Bai, H. - Effect of CO2 partial pressure on the corrosion behavior of J55 in crude mixture

materials
Article
Effect of CO2 Partial Pressure on the Corrosion
Behavior of J55 Carbon Steel in 30% Crude
Oil/Brine Mixture
Haitao Bai 1 , Yongqing Wang 1, *, Yun Ma 2 , Qingbo Zhang 2 and Ningsheng Zhang 2
1
2
*
Institute of Petroleum and Gas Engineering, Southwest Petroleum University, Chengdu 610500, China;
[email protected]
College of Petroleum Engineering, Key Laboratory of Environment Pollution Control Technology of Oil Gas
and Reservoir Protection in Shaanxi Protection, Xi’an Shiyou University, Xi’an 710065, China;
[email protected] (Y.M.); [email protected] (Q.Z.); [email protected] (N.Z.)
Correspondence: [email protected]; Tel.: +86-150-9186-5583
Received: 22 August 2018; Accepted: 17 September 2018; Published: 18 September 2018
Abstract: The influence of CO2 partial pressure on the corrosion properties, including corrosion rate,
morphology, chemical composition, and corrosion depth, of J55 carbon steel in 30% crude oil/brine
at 65 ◦ C was investigated. A corrosion mechanism was then proposed based on the understanding of
the formation of localized corrosion. Results showed that localized corrosion occurred in 30% crude
oil/brine with CO2 . The corrosion rate sharply increased as the CO2 partial pressure (Pco2 ) was
increased from 0 to 1.5 MPa, decreased from Pco2 = 1.5 MPa to Pco2 = 5.0 MPa, increased again at Pco2
= 5.0 MPa, and then reached a constant value after Pco2 = 9.0 MPa. The system pH initially decreased,
rapidly increased, and then stabilized as CO2 partial pressure was increased. In the initial period,
the surface of J55 carbon steel in the CO2 /30% crude oil/brine mixtures showed intense corrosion.
In conclusion, CO2 partial pressure affects the protection performance of FeCO3 by changing the
formation of corrosion scale and further affecting the corrosion rate.
Keywords: mechanism of CO2 corrosion; J55 carbon steel; CO2 partial pressure; localized corrosion
1. Introduction
In recent years, the carbon dioxide flooding enhanced oil recovery (CO2 -EOR) technology has
been widely applied worldwide [1–3] and has made a positive contribution to the geological reserves
of carbon. However, CO2 -EOR is expected to significantly increase the corrosion failure risk of
tubes [4,5]. The acceptable rate of wellbore corrosion in China is less than 0.076 mm·year−1 [6], and the
qualitative categorization of carbon steel corrosion rates for oil production systems in the US includes
low (<0.025 mm·year−1 ), moderate (0.025–0.12 mm·year−1 ), high (0.13–0.25 mm·year−1 ), and severe
(>0.25 mm·year−1 ) [7]. When water cut is greater than 50%, the corrosion rates of carbon steel (API
5CT L80) and P110 steel are 3.4–34.2 and 0.03–5.0 mm·year−1 , respectively [8,9], which are far beyond
the acceptable range. Thus, many studies have focused on CO2 corrosion, especially on the effect of
environment on corrosion.
Mass loss during CO2 corrosion is generally related to environmental conditions, such as
temperature, pressure, salt concentration, solution pH, and CO2 partial pressure. CO2 partial pressure
and protective scale considerably impact corrosion rate. Many studies demonstrated that the CO2
corrosion rate of carbon steel increases with increasing CO2 pressure [10–12]. The concentration of
H2 CO3 increases as CO2 partial pressure increases, which accelerates the cathodic reactions and
increases the corrosion rate [13–16]. CO2 partial pressure affects the protective properties and
components of the corrosion product layer by changing the system pH. Other studies [15–21] indicated
Materials 2018, 11, 1765; doi:10.3390/ma11091765
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Materials 2018, 11, 1765
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that FeCO3 is the main composition in the corrosion product layer that is formed on corroded carbon
steel surface exposed to CO2 environment. A.H. Mustafa [17] reported that the corrosion product film
of X52 steel is inhomogeneous and porous in CO2 /formation water at different CO2 pressures (10,
40, and 60 bar) and 60 ◦ C, and the corrosion product layer is mainly composed of FeCO3 and Fe3 C.
However, increasing CO2 partial pressure does not often accelerate corrosion. Yoon-Seok Choi [19]
proposed that the corrosion rates of carbon steel measured in CO2 -saturated water show no significant
difference (19.5–20.1 mm·year−1 ) with pressure (4, 6, and 8 MPa) at 50 ◦ C. Preliminary studies mainly
focused on the influences of CO2 partial pressure on corrosion in brine environment and of water cut
on corrosion in CO2 /crude oil/brine environment, but few studies focused on the influence of CO2
partial pressure on corrosion in crude oil/brine environment. Thus, understanding the effect of CO2
partial pressure on the corrosion behavior of J55 carbon steel in crude oil/brine mixtures is important.
In the present work, the effect of CO2 partial pressure on the corrosion behavior of J55 carbon
steel was compared in CO2 /30% crude oil (v/v, the same below)/brine mixtures. The corrosion rates
were determined by weight mass loss, and the maximum corrosion depth was obtained with an optical
digital microscope. The morphology and composition of the formed corrosion product film were
characterized by scanning electron microscopy (SEM), energy dispersive spectrometry (EDS), and
X-Ray diffraction (XRD).
2. Materials and Methods
The material used in this work was J55 carbon steel with a composition (wt.%) of 0.36% C, 0.30%
Si, 1.45% Mn, 0.016% P, 0.004% S, 0.051% Cr, 0.009% Ni, 0.07% Cu, and Fe balance. The specimen for
weight loss test was machined into 50 mm × 10 mm × 3 mm and a hole of 6 mm with an exposed area
of 13.6 cm2 . The samples were placed in acetone to remove oil on the surface and then immersed in
ethanol for 5 min for further degreasing and dehydration. The samples were dried in cold air, packed
with filter paper, and then placed in the dryer for 4–7 h. Finally, the size and weight of the samples
were measured to within an accuracy of 0.1 mg.
The corrosive medium is a mixture of oil and water, the crude oil is obtained from the C8 reservoir
of a certain block in Changqing oilfield, and the brine is the simulated solution prepared according to
the composition of the brine in the reservoir. The compositions of the crude oil and simulated solution
are shown in Tables 1 and 2, respectively.
Table 1. Composition properties of crude oil.
