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H2S/CO2 Corrosion of X60 Steel under Wet Gas Environment
 
 
Xinru Wang1
, LeiZhang1
, Wei Yu2
, Jianwei Yang1
, Jinhui Ding1
, Minxu Lu1
 
1
Corrosion and Protection Center University of Science and Technology Beijing, Beijing, 100083, P R China
2
The First Oil Production Company, Daqing Oilfield Company Ltd, Daqing, 163000
 
ABSTRACT
The study investigates the influence of H2S on carbon dioxide (CO2) on top of the line corrosion (TLC) both
experimentally and theoretically. The experiments were conducted in hydrogen sulfide(H2S) wet gas
autoclave.Experiments were performed for 120 hours under the constant H2S/CO2 partial pressure ratio (pH2S/CO2=1.7)
using a superficial gas velocity (Vsg) of 1 m/s. Weight loss (WL) method was used to investigate the scale formation
using X60 carbon steel as substrates. Scanning Electron Microscopy (SEM/EDS), X-ray Diffraction methodology
(XRD) were used to analyze the scale. The experimental results show that the H2S corrosion in CO2/H2S system in the
paper plays a leading role. Under 1.0~2.5MPa H2S partial pressure, the corrosion scale was stratified. Mackinawite was
the predominant scale formed on the steel surface. It was also found that ferrous ions forming mackinawite scale
mainly come from Fe
2+
 released from the steel surface.Under 2.0 MPa H2S partial pressure, localized corrosion was
identified on the steel surface. And under 2.5MPa H2S partial pressure, pyrrhotitewhich has whole crystal shapewas
observed.The corrosion scale near the solution was loose and  sulfur-rich while it was dense andsulfur-poor near the
matrix.This paper provides the reference forthe influence of H2S on CO2 on top of the line corrosion (TLC).
Key words: Top-of-the-Line Corrosion, wet gas, H2S/CO2, High H2S partial pressure, corrosion scale, hydrogen
permeation
 
INTRODUCTION
Top-of-the-Line Corrosion (TLC) is a phenomenon encountered in the oil and gas industry. The first TLC case was
reported in 1960[1~2]
, when they detected severe localized TLC in the gas system at the sour gas field of Lacq in France.
It occurs exclusively in wet gas transportation and in a stratified flow regime. Later, there are some examples about
TLC found in many countries, such as Canada, America and India
[3]
. 
 
CO2 corrosion is the most prevalent form of attack encountered in oil and gas production; it is also a major concern in
the application of carbon steels. CO2 corrosion phenomena have been widely studied
[4~7]
. However, understanding and
control of top of the line corrosion (TLC) lags significantly behind general understanding of corrosion when H2S is
present. Top of the line corrosion occurs in multiphase flow or during wet gas transportation when water vapor
condenses on the internal walls of the pipeline, due to the heat exchange occurring between the pipe and the
surroundings
[8]
.The dissolution of corrosive gases, such as carbon dioxide (CO2) and hydrogen sulfide (H2S) as well as
Paper No. 
11006 2
 
condensation of acidic vapors such as acetic acid (HAc)  in the droplet can cause serious corrosion problems at the
metal surface. A growing concern is focus on TLC in the oil and gas industry and exploring a better understanding of
the corrosion mechanisms. Many researches formerly made a large amount of work in H2S/CO2 corrosion and
protection in solution immersion environment
 [9~14]
.But only a few researchers investigate the corrosion behavior in the
wet gas environment containing H2S/CO2
[15~17]
.There searchers
 [18~19]
show the corrosion mechanism under the
coexistence between H2S and CO2containscompetition and synergistic effect. However, the effect of small quantities of
H2S on TLC remains unknown to date. In the light  of past TLC related failures of sour wet gas lines
[20]
, a better
understanding of the corrosion mechanism and laws under high H2S partial pressure (>1MPa) in wet gas environment is
required.
Surface scale formation is one of the important factors governing the rate of corrosion. In this work, it discussed that
high H2S partial pressure (0.15MPa~2.5MPa) in the wet gas environment containing H2S and CO2 had an effect on the
corrosion rate, corrosion scale, corrosion types of API-X60 pipeline. The structure of corrosion scale and the corrosion
mechanism was studied in detail. It provides the theoretical reference for the exploring the sour oil and gas fields
containing high sulfur.
EXPERIMENTAL PROCEDURE
API-X 60 carbon steel was used in all experiments. The chemical composition is shown in Table1. All specimens were
degreased with acetone, grinded mechanically with carborundum paper, washed in water, and put in absolute ethyl
alcohol. The specimens were placed in a high temperature and high pressure H2S wet gas autoclave made of Hastelloy
C276 simulating flowing wet gas environment and then average corrosion rate was calculated by the WL method. The
temperature of gas phase was controlled by heating system of autoclave to simulating high temperature inside the pipe.
Temperature difference between the gas phase and specimen surface was controlled by the cooling system around the
specimens to simulate the lower temperature of internal walls. The temperature of gas phase and cooling water in the
autoclave is 60℃ and 30℃ respectively. The gas flow rate of 1m/s was set. After the specimens were installed, high
purity nitrogen was purged through the solution in the autoclave for over 24 hours. When the temperature of autoclave
reached to 60℃, fine H2S and CO2were input into the autoclave up to scheduled pressure. All the experiments had the
same partial rate (pH2S/pCO2=1.7), and the H2S partial pressure was 0.15MPa,  0.33MPa, 1.5MPa, and 2.5MPa. The
experimental period is 120 hours. Analysis of the morphology of corrosion layer was performed by LEO-1450
Scanning Electron Microscopy (SEM); its elemental composition and phase composition was determined by Energy
Disperse Spectroscopy (EDS) and X-Ray diffraction patterns (XRD) of RIGAKU 12kw rotating anode respectively.
 
