Predictive ModeI for CO, Corrosion Engineering in Wet Natural sL Gas Pipelines*

C. de Waard, * U. Lotz, * and D. E, Milliams** _.-

- ABSTRACT can affect the corrosion rate of carbon steel and that should be included in a predictive rnodel. Eor rnany of

e & Starting from a 'korst caseJ1 corrosion rafe p!ediction with these pararneters, - their effects are not known with a the de Waard-Milliams equation, correction factors can be hiqh degree of certainty. In these cases, t h e m applied to quantify the fnfluence of environméntal ~sio_m- should_give conservatll answers, $,a-ssirnistiri w a n d _ c o _ r s i o n product sc&.&medunder v e corrosion rates, by u ~ q u a t i o n s that accoi condition~~, ~quationcare proposed for each factor. A low- t h e e data% a conservative rnanner. - temperature scale formed in condensing water can cause 3: ueduction in the top-of-the-line corrosion rate in pipelines. --- BASlC CORROSION RATE EQUATION . .-.

-, At higher -- temperatures, a more protective scale forms even under high liquid flow rates. The decreáse of corro- AND ITS MODlFlCATlON e. ., * ' , >

sion rates caused by dissolved Fe is accounted for with a - L

pH correction factor. The effkct of the présence of a liquid - As a starting point for the prediction of corrosion -. -g hydrocarbon~hse [S inclu& ~quations are presented rates of carbon steel in COZ-containing environrnents, m a b x - t h e effect of glycol injection on corrosion to be calcula~ed along the length of a pipeline. Combinations of the deWaard-Milliarns equation and the corresponding

effects in the model are discussed. nornograrnl has gained wide acceptance. This equation contained o tern erature-dependent terrns. A re- + *

KEY WORDS: carbon dioxide, wet gas, condensation, iron evaluation of t e data used has shown that it is carbonate, glycol, corrosion model possible to sirnplify the equation for the "nornograrn

corrosion rate" Vnomo to: INTRODUCTION

71 O + 0.67 log (pC0.J (1 ) I O ~ Vnom0 = 5.8 - -

i 1

The feasibility of transporting wet, untreated natural T gas is becorning an irnportant factor for the develop- rnent of gas producing fields. The prediction of the where T = ternperature, O K , and pCO, (= rnol% CO, x , corrosivity associated with the présence of even total pressure P) is the partial pressure ofT0,, in Bar. srnall arnounts of CO, can often play a decisive role The nornograrn itself can be sirnplified with straight . in the deterrnination of this feasibility. To this end, lines only instead of using a curved ternperature systernatic review is needed of every pararneter that scale and is given in Figure 1. T ~ ~ g @ n g c o r r ~ s i o n

rates, which do - --- not differ ..L.-. --- - significantly VI frgm those, o>t)tF~J~w$~ the old equation, represent a "worst

1 * Submmed for publication July 1991 Presented as paper no. 577 at

CORROSIONISI in Cincinnati, OH, March 1991. - casexrediction. ..... S ..-vra.uU. Shell Research, Billiton Research B V Laboratory, P .0 Box 40, 6800 The proposed rnodel systernatically rnodifies this

1 AA, Arnhem. The Netherlands. -!

prediction by rnultipl "' Shell Internationale Petroleum Maatschappg B.V., P.0 Box 162, 2501 AN, The Hague, The Netherlands. which is associated ._-_.-_.\ _-. - - 1 %

r 7

O01 0-931 2191/000257/$3.00/0

4-%% 0 1991, National A-ociation of Corrosion Engineers

I ' " *

Fugacity CoeMcient a C02 FugaFity = axCO2 partial pressure 1

c02 pressure bar 3 lo

- Corrosion Rate

* Total System Pi.essure, bar

FIGURE 2. Fugacity coefficient for CO, in rnethane for gas mixtures with les than 5 mol% CO, -?-",e 3 9 . Y P--2'

LLcur -

FIGURE 1. Nomograrn for CO, corr&on.

c~eemicabe.t&cScS@~t can cause ..._ deviation$J~pfl&ua- *.a--

t y (1). These fac%i in drnost al1 cases V.ciriu. less thay one and will tend to reduce the corrosion rates pre- d%& with this equation, which in rnany cases, would c' wise give over-conservative results.

DH of a rnediurn that is under- ion product, Facn nr Fe (3 a

d

correc 1

may beob-fain

1 EFFECT OF TOTAL PRESSURE

I An increase in total pressure P of the gas will lead to an increase in corrosion rate, because pCO, in Equation (1) will increase in proportion. However, with I

-', increasing pressure, thaReRisl*+Wnaturabgas ;; wiii play an increasing role, and instead of the CO, par-

.! tial pressure, the CO- fugacity fC0, should be used: ..