Property
Kinematic viscosity (65
Acid value
Sulfur content
Wax content
Colloid
Asphaltene
◦ C)
Unit
Value
mm2 ·s−1
7.254
0.107
0.08
12.86
2.31
0.60
mg KOH·g−1
wt.%
wt.%
wt.%
wt.%
Table 2. Properties of simulated brine preparation.
Property
Unit
Value
NaCl
CaCl2
MgCl2
Na2 SO4
NaHCO3
salinity
g ·L−1
18.5028
13.7338
0.5897
0.2440
0.0631
33.0000
g ·L−1
g ·L−1
g ·L−1
g ·L−1
g ·L−1
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In CO
CO22-EOR,
channelling often
occurs [22,23],
[22,23], during
during which
which the
the CO
CO22 partial
partial pressure
pressure rises
rises
In
-EOR, gas
gas channelling
often occurs
from the
the bottom
bottom hole
hole to
to no
no more
more than
than 15
15MPa
MPain
inthe
theCC88reservoir.
reservoir.Corrosion
Corrosiontest
test was
was carried
carried out
out in
in
from
the
PARR-4578
autoclave
(Parr
Instrument
Company,
Champaign,
IL,
USA)
by
using
the
the PARR-4578 autoclave (Parr Instrument Company, Champaign, IL, USA) by using the weight-loss
weight-loss
and the
schematic
is shown
1. of
A the
1 Lmixture
aliquot of
of 30%
the mixture
of 30%
method,
andmethod,
the schematic
is shown
in Figure
1. Ain
1 LFigure
aliquot
crude oil/brine
crude
oil/brine
added and
to the
thewas
dissolved
was purged
the solution
was
added
to thewas
autoclave,
theautoclave,
dissolved and
oxygen
purgedoxygen
in the solution
with ainsmall
amount
◦ C.aThe
with
a smallgas
amount
nitrogen
gas forof4 0.5
h under
a pressure
of 0.5 MPa [13]
and
temperature
65
of
nitrogen
for 4 hof
under
a pressure
MPa [13]
and a temperature
of 65
autoclaveof
was
°C. The autoclave
pressured
with pure Nvalues
2 gas (total
to thepressure
experimental
values
(total pressure
pressured
with purewas
N2 gas
to the experimental
value—CO
2 partial pressure)
−1
value—CO
2
partial
pressure)
and
with
CO
2
gas
to
a
total
pressure
value
of
15
MPa
for
at·sthe
and with CO2 gas to a total pressure value of 15 MPa for 2 days at the running speed 2ofdays
0.5 m
−1 (200 r·min−1).
−
1
running
speed
of
0.5
m·s
(200 r·min ).
Figure
Flow chart
chart of
Figure 1.
1. Flow
of steel
steel corrosion
corrosion rate
rate evaluation
evaluation system
system (Mass
(Mass loss
loss method).
method).
After corrosion induction, the three corroded samples were divided into two groups for scanning
After corrosion induction, the three corroded samples were divided into two groups for
electron microscope (SEM), energy dispersive spectrometer (EDS), and X-ray diffraction (XRD) analyses
scanning electron microscope (SEM), energy dispersive spectrometer (EDS), and X-ray diffraction
of the corrosion scales formed on the steel surface. After these tests, the three corroded samples were
(XRD) analyses of the corrosion scales formed on the steel surface. After these tests, the three
subjected to mass loss tests to determine the average corrosion rate.
corroded samples were subjected to mass loss tests to determine the average corrosion rate.
The corrosion rate of the steel was determined by the mass loss technique in accordance with
The corrosion rate of the steel was determined by the mass loss technique in accordance with
the ASTM (American Society for Testing Materials) G1-03-Standard practice for preparing, cleaning,
the ASTM (American Society for Testing Materials) G1-03-Standard practice for preparing, cleaning,
and evaluating corrosion [24]. Immediately after corrosion induction, the samples were rinsed with
and evaluating corrosion [24]. Immediately after corrosion induction, the samples were rinsed with
distilled water and the crude oil on the surface was removed with acetone. Corrosion products were
distilled water and the crude oil on the surface was removed with acetone. Corrosion products were
removed with an ultrasonic cleaner. Then, the samples were immersed in an acid cleaning solution
removed with an ultrasonic cleaner. Then, the samples were immersed in an acid cleaning solution
(500 mL of HCl and 3.5 g of hexamethylenamine diluted with water to 1000 mL) for 10 min, and the
(500 mL of HCl and 3.5 g of hexamethylenamine diluted with water to 1000 mL) for 10 min, and the
corrosion products on the surface were removed. After being immersed, the samples were thoroughly
corrosion products on the surface were removed. After being immersed, the samples were
washed with distilled water until the acid cleaning solution on the surface was completely removed.
thoroughly washed with distilled water until the acid cleaning solution on the surface was
Then, the samples were placed in ethanol for cleaning and dehydration twice. The samples were dried
completely removed. Then, the samples were placed in ethanol for cleaning and dehydration twice.
in cold air, packed with filter paper, and then placed in the dryer for 4–7 h. Finally, the samples were
The samples were dried in cold air, packed with filter paper, and then placed in the dryer for 4–7 h.
weighed to within an accuracy of 0.1 mg. The corrosion rate was calculated as follows:
Finally, the samples were weighed to within an accuracy of 0.1 mg. The corrosion rate was
calculated as follows:
8.76 × 104 × (m − mt )
rcorr =
(1)
8.76 ×S10×4t××(ρm − mt )
rcorr =
(1)
S ×−1t;×mρis the weight of the test sheet before the
where rcorr is the average corrosion rate, mm·year
experiment, g; mt is the weight of the test sheet after the
experiment, g; S is the whole surface contacted
where rcorr is the average corrosion rate, mm·year−1; m is the weight of the test sheet before the
with solution, cm2 ; ρ is the density of tested steel, g·cm−3 , which is 7.86 g·cm−3 in the case of carbon
experiment, g; mt is the weight of the test sheet after the experiment, g; S is the whole surface
contacted with solution, cm2; ρ is the density of tested steel, g·cm−3, which is 7.86 g·cm−3 in the case of
Materials 2018, 11, 1765
Materials 2018, 11, x FOR PEER REVIEW
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steel; and
t isand
thetimmersion
duration,
h. Theh.mean
corrosion
rate error
was calculated
usingusing
three
carbon
steel;
is the immersion
duration,
The mean
corrosion
rate error
was calculated
parallel
specimens
in each
three
parallel
specimens
in test.
each test.
