for protective films at high temperature. However, it is not distinguished between effect of corrosion films for cases with and without formation water. Acetate in the water analysis is assumed to be present as acetic acid, giving a lower ph value when acetate is present. The presence of acetic acid is pointed out as important both due to the effect of acetic acid on the corrosion rate and the possibility of overestimation of bicarbonate content and ph from a water analysis when acetate is present 21. Oil wetting effects are not included in this model. Important aspects in the practical use of this model are the use of corrosion inhibitor availability rather than inhibitor efficiency and the use of corrosion risk categories as a way of quantifying the corrosion risk 22. KSC Model This model ( 5 ) (denoted Model KS) is a mechanistic model for CO 2 corrosion with protective corrosion films developed at Institute for Energy Technology 23, 24. The model is based on an electrochemical model 25 by building it together with a transport model. The model simulates electrochemical reactions at the steel surface, chemical reactions in the liquid phase, diffusion of species to and from the bulk phase and diffusion through porous iron carbonate films. The properties of the protective corrosion films are correlated with a large number of flow loop experiments. The model calculates the concentration profiles and fluxes of the different species and the resulting corrosion rate. The model calculates a corrosion rate without protective films, a corrosion rate with protective films and a risk for mesa attack. The corrosion rate with protective films is the preferred value, but when the risk for mesa attack is high the corrosion rate without film should be used. This model includes a relatively strong effect of protective corrosion films which is sensitive to ph and temperature, and therefore tends to predict low corrosion rates for high temperature and high ph. The model does not take any effect of oil wetting into account. The strength of Model KS is primarily as a tool for understanding the different processes taking place during CO 2 corrosion of carbon steel in the presence of protective corrosion films. It is not primarily intended as a design tool. Multicorp This model ( 6 ) (denoted Model MU) is developed by Ohio University. This model was originally based on a Model KS using mechanistic modeling of the chemical, electrochemical and transport processes occurring during CO 2 corrosion 23. This has been developed further at Ohio University by including modeling of multiphase flow, precipitation of iron carbonate films and effects of oil wetting and crude oil chemistry, and further verified against laboratory and field data 26, 27. Effects of organic acids and H 2 S, including iron sulfide film precipitation, has also been included 28. The model is based on detailed mechanistic modeling of the kinetics of chemical reactions in the bulk and electrochemical reactions at the steel surface and transient transport of species between the bulk solution and the steel surface, through the turbulent boundary layer and a porous corrosion product layer. Kinetics of iron sulfide and iron carbonate precipitation, growth of corrosion product layers and development of localized attack is also modeled. Further effects of multiphase flow including water entrainment and dropout, effects of H 2 S and organic acids, effects of steel type and effects of inhibition by crude oil and/or corrosion inhibitors are included to make a comprehensive model well suited for understanding ( 5 ) KSC Model: Institute for Energy Technology, Kjeller, Norway ( 6 ) MULTICORP: Ohio University, Athens, Ohio 5 5

6 all the various mechanisms occurring during CO 2 / H 2 S corrosion of carbon steel. The model is correlated against a large amount of laboratory data and some field data. ECE Model This model ( 7 ) (denoted Model EC) developed by Intetech is based on Model DW, but includes a module for calculation of ph from the water chemistry and bicarbonate produced by corrosion, a new oil wetting correlation and effects of small amounts of H 2 S and acetic acid 29, 30. It is developed for wells and flowlines. The oil wetting correlation is based on a compilation of tubing corrosion data from a light crude oil field 29. The oil wetting factor is dependent on the oil density, the liquid flow velocity and the inclination of the flow. An emulsion breakpoint is calculated from the oil density. This can be 40 to 50 % water cut for heavy crude oils and close to zero for light condensate. For water cuts lower than the emulsion breakpoint the water is believed to be present as a water-in-oil emulsion, and the predicted corrosion is low, but not zero. The critical flow velocity for water dropout is taken as 1 m/s for horizontal flow and lower for inclined flow. The model includes a module for calculation of ph from the water chemistry and bicarbonate produced by corrosion. The way of accounting for bicarbonate produced by corrosion can result in markedly higher calculated ph than many other models. However, it is possible