1 10 100 1s ?h. Total 1x0 s&em ti resc cure, /IGG bar

FIGURE 3. Examples of effect of totalpressure on corrosion rate at a constant CO, partíal pressure of 1 bar. log V,,,,, = 5.8 -m + 0.67 log(fC0.j

- . T

described by the rnultiplier Fsystem.

1 where a = fugacity coefficient, analogous to activity I coefficients in solutions. Theu~>aq$y,coeffic.ient . . can .?%.a

be calculated by solving the equation of state for the 1 niiiture ó i ~ 0 , and natural gas. For the binary ' @ t e r n . ~ ~ , - ~ ~ , calculations were rnade using an

[ approach described by Larnrners.' The results given i, 'gure 2 can be used as a conservative estirnate

' i -.A; the presence of other gases will generally ! further reduce the fugacity coefficient. As a first estirnate the effect on corrosion rate can be

1

to be applied to Vno, in Equation (1). '~he effect on corrosion is illustrated in Figure 3, where corrosion rate is given for a constant CO, partial pressure, but with increasing total pressure. No ezerirnental

L < ' i i r " " P - - 5 - . u

ev7dence is avai~&&Jgt~~~~~ It is of such -<--a

fundamental nature, however, that it should be taken into account in the model.

FIGURE 4. Effect of high-ternperature corrosion product film calculated with scale factor (Equation [4]).

temp(1 bar C02)=

48 4.4 O OA 0.8 1.2 1.6

(ITTSC~I~I~~), aooo, *K

FIGURE 5. Cornparison of proposed equation for the scale factor with some ~ublished data. f.4.6e7

HIGH-TEMPERATURE PROTECTIVE FILMS log F,,,, = -00 - 0.6 log(fC0.J - 6.7 T

The effect of the formation of protective films has been studied e~tensively.~ T@ precipitation of FeCO, (or Fe,O,) in itself does not necessarily result in the for- - mation of a protective film. At lower temperatures (e.g., less than 60°C) the corrosion product film has a .

and ¡S easily removed by temperatures, the film is differ-

ent in texture, is more protective, and is less easily d..,--."- - - . -A-.- . , w _ í y h e d m ~ ~ -- Further increase a- in temjerafüre-?ésults in lower corrosion rates ani3-tFie corfosiori-tkie'goes t ~ ~ f i ü m ~ ~ ~ f e ~ ~ ~ r ~ f Urge-

. k & & $ & - t ~ b ~ , n ~ o ~ a higher flow rate will result in a higher scaling temperature. Also, a .

r steel's surface are such that a protective film is forrned. +

\.,*

higher bulk pH will tend to lower this temperature. Data , ' on CO, corrosion rates for high temperatures and CO, pressures have been reported by lkeda et Since they were obtained at high flow r a m o v e r i n g the widest published ranges in terms of temperatures and CO, pressures, these data have been used as the ba- sis for the equ&nfoc the scale factor F,, in the -- y

, , model. This was done by calculating log(V,N-J (V, = observed corrosion rate, V,, from Equation [1 a]) at temperatures above 60°C and finding a best fit to 1/T and log(fC0,) by _ - multidimensi~na! regression analpis with a computer spread&eeJ. With a small

'-, shiít to obtain a-6nservative envelope for Ikeda's data, the formula for the scale factor used in the model be- comes

with a maximum value for F,, of 1. F is set = 1 when Equation (4) would give a higher value. This factor is used to correct the corrosion rate given by Equation (1 a) by multiplying V,,,,, with FJcal,, The temperature at which log(F,,,) = O is the scaling temperature

T m s the temperature where the corrosion rate goes throuqh a maximum. In the present approach the iiíáximum will appear as a sharp peak (Figure 4). Tbe scaling temperature decreases with increasing CO, .. pressure.

For temperature/pressure combinations below the scaling temperature, the nornogram corrosion rate does not need to be corrected for this effect. Equations (4) and (5) can be combined to 1

1 ) log (F,,,,,) = 2400 1 - - (T Tsca~e,

where T > T,,,, otherwise Fscale = 1.