The surface
surface microstructure
microstructure of
scales
onon
thethe
surface
of corroded
samples
was
The
ofthe
thecorrosion
corrosionproduct
product
scales
surface
of corroded
samples
was
analyzed
via SEM
(FEI Quanta
600F microscope,
FEI Corporation,
Hillsboro,
TX,
The
analyzed
via SEM
(FEI Quanta
600F microscope,
FEI Corporation,
Hillsboro,
TX, USA).
TheUSA).
elemental
elemental
compositions
of the product
corrosionscales
product
were by
estimated
by EDS INCA
(OXFORD
INCA
compositions
of the corrosion
werescales
estimated
EDS (OXFORD
energy
350,
energy
OxfordOxford,
Instrument,
Oxford,
UK). The
composition
of the was
corroded
samples
was
Oxford 350,
Instrument,
UK). The
composition
of the
corroded samples
performed
with XRD
performed
(Bruker
D8 XRD,Karlsruhe,
Bruker Corporation,
(Bruker D8with
XRD,XRD
Bruker
Corporation,
Germany).Karlsruhe, Germany).
The
The maximum
maximumcorrosion
corrosiondepth
depthof
of the
the corroded
corroded samples
samples was
was analyzed
analyzed with
with an
an optical
optical digital
digital
microscope
(OLYMPUSDSX500,
DSX500,Olympus
Olympus
Corporation,
Tokyo,
after removal
of the
microscope (OLYMPUS
Corporation,
Tokyo,
Japan)Japan)
after removal
of the corrosion
corrosion
product
the acid cleaning
Under bright-field
mode,
the corroded
product layers
by layers
using by
theusing
acid cleaning
solution.solution.
Under bright-field
mode, the
corroded
sample
sample
was subjected
to horizon
grand horizon
three dimensions
(3D) image
capture
using adjacent
surfacesurface
was subjected
to grand
three dimensions
(3D) image
capture
using adjacent
visual
visual
synthetic
diagram
The magnification
100with
times,
a 3 × 3 nine-image
synthetic
diagram
mode. mode.
The magnification
was 100was
times,
a 3with
× 3 nine-image
syntheticsynthetic
diagram
diagram
and an ratio
overlap
ratioFour
of 10%.
Four
on the
back of
surfaces
of the were
samples
were
and an overlap
of 10%.
points
onpoints
the front
andfront
backand
surfaces
the samples
collected,
collected,
shown2.inThe
Figure
the 3 × 3 nine-image
synthetic
7612µm,
μmthe
×
as shown as
in Figure
area2.ofThe
the 3area
× 3of
nine-image
synthetic diagram
wasdiagram
7612 µmwas
× 7612
7612
total area
of image
acquisition
cm2of
, and
the exposed
surface
area
total μm,
areathe
of image
acquisition
was
4.63 cm2 ,was
and 4.63
43.27%
the 43.27%
exposedofsurface
area was
occupied,
was
occupied,
which
wasthan
much
thanstudies
that in[15–21].
other studies
[15–21]. The
maximum
which
was much
larger
thatlarger
in other
The maximum
corrosion
depthcorrosion
could be
depth
could
acquiredthe
by corrosion
comparing
the corrosion
measured
in different
Therefore,
acquired
by be
comparing
depth
measureddepth
in different
areas.
Therefore,areas.
the method
can
the
can reflect
also accurately
reflectcorrosion
the maximum
depth of
the corroded samples.
alsomethod
accurately
the maximum
depthcorrosion
of the corroded
samples.
Figure 2. Schematic of image acquisition.
Figure 2. Schematic of image acquisition.
3. Results
3. Results
3.1. Weight Loss Tests
3.1. Weight Loss Tests
Figure 3 shows the macroscopic morphologies of the J55 carbon steel before corrosion test and after
Figure
the macroscopic
of the pressures.
J55 carbonLocalized
steel before
corrosion
test and
the removal3ofshows
corrosion
scales under morphologies
different CO2 partial
corrosion
occurred
on
after
the removal
of carbon
corrosion
scales
under in
different
2 partial
Localized
corrosion
the surface
of the J55
steel.
As shown
Figure 4,CO
the
averagepressures.
corrosion rate
of the J55
carbon
occurred
the surface
the2 /crude
J55 carbon
steel. As
shown in Figure
4,increased
the average
corrosion
rate of
steel afteron
immersing
in of
a CO
oil/brine
environment
initially
and
then decreased
the
J55
carbon steel
immersing
a COfinally
2/crude
oil/brine environment
initially
with
increasing
CO2after
partial
pressure in
before
stabilizing.
When the CO
pressure and
was
2 partialincreased
then
decreased
increasing
2 partial rate
pressure
finally
stabilizing.
When the CO
partial
increased
from with
0 to 1.5
MPa, theCO
corrosion
of J55before
increased
sharply.
The concentration
of2 H
CO
2
3
pressure
increased
from 0oftoCO1.5
MPa,
the corrosion
rate of J55
The
increasedwas
as the
partial pressure
increased,
which decreased
the increased
system pHsharply.
and therefore
2 was
concentration
H2CO3 increased
as the
partial
of CO
2 was increased,
which
decreased
the
increased the of
corrosion
rate [13–16].
When
the pressure
CO2 partial
pressure
was increased
from
1.5 MPa
to
system
pHthe
and
therefore
increased
the corrosion
When
the CO
pressure
was
5.0 MPa,
corrosion
rate
of J55 decreased.
Withrate
the[13–16].
continuous
increase
in2 partial
CO2 partial
pressure,
increased
from
1.5 MPa
to 5.0 MPa,
theon
corrosion
rate of
of the
J55 decreased.
continuous
a protective
layer
gradually
formed
the surface
J55 carbonWith
steel.the
When
the COincrease
2 partial
in
CO2 partial
pressure, from
a protective
layer
gradually
formed
of the
carbon steel.
pressure
was increased
5.0 to 9.0
MPa,
the corrosion
rateonofthe
J55surface
increased.
TheJ55
protective
layer
When
the
CO
2
partial
pressure
was
increased
from
5.0
to
9.0
MPa,
the
corrosion
rate
of
J55
increased.
formed on the surface of J55 may be dissolved gradually, thereby increasing the corrosion rate [14,15].
The
protective
formed
on the
surface
of J55from
may 9.0
be dissolved
gradually,
thereby
increasing
When
the CO2layer
partial
pressure
was
increased
MPa to 15.0
MPa, the
corrosion
rate ofthe
J55
corrosion
rate
[14,15]. A
When
the CO
2 partial
pressure
wasthe
increased
fromas9.0
MPa
15.0 MPa,
the
was almost
constant.
protective
layer
formed
faster on
steel surface
the
CO2topartial
pressure
corrosion rate of J55 was almost constant. A protective layer formed faster on the steel surface as the
CO2 partial pressure was increased [17–19]. When CO2 dissolved in water equilibrium, CO2
Materials 2018, 11, 1765
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Materials 2018, 11, x FOR PEER REVIEW
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was increased [17–19]. When CO2 dissolved in water equilibrium, CO2 solubility almost no longer
solubilitywith
almost
no longer increased
with increasing
COsystem
2 partial
pressure.
