7/28/2019 7 de Abril Del 2013

1/9

0033-1732/05/4101- 2005 Pleiades Publishing, Inc.0076

Protection of Metals, Vol. 41, No. 1, 2005, pp. 7683. Translated from Zashchita Metallov, Vol. 41, No. 1, 2005, pp. 8290.Original Russian Text Copyright 2005 by Moiseeva.

Carbon dioxide corrosion was first faced with at gasand gas-condensate fields of the USA in the 1940s [1].In Russia, this problem dates from the 1950s (Krasno-dar region) [2]. Intense corrosion of oil and gas pipe-lines in West Siberia and oil and gas-condensate fields

of Ukraine and Belarus was first reported in the late1970s [24]. Carbon dioxide corrosion takes place inthe operation of gasher, pumping, and gas-lift oil, gas-condensate, and gas wells and in recovering oil underwater drive with the use of fresh water containing 3 to4% CO2

[2

15]. In [15, 16], we began to discuss thepatterns of carbon dioxide attacks on oil and gas fieldequipment and methods of their inhibition. The goal ofthis review is to further consider conditions for carbondioxide corrosion in oil and gas fields and discuss itsmechanisms with the aim of searching for the mostpromising lines of steel protection.

PECULIAR CONDITIONS FOR CO

2

CORROSIONOF STEEL IN OIL, GAS,

AND GAS-CONDENSATE FIELDS

At present, types of carbon dioxide corrosion in oil,gas-condensate, and gas fields are distinguished. Thedistinctions arise from the nature of an electrolyte andthe hydrocarbon phase, as well as from the possibilityof self-inhibition [1, 2]. Specific corrosion patterns inoil and gas wells are determined by differences betweenthem. The temperature in a common gas well (100 to150

C) is higher and extracted hydrocarbons are lighterthan those in an oil well (30 to 60

C). The oil well pres-sure is low, while the pressure in gas and gas-conden-sate wells reaches 30 to 35 MPa. Gas wells are usuallydeeper, their aqueous phase is less strongly mineral-ized, and the gas-liquid flow rate is higher [2, 17]. Aconsiderable temperature difference between the upperand lower parts of a gas well causes a variety of corro-sion attacks in the same well, which is not characteristicof oil wells [18]. The presence of two (electrolytehydrocarbon) or more phases in oil and gas wells givesrise to the distribution of CO

2

between them accordingto its solubility in the phases.

In oil wells

, CO

2

dissolves in 1 to 10% NaCl brinesupplied with oil; equipment is most intensely attackedby general corrosion at a water content of 70 to 85%[2, 17]. Because of pressure and temperature gradientsalong the well bore from the bottom hole to the well-

head and discharge lines, gases (including CO

2

) evolvefrom the solution; for this reason, the pH value at thewellhead (6.8 to 7.6) is higher than in the depth (4.2 to5.1) [2, 17]. Mineralized water in oil wells can containaliphatic (formic and acetic) acids, but their concentra-tions are mostly much lower than that of CO

2

and insuf-ficient to produce a serious effect on corrosion [1719].

Gas-lift oil wells are more susceptible to general andlocalized corrosion than pumping wells because of thehigher temperature t

and the higher concentration ofCO

2

(provided that CO

2

and H

2

S have not beenremoved from a working gas, so that the solution at thewell bottom shows pH 2 to 3) and a lot of water and O

2

is present in the injected gas [17, 19, 20]. In addition,low-molecular hydrocarbons of a gas condensate, incontrast to oil, exhibit no protective effect [2, 4].

In operated gas wells

more than 6000 m deep at high

total and partial CO

2

pressures ( ) and t

> 200

C

their production contains no liquid hydrocarbons, whilethe CO

2

content of the aqueous phase is 2 to 5%equipment is attacked by intense carbon dioxide corro-sion promoted by low-molecular carboxylic acids[21

23]. Carbon dioxide and carboxylic acids occupyseparate corrosion zones. Organic acids attack metaltubing at a depth of 120 to 150 m and at 40 to 100

C. In

this range, the corrosion rate is 1 to 3 mm/yr (shallowand deep pitting) [22].