to override this an calculate the ph without bicarbonate produced by corrosion. On the other hand the calculated corrosion rates are not very sensitive to calculated ph. The model includes H 2 S effects, effect of acetic acid and calculation of top of line corrosion. Small amounts of H 2 S can give a considerable decrease in the predicted corrosion rate due to protection by iron sulfide films. Predict This model ( 8 ) (denoted Model PR) was developed by InterCorr International, now a part of Honeywell 31, 32, 33. The basic part of the model is based on Model DW, but other correction factors are used together with an effective CO 2 partial pressure calculated from the system ph. The model includes very strong effects of oil wetting and variation in ph, and this tends to give very low corrosion rates for many situations. The model includes a flow modeling module for calculation of flow velocity and flow regime. The model distinguishes between persistent and not persistent oil types in order to predict oil or water wetting. Low corrosion rates are typically predicted when the water cut is below 50 % for highly persistent oils and 5 % for not persistent oils. The model has a very strong ph dependence on the corrosion rate, due to both effect of protective corrosion films and particularly effect of H + mass transport limitations. This tends to give low corrosion rates when the ph value is higher than 4.5 to 5. Tulsa Model The SSPS CO 2 corrosion model ( 9) developed at the University of Tulsa (denoted Model TU) is a mechanistic two-phase flow model with detailed modeling of the kinetics of electrochemical reactions and mass transfer 34, 35, 36. The model calculates the corrosion rate in presence of iron carbonate scales and also indicates what the corrosion rate would have been without the formation of iron carbonate scales. The model puts much emphasis on flow modeling and can be used for straight pipes or ( 7 ) Electronic Corrosion Engineer (ECE): Intetech, Chester, United Kingdom ( 8 ) PREDICT: Honeywell Corrosion Solutions, Houston, Texas ( 9 ) SPPS CO 2 : University of Tulsa, Tulsa, Oklahoma 6 6

7 elbows. The model has a very strong effect of protective corrosion films. This effect is highly dependent of ph, and the model is therefore very sensitive to variation in ph, with low corrosion rates usually predicted when the ph value is above 5. The model also indicates the corrosion rate in absence of protective iron carbonate films in the case that the films are destroyed for instance by erosion or tool scratching. The Tulsa group has worked extensively on sand erosion and erosioncorrosion. The model has a high sensitivity to flow velocity. It does not take any effect of oil wetting into account. ULL Model This corrosion model ( 10 ) (denoted Model UL) consists of a package of programs developed primarily for gas condensate wells by the University of Louisiana at Lafayette (ULL) 37, 38. The model calculates temperature and pressure profiles, phase equilibria, flow rates and flow regime and then calculates the ph profile and predicts the corrosion rate profile along the well. The model puts much weight on calculating the flow regime and the location for condensation of water and hydrocarbons in the well. The model has a strong effect of oil wetting when hydrocarbon condensation occurs. It typically predicts oil wetting and no corrosion for the part of the tubing where hydrocarbon condensation occurs, and corrosion when only water condenses. The model has later been extended to cover oil and gas pipelines 39, 40. This version contains multiphase flow calculations and has not been evaluated in the work described here. CorPos This model ( 11 ) (denoted Model CP) is a tool developed by CorrOcean (now part of Force Technology) where results from multiphase flow calculations are combined with water chemistry calculation and a point corrosion model in order to calculate ph and corrosion rate along a pipeline 41, 42. The model is based on using input from an external fluid flow model combined with calculation of a probability of water wetting and calculation of ph. Bicarbonate produced by corrosion is accounted for in the ph calculation, giving an increase in the ph along the pipeline. Model NO is then used to calculate the corrosion rate in several points along the pipeline. A probability of water wetting is calculated depending on water cut, flow regime, local phase velocities and emulsion stability. This gives lower corrosion rates than Model NO for pipelines with very low water cut. OLI Model The corrosion model developed by OLI Systems ( 12 ) (denoted Model OL) combines a thermodynamic model for the concentration of molecular and ionic species of aqueous systems with an electrochemical corrosion model and a model for formation and dissolution of iron carbonate or sulfide scales 43, 44. The model is based on detailed mechanistic modeling of the phase behavior and the various chemical and electrochemical reactions. Much weight is put on thermodynamic calculation of the phase equilibria and the concentration of the different species in the system. Protectiveness of corrosion films is modeled by assuming that the electrochemical reactions only occur on the parts of the steel surface not covered by corrosion films. The scale formation parameters have been calibrated against selected laboratory data. The model does not include any effect of oil wetting. ( 10 ) UL Lafayette Corrosion Prediction Model: University of Louisiana at Lafayette, Lafayette, Louisiana ( 11 ) CorPos: Force Technology Norway, Trondheim, Norway ( 12 ) OLI Corrosion Analyzer: OLI Systems, Morris Plains, New Jersey 7 7