Thus,invariable
the system
pHand
was
increased
increasing
pressure.
Thus,CO
the
pH
was almost
[25],
2 partialwith
solubility
almost
no longerCO
increased
increasing
2 partial pressure. Thus, the system pH was
almost
invariable
[25],
and
the
protective
layer
was
not
dissolved.
the protective
layer
wasand
notthe
dissolved.
almost
invariable
[25],
protective layer was not dissolved.
(a)
(a)
(b)
(b)
(c)
(c)
(d)
(d)
(e)
(e)
(f)
(f)
Figure 3. Macroscopic morphologies of J55 carbon steel before corrosion test: (a) before corrosion test
Figure 3. Macroscopic
carbon
steel
before
corrosion
test:test:
(a) before
corrosion
test
Macroscopicmorphologies
morphologiesofofJ55
J55
carbon
steel
before
corrosion
(a) before
corrosion
and after the removal of corrosion scales under different CO2 partial pressures; (b) Pco2 = 0 MPa; (c)
2
partial
pressures;
(b)
Pco
=
0
MPa;
(c)
and
after
the
removal
of
corrosion
scales
under
different
CO
test and after the removal of corrosion scales under different CO2 partial pressures; (b) 2Pco2 = 0 MPa;
Pco2 = 1.5 MPa; (d) Pco2 = 5.0 MPa; (e) Pco2 = 9.0 MPa; and (f) Pco2 = 15.0 MPa.
MPa;
(d)(d)
PcoPco
MPa;
(e)(e)
Pco
MPa;
and
(f)(f)
Pco
15.0
MPa.
Pco
(c) Pco
= 1.5
MPa;
= 5.0
MPa;
Pco
= 9.0
MPa;
and
Pco
15.0
MPa.
2=
2 =21.5
2 =2 5.0
2 =2 9.0
2 =
8
-1
Average corrosion rate / mm·y -1
Average corrosion rate / mm·y
8
6
4
6
4
The data of mass losses during the experiment
2
0
The data/ of
mass losses
CO2 partial pressure
MPa
0.0 during
0.5 the experiment
1.0
1.5
2.5
3.0
CO2
partial
pressure
0.0
0.5
1.0
1.5
2.5
3.0
Mass
loss
weight // gMPa
0.0005
0.0050
0.1936
0.3863
0.3430
0.2734
Mass
loss
weight
/g
0.0050 7.0
0.1936 9.0
0.386311.0
0.343013.0
0.273415.0
CO2
partial
pressure
/ MPa0.0005 5.0
CO2
partial
pressure
5.0
7.0
9.0
11.0
Mass
loss
weight // gMPa
0.2037
0.2306
0.3055
0.3071 13.0
0.3102 15.0
0.3091
Mass loss weight / g
0.2037 0.2306 0.3055 0.3071 0.3102 0.3091
2
0
0
0
2
2
4
4
6
6
8
8
10
10
12
12
CO2 partial pressure / MPa
pressure / MPa
CO2 partial
14
14
16
16
Figure 4. Average corrosion rate determined by mass loss technique as a function of CO2 partial
Figure for
4. Average
corrosion 30%
rate crude
determined
by mixtures.
mass loss technique as a function of CO2 partial
pressure
steel immersed
oil/brine
Figure
4. Average
corrosioninrate
determined
by mass
loss technique as a function of CO2 partial
pressure for steel immersed in 30% crude oil/brine mixtures.
pressure for steel immersed in 30% crude oil/brine mixtures.
3.2. Microstructure and Composition of the Corrosion Scale
3.2. Microstructure and Composition of the Corrosion Scale
3.2. Microstructure
and Composition
of the Corrosion
Scale scales formed on the J55 steel surface as a
Figures 5–9 show
the SEM images
of the corrosion
Figures
show
the
SEM
images
of
the
corrosion
scales at
formed
on the
J55 steel surface
function
of CO5–9
partial
pressure
in
30%
crude
oil/brine
the same
magnification
(×100as
or a
2 show the SEM images of the corrosionmixtures
Figures 5–9
scales formed on the J55 steel surface as a
of CO
pressure
30% crude
oil/brine
mixtures
the same
magnification
(×100
×function
2000). EDS
was2 partial
performed
on theincorrosion
product
scales
of the at
tested
samples.
Table 3 shows
theor
function of CO2 partial pressure in 30% crude oil/brine mixtures at the same magnification (×100 or
×2000).
EDSofwas
performed
on the
corrosion
product
scales
ofline
the region
tested in
samples.
3 shows the
EDS
spectra
the corrosion
scale
in the
inner surface
of the
blue
FiguresTable
4–8, respectively.
×2000). EDS was performed on the corrosion product scales of the tested samples. Table 3 shows the
EDS spectra
corrosion
in the inner
linesurface
regionatinPco
Figures
4–8,
Figure
5 shows of
thethe
SEM
images ofscale
the corrosion
scalessurface
formedof
onthe
the blue
J55 steel
2 = 0 MPa
EDS spectra
of the corrosion scale in the inner surface of the blue line region in Figures
4–8,
◦
respectively.
5 shows
SEM images
corrosion
formed
on the J55
steel surface
and
65 C. TheFigure
polishing
marksthe
visibleofonthe
surface ofscales
the J55
steel, and
visible
of
respectively.
Figure
5 shows
thewere
SEMstill
images
of thethe
corrosion
scales
formed
on thenoJ55
steel signs
surface
at Pco2 =were
0 MPa
and 65on
°C.the
The
polishing
were
still visible
on consisted
the surface
J55
steel,
and
corrosion
observed
sample.
Themarks
corrosion
product
mainly
ofof
Fethe
C
(the
content
3 J55 steel, and
at Pco2 = 0 MPa and 65 °C. The polishing marks were still visible on the surface of the
no visible
signs
corrosion
were
observed
on the
sample. The
corrosion
productfrom
mainly
consisted
ratio
of Fe and
C of
atoms
is about
1:3)
and minor
constituents
of alloying
elements
carbon
no visible signs of corrosion were observed on the sample. The corrosion product mainlythe
consisted
of Fe
3C (theFigure
content6 ratio
ofthe
Fe and
Cimages
atoms of
is about
1:3) andscales
minorformed
constituents
of alloying
elements
steel
shows
SEM
the corrosion
on the
steel surface
at
of
Fe3matrix.