Figure 5 shows the satisfactory fit of this equation with the data from lkeda and ~ t h e r s . ~ ~ ~ ~ ~ ~ ~ Videm's re- sults from once-through tests were corrected for lower pH associated with the absence of Fe++ (Equation [9]); they also fit predictions rather well, even though these tests were done at very high flow rates up to 20 mls,

I P

e,

ENGlNEERlNG

,' j while most other tests were at 2 to 4 m/c. The nomo- formation of both FeCO, and of magnetite, Fe304 (and Sr-- in Figure 1 -contains the scale factor: when the under some conditions, even the formation of Fe,O, SC, factor line is intersected, the factor is to be ap- may be possible). plied, otherwise no correction needs to be made. During experiments with a constant volume of wa-

At temperatures exceeding the scaling tempera- ter (at constant CO, pressure), the Fe++ concentration ture, corrosion rates tend to decrease to close to zero will increase while themoncentration will decrease with time. The reliability of a complete protection af-

-- with time until the solution is saturated with FeCO, or

forded by scale cannot be sufficiently quantified at Fe,O,. This precipitation does not necessarily result in present, and the scale factor gives a minimum estimate the formation of a protective film, and corrosion can for its protectiveness. It should -- be noted that w-n _ - continue in such a solution. When saturation with brines such as formation water -- are likek tgbe present, FeCO, occurs, further addition of ¡ron will not change the model will suggest Fd, = 1-because of the risk of

- -

the Fe++ concentration or the pH in the solution any fur- breakdown of the film?- '- ther. In the case of saturation with Fe304, however, the

The hGh-temperature scale can be eroded by ,pH and the Fe++ concentration can keep increasing in high-speed liquids. Practica1 velocities for 5w\0& flow

ep" h o s t cases, although the rate of change Y~~ . i l SL .ta8:ti -

in systems with liquid only are often too low to achieve than without saturation. this; only the impact of high-speed -- --- liquid droplets can Initially, the pH is that of water and CO, onlyl be expected to d a m a g e t h e A s s u m i n g the occur- rence of disturbed flow in practica1 systems, the pH(water+CO, only) = 3.71 + 0.00417 t - 0.510g(fC02) (7) suggestion made by Smartg is followed that the onset of erosion corrosion is coincident with the transition to the This equation is also given in ihe-iorm of a nomo- anñuiarmí-s~r-u7tTphaphasef h. WSth the gram in Figure. - - - Superficial liquid velocities ass%Ei5feWwet gas

_-- *, - m e corrosion rate is often observed to first in- 9

transport, this transition can be expected for -perficial- ,,-'crease with time and then to pass through a broad , , - f

gas velocities between 15 and 20 m/c. Above 20 mls, it , LL - maximum or plateau. Hausler et al.1° also reported the is pr&ent to set FWb= 1: ' -&@ Y 3,29&>

~ d - a ~ ~ c ~ t e - , - w h i c h k diff i- sir YC cult to maintain without -- pH control. At this point in the

= &S, 6 't test, the activation of the surface is complete, but the RxATION BEWEEN Fe++ 54 pH has shifted away from the original value for CO, and CONCENTRATION AND pH water. More importantly, it is to be expected that the in-

crease of Fe++ in the solution will also have contributed Depending on temperature and CO, pressure, cor- to the change of the corrosion rate. It is postulated that

rosion of steel in the Cofiater system can lead to the the occurrence ---- of a plateau or steady-state cormcion" y

I C02 pressure

bar 0.01 T

V

FIGURE 6. Nomogram forpH of waterand CO, as function of CO, pressure (fugacity) and temperature.

130 120

110

100

. 9 . . . . . . . . , .

. . . . . . ~ . . . . . . ... . -'- . 2 . : .. .'..i. :

8 , . . , . , . . . , . . . . . . . . . , ... - :- . : . : .'-..' l . , . . . . . . . , . . . ... . , . , .... . . . . ....

0.01 0.1 1 10

C02, bar FIGURE 7. Calculated pH of water at saturation with FeCO, or Fe-O..

' 90 -- -4.5

30 -- 20 -- 10 --

3 - 10

-- Example: PH -- 0.4 bar C02 at 40 'C 5 -- gives pH of 4.1 -- -= 0.1

FIGURE 8. Comparison of "once-through" and "constant vo1urne"corrosion tests as function of reciprocaltemprature. Al1 tests at 1 bar CO,. fines drawn are for Equation (1) with and without pH cvrrection factor of Euuation (101.

rate coincides with the onset of saturation with FeCO, or Fe O The data on wh i chE t i on (1) was otiginally

*&e steady-state corrosion rate readings during constant volume tests with a Fe* concentration in the test solution reaching the values needed for FeCOJ Fe304 saturation, while the pH increas ed to a value de- noted as piH,. -

Experirnentally, the pH shii when this plateau is reached ranges frorn 0.5 to 12. This agrees with themiodynarnic calwlations based on I i i a t & r l ' , for the pH at the onset of FeCO, or Fe,04 saturation for differeni tern~eratures, pH,. The results (for 100/o NaCI) can be approximated by

smallest value of

pH,, = 1.36 + m - 0.1 7 log(fC0J t+273 and

pH,,, = 5.4 - 0.66 log(fCO;)

which is shown in Figure 7. In this equation, the first formula refers to the formation of Fe,O4, the second to FeCO,; the srnallest pH, refers to corrosion product that is more stable and more likely to forrn

F first. These results confirm earlier calculations published by ~ u n l o ~ 9 6 showing that FeCO, is - only stable-in a rather narrow window of low tempera- tures and high CO, pressures with Fe,04 being forrned otherwise.