In

gas-condensate wells

, corrosion attacks are usu-ally caused by CO

2

and H

2

S dissolved in water dropletscondensed on the tube walls. As a rule, tubing below thecondensation zone does not corrode. The pressure ingas-condensate wells, which determines the solubilityand corrosivity of carbon dioxide, usually exceeds 1

10

7

Pa [2, 17]. As noted in [11, 20], the corrosion ratedecreases from 4 to 5 to 0.2 to 2 mm/yr during the

PCO2

REVIEW

Carbon Dioxide Corrosion of Oil and Gas Field Equipment

L. S. Moiseeva

Scientific and Engineering Center, Oil Company LUKOIL, ul. Usacheva 11, Moscow, 119048 Russiae-mail: cselukoil@hotmail.com

Received August 6, 1999; in final form, December 3, 2003

Abstract

Conditions for carbon dioxide corrosion in oil, gas, and gas-condensate fields are discussed. Cor-rosion mechanisms in oil, gas, and gas-condensate fields and gas and oil pipelines are compared. Various factorsare shown to affect the CO

2

corrosion rate of steel in oil and gas field media.

7/28/2019 7 de Abril Del 2013

2/9

PROTECTION OF METALS

Vol. 41

No. 1

2005

CARBON DIOXIDE CORROSION 77

development of gas-condensate fields because of

decreasing and temperature. The corrosion pat-

tern becomes more uniform. However, when the initial

value is low, corrosion intensifies with time

because of a growing moisture content [11, 19].

Carbon dioxide corrosion of the underground equip-ment of gas-condensate fields can be substantiallyintensified by formic, acetic, propionic, and butyricacids; their total concentration in condensation watersis 500 mg/l, they are characterized by close pH values(

~

4.6), and iron salts are nearly equally soluble in them[17]. Corrosion is favored by high temperature (80 to90

C) and low pH (3 to 5). Even at the acetic acid con-centration of 15 to 20 mg/l, the corrosion rate by carbondioxide increases 1.5 to 2 times [19] and the corrosion

is initiated at lower [2022].

At present, the role of acetate ions in corrosion isconsidered complexly. First of all, it is taken intoaccount that in the presence of several acids, pH is

determined by the strongest one (

pK

= 4.76

[23], pK =

3.88 [24]) and that the best buffering

effect is exhibited by solutions with close pH and pK

a

values [23]. As a result of their interaction, hydrogenions are transferred from one buffer to the other (relax-ation reaction) [25]:

(1)

This makes carbonate solutions more acid, increasingthe limiting diffusion current of hydrogen ions. It is notimprobable that carboxylic acids affect metal directly;iron carboxylates were reported to inhibit, under certain

conditions, carbon dioxide corrosion in gas wells [25].

MECHANISMS OF THE CARBON DIOXIDECORROSION OF STEEL

At different segments of the same unit (e.g., an oilwell), CO

2

corrosion can follow different mechanismsbecause of changing conditions. On the whole, themechanisms of the carbon dioxide corrosion of steel inoil and gas fields are complex and many-sided, yetbeing characterized by some common features. Twopeculiar effects of CO

2

were reported in [1, 9, 1215,2527]: (1) more intense cathodic evolution of hydro-gen than that expected from the acidity of the solutionand (2) the formation of carbonate films at the anodicmetal surface. The first effect is associated with thebuffering properties of carbonic acid [1, 13, 15, 25, 26],while the other, with the low solubility of iron carbon-ate [1, 9, 1214, 2527]. It was experimentally provedin [26] that carbonic acid solutions are more corrosivethan solutions of the stronger acids (e.g., HCl) at thesame pH value, which is quite natural since the latterexhibit no buffering effect.

PCO2

PCO2

PCO2

aCH3CO2H

aH2CO31( )

H2CO3 Ac

HAc HCO3.+ +

Two viewpoints are involved when treating thecathodic process at carbon steels in oil and gas fields[315]. One viewpoint assumes that in the presence ofCO

2

, it is H

3

O

+

cations generated near the cathode thatare mainly reduced, while buffering carbonic acidserves as their source.

According to the other, carbonic acid itself (or, at

elevated temperatures, HC ions) serves as a protoncarrier [1, 7, 9, 10, 1214, 16, 24, 25]. Homogeneous,heterogeneous, and mixed depolarization mechanismsare distinguished [1, 9, 10, 1216, 2634]:

(2)

(2a)

(3)

with the subsequent regeneration of carbonic acid [10]:

(4)

Actually, this means that carbonic acid combines thefunctions of a buffer and a carrier of discharging proton[9, 10, 3036]. Apparently, homogeneous and hetero-geneous depolarization mechanisms may be applied toany of the possible depolarizers involved in thecathodic reaction, including hydroxonium ions.