C (the content
ratio
of Fe
and
C atoms
is about
1:3) and minor
constituents
of J55
alloying
elements
◦matrix.
from
the
carbon
steel
Figure
6
shows
the
SEM
images
of
the
corrosion
scales
formed
on
the
Pco
=
1.5
MPa
and
65
C.
The
surface
was
severely
attacked
and
showed
disperse
FeCO
and
CaCO
2 the carbon steel matrix. Figure 6 shows the SEM images of the corrosion scales formed
3
from
on the3
J55 steel
surface
at Pco2 = 1.5
MPa and
65 °C. from
The the
surface
was severely
attacked
showed
scales
andsurface
minor at
constituents
of MPa
alloying
carbon
matrix.
Figureand
7and
shows
the
J55
steel
Pco2 = 1.5
andelements
65 °C. The
surface
was steel
severely
attacked
showed
◦ C.steel
disperse
FeCO
3 and
CaCO3 scales
and
minor
constituents
ofsurface
alloying
elements
from
the
carbon
SEM
images
of
the
corrosion
scales
formed
on
the
J55
steel
at
Pco
=
5.0
MPa
and
65
A
2
disperse FeCO3 and CaCO3 scales and minor constituents of alloying elements from the carbon steel
matrix.
Figure
7surface
shows was
the SEM
images
offully
the corrosion
scales
formed
on
the
J55
steel
surface
at
Pco
large
part
of
the
attacked
and
covered
by
FeCO
and
CaCO
.
Figures
8
and
9
show
3
matrix. Figure 7 shows the SEM images of the corrosion scales formed
on the 3J55 steel surface at Pco2 2
= 5.0
MPa
andof65the
°C.
A large scales
part of
the surface
was
attacked
and
fully
covered
by FeCO
and
the
SEM
images
corrosion
formed
on
the
J55
steel
surface
Pco2covered
=
9.0 and
MPa.3 3and
The
= 5.0 MPa and 65 °C. A large part of the surface was attacked and atfully
by15FeCO
CaCO3was
. Figures
8 and
9 show
the SEM
images
of the
corrosion
scales
formed
on
the
J55
steel
surface
surface
almost
covered
by
protective
FeCO
layer
and
few
CaCO
.
At
Pco
=
15.0
MPa,
the
3 on the2 J55 steel surface
CaCO3. Figures 8 and 9 show the SEM images of the3 corrosion scales formed
at Pco2 =product
9.0 andlayer
15 MPa.
The surface
was almost
covered
by
the
protective
FeCO3 layer and few
corrosion
was
thicker
and
denser
than
that
at
Pco
=
9.0
MPa.
2
at Pco2 = 9.0 and 15 MPa. The surface was almost covered by the protective FeCO3 layer and few
CaCO3. At Pco = 15.0 MPa, the corrosion product layer was thicker and denser than that at Pco =
CaCO3. At Pco2 2= 15.0 MPa, the corrosion product layer was thicker and denser than that at Pco2 2=
9.0 MPa.
9.0 MPa.
Materials 2018, 11, 1765
Materials 2018,
2018, 11,
11, xxx FOR
FOR PEER
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REVIEW
Materials
Materials
2018,
11,
FOR
PEER
REVIEW
(a)
6 of 15
of 14
14
666 of
of
14
(b)
Figure 5.
5. SEM
SEM images
images of
of corrosion
corrosion scales
scales formed
formed on
on the
thesteel
steel surface
surfacein
in30%
30%crude
crudeoil/brine
oil/brine mixtures
mixtures
Figure
scales
formed
on
the
steel
surface
in
30%
crude
oil/brine
Figure
5.
SEM
images
of
corrosion
corrosion
scales
formed
on
the
steel
surface
in
30%
crude
oil/brine
mixtures
MPa: (a)
(a) ×
×100;
(b)
×2000.
at Pco
Pco222 ==== 000 MPa:
×100;
at
100;(b)
(b)×2000.
×2000.
MPa:
(a)
×100;
(b)
×2000.
at
Pco
2
(a)
(a)
(b)
(b)
Figure 6.
6. SEM
SEM images
images of
of the
the corrosion
corrosion scales
scales formed
formed on
on the
the steel
steel surface
surface in
in 30%
30%crude
crudeoil/brine
oil/brine
Figure
the
steel
surface
in
30%
crude
oil/brine
Figure
6.
SEM
images
of
the
scales
formed
on
the
steel
surface
in
30%
crude
oil/brine
1.5MPa:
MPa: (a)
(a) ×
×100;
(b)
×2000.
mixtures at
at Pco
Pco22 ====1.5
1.5
MPa:
×100;
mixtures
100;(b)
(b)×2000.
×2000.
1.5
MPa:
(a)
×100;
(b)
×2000.
mixtures
at
Pco
2
(a)
(a)
(b)
(b)
Figure
images of
of the
the
7. SEM
SEM images
corrosion scales
scales formed
formed on
on the
the steel
steel surface
surface in
in 30%
30%crude
crudeoil/brine
oil/brine
Figure
7.
corrosion
scales
formed
on
the
steel
surface
in
30%
crude
oil/brine
Figure 7.
7.
SEM
images
of
the corrosion
corrosion
scales
formed
on
the
steel
surface
in
30%
crude
oil/brine
mixtures
at
Pco
=
5.0
MPa:
(a)
×
100;
(b)
×
2000.
at
Pco
=
5.0
MPa:
(a)
×100;
(b)
×2000.
2
mixtures
mixtures at
at Pco
Pco222 == 5.0
5.0 MPa:
MPa: (a)
(a) ×100;
×100; (b)
(b) ×2000.
×2000.
Materials 2018, 11, 1765
Materials
Materials 2018,
2018, 11,
11, xx FOR
FOR PEER
PEER REVIEW
REVIEW
7 of 15
77 of
of 14
14
(a)
(b)
Figure 8.
8.
the corrosion
corrosion
scales
formed
on
the
steel
surface
in
30%
crude
oil/brine
Figure
images of
of the
8. SEM
SEM images
corrosion scales
scales formed
formed on
on the
the steel
steel surface
surface in
in 30%
30%crude
crudeoil/brine
oil/brine
9.0
MPa:
(a)
×100;
mixtures at
100; (b)
(b) ×2000.
×2000.
9.0MPa:
MPa: (a)
(a) ×
×100;
(b)
×2000.
at Pco
Pco222 ===9.0
(a)
(b)
Figure
scales
formed
on
the
steel
surface
in
30%
crude
oil/brine
Figure 9.