FIGURE 9. Nomogram correction factor forpH shii? w.r.t. pH of water and CO. onlv.

EFFECT OF Fe++ AND pH ON CORROSION RATE

The contarnination of the CO, solution wAh~rp--.. s@ngmduct reduces the corrosion rate. Without the presence of corrosion products, much higher corrosion rates are possible, as is demonstrated by cornparison of data frorn "once-through" and frorn constani volurne tests in Figure 8. In order to describe this effect, the pH shii caused by the presence of dissolved Fe++ (as pre- dicted from Equations m and [8]) was chosen as a parameter. The following correlation was found

where F, is a correction factor for the nornograrn corrosion rate of Equation (1). and pH, is the actual pH. The correction factor resulting frorn Equation (9) is shown in Figure 9. When pH, = pH,, no correc- tion is needed, that is, F, = 1. When pH, is the initial pH, the corrosion rates in "once-through" tests were a factor 2;2 to 3.3 higher f r a ternperature range of 80 to 20°C. When pH, r &=t because of the presence of alkaline substances, NaHCO,, for exarnple, ihe validity o f E q u a t i ~ - ~ u b t f u l since it could relate to over-saturation w.r.t. Fe++. In this case the formula proposed by Dugstad and Vidern13 can be used for solutions that are Fe++ saturated:

1 I water on 1 m2 steel

/\+l-

20 30

time, sec

FIGURE 10. Example of calculatedpH and corrosion rate as a function of time íconditions as shown).

It should be appreciated however, that Equation (1 0) was derived for very low CO, pressures.

It is recognized that an increase in pH can also lead to the precipitation of protective scales from the water, CaCO,, for example. This is not included in the model at present.

u

INFLUENCE OF FLOW RATE ON Fe++ SATURATION

In order to demonstrate the influence of the arnount of water in a corroding system, spreadsheet calculations were rnade by n~rnerical integraton-~f~ the effect of pH with time. Byusing straighffo?ward calcula- Kons based on &ince of ionic charges for a number of small time steps, the pH can be predicted as a func- tion of time up to the point where saturation occurs. An example is given in Figure 10. Depending on the ratio of water volume to surface a r h and on the severity of the corrosion, the time needed to reach FeCOJFe,O,

, saturation can be significant. This implies that within this time corrosion rates can be experienced that are- higher than the nomogram predicts. For the case that Fe-free water enters a pipeline, this means that a cer-. tain length will corrode faster than Vno,,. In the example of Figure 10, it takes 45 seconds to reach saturation; for a 1 -mrn water film traveling in a pipeline with a flow rate of 1 m/c, this means that a length of 45 m has higher corrosion rates than predicted with the nomo- gram. For a completely water-filled pipeline, these l-gths would be much larger and dependent on diarn-

r. U

Whether or not saturation will be reached also de- pends on the inflow of "new" water for a given situation.

10 20 30 40 50 60 70

Temperature, 'C

FIGURE 1 1. Critica1 inflow of iron-free water below which saturation with FeCO/Fe,O, is maintained. Higher flow rates lead to undersaturation and corrosion rates higher than predicted with the nomogram.

Fcond

1

0.9

0.8

0.7

0.6

0.5

0.4

0.3

0.2

0.1

O O 0.5 1 1.5 2 2.5

Water Condensation rate, gl(m2.s)

FIGURE 12. Experimentar7 data for condensation factor as a function of condensation rate.

Figure 11 gives the maxirnum amount of fresh, C0,- saturated water that can be accornmodated without - losing saturation for a given area of corroding steel. This may be referred to as the "critical water inflow." For example, at one bar CO, at 50°C, an inflow of more than 10 g of water per second per m2 would cause undersaturation of FeCO, (or Fe,O,) and a lower pH, and corrosion rate predictions would have to be cor- rected using Equation (9) to give a higher rate. A lower influx will maintain saturation. This is especially relevant

37.5 MMsm3fd in 36 inch line 0.02 --

O

n d e 0.015 -- n R

a s t

a e 0.01 -- t i O 0.005 -- n

0.025

FIGURE 13. Example of water condensation rates calculated

gl(m2.s)

for a wet gas pipeline.

water saturated gas L at 105 bar 55 -C 1 . l

for systerns with surfaces where water condenses, like in cooler tubes and in slowly cooling wet gas transport lines, as discussed below.

EFFECT OF HYDROCARBON LlQUlD

L The presence of crude oil, for exarnple, in a line

with "live" oil and gas, can have a beneficia1 effect on corrosion by COZ. In the rnodel this is taken into ac- count with the oil factor F,,.