RESULTS AND DISCUSSION
Corrosion Rate
Dense corrosion scale which formed in wet gas environment under 0.15MPa~ 0.3MPa H2S partial pressure integrally
covered on the surface of the specimens. Under2.0MPa H2S partial pressure, the amount of surface corrosion scale
increased, integrity of films became worse and it presented lamellar shapes after it was dehydrated. Slight pitting was
identified after we removed the corrosion scale (Figure 1). Above the 2.0MPa of the H2S partial pressure, the amount of
corrosion scale was decreased, but could cover the matrix integrally. Table 2 shows the corrosion types under different
H2S partial pressure.
 
In wet gas environment, thin liquid film on the surface of metal which dissolved sour gas results in the metallic
corrosion. The change of pH value in liquid film leads to  different anodic dissolution rate under the film and form
different morphology of corrosion scale. The speed of the reaction in the area where mackinawite crystal was the
predominant scale (Figure2a) was rapid, while the speed of the reaction in the area where pyrrhotite and cubic ferrous
sulphide (FeS) was the predominant scale (Figure 2b) was slow. This corrosion process could lead to local non-uniform
corrosion under the film.
 
Figure 3 shows the relationship between H2S partial pressure and average corrosion rate of X60 pipeline steel by WL
method in wet gas (H2S +CO2) environment under H2S/CO2 partial pressure ratio of 1.7MPa. The corrosion rate of X60
increased with the H2S partial pressure under 0.15MPa~2.5MPa H2S partial pressure. The relationship is different from 3
 
that in simulated solution
[21]
. The first reason is that the pH value in the interface of condensed liquid film/Metal in wet
gas environment is different from it in immersing solution. The second reason is that corrosive reactants are easy to
reach the reactive nterface by flowing solution and it accelerated the corrosive processing. Third, metallic Wall shear
force and the destructiveness of corrosion scale in flowing solution are more critical than it in wet gas environment.
Surface Analysis
The surface appearance of the coupons was recorded immediately after their removal from the holder. The XRD
spectrograms of corrosion scale are shown in Figure 4. In all cases, the layer seen there had similarities. The corrosion
scale was composed of FeXSy, and FeCO3 wasn’t observed. It reveals that the corrosion process of X60 steel in wet gas
environment is controlled by H2S under the H2S/CO2 partial pressure ratio of 1.7. Mackinawite (FeS1-x) crystal was the
predominant scale formed on the steel surface under 0.15MPa~2.5MPa H2S partial pressure. Little amount of cubic
ferrous sulphide (FeS), pyrrhotite and troilite were observed under 1.5MPa H2S partial pressure. Beside the
mackinawite, the amount of monoclinic pyrrhotite crystals (Fe1-xS) obviously increased with H2S partial pressure under
1.5MPa~2.5MPa H2S partial pressure. Beside the mackinawite, the content of cubic ferrous sulphide and troilite rose
with H2S partial pressure under 1.5MPa~2.5MPa H2S partial pressure, but the absolute content still remained low.
 