In neutral and weakly basic media, the equilibrium

(5)

is shifted to the right, which accounts for carbonatedeposition in water lines.

For reaction (3), De Waard and Milliams [10, 31]take the standard kinetic equation

(6)

where k

c

is the cathodic reaction rate constant, [H

2

CO

3

]is the concentration of carbonic acid in solution,

E

isthe activation energy of the process, and n is the reac-tion order in H

2

CO

3

. Taking the Henry law for the sol-ubility of CO

2

in mineralized water and the vant Hoffisobar G

= G

exp(

H

/

RT

)

(where

H

is the change inthe enthalpy during dissolution and G

is the Henry con-stant), they derive the temperature dependence [3, 10]

(7)

In [3], its antilogarithmic version was reported:

(8)

where k

c

is the cathodic reaction rate constant andE

c

isthe potential of the cathode through which a currentflows.

In a hydrogen atmosphere, the potentials of the elec-trode reactions under consideration [29] satisfy the

O3

HCO3sol

e

Hads CO32

,+ +

HCO3near-el

Hads e

H2 CO32

,+ + +

H2CO3sol e Hads HCO3ads

,+ +

HCO3ads

H3Onear-el+

H2CO3ads H2O.+ +

HCO3

OH

+ H2O CO32

+

ic kc H2CO3[ ]n E/RT( ),exp=

iclog kclog E/2.3026RT( ) n PCO2

.log+=

ic = kcPCO2nG0n

nH/RT( ) 2.3Ec/bc( )exp( ),exp(

7/28/2019 7 de Abril Del 2013

3/9

78

PROTECTION OF METALS Vol. 41 No. 1 2005

MOISEEVA

equation

(9)

The Tafel slope of the cathodic voltammogram of low-carbon steel in two-phase carbon dioxide media is closeto a classic value of 120 mV, being sometimes affectedby diffusion control [5, 35].

For synthetic stratal water of the Samotlor oil field( = 1 to 100 kPa, [Cl] = 17 g/l, pH 6.5), bc = 0.115

to 0.128 V [3]. For 3 in the mineralized waterkero-sene two-phase system saturated with CO2 and acidi-fied to pH 2, we obtained bc = 0.11 V [29]; this valuecorrelates, for a heterogeneous metal surface, with theslow electrochemical desorption theory. However, thebc value alone is insufficient to specify the mechanismof cathodic hydrogen evolution during CO2 corrosion.

According to [3], the kinetic parameters Ec/pHand /pH (Ec is the cathode potential at a currentic) in the stratal water of oil fields at = 1 to 100 kPa

unambiguously fit neither the slow discharge nor slowmolization theory and different mechanisms are validfor different areas of the electrode surface.

In the most general case covering the whole range ofpossible conditions in oil and gas fields in the presenceof CO2 , the cathodic current can be written as ic =

+ + + + . Each term can vary

from 0 to the total (or part of the total) depending on

pH, , t, the chemical composition of the medium,

and its flow rate [15, 16].

When comparing the proposed schemes for the

cathodic process [1, 3, 7, 912, 15, 3038] with the datafor ion equilibria in carbon dioxide media [3941], onecan distinguish between the ranges in which one oranother depolarizer is dominant. The most probabledepolarizers are H2CO3 and H3O

+ at pH < 5 ([H2CO3]

100%), HC and H2CO3 at 5 pH < 6.8 ([H2CO3]

30%, [HC ] 70%), HC at pH 6.8 ([HC ]

100%), and H2O and HC at pH > 7.

In deep and ultradeep gas wells, an intense CO2attack occurs in the upper part of the well bore (watercondensation zone) [10, 25]. Because pH is low and the

concentration of carbonic acid is high, the cathodic pro-cess can roughly be represented as its direct reductionfollowed by regeneration in reaction (4).

In special cases (e.g., in CO2-saturated aqueous cal-cium chloride; [CaCl2] up to 30%, pH 2 to 4, t= 20 to107C), CO2 itself can be successively reduced to for-mic acid, formaldehyde, and further to methane [37, 38,4144]:

(10)

Er 0.059pH= 0.295 PH2.log

PCO2

iclog

PCO2

iH2CO3 iHCO3 i

H3O+ iH2O iO2

PCO2

O3

O3

O3

O

O3

CO2 2H3O+

2e

HCOOH 2H2O,+ + +

(11)

(12)

(13)

In [38], these reactions were believed to be respon-sible for an increased steel potential in a wet ground

through which CO2 had been passed; however, this isquestionable simply because the equilibrium potentialof reaction (10) is more negative by about 0.2 V thanthe hydrogen potential at the same pH value.