Foil = O if water cut < 30%

and Vcrud, > 1 rnls .

CONDENSATION FACTOR

otherwise Fo, = 1. This expresses the view that the steel can be expected to be oil-wetted (and hydro- phobic) if al1 water is entrained in the crude. If the '

- Work by van Bodegom et a1.16 has shown that cor- rosion rates of steel exposed to condensing water phase in a CO, atrnosphere quickly decrease with time.

1

Averaged over time, these rates can be 113 to 111 0 of the nornograrn corrosion rate, depending on the rate of water condensation. For wet water-saturated gas, sorne very conclusive tests1' were carried out by IFE, Norway, using pipe with a radioactive segrnent in the top. The results are in Figure 12, as the ratio observedl nornograrn rates as a function of water condensation rate in g/(rn2.s). This ratio has been narned the conden- sation factor F,,. The data can be conservatively described by

flow rate VcWde of the oil is too low, water can sepa- rate and cause corrosion on the bottorn of the line. This critical flow rate can be calculated,14 and is less

Fond = 0.4 x (condensation rate, g/[m2.s]), (12) when condensation rate < 2.5

than 1 rn/s for normal crudes. At higher flow rates, the water will be dispersed in the oil. Work by Lotz et aI.l5 indicate that in that case at least 30 percent water can be accornrnodated before the steel is water-wetted. It should be emphasized that light hydrocarbon condensates, for exarnple, natural gas liquids, do not offer any protection in the absence of an inhibitor, regardless of the water content.

Fx,, . i rhe;i condensation rate >= 2.5

For wet gas transport, cooling rates and flow rates in pipelines are normally such that condensation rates are far below 0.25 g/(rn2.s). An exarnple is given in Figure 13. For such systerns, taking Fcon, = 0.1 will cover al1 conditions in a conservative rnanner without having to actually calculate the condensation rates. It is irnportant to note that for these slowly cooling systerns, the condensation rates are far below the critical water influx, and the water film will be satu- rated with corrosion product. For ternperatures below the scaling ternperature, the corrosion product films forrned frorn saturated FeCO, solutions are norrnally not protective since they are very easily washed away. However, it is postulated that the low liquid flow rates associated with water condensation frorn slowly cooling gas leave this film intact.

TOP-OF-THE-LINE CORROSION

For wet gas transport lines, water and light hydro- carbons can condense frorn the gas as the ternperature drops with distance. For rnoderate gas flow velocities of less than 16 to 20 mls, stratified gaslliquid flow will be the predominant flow pattern. When a corrosjm-inhibi- tor solution isueed into such a liy, it wiII not protea again~ssorrogon intJefreshly condensing liquid at the top of the lim Actual occurrences of top-of-the-linez- rosion have been rep~r ted , l~~ l~ but here the presence of p a y have played an irnportant role.

Without inhibition, the corrosion rate in the top of the line will be lower than that at the bottorn, to the ex- tent given by Equation (12), which is very conservatively covered by Feo, = 0.1. In cases where this still gives corrosion rates that are too high, the in- jection of glycol may further reduce this.

EFFECT OF GLYCOL

Glycol is often added to wet gas pipelines to p x - v m t h e f o r m a t i n n . Normally this is rnono-

1 o

J O

r r f o S

i O

n r 0.1 a t e

0.01 90 80 m 60 so m o

Glycoi concentration, %w

FIGURE 14. Exam~le of effect of alvcol on corrosion rate.

or di-ethylene glycol (MEG or DEG), but triethylene- glycol (TEG) is also possible. The presence of glycol

) by reducing the corrosivity of the water phase it rnixes with, and

(2) by absorbin~ water frorn the gas phase. - - The effect of glycol on CO, corrosion was systern-

atic screened by Veritec20 tests with tiny corrosion _T-

cougns (volurne/sMface ratio about 10 l/crn2) of two grades of carbon steel in glycol/water rnixtures at 20 and 40°C, for various types and grades of MEG and DEG, both with weight loss and polarization resistance rneasurernents. For TEG, time-averaged weight loss data ranging over 90fo380 h of exposure frorn a differ- ent source were ~ s e d . ~ ' Data for r n e m w h i c h can also be used, are not included in the rnodel because of high Ccatter in the results. For analytical grades of gly- col, the effect on corrosion rate could be expressed as a rnultiplier Fgh:

W% = water content of waterlglycol rnixture, in %w

The data showed A to depend only weakly on type of glycol, and A = 1.6 can be used for the rnodel for al1 glycols. Figure 14 shows an exarnple of the data for 20°C. For various technical grades corrosion rates were less than or equal to those in analytical grade glycols.