8 SweetCor This prediction tool ( 13 ) (denoted Model SW) was developed by Shell for analysis of CO 2 corrosion by managing a large database of corrosion data from laboratory experiments and field data 45. The approach is to group data by ranges of temperature and CO 2 partial pressure or by the stable corrosion product. Statistical analysis of the grouped data is used to make correlations for predicting corrosion rates for specific conditions. Corrosion prediction can be done by using these prediction correlations or by filtering the database for conditions close to the conditions of interest in terms of temperatures, CO 2 partial pressure, flow/no flow and inhibitor/no inhibitor. The model includes only a weak effect of protective corrosion films and does not take any effect of oil wetting into account. The ph value is calculated assuming a bicarbonate content in the water corresponding to water saturated with corrosion products, but the predicted corrosion rate is very little dependent on ph. IMPORTANT FACTORS FOR CO 2 CORROSION PREDICTION Among the most important factors which are needed to understand the differences between the various CO 2 corrosion prediction models are how the ph value is calculated, effect of organic acids, effects of protective corrosion films, effects of oil wetting, effect of H 2 S and connection with multiphase flow properties. The importance of these factors are described below. An overview of how these factors are treated in the different models is shown in Table 1. Some of the models have been issued in several versions and the author has not evaluated the latest version of every model, so all details in the table may not be accurate. Also several of the table entries include interpretations of weak, moderate and strong effects which by nature are somewhat subjective. Nevertheless, the table should together with the description in the following give some guidance to understanding the differences between the models. Determination of ph One of the most crucial aspects in corrosion evaluation of oil and gas wells and pipelines is to obtain a realistic estimate of the actual ph in the water phase. For cases with only condensed water this should include an evaluation of increase in the ph of the condensed water due to bicarbonate produced by corrosion. Some of the models include bicarbonate produced by corrosion in the ph calculation. When formation water is produced it is important to obtain good water analysis data, especially with respect to bicarbonate and organic acids. In many cases formation water samples are very scarce during the first well tests. Another uncertainty is when and how much formation water will actually be produced. It is often very uncertain when formation water breakthrough will occur. The water chemistry and hence the ph and the resulting corrosion rate can change considerably if the water composition changes from pure condensed water only to condensed water with small amounts of formation water, or to a water chemistry dominated by formation water. The reported ph in a water analysis is most often totally useless for a corrosion prediction, as it is usually measured at atmospheric conditions after depressurization. This gives no information about the actual ph in the pipeline, which must be calculated from the CO 2 partial pressure, temperature, bicarbonate content in the water and ionic strength. Several of the models have ph modules which perform such calculations. On the other hand, some of the models show little dependence of ph on the corrosion rate, and therefore uncertainties in the ph calculations will not have a large effect on the predicted corrosion rate. ( 13 ) SweetCor: Shell Global Solutions, Houston, Texas 8 8

9 In some cases the specified water chemistry from a water analysis can indicate supersaturation of calcium carbonate. It may be advisable to check the water analysis for supersaturation of calcium carbonate at reservoir conditions, which may indicate an erroneous bicarbonate analysis since supersaturation of calcium carbonate is not possible in the reservoir. In this case it may be advisable to reduce the bicarbonate value to the bicarbonate solubility at reservoir conditions with the actual calcium content, as it is more likely that the measured bicarbonate level is erroneous than that the calcium measurement is too high. Only a few of the models have a built-in check of this effect. For liquid only systems the CO 2 partial pressure is defined by the conditions in the last separator stage upstream the pipeline, or by the bubble point pressure for oil