9. SEM
SEM images
images of
of corrosion
corrosion scales
scales formed
formed on
on the
thesteel
steel surface
surfacein
in30%
30%crude
crudeoil/brine
oil/brine mixtures
mixtures
at
Pco
=
15.0
MPa:
(a)
×
100;
(b)
×
2000.
15.0 MPa:
MPa: (a) ×100;
×100; (b)
(b) ×2000.
×2000.
at Pco22 == 15.0
2
Table 3. EDS of the corrosion scale of immersion in 30% crude oil/brine mixtures under different CO2
Table
EDS
Table 3.
3.
EDS of
of the
the corrosion
corrosion scale
scale of
of immersion
immersion in
in 30%
30% crude
crude oil/brine
oil/brine mixtures
mixtures under
under different
different CO
CO22
partial
pressures.
partial
pressures.
partial pressures.
Element (At. %)
Element
Element (At.
(At. %)
%)
CK
C
CK
K
OK
O
K
O
Si K
K
Si
CrK
K
Si
K
Ca K
K
Cr
Cr
K
Cl K
K
Ca
Ca
K
Mn K
Cl
Cl
K
Fe K
K
Mn
K
total
Mn
K
Fe
Fe K
K
total
total
Pco2 = 0 MPa
== 00 MPa
P
MPa
P
Whole
Local
Whole
Local
Whole Local
75.70
76.23
75.70
76.23
75.70
76.23
0.34
1.50
0.34
1.50
0.34
1.50
/
/
///
///
///
///
0.14
//
//
/
0.40
0.30
0.14
//
0.14
23.42
21.97
0.40
0.30
100.0
100.0
0.40
0.30
23.42
21.97
23.42
21.97
100.0
100.0
100.0
100.0
Pco2 = 1.5 MPa
P
== 1.5
P
1.5 MPa
MPa
Whole
Local
Whole
Local
Whole Local
37.34
33.40
37.34
33.40
37.34
33.40
44.87
55.80
44.87
55.80
44.87
55.80
/
/
//
0.29
///
3.49
3.17
0.29
//
0.29
0.37
0.16
3.49
3.17
3.49
3.17
0.54
0.35
0.37
0.16
0.37
0.16
13.10
7.12
0.54
0.35
100.0
100.0
0.54
0.35
13.10
7.12
13.10
7.12
100.0
100.0
100.0
100.0
Pco2 = 5.0 MPa
P
== 5.0
P
5.0 MPa
MPa
Whole
Local
Whole
Local
Whole Local
50.29
33.25
50.29
33.25
50.29
33.25
36.73
45.10
36.73
45.10
36.73
45.10
0.21
/
0.21
/
///
0.21
///
0.20
//
0.30
0.37
//
0.20
0.20
0.14
0.28
0.30
0.37
0.30
0.37
12.33
20.80
0.14
0.28
100.0
100.0
0.14
0.28
12.33
20.80
12.33
20.80
100.0
100.0
100.0
100.0
Pco2 = 9.0 MPa
P
== 9.0
P
9.0 MPa
MPa
Whole
Local
Whole
Local
Whole Local
27.87
18.66
27.87
18.66
27.87
18.66
46.48
53.98
46.48
53.98
46.48
53.98
/
/
///
///
1.84
2.29
//
//
/
/
1.84
2.29
1.84
2.29
/
/
//
//
23.81
25.07
/
//
100.0
100.0
/
23.81
25.07
23.81
25.07
100.0
100.0
100.0
100.0
Pco2 = 15.0 MPa
P
== 15.0
P
15.0 MPa
MPa
Whole
Local
Whole
Local
Whole
Local
63.00
62.49
63.00
62.49
63.00
62.49
23.68
25.52
23.68
25.52
23.68
25.52
/
/
///
/ //
0.44
0.59//
//
/
/
0.44
0.59
0.44
0.59
/
/
/
//
/
12.88
11.40
/
//
100.0
100.0
/
12.88
11.40
12.88
11.40
100.0
100.0
100.0
100.0
The main elements of the corrosion products in the 30% crude oil/brine environment without
CO2 were Fe and C, and the content ratio of iron and carbon atoms was about 1:3, indicating that
The main elements of the corrosion products in the 30% crude oil/brine environment without
the corrosion products consisted mainly of FeC3 . The main elements of the corrosion products in the
CO22 were Fe and C, and the content ratio of iron and carbon atoms was about 1:3, indicating that the
CO2 /30% crude oil/brine environment were O, Fe, and Ca, indicating that the corrosion products
corrosion products consisted mainly of FeC33. The main elements of the corrosion products in the
consisted mainly of FeC3 and mixed carbonate (Fex Ca1−x CO3 ) [26,27]. At Pco2 = 1.5 and 5.0 MPa,
CO22/30% crude oil/brine environment were O, Fe, and Ca, indicating that the corrosion products
consisted mainly of FeC33 and mixed carbonate (FexxCa1−x
1−xCO33) [26,27]. At Pco22 = 1.5 and 5.0 MPa, the
Materials 2018, 11, 1765
8 of 15
Materials 2018, 11, x FOR PEER REVIEW
8 of 14
the minor constituents of alloying elements from the carbon steel were detected, indicating that the
minor constituents of alloying elements from the carbon steel were detected, indicating that the
surface was not fully covered by the corrosion product layer. At Pco2 = 9.0 and 15.0 MPa, the minor
surface was not fully covered by the corrosion product layer. At Pco2 = 9.0 and 15.0 MPa, the minor
constituents of alloying elements from the carbon steel were not detected,
suggesting that the surface
constituents of alloying elements from the carbon steel were not detected, suggesting that the surface
was fully covered by the corrosion product layer.
was fully covered by the corrosion product layer.
Figure 10 shows the XRD spectra of the surface layer on the corroded samples immersed
Figure 10 shows the XRD spectra of the surface layer on the corroded samples immersed in
in CO2 /30% crude oil/brine mixtures. Related research [15–21] reported that the main CO2
CO2/30% crude oil/brine mixtures. Related research [15–21] reported that the main CO2 corrosion
corrosion product of carbon steel is FeCO3 . The compositions of the corrosion product layer in
product of carbon steel is FeCO3. The compositions of the corrosion product layer in the CO2/30%
the CO2 /30% crude oil/brine mixtures were similar and mainly consisted of the complex salt of
crude oil/brine mixtures were similar and mainly consisted of the complex salt of CaCO3 and FeCO3.