The drying action of injected glycol will lower the watei - cEG@EGf%e gaq. is rneans t m re water u -~ndense as long as the t e r n p e r a w s n - o t - fai-Jow this d e w m l t - @S not rnean that nothing can condense at all, s~a~&rn~ug t~ f&~&e~ , r~ ; i i k~ tures rnay still condense together with hydrocarbon

> > b . . 1

bottorn

2000kglMMsm3 90% DEG

FIGURE 15. Example of dictribution of glycol injected in a wet gas pipeline, with and without hydrocarbon layer. Stratified flow (conditions as stated).

~JUI. For a systern in cornpleteeguilibriurn the corn- ,,.. -....-. ,. ...-.-. . .-"- .. :...,,k,..; ..-*-.. .., . position of the condensing glycoVwater would be the ,.<, ,, * - .. . .. . , . ;C.. ".....d. . .i -. .h.., rr.- .n .. .. ... .. -.d. .: : o , s . c ...,.. . r r r .., .......... .a sarne as that accurnulated on the bopom,,Runs with a . . . . . - . . ; A : . - , ,

cornputer prograrn, which can sirnulate the effect of de- viation from eguilibriurn in practical cases,= showed the condensing phase to be about 10 percent leaner in gly- col than in the stratified liquid on the bottorn for sorne conditions of practical interest. For prediction of the cor- rosion in the condensing liquid, which is of little consequence in view of the conservative value used for F,,, and can be ignored. Hence the glycol concentra- tions for the stratified liquid on the bottorn and in the condensing phase can be assurned to be equal for practical purposes. The equilibriurn cornposition of gly- collwater can be linked to the water dewpoint tw of the gas at any ternperature t by the following formula:

with DEG% = glycol concentration in liquid, in %w. Equation (14), which is for DEG, was derived frorn a best fit to published data,23 and holds well for concen- trations up to 95%. Similar equations can be derived for MEG and TEG. T m e ~ ~ o , ¡ . p t ~ [Jhe gas ¡S rg!ated tD the arnount of water vapor in the gas at pressu% P : ---

2000kglMMsm3 90% DEG 0.25

0.4moleokC02

.. : ' --bottm

-. ___. - . - . - . - - - .__<

- - u r i t h o u t HC iayer -. . .. _ ...... with HC layer

- .. _ -. -. -. - . -_ -. - - - _

. :top

, ; ; ; ; ( ; ; : ; ; : ; ; ! ; ; : ' L . . :

FIGURE 16. Corrosion rates for example in Figure 15.

which describes the graph frorn McKette and Wehe.24 Equations (1 4) and (1 5) can be used to predict the effect of rnixing DEG and wet gas. Using the concen- tration of the injected DEG in Equation (14), the resulting dewpoint can be inserted into Equation (1 5) - ' to calculate how rnuch water the gas will release by ' absorption into the glycol. However, this will dilute the glycol, and a nurnber of iterations (norrnally less than 10) are needed to calculate the equilibrium concen- tration. With cornrnonly used computer spreadsheets, this approach can be used to calculate the glycol concentrations along the length of a pipeline as a function of gas flow rate and glycol injection rate, -Rthe.resylting-corq.M raks-b)i_ap&ly- 3Ec1,u>ua$nL(lA2J. An exarnple of a glycol concentration profile is given in Figure 15 with corresponding corrosion rates in Figure 16. The above calculation is only correct when the contact between the glycol water on the bottorn and the gas

- 7 s r n t e s f n c ~ e ~ y t h e p ~ s ~ c T o ~ r a t i f i e d ~ y ~ of hydrocarbon condensate on top of the glycol. In the presence of such a layer, this cannot always be guaranteed. To predict what the effect would be in such a situation, computer calculations were made for the cornposition of the condensing liquid for

i, various degrees of contact between gas and glycol. For the worst case of complete blockage, they showed that downstrearn of the glycol injection point, concentration of the glycol reduced almost linearly to the point where the pipe-wall ternperature has cooled below the water dewpoint. Here 100-percent water

7 condenses, and corrosion is only reduced by the condensation factor Feo,, and of course, by the lower

V ternperature. This "worst case" scenario can be included in the rnodel calculations described above.

The possible effect of a hydrocarbon (HC) layer is included in Figures 15 and 16. The likelihood of this situation is probably low since it would irnply that gas hydrates could forrn in the top of the pipe, which is not a recognized problern in this situation. The. presence of a stratified-wavy flow pattern is likely to reduce this risk even further.