wells, which gives the actual dissolved CO 2 in the aqueous phase and a corresponding CO 2 partial pressure. Using the CO 2 mole % in the associated gas and the total pressure in an oil well without free gas can give much too high estimates for the CO 2 partial pressure, and consequently too high corrosion rate predictions. TABLE 1. IMPORTANT FACTORS IN CO 2 CORROSION PREDICTION MODELS Model DW NO HY CO CA KS MU EC PR TU UL CP OL SW Lab data, Field data model, L L M F L M M L L M F L M L Mechanistic model Scale effect formation water* N M N W W M M W S S M W W Scale effect condensed water* W M W W W M M W S S M M W Effect of ph on corrosion rate* W M W M W M M W S S S M W W Risk for localized attack Y Y Y Y Oil wetting effect crude oil* S N M M N N S S S N S M N N Oil wetting effect condensate* N N N M N N M M M N S M N N CaCO 3 correction for ph Y Y Y Effect of organic acid on corrosion Y Y Y Y Y Y Y Top of line corrosion Y Y Y Y Y Effect of H 2 S on corrosion rate* N N W N N N M S S N W N S N Multiphase flow calculation** N P M P N N P M P P M M N N Max. temperature limit C Max. CO 2 partial pressure bar Open, Commercial, Proprietary O O P O O O P C C P P P C P * S - strong effect, M - moderate effect, W - weak effect, N - no effect ** P - point calculation, M - multiphase profile calculation, N - no multiphase flow calculation 9 9

10 Effect of Organic Acids In addition to the CO 2 /bicarbonate buffer system also the H 2 S/sulfide and the acetic acid/acetate buffering systems can be important for determining the actual ph value. The presence of acetic acid and other organic acids can give too high values for bicarbonate and hence too high calculated ph values if organic acids are not measured in the water analysis, which has been most typical until recently 21. In addition, the presence of acetic acid can have important effects on the corrosion process, especially at low CO 2 partial pressures. Not all of the models take this effect into account. Model CO distinguishes between condensed water and formation water cases with respect to effects of acetic acid. When condensed water is specified, it assumes that acetic acid is co-condensing with the water and lowers the ph of the condensed water. When formation water is specified, a given acetate content in the formation water is assumed to be as acetate ions, resulting in an increase in ph, if not explicitly given as acetic acid. Model CO also lists recommended default values for total acetate content in produced waters when this is not known, as shown in Table 2. These values are used within Total when no water analysis is available. The values are developed from general experience on organic species analyses of reservoir and condensed water 4. Based on experience the total organic acid content is likely to be closer to this value than to zero when no data is available. The temperature considered is the bottom-hole temperature. TABLE 2. DEFAULT VALUES FOR TOTAL ACETATE IN meq/l IN FORMATION WATER In meq/l 1% CO 2 in gas > 1% CO 2 in gas T < 60 C 0 0 T < 80 C 1 1 T < 100 C 3 5 T < 120 C 5 10 T < 135 C 3 5 T < 150 C 1 1 T 150 C 0 0 * 1 meq/l is equivalent to 59 mg/l. Effect of Protective Corrosion Films One of the major difficulties with prediction of CO 2 corrosion of carbon steel is the very important effect of protective iron carbonate films especially at high temperature or high ph. At low temperature the iron carbonate solubility is high and the precipitation rate slow, and protective films will not form unless the ph is artificially increased. At high temperature the iron carbonate solubility is lower and the precipitation rate much faster, and very dense and protective iron carbonate films can form. This can lower the corrosion rate from several mm/y for a carbon steel without any corrosion films to less than 0.1 mm/y when protective films are present. The effect of protective corrosion films can almost be considered as an on/off switch, and the success of a prediction model depends to a large degree on whether it is able to predict the presence or absence of protective films or localized attack reliably, rather than the ability to predict the general corrosion rate in the absence of protective films with a certain accuracy. The picture is further complicated by the tendency to development of localized attack in the form of pits or mesa attack on steel surfaces with a partially protective film