The morphology of corrosion scale under different H2S partial pressure is shown in Figure 5. The composition of
corrosion scale in wet gas environment under 0.15MPa~0.3MPa H2S partial pressure changed from amorphous
mackinawite grains to coarse irregular mackinawite grains (Figure 5a), and a little cubic FeS was identified at the
boundary and breakage. Less than 1.0~1.5 H2S partial pressure, much cubic ferrous sulphide (FeS) and pyrrhotite was
observed instead of coarse mackinawite on the surface. The structure of the corrosion scale is loose and had many bag
holes, in which FeS1-x was observed (Figure 5b,c).Under 2.5MPa H2S partial pressure, there were prismatic coarse
grains and many nucleated pyrrhotite (Figure 5d). It had complete crystal shapes which were composed of Fe1-xS by
XRD. The content of sulfide was about 37%, which was the  same with pyrrhotite. And the hydrogen blistering was
identified on the surface of X60 under 0.3~2.5 H2S in wet gas environment.
 
Figure 6 is the corrosion scales cross-section for X60 under different H2S partial pressure. The type of corrosion
changed from general corrosion to location corrosion with H2S partial pressure increasing. The corrosion scale was
thick in wet gas environment, and the partial pressure could influence it. The interface bonding force of film/metal
matrix became smaller (Figure 6d).
 
The delamination was observed in the corrosion scale. The structure of the corrosion scale near the solution was loose
while it was dense near the matrix. The sulfide content of the corrosion scale near the solution was higher than it near
matrix (Figure 7). 
 
H2S dissolved in liquid film and the ionization reaction happened: H2S→HS-
+H-
;HS→H-
+S2-
. During the corrosive
process initially, much Fe
2+
 which was formed by anode reaction consumed HS-
and S-
 near the specimens. Iron-rich
FeS1-x was formed at the same time. Fe
2+
 from the anode reaction diffused through films and was precipitated to pyrite
compounds. The whole corrosion process was controlled by the diffusion of Fe
2+
. The corrosion process was limited by
the diffusion of Fe
2+
, and the dense films restrained corrosion; and conversely accelerated it. Under 2.0~2.5MPa H2S
partial pressure at the temperature of 60o
C，X60 had a high corrosion rate, and a thick corrosion scale while the
delamination of the corrosion scale was not obvious. So initial corrosion scale didn’t restrain corrosion and protect the
matrix, which accelerated the corrosion. Because of the high Fe
2+
 content on the interface of film/matrix, Fe
2+
 diffused
from matrix to outside through films. The corrosion scale restrained the diffusion, so the content decreased gradually.
However, the HS-
 diffused from the outside to the matrix through films, so it formed sulfide-rich phase outside the film
and poor sulfide near the matrix.
 
In wet gas environment under 1.0~2.0 H2S partial pressure, the corrosion scale was stratified (Figure 8). The dense
corrosion scale made of mackinawite was on the ground floor. However, the crystal was small on the surface, whose
structure was complicated. And it changed into sulfur-rich pyrrhotite. 
 
 4
 
CONCLUSIONS
(1) The corrosion rate of X60 under the partial pressure ratio (pH2S/CO2=1.7) in flowing wet gas environment increased
obviously with H2S partial pressure under 0.15MPa~2.5MPa H2S partial pressure. Under 1.0~2.0MPa H2S partial
pressure, the corrosion scale was stratified. Mackinawite was the predominant scale formed on the steel surface. Under
2.0MPa H2S partial pressure, localized corrosion was identified on the steel surface. And under 2.5MPa H2S partial
pressure, pyrrhotite which has whole crystal shape was observed. 
(2) The corrosion process of X60 under the partial pressure ratio (pH2S/CO2=1.7) in flowing wet gas environment was
controlled by H2S. The corrosion scale near the solution was loose and sulfur-rich while it was dense and sulfur-poor
near the matrix.
(3) The hydrogen blistering was identified on the surface of X60 under 0.3~2.5MPa H2S in flowing wet gas
environment.
 