The effect of an inhibitor can be included in the model by sirnply dividing corrosion rates by an inhibitor efficiency factor, for example, for an inhibitorwith 90 percent efficiency, the corrosion rate should'Feaívíded by 10. For stratified flow patterns, the model will autf;:. m 6 l l y account for the likely absence of inhibitor in the top of t k ~~~~~ a~G~ee~e-- --

woud reported that gas velocities exceeding 17 rnls rnay affect inhibitor performan~e.~~

The model provides correction factors to be ap- plied to the nornograrn corrosion rate V,,, (Equation [l]) to obtain a conservative estirnate of CO, corrosion rates. As a first order approxirnation, correction of V,,,, is to be considered for each factor that differs frorn 1. In sorne cases, this could lead to application of more than one factor, al1 significantly differing frorn 1, which could influence each other, or in the worst case, might be mu- tually exclusive. The cornbination of the scale factor Fde with the condensation factor F,,, falls in this cat- egory, since they both relate to protection frorn a corrosion product film. Starting with ~ = k w t p e m ~ filrn,an.in~rease in ternperature wili change the film's, texture - -- - to a more adherent one, Since no quantitative information is available at present about this, the follow- ing conservative point of view is incorporated in the rnodel: when the scaling ternperature is exceeded, the c o r r o s i o n r ~ k k e p ~ t a n t A theuakie &km* - -

F at t=t-, until the ternperature is reached where cp"d

this rate is larger than V,, x FscN Although it ¡S prob- able that the corrosion rate decreases when the scale temperature is exceeded, no further reduction of the corrosion risk will be predicted in the rnodel until the high-ternperature scale alone will lead to a lower rate. At present, the combination of Fd, with FpH (to account for bulk pH) is not allowed in the model; the corrosion rate of scale~covered steel is more likelyzbe con- trolled by the pH and Fe++ concentration resultinq frorn @al saturation with FeCQ, or Fe,O-atthesjeel's su^ f a ~ e . ~ For this reason, F-, is set = 1 when F ,-,_ < 1. -

Application of F &d F,,, at the sarneTrne is al- lowed since the steAkEan be expected to "see" the glycol in the presence of a low-ternperature FeC0.J Fe,O, film. Cornbination of Fglyc and FF, is allowed be-

ENGINEERING

e3 Cornbination of the correction factors used to ac- count for various effects is possible in sorne, but not all, instances.

.se different experirnents on the effect of glycol with ' --. ?urface areaívolurne ratios (leading to different

) give uery similar results for F ,, suggesting th. &' 3 effects are independent. ~irni far l~, at high ternperatures, the rernaining corrosion rate of scale- covered steel in the alkaline micro-environrnent at the REFERENCES steels's surface is expected to be affected by the pres- ente of glycol approximately in the sarne rnanner, which implieslhat rnultiplication with both F, and F, is allowed.

urham, 1- With these considerat$-, --- the equations .. - . for . .~ the, .~ 2. J. Lammers. Sheil Research B.V. interna1 report, Amsterdam 1973.

various fáctors can be cornbined --- -. t0 p i e x t - CO~~OS~O~¡ - - --- 3. R.H. Hausler, D.W. Stegmann, " ~ o , Corrosion and its Prevention by

rates in wet gas lines. They can be incorporated in an t Chemical lnhibition in Oil and Gas Production," CORROSIONl88. Pa-

computer program, although in ~ a d T r S K ~ p e a ~ a , per no. 363. (Houston, TX: NACE, 1988).

-- - _. 4. K. Videm, A. Dugstad. "Effect of Flow Rate. pH, Fez* Concentration and persoñai Computer-hased - .~ - - spreadsheets f 0 r t ~ ~ íin ids?:! : Steel Q u a l i on the coz Corrosion of ~a rbon Cteels," CO:.K<< si??. :;- vehicle for th&e calculations because they are inher-, -- I

paper no. 42, (Houston, TX: NACE, 1987). .. ~

ently transparent to-ihe user. d 5. K. Videm. A. Dugstad, 'Film Covered Corrosion, Film Breakdown and - --/--- Pitting Attack of Carbon Steels in Aqueous CO,," CORROSIONl88, pa-

perno. 186, (Houston, TX: NACE. 1988).

CONCLUSIONS p ~ , k ~ 6 . A. Ikeda, S. Mukai, M. Ueda, "Prevention of COZ Corrosion of Line Pipe "' and Oil Country Tubular Goods," CORROSION/84 paper no. 289,

. (Houston, TX: NACE, 1984). r, hr 7. K. Satoh, K. Yamamoto, and N. Kagawa, "Prevention of COZ Corrosion

0:. The corrosion rate predicted by the de Waard- in Gas Gathering Systems," Advances in coz Corrosion vol. i ,(HOUS- Miliiams equation for CO, corrosion holds for water ton. TX: NACE, 1984). p. 151.

that is saturated with corrosion product, A conection e"& 8. R.H. Hausier, "The Mechanism 0f CO, Corrosion 0f Steel in Deep H0t

can be calculated in case the water is undersatu- Gas Weils," A d v ~ s in COZ Corrosion, vol. 1, (Houston, TX: NACE. , 1984),p.72.

rated. : , ; , 9. J.S. Smarl III, "A Review of Erosion Corrosion in Oil and Gas , - offect of dissolved Fe++ on CO, corrosion rate Production,"CORROSION/90, paper no. lo, (Houston, TX: NACE.