11 The effect of protective corrosion films on the predicted corrosion rate varies considerably between the models. Some of the models include very strong effects of protective films, while others include only moderate effects of protective films or do not take any account for protective corrosion films for formation water cases due to high risk for localized attack for such cases. Generally the models with the strongest effects of protective films rely on easy formation of corrosion films with good protective properties and absence of localized attack, while the models with weak effects of protective corrosion films assume that the films have only limited protectiveness or that there is a high risk for localized attack. Some of the models predict a corrosion rate with protective corrosion films together with the corrosion rate if there were no corrosion films, and some include also a qualitative risk for localized corrosion attack. Effect of Oil Wetting It is important to know whether water or oil wets the steel surface since corrosion takes place only when water is present at the surface. If the water is transported as a water-in-oil emulsion or dispersion the corrosion can be substantially reduced. The degree of oil wetting depends heavily on flow conditions, water cut and the properties of the actual hydrocarbon, and this is difficult to assess without performing laboratory or field tests with the actual oil-water mixture. Some of the models have a very strong effect of oil wetting for some flow conditions, while other models do not consider oil wetting effects at all, either because oil wetting effects are not modeled or because it is believed that water will wet the steel surface and cause corrosion somewhere in the pipeline anyway. Better understanding of the parameters controlling the entrainment of oil and the oil wetting mechanism has a potential to improve the corrosion predictions and increase the confidence in the models. In the simplest form oil wetting is considered an on/off switch in the models: either the surface is water wet with full corrosion or oil wet with zero corrosion. In Model DW oil wetting and zero corrosion was assumed if the liquid flow velocity is larger than 1 m/s and the water cut is less than 30 %. This effect is used for crude oil only and not for condensate, as water is considered to separate out much more easily in condensate systems 6. In the more recent Model HY these limits were changed to 40 % and 1.5 m/s, and partial protection is assumed when the water cut and flow velocity are above these limits. Also here no protection is assumed for condensate systems 14. In Model EC the oil wetting factor is dependent on the oil density, the liquid flow velocity and the inclination of the flow 29. Model PR includes strong effects of oil wetting, and distinguishes between persistent and not persistent oil types 31. Low corrosion rates are typically predicted when the water cut is below 50 % for highly persistent oils and 5 % for not persistent oils. Model UL has a strong effect of oil wetting when hydrocarbon condensation occurs. It typically predicts oil wetting and no corrosion for the part of the well where hydrocarbon condensation occurs, and corrosion when only water condenses. Another approach is to model the transition between separated and dispersed water/oil and use this to determine the degree of water wetting 46. Connection with Fluid Flow Modeling CO 2 corrosion is dependent on the flow velocity, and the models have varying degree of flow dependence. Most of the models include a simplified fluid flow calculation based on production rates and pipe diameter, while some only take flow velocity as input and require that liquid flow velocity in the well or pipeline have been calculated by a fluid flow model. A corrosion module has been 11 11

12 developed in the OLGA three-phase fluid flow model 14, where the NO and DW models have been combined with this fluid flow model 46. Some of the corrosion models include a full fluid flow model giving temperature, pressure and flow profiles along the well or pipeline. Other models include options for point calculations of the flow parameters used in the corrosion prediction. A few of the models take liquid velocity as input and require that this has been calculated separately. The variation of temperature along a well or pipeline is often much more important for the corrosion behavior than variation in flow velocity and flow regime, and there may have been a tendency to over-emphasize the effects of flow parameters on CO 2 corrosion. The most important effects of the flow parameters are probably the switch between oil and water wetting and the effect of flow on localized attack on surfaces covered by corrosion films, and not the effect of flow velocity on the corrosion rate itself, especially for cases where protective corrosion films may form. Top-of-Line Corrosion The discussion above concerns primarily corrosion in the bulk water phase. The situation is quite different for top-of-line corrosion when water condenses out in the upper part of a pipeline. The condensing water is unbuffered with low ph, but can become rapidly saturated or supersaturated with corrosion products, giving rise to increased ph and possibility for iron carbonate film formation. The top-of-line corrosion rate then becomes dependent on the water condensation rate and the amount of iron which can be dissolved in the condensing water 47. Already an early version of Model DW included a very simplified model for top-of-line corrosion 6, but little attention was paid to this type of corrosion until top-of-line corrosion failures started to emerge in gas fields in the Far East in the 1990's 48. Topof-line corrosion is now included several of the corrosion models. In addition to the models discussed above, Institute