REFERENCES
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Corrosion/1999[C]. Houston: NACE, 1999: 36
[2] Estavoyer E. Corrosion Problems at Lack Sour Gas  Field. NACE publication H2S corrosion in oil and gas
production[M].Houston Texas,1981:905
[3] Mark A, Edwards, Cramer B. Top of line corrosion-diagnosis, root cause analysis, and treatment[C].Corrosion
2000.Houston Texas: NACE International ,2000:72
[4] Waard C., Milliams D.E., Corrosion 31,177(1975)
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Corrosion 99, Paper 36, (Houston, TX:NACE 1999)
[6] Kermani M. B., Morshed A. Corrosion 52,280 (1996)
[7] Nesic S., Postlethwaite J., Olsen S., Corrosion 52, 280(1996)
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Paper No. 08470,2008
[9] Chen C F, Lu M X, Zhao G X,  Bai Z Q,  Yan M L, Yang Y Q.ActaMetall Sin, 2003;39:94
[10] Su W., Nesic S., Papavinasam S.,Corrosion 2006, NACE. Paper No. 06644,2006
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[12] Bai Z Q,  Li H L,  Liu D X,  Wang X F. MaterProt, 2004:36(4):32
[13] Li G M,  Liu L W,  Zheng J S.  J Chin SocCorros Prot. 2000;20:204
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[15] Bich N N. Corrosion 2006. NACE, Paper No. 06642,2006
[16] Jiang F, Dai H Q, Cao X Y, Huang H B. ChemEng Oil Gas, 2005;34:213
[17] Zhang Z, Hinkson D, Singer M, Wang H, Nesic S. Corrosion 2007.NACE, Paper No. 07556,2007
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NACE. Paper No. 02235,2002
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[20] Gunaltun Y. M., Supriyatman D., Jumaludin J., Top of the line corrosion with calculated water condensation rates,
Corrosion 00, Paper 71, (Houston, TX:NACE 2000)
[21] Lei Zhang, Wen Zhong, Jianwei Yang etc. “Effect of Temperature and Partial Pressure on H2S/CO2 Corrosion of
Pipeline Steel in Sour Conditions,” NACE Corrosion 2011, Paper No. 11079 
 
 
Table1Chemical composition of the X60( wt% )
Materials C Si Mn S P Nb Ti Mo V Cu Ni
X60 0.071 0.26 1.10.0041 0.0024 0.042 0.006 0.003 0.025 0.01 0.024
 5
 
 
 
Figure1.SEM surface images of X60 removed the corrosion scale in wet gas (pH2S=2.0MPa)
 
Table 2 Corrosion Types under different H2S partial pressure
H2S Partial pressure
(MPa)
0.15~0.3 0.3~2.0MPa  2.0MPa >2.0MPa 
Corrosion type
General
corrosion
General corrosion
(hydrogen blistering)
Localized
corrosion
General
corrosion
 
  
Figure2. The structure of crystal in different area in corrosion scale
( a ) FeS1-x, ( b ) Cubic FeS and Fe1-xS
 
0.00.51.01.52.02.5
0.0
0.5
1.0
1.5
2.0
2.5
General corrosion rate, mma
H2
S partial pressure , MPa
pH2S/pCO2
=1.7
Wet gas temperature 60℃
Cooling water temperature 30℃
 
Figure 3.The relationship between average corrosion rate with H2S partial pressure in wet gas environment
（pH2S/pCO2=1.7）
(a)  (b)6
 
20406080100
1
1
4
4 4 4 3 3
3 3 3
2
2
2
2
2
2
1
1
1
1
1
1
1
1 1 1
1 1
1
pH2S=1.5MPa
pH2S=2.5MPa
pH2S=0.3MPa
 
  Intensity, CPS
2 deg
1-Mackinawite-FeS1-x
 
2-Pyrrhotite-Fe1-x
S
3-Troilite-FeS
4-Cubic FeS   
1
2 3
4
 
Figure 4.XRD patterns of corrosion scales formed under different H2S partial pressure
 
  
 
  
Figure 5. SEM surface images of the corrosion scales for X60 with the different H2S partial pressure
 (a) pH2S=0.3MPa,  (b) pH2S=1.0 MPa,  (c) pH2S=1.5MPa, (d) pH2S=2.5MPa
 
   
   
(d) (c) 
(b) (a) 
(a)  (b)
Scale  (c)  (d)7
 
Figure 6. SEM images of the corrosion scales cross-section for X60 with the different H2S partial pressure
(a) pH2S=0.3MPa,  (b) pH2S=1.0 MPa,  (c) pH2S=1.5MPa, (d) pH2S=2.5MPa
 
 
 
Figure 7.Distribution of S and Fe on the corrosion scales cross-section (a) Fe, (b) S
 
  
Figure 8. SEM surface images of the corrosion scales for X60 at 2.0MPaH2S partial pressure
 (a) inside and outside of the corrosion scale, (b) delamination of the corrosion scale
 
 
(a)  (b)
(a)  (b)2787