During cathodic polarization of pipe steels in car-bonate electrolytes (0.5 M NaHCO3 + 0.5 M Na2CO3)starting from free corrosion potentials, an anomalousanodic loop was observed [45]. X-ray powder diffrac-tion analysis revealed that the surface film covering171 steel at 22 and 42C consists of FeOOH, whilethe film at 82C is formed by iron carbonates. The iden-tified surface compounds are not primary corrosionproducts, yet their nature is obviously temperature-

dependent.The formation of carbonateoxide films is closely

related to anodic metal dissolution. Earlier [15, 16], wedescribed in detail the main groups of dissolution reac-tions in the media of oil and gas fields in the presenceof CO2 . The most typical anodic reactions are:

at pH < 7,

(14)

and at pH > 7, in the presence of oxygen,

(15)

Most of researchers [912, 30] assign a significantrole to OH ions in the anodic process during CO2 cor-rosion. Heusler [46] and Bockris models [47] areoften said to be classical. According to Heusler, the sur-face compound FeOHads acts autocatalytically. The lim-iting step is

(16)

The kinetic equation has the form

(17)

where ka is the anodic reaction rate constant, is thetransfer coefficient, and is the activity of OH

ions.

According to Bockris [47], the limiting step is

(18)

and the kinetic equation is written as

ia = ka exp[(1 + )FE/RT]. (19)

HCOOH 2H3O+

2e

HCOH 3H2O,+ + +

HCOH 2H3O+

2e

CH3OH 2H2O,+ + +

CH3OH 2H3O+

2e

CH4 2H2O,+ + +

Fe 2H2O Fe OH( )2s 2H+

2e,+ + +

2Fe O2 2H2O 2Fe OH( )2s .+ +

Fe FeOH( )ads OHads

FeOHads FeOH+

2e.+ + +

ia kaaOH2

1 2+( )FE/RT[ ],exp=

aOH

FeOH FeOH+

2e,+

aOH

7/28/2019 7 de Abril Del 2013

4/9

PROTECTION OF METALS Vol. 41 No. 1 2005

CARBON DIOXIDE CORROSION 79

In the former case, the reaction order m in hydroxylion is two and ba = 30 mV. In the latter case, the slopeequals 40 mV. For 3 in a CO2-saturated two-phasesystem at pH 2 and 20C, we obtained ba 40 mV [28].For a steel electrode in synthetic stratal water of the

Samotlor oil field ( = 1 to 100 kPa, [Cl] = 17 g/l,

pH 6.5, 50C), ba = 0.1 V and m 0.7 [3]; i.e., neither

individual mechanism is valid.Lorenz et al. [48] assumed that the process includes

a number of series ((20)(24)) and parallel chemicaland electrochemical reactions ((24), (25)):

(20)

(21)

(22)

(23)

(24)

(25)

Currents (20), (21), (23), and (25), which add up togive the net current, involve adsorbed speciesFe(OH)2ads and FeOHads.

According to the theory developed by Kolotyrkinand his school [49, 50], the electrochemical dissolutionof metals includes adsorption-electrochemical andchemical steps. Electrolyte anions are directly involvedin the anodic reaction to give unstable intermediatecomplexes, even though they are not components of thefinal reaction product.

With the participation of OH ions, the kinetic equa-

tion takes the form [10, 31]:

(26)

where ka is the anodic reaction rate constant,Ea is thepotential of the anode through which a current ia flows,

and m is the reaction order in OH.

Carbonateoxide films play an important role in thecarbon dioxide corrosion of iron. Ultimately, the corro-sion rate depends on their composition and structure,while their protective properties are primarily deter-mined by the tand the pH of the medium [1, 5, 814,18, 29, 3032]. These films exhibit a poor protectiveeffect at pH < 7 and a good one at pH > 7; at pH 7,both nonprotective and protective films can form. AtpH < 7, the corrosion rate can vary stepwise with pH.For instance, the highest corrosion rates were found in3% NaCl at pH ~ 6.6, 5.6, and 4.2 [8, 51]. In water linesfor stratal and waste waters of oil fields, a shift in pH tobasic values increases the risk of intense carbonate dep-osition because stratal water contains calcium ions.