for Energy Technology has developed a dedicated top-of-line corrosion model which is dependent on the water condensation rate and the amount of iron which can be dissolved in the condensing water 47. A key parameter to prediction of top-of-line corrosion is estimation of the water condensation rate, which requires a rather detailed fluid flow simulation including heat transfer through the pipe walls. Top-of-line corrosion is primarily a concern in the first few kilometers of wet gas pipelines with relatively high inlet temperatures, as the water condensation rate is rapidly reduced when the temperature decreases. The presence of acetic acid in the gas may increase the top-of-line corrosion rate considerably, as it increases the amount of iron which can be dissolved in the condensing water before protective corrosion films are formed. Effect of H 2 S All the models discussed here are primarily CO 2 corrosion prediction models and are not particularly suited for situations with appreciable amounts of H 2 S. When even small amounts of H 2 S are present, the corrosion products are iron sulfide rather than iron carbonate, since iron sulfide is much less soluble and precipitates much more rapidly than iron carbonate. Some of the models try to take this into account, but the steps to be taken when moving from sweet corrosion to sour corrosion prediction are large since the type of corrosion films, corrosion attacks and mechanisms to be predicted are very different. Prediction models developed on the basis of formation of protective iron carbonate films can therefore not be used for situations where iron sulfide films are formed instead, and adding sulfide correction factors to CO 2 corrosion models will not give reliable results. Some of the models discussed above use the H 2 S content in the ph calculation without actually predicting 14 OLGA: SPT Group, Kjeller, Norway 12 12

13 sulfide-dominated corrosion, while some of the models give a warning that the results are not valid when the H 2 S content is above a certain low level. Several of the models do not take the effect of sulfide films into account at all. Some of the models show a marked reduction in corrosion rate due to iron sulfide films when the H 2 S content is higher than about 1 mbar or even lower 32, 44. Model HY uses the sweet corrosion rate multiplied with a pitting factor between 0.7 and 6 for the sulfide dominated regime defined as pco 2 /ph 2 S < 20. This pitting factor indicates the tendency to pitting in sulfide dominated systems and increases with chloride content and presence of elemental sulfur 14. There is a need for H 2 S corrosion models that take the mechanisms for formation of different types of iron sulfides and development of localized attack into account. Work is ongoing in this field in several laboratories, including the author's, but this research area has not yet advanced as far as for sweet corrosion with iron carbonate film formation. The best advice for the time being is to be very careful in using any of these models for situations with more than a few mbar H 2 S, and to be aware of the limitations of corrosion prediction models in taking H 2 S effects into account. EVALUATION OF MODELS AGAINST FIELD DATA A database of corrosion field data was collected by the operators representatives in three joint industry projects conducted by the author. The difficulties in obtaining reliable corrosion field data have been reported previously 2, 3. Most of the field data used for models evaluation were failure cases where failure reports were available. The amount of available data varied considerably from case to case. For some cases detailed corrosion data along the pipeline or well were available in the form of caliper surveys or intelligent pigging data. For other cases corrosion data were only available at single points or as maximum rates. For some of the cases the full production rate history was available, while others only stated typical production rates. Typical for many of the cases was that when corrosion problems are encountered, it is often difficult to trace back to obtain all the relevant information from earlier stages of the history of the field. Even when the operators representatives in the project were actively seeking for field data within their own organization it was often difficult to find all the necessary data to be able to run the different models. When field data are to be used for corrosion prediction model evaluation or validation it is necessary to restrict the analyses to uninhibited cases, and this of course limits the number of available field data that can be used considerably. A selection of available field data was made for use in the corrosion models evaluation, based on the uninhibited cases where detailed and reliable information was available for both production characteristics, geometry and water chemistry, and where CO 2 corrosion was identified as the corrosion mechanism. An overview of a few examples of the field data cases is shown in Table 3. This shows three examples from the selection of field data cases used in the models