.ccounted for through the effect of changes in 6 lggO). -. 10. R.R. Hausler, D.W. Stegmann, R.F. Stevens,"The Methodology of Cor- c &' .sed by the k++. Using a theoretically derived rosion lnhibitor Development for coz Systems," Werkstoffe und pH shift at saturation, the observed difference be-. Korrosion 40 (1989): p. 98-1 13. ween 'onc~-thr~ugh'~ and constant volume corrosion 5.mLxJ l . l. Ba", O. Knacke, O. Kubaschewski, 7ierm?chemical Properlies of G, ? . 1 .-1 - tests can be reproduced over a ternperature range of

1'""' lnorganic Substances," (Springer Verlag, 1973J1977).

E - .. ,-,y1 2. A.K. Dunlop, H.L. Hassell, P.R. Rhodes, "Fundamentai Considerations bA. i h? - 20 t0 80°C.. " cf in Sweet Well Comsion," CORROSION/83, paper no. 46, (Houston. ,L, ., 6 - v,:' -q

It is possible to calculate the flow of water needed TX: NACE, 1983). ~3 SZ

to maintain undersaturation with F~CO, ~ ~ ~ 0 , . ln . ..., 13. A. Dugstad, K. Videm. 'CO, Corrosion of Steel Drums Used for Active -? '+ Waste," 1 l t h Scandinavian Corrosion Congress, Stavanger 1989.

practica' the flow of water condensing in a ' , ~ ~ ~ v 1 4 . M. Wicks, J.P. Fraser, "Entrainment of Water by Flowing Oil," Materials ;,! .; .. ,

pipeline systern can be expected to be less than this, -

Performance 14,5(05): p. 9.

'ihat ¡S, saturation will occur, and the dewaard- Q$& 15. U. ~otz , L. van Bodegom, C. Ouwehand, 7 h e ~f fec t of Oil or Gas Con-

Milliarns equation can be applied. densate on Carbonic Acid Corrosion," CORROSIONBO, paper no. 41. (Houston, TX: NACE, 1990).

.: 9 The temperature her re the de Waard-Milliarns pA 16. K. van Gelder. L. van Bodegom, J.A.M. Spaninks, M.J.J. Simon Tho- equation is applicable can be extended to higher mas, "Control of coz Corrosion in Wet Gas Lines by lnjection of GI~COI."

. temperatures by using a corre tor to account CORROSION188 paper, (Houston. TX: NACE, 1988). 17. Poseidon project: lnternal Reporl by lnstitute For Energy Technology, for the protection by corro-rns formed at - d K,el,r, Nomy 1g87.

: these temperatures. This f a c t o r irnplies the existente .d 18. Estavoyer. ~or ros ion Problems at ~ a c q ~ a i r Field." JInst.Petr. 46, 'of a temperature where the corrosion rate goes through a rnaxirnurn, which is called the scale tern- '.39. N.N. Bich, K.E. Sklarz, "Crossfield Corrosion Experience," CORRO-

SIONl88, paper no. 196, (Houston, TX: NACE, 1988). perature. b+'P-'20. fleqri_Cfed veritec repon to Nor?ke_gheli, -89. e:* At lower ternperatures, the film f o r r n e d in condens- 21. L. van Bodegom. K. van GeldG, M.K.F. Paksa, L. van Raam, "Efiect of

ing water in the top of a pipeline gives significant Glycol and Methanol on COZ Corrosion of Carbon Steel," CORROSlONl .

protection because of the low flow rates involved 88, paper no. 55, (Houston, TX: NACE, 1987). 22. J. Lammers paper presented at the European Oil and Gas Conference. . - here. Palermo, Italy, October 1990. .

* --9 reduction of corrosion rates to be expected 23. Gas Conditioning Fact ~ook , DOW Chemical. Fig.1.34, p.61.

( ' > 'ycol is injected into a wet gas transport line 24. McKette and Wehe. Hydroc Proc, Aug. 1958..

( 25. P.M.H. Geeien, K. Groenewoud, "lnternal Corrosion of Oli and Gas Con- calculated along the length o f the line with the duits and lis Prevenlion in the Netherlands: COZ Corrosion in Oil and

p t urosed rnodel. Gas Produclion, (Houston, TX: NACE, 1984), p. 456.

CORROSION-vol. 47, NO. 12 985