In [9, 11, 13, 14], films formed during the carbondioxide corrosion of ferrous metals at t< 20C werefound to contain iron and oxygen in nearly 1 : 2 ratio

PCO2

Fe H2O+ FeOHads e,+

FeOHads FeOH+

e,+

FeOH+

H+

Fe2+ H2O,+ +

FeOHads H2O+ Fe OH( )2ads H+

e,+ +

Fe OH( )2ads A

Fe OH( )A OH,+ +

Fe OH( )2ads H+ FeOH+ H2O e.+ + +

ia ka OH[ ]

m2.3Ea/ba( ),exp=

and possibly water. May be, this is FeOOH formed inthe reactions

(27)

(28)

According to [9, 52], the corrosion mechanismchanges at 40 to 60C: the corrosion rate is now deter-mined by a siderite film (FeCO3). At t < 60C, the

anodic formation of FeHC and the cathodic dis-

charge of H2CO3 (at pH < 5) are the limiting heteroge-neous steps. The resulting porous films exhibit no pro-tective effect.

At t 60C, corrosion products form a denser pro-tective film, thus changing the limiting step [9]. Nowthe corrosion rate is controlled by the deposit solubilityand permeability and hence is pH-dependent: with adecrease in pH, the corrosion rate increases. However,

this dependence is ambiguous.Iron carbonate can both form immediately at the

metal surface and precipitate from solution. In theformer case, its formation includes several steps, thenumber and sequence of which depend on the pH of themedium [1, 9, 12, 51]. These steps were described indetail in [15].

In real oil fields at t> 60C, crystalline forms of ironcarbonate contain calcium and magnesium carbonates

[52]. The higher the concentrations of C , iron, and

calcium in solution, the lower the dissolution rates ofsiderite and calcite [37, 38, 53, 54]. In neutral and

weakly basic media over the temperature range from 20to 100C, siderite dissolves more rapidly than iron(II)hydroxide so that the adsorption of carbonate ions stim-ulates the destruction of a passive hydroxide film [37,38].

At t> 100C, the fraction of iron carbonate in thelayer of corrosion products is reduced, while the con-tent of magnetite Fe3O4 grows [9]. This suggests animportant role of a summary reaction [13, 14]

(29)

At t> 150C, siderite decomposes and undergoes

surface hydrolysis to give Fe3O4 and Fe2O3, thus signif-icantly decreasing the corrosion rate to ~1 mm/yr. In [1,29, 31, 49, 5260], this effect is believed to be respon-sible for easy steel passivation in carbon dioxide media.

It should be noted that graphite inclusions (1 to 2%)were detected in corrosion products in a number of gaswells operated at t> 80C [25]. Apparently, graphiteforms in a summary reaction

(30)

Fe O2 2H2O Fe OH( )2s ,+ +

4Fe OH( )2 O2+

4FeOOH mH2O 2 m( )H2O.+

O3+

O32

3Fe 4H2O Fe3O4 4H2.+ +

3Fe 2CO2 Fe3O4 2C+ +

7/28/2019 7 de Abril Del 2013

5/9

80

PROTECTION OF METALS Vol. 41 No. 1 2005

MOISEEVA

Carbon steel corrosion in water and NaCl solutions

at = 0.002 to 6 MPa yields several types of films

[8, 13, 14]:

(1) transparent films difficult to discern visually,which contain FeO H2O and FeOOH. These stable

films form at t< 20C even in the absence of Fe2+ ionsfrom solution, though their presence substantially

accelerates the film formation;(2) predominantly siderite films form in media satu-

rated with Fe2+ at t> 40C (at pH 6 to 8, even at roomtemperature);

(3) thin films with cementite inclusions (Fe3C) format 60 < t< 90C;

(4) high-temperature (predominantly magnetite)films form at t> 90C.

The protective properties of transparent films areenhanced with time. After a one-week exposure, thecorrosion rate decreases ten times and the specimensare passive [13, 14, 33]; this is not the sole type of low-temperature films.

After a prolonged (>7 days) exposure sufficient forthe solution to be saturated with Fe2+ ions, an upper sid-erite layer can form to give two-layer films at room andlower temperatures [7, 13].

The solubility of siderite increases with an increase

in and diminishes with an increase in the temper-

ature; for this reason, an increase in both the tempera-ture and pH of the medium enhances the protectiveproperties of siderite films, making them more adhesiveand less permeable [13, 14].