CaCO3 and FeCO3 . This result may be attributed to the presence of metal cation isomorphous
This result may be attributed to the presence of 2+
metal cation isomorphous substitution in CO2
substitution in CO2 corrosion [27]. When the [Fe ] × [CO3 2− ] in the medium exceeds FeCO3
corrosion [27]. When the [Fe2+] × [CO32−] in the medium exceeds FeCO3 solubility product Ksp
solubility product Ksp (FeCO3 ), that is, when the FeCO3 supersaturation in the medium is
nh
i h
io ), 2+that
is, 2−when
FeCO
supersaturation
in bethe
medium
is metal
S = surface.
Fe2+ ×
S(FeCO
= 3Fe
× CO
/ K the
the FeCO would
deposited
on the
(FeCO
) 3> 1,
sp
3
3
3
2As
shown
following
[27]: 3 would be deposited on the metal surface. As shown in the
FeCO
> 1, form
the FeCO
/ Kinspthe
CO
3
3
following form [27]:
Fe2+ +CO23− → FeCO3 (s)
(2)
CO23→
2+
(2)
FeCO3 (s)
Fe +
The Ca2+ in the solution to the replacement in FeCO3 crystal Fe2+ and the formation of the Fe (Ca)
The Ca2+ can
in the
to as
the replacement in FeCO3 crystal Fe2+ and the formation of the Fe (Ca)
CO3 complex
besolution
expressed
CO3 complex can be expressed as
+
Ca2+ +2+FeCO3 (s) → Fe22+
+ CaCO3 (s)
(3)
(3)
Ca + FeCO (s) → Fe +CaCO3 (s)
•
Intensity
•
♦•
•
•
•
♦
FeCO3
•
CaCO3
Pco2=2MPa
• ♦
•
•
•
Pco2=5MPa
•
•
♦
10
20
♦
•
30
•
•• ♦
40
50
Pco2=9MPa
♦♦
60
70
2θ（degree）
Figure
Figure 10.
10. XRD
XRD spectra
spectra of
of surface
surface layer
layer on
on the
the corroded
corroded samples.
samples.
3.3. Maximum Corrosion Depth Tests
3.3. Maximum Corrosion Depth Tests
Figure 11 shows that the maximum corrosion depth of the cleaned sample surface exposed to
Figure 11 shows that the maximum corrosion depth of the cleaned sample surface exposed to
30% crude oil/brine condition at Pco2 = 1.0 MPa and 65 ◦ C was 237.753 µm. The maximum corrosion
30% crude oil/brine condition at Pco = 1.0 MPa and 65 °C was 237.753 μm. The maximum corrosion
depths measured in the seven other 2regions were compared, and the maximum corrosion depth of
depths measured in the seven other regions were compared, and the maximum corrosion depth of
the cleaned sample surface exposed to 30% crude oil/brine condition at Pco2 = 1.0 MPa and 65 ◦ C
the cleaned sample surface exposed to 30% crude oil/brine condition at Pco2 = 1.0 MPa and 65 °C
was 382.742 µm. As shown in Figure 12, the maximum corrosion depth of the cleaned
sample surface
was 382.742 μm. As shown in Figure 12, the maximum corrosion depth of the cleaned sample
exposed to 30% crude oil/brine condition at Pco2 = 1.5 MPa and 65 ◦ C, where the average corrosion
surface exposed to 30% crude oil/brine condition at Pco = 1.5 MPa and 65 °C, where the average
rate was the highest, was 90.395 µm. The type of corrosion2 damage changed from localized corrosion
corrosion rate was the highest, was 90.395 μm. The type of corrosion damage changed from
to mesa corrosion. Figure 13 shows the maximum corrosion depth and penetration rate/average
localized corrosion to mesa corrosion. Figure 13 shows the maximum corrosion depth and
corrosion rate ratio of the J55 carbon steel surface after removal of the corrosion product layers by
penetration rate/average corrosion rate ratio of the J55 carbon steel surface after removal of the
using acid cleaning solution as a function of CO2 partial pressure in the 30% crude oil/brine mixtures.
corrosion product layers by using acid cleaning solution as a function of CO2 partial pressure in the
The maximum corrosion depth varied with the increase in CO2 partial pressure possibly because
30% crude oil/brine mixtures. The maximum corrosion depth varied with the increase in CO2 partial
of the protection conferred by the corrosion product layer. The variation trend of the penetration
pressure possibly because of the protection conferred by the corrosion product layer. The variation
rate/average corrosion rate ratio of the J55 carbon steel surface was the same as that of the maximum
trend of the penetration rate/average corrosion rate ratio of the J55 carbon steel surface was the same
as that of the maximum corrosion depth as the CO2 partial pressure was increased. The penetration
rate/average corrosion rate ratios were greater than 4, indicating that local corrosion occurred on the
Materials 2018, 11, 1765
9 of 15
corrosion
depth
as the
CO
Materials 2018,
11, x FOR
PEER
REVIEW
9 of 14
2 partial pressure was increased. The penetration rate/average corrosion
Materials 2018, 11, x FOR PEER REVIEW
9 of 14
rate ratios were greater than 4, indicating that local corrosion occurred on the surface of the carbon
surface
ofofthe
steel
[8,18].
1.0 MPa,
depth was
largest
at 382.742
steel
[8,18].
At
Pco
MPa,
the At
corrosion
wasthe
thecorrosion
largest at 382.742
µm,the
which
corresponded
2 = depth
2 = 1.0
surface
thecarbon
carbon
steel
[8,18].
AtPco
Pco
2 = 1.0 MPa, the corrosion depth was the largest at 382.742
μm,
which
corresponded
to
69.8504
mm/a.
This
penetration
rate
was
considerably
greater
the
to
69.8504
mm/a.
This
penetration
rate
was
considerably
greater
than
the
weight-loss
corrosion
rate
μm, which corresponded to 69.8504 mm/a. This penetration rate was considerably greaterthan
than
the
−1 ) shown
−1) shown in Figure 3, thereby confirming local attack.
weight-loss
corrosion
rate
(3.3058
mm·year
(3.3058
mm
·
year
in
Figure
3,
thereby
confirming
local
attack.
−1
weight-loss corrosion rate (3.3058 mm·year ) shown in Figure 3, thereby confirming local attack.
(a)(a)
(b)
(b)
(c)(c)
Figure 11. Corrosion depth analysis on cleaned surface of the sample exposed to 30% crude oil/brine
Figure
Corrosion
depth
analysis
cleaned
surface
sample
exposed
30%
crude
oil/brine
Figure
11.11.