evaluation. In all these cases the corrosion rates were relatively high, from 1 to 5 mm/y. Two of these cases resulted in leakages, and for these cases corrosion measurements were also available at other locations from intelligent pigging or caliper runs. The third case is from an onshore pipeline with ultrasonic wall thickness measurement. The case called Oil line 3 is a multiphase oil line which suffered multiple leakages after seven years of operation. After the leakages this case was extensively investigated with intelligent pigging, inspection and detailed studies of metallurgy and water chemistry 21, 49. This pipeline had a low CO 2 content but presence of acetic acid. At the locations with the largest corrosion damage the flow regime was slug flow with high liquid velocity

14 TABLE 3. OVERVIEW OF SELECTED FIELD DATA Oil line 3 Oil well 5 Gas line 3 Temperature C CO 2 partial pressure bar Bicarbonate mg/l Acetate mg/l 100 Calcium mg/l Chloride mg/l At location with max. corrosion: Temperature C CO 2 partial pressure bar Water cut % Liquid flow velocity m/s Corrosion rate mm/y Corrosion measurement Leakage, pigging Leakage, caliper run Ultrasonic testing FIGURE 1 - Penetrating Localized Attack in Oil Well 5 The Oil well 5 is an oil well where a leakage occurred after 18 months of service. Contrary to the belief during design, the well started to produce formation water very soon, with water cut increasing from 5 % after 2 months to 80 % after 17 months. The CO 2 molar fraction in the gaseous phase was 30 %, and the bubble point pressure was 5.2 bar. The wellhead pressure was always higher than this, so this was a liquid-only oil well with a CO 2 partial pressure of 1.6 bar. The calculated ph is between 5 and 5.5. Here both detailed caliper data over the whole depth and detailed inspection of the recovered well string was available 50. The tubing had penetrating mesa attack close to the top of the well, at around 100 m depth, corresponding to 4.6 mm/y corrosion rate based on the total production period. A section of the tubing where penetrating localized attack was found is shown in Figure 1. Further down in the well the corrosion rate was measured to mm/y by caliper data

15 The Gas line 3 case is from a short onshore gas line with condensed water only and 10 % water cut. Ultrasonic wall thickness measurements were done in different bends just before the slug catcher after one year of operation. The highest measured corrosion rate was 4.1 mm/y. The corrosion rates predicted with some of the models for the field cases described in Table 3 are compared with the actual measured corrosion rates in Table 4. Here the models are anonymized for commerciality reasons and in order not to rank models based on a few example cases. Comparison with a large number of field cases showed that none of the models performed markedly better for all cases, while some of the models are more conservative than others. Here the maximum corrosion rate measured for each case is compared with the predicted corrosion rates for the location where the highest corrosion rate was measured. The Oil line 3 case has the lowest measured corrosion rate of the cases in Table 3. This pipeline had a low CO 2 content but presence of acetate. Early water analyses reported 110 ppm bicarbonate. However, a later water analysis where acetate was looked for showed 49 ppm bicarbonate and 100 ppm acetate. This is an example of a case where presence of organic acids can lead to too high values for bicarbonate and hence too high calculated ph values 21. The total alkalinity measured by standard titration will not give a correct measure for the bicarbonate content when organic acids are present, since the total alkalinity is the sum of bicarbonate and acetate, and varying amounts of acetate can be included in the titration depending on the end point of the titration. This means that some of the acetate may be interpreted as bicarbonate if the bicarbonate is taken as the total alkalinity and it is not analyzed for organic acids. TABLE 4. MAXIMUM MEASURED AND PREDICTED CORROSION RATES Maximum measured and predicted corrosion rate mm/y Oil line 3 Oil well 5 Gas line 3 Measured Model A Model B Model C Model D Model E Model F Model G For the Oil well 5 case the model predictions were done for different times during the production history and for different depths of the well, and then integrated over the production history. The resulting accumulated predicted corrosion at different depths in the well is shown in Figure 2 as average corrosion rate over the tubing life. Some of the models predicted a considerable increase in corrosion rate during the tubing life, as a result of increasing water cut 3. The predicted corrosion rates are compared with the actual corrosion damage measured by caliper runs and inspection of selected parts of the recovered tubing string. The corrosion damage was relatively small with general corrosion with corrosion rates around 0.5 mm/y in the lower part of the well, and more severe in the upper part of the well with localized attack, and penetrating mesa attack at around 100 m depth