In CO2-containing water, films can either form ordissolve. The direction of the process is determined by

the concentration of Fe2+ and the pH of solution. When[Fe2+] is lower than the limiting solubility (30 mg/l) inCO2-saturated NaCl solutions, the formation of FeCO3stops and its film begins to dissolve. At pH > 6, theeffect of [Fe2+] is insignificant because of the very lowsolubility of FeCO3. The critical concentrations of Fe

2+

ions in simulated stratal water were reported in [8].

Later, the phase diagram of FeCO3 for Nizhne-vartovsk oil fields was plotted from the calculated satu-

ration indices of the aqueous phase [3]. At =

60 kPa, [HC ] = 750 mg/l, and [Fe2+] = 10 mg/l, the

protective siderite layer covers steel even at 20C. Atemperature range from 20 to 50C was reported forcarbon dioxide media in some other works [7, 11].

When passing from one temperature range toanother, both the compositions and structures of surfacelayers change. The limiting step can be the dissolutionof FeOOH, FeCO3 , or oxides. In the first case, the dis-solution rate depends on the concentrations of anionsand hydrogen ions in solution and deposit pores; in the

second case, on the concentrations of C and Fe2+

PCO2

PCO2

PCO2

O3

O32

ions; in the last case, on the concentrations of HC

and FeOH+.

ESTIMATION OF THE EFFECT OF VARIOUSFACTORS ON CARBON DIOXIDE CORROSION

Oil field media favoring carbon dioxide corrosionvary in pH from 2 to 8 and in temperature from 15 to

200C. Even in the same oil field, the operating condi-tions do not remain constant. Contributions from many

factors (temperature, pH, , the chemical composi-

tion of mineralized water, etc.) were estimated by gen-eralizing the literature data [1, 2, 9, 11, 1719, 5365].For instance, under the real conditions of oil and gasextraction, an increase in the gas-liquid flow rate from1 to (8 to 10) m/s accelerates the carbon dioxide corro-sion 1.5 to 2 times but then inhibits it; however, at flowrates of 10 to 12 m/s, the corrosion rate increases again,

especially in eddy flows [2]. With a decrease in in

wells, the maximum Vcor value and the erosive corro-

sion range are shifted to higher flow rates, which pro-vide better supply of CO2 and, hence, acidification ofthe near-electrode layer to make corrosion more intense[14, 5359].

Carbon dioxide corrosion is mostly controlled bymixed kinetics and therefore is strongly temperature-dependent. At t< 20C, the restrictions are few and thecorrosion rate is virtually independent of the flow rate;the limiting step is the heterogeneous discharge of

adsorbed H2CO3 molecules or HC ions. At t> 60C,when the corrosion is controlled by siderite dissolution,the role of the flow rate becomes decisive [5355]. Thecorrosion rate is limited by the removal of the dissolved

substance (the concentration gradients of Fe2+ and

C ions between the surface and the bulk of electro-

lyte) and described by an equation [54]:

(31)

where Sis the surface area of a specimen, SP is the sol-ubility product of siderite at 60C, and [Fe2+] and

[C ] are the concentrations of these ions in solution

(mg/dm3).

It was found [59] that the dependence of the corro-

sion rate on the flow rate of CO2-saturated mineralizedwater (

7/28/2019 7 de Abril Del 2013

6/9

PROTECTION OF METALS Vol. 41 No. 1 2005

CARBON DIOXIDE CORROSION 81

an additional one to two hours for the surface to becompletely covered with a gray or black deposit. Theprocess (at 50C) is stabilized over less than 3.5 h andthe final corrosion rate Vcor (7 to 9 h) remainsunchanged. An increase in pH favors deposition. At

pH < 6.5 and high values, no deposit forms [6,

60].

For real flows in an oil or gas well, the dependenceis more complicated. With an increase in the partialpressure of CO2 to 0.3 MPa, the corrosion rate steeplyincreases but then its growth sharply decelerates toreach a level of 5.7 mm/yr at 1.2 MPa [2, 6].

Several equations relating and temperature to

the corrosion rate were proposed. Among them, the DeWaardMilliams equation is best known [10]:

(32)

where Vcor is the corrosion rate (mm/yr) and is the

partial pressure of CO2 (MPa). The equation is valid at< 1.0 MPa and t< 140C [3, 10]. In [3], it was

extended to > 1.0 MPa and modified by introduc-

ing a pH-dependent term. For stratal water of theSamotlor oil field saturated with CO2 (1 to 100 kPa), theresulting equation

(33)

is valid for 10 < t< 60C, 5.4 < pH < 7.6, 0.001