Corrosion
depth
analysis
onon
cleaned
surface
of of
thethe
sample
exposed
to to
30%
crude
oil/brine
condition at Pco2 = 1.0 MPa and 65 ◦°C: (a) corrosion morphology; (b) corrosion depth distribution
=
1.0
MPa
and
65
°C:
(a)
corrosion
morphology;
(b)
corrosion
depth
distribution
condition
at
Pco
condition at Pco2 =
2 1.0 MPa and 65 C: (a) corrosion morphology; (b) corrosion depth distribution
contour diagram; and (c) corrosion depth distribution 3D diagram.
contour
diagram;
and
corrosion
depth
distribution
diagram.
contour
diagram;
and
(c)(c)
corrosion
depth
distribution
3D3D
diagram.
(a)(a)
(b)
(b)
(c)(c)
25
20
25
Penetration rate / Average corrosion rate ratio
Penetration
rate
Maximum
corrosion
Penetration
rate /depth
/ Average
Average corrosion
corrosion rate
rate ratio
ratio
Maximum
Maximum corrosion
corrosion depth
depth
400
400
350
350
Maximum corrosion depth / μm
Maximum corrosion
corrosion depth
depth // μm
μm
Maximum
Penetration rate / Average corrosion rate ratio
Penetration rate
rate // Average
Average corrosion
corrosion rate
rate ratio
ratio
Penetration
Figure 12.
12. Corrosion depth
analysis on
the cleaned
cleaned surface of
of the sample
sample exposed to
to 30% crude
crude
Figure
Figure 12.Corrosion
Corrosiondepth
depthanalysis
analysisononthe
the cleanedsurface
surface ofthe
the sampleexposed
exposed to30%
30% crude
◦
=
1.5
MPa
and
65
°C:
(a)
corrosion
morphology;
(b)
corrosion
depth
oil/brine
condition
at
Pco
22 = =1.5
oil/brine
1.5MPa
MPaand
and6565 C:
°C:(a)(a)corrosion
corrosionmorphology;
morphology;(b)(b)corrosion
corrosiondepth
depth
oil/brinecondition
conditionatatPco
Pco
2
distribution contour
contour diagram;
diagram; and
and (c)
(c) corrosion
corrosion depth
depth distribution
distribution3D
3Ddiagram.
diagram.
distribution
distribution contour diagram; and (c) corrosion depth distribution 3D diagram.
20
300
300
15
10
5
0
15
250
250
200
200
10
150
150
5
0
100
100
0
0
2
2
4
4
6
6
8
8
10
10
12
12
CO2 partial pressure / MPa
CO22 partial pressure / MPa
14
14
16
50
16
50
.
.
Figure 13. Maximum corrosion depth and penetration rate/average corrosion rate ratio of J55 carbon
Figure 13. Maximum corrosion depth and penetration rate/average corrosion rate ratio of J55 carbon
Figure
13. Maximum
corrosion
depth and
penetration
corrosion
rate ratio of J55 carbon
steel
surface
as a function
of CO partial
pressure
in 30% rate/average
crude oil/brine
mixtures.
steel surface as a function of CO22 partial pressure in 30% crude oil/brine mixtures.
steel surface as a function of CO2 partial pressure in 30% crude oil/brine mixtures.
4.4.Discussion
Discussion
2 Partial Pressure
4.1.
2 Partial Pressure
4.1.Variation
VariationofofpH
pHwith
withCO
CO
As
the
CO
2 partial pressure was increased, the corrosion rate of the J55 carbon steel initially
As the CO2 partial pressure was increased, the corrosion rate of the J55 carbon steel initially
increased,
increased,decreased,
decreased,increased
increasedagain,
again,and
andthen
thenstabilized.
stabilized.This
Thisresult
resultisisdifferent
differentfrom
fromthe
thereport
reportofof
Materials 2018, 11, 1765
10 of 15
4. Discussion
4.1. Variation of pH with CO2 Partial Pressure
As the CO2 partial pressure was increased, the corrosion rate of the J55 carbon steel initially
increased, decreased, increased again, and then stabilized. This result is different from the
report of some scholars that the CO2 corrosion rate of carbon steel increases with increasing CO2
pressure [13,15,28]. G.A. Zhang [13] reported the corrosion rate of N80 carbon steel increases from
19.13 mm·year−1 to 23.91 mm·year−1 when the CO2 partial pressure increases from 5 MPa to 8 MPa.
When the samples were immersed in formation water for 96 h at 60 ◦ C and a rotational speed of
2 m·s− 1 . Zhang Y. The authors of [15] proposed that the corrosion rate of X65 carbon steel increases
from 1.64 mm·year−1 to 7.26 mm·year−1 when the samples are immersed in aqueous environment for
168 h at 80 ◦ C and 1–9.5 MPa. M. Seiersten [28] reported that the corrosion rates of X65 carbon steels in
aqueous CO2 conditions range within 1–6 mm·year−1 at 40 ◦ C and 7.5–9 MPa. The corrosion rate in
the literature is greater than that in the test. The difference may be attributed to the different tested
corrosion media and the obvious corrosion inhibition effect of crude oil that can greatly reduce the
corrosion rate of CO2 [9].
The acid value of crude oil is 0.107 mg KOH·g−1 , and crude oil would not substantially change
the system pH. The initial system pH is 6.5, and the change in pH is mainly caused by the dissolution
of CO2 in water. CO2 dissolves in water and forms carbonic acid in situ, and the acidity of the solution
increases, thereby decreasing the pH. The equilibrium relationship can be described this process:
H2 O
H+ + OH− ,
CO2(aq) + H2 O
HCO3 −
Kw
H+ + HCO3 − ,
(4)
Ka1
H+ + CO3 2− ,
Ka2
Kw = xH+ xOH− γH+ γOH− ,
xH+ xHCO3 − γH+ γHCO3 −
,
Ka1 =
xCO2(aq) γCO2(aq)
xH+ xCO3 2− γH+ γCO3 2−
Ka2 =
,
xHCO3 − γHCO3 −
(5)
(6)
(7)
(8)
(9)
where Kw is the ionization constant of water, Ka1 is the first ionization constant of CO2 , Ka2 is the
secondary ionization constant of CO2 , x is the concentration of subscript ion, mol·L−1 , and γ is the
activity coefficient of subscript ion.
Stumm and Morgon [29] calculated the first and secondary ionization equilibrium constant of
CO2 in water, and Morshall and Franch [30] calculated the ionization equilibrium constant of water.
log(Ka1 ) =
134737.5
9036500
− 2211.492 − 0.30004T + 785.768 log T −
,
T
T2
1713800
24784.1
− 452.824 − 0.078515T + 162.47 log T −
,
T
T2
3245.2 223620 39840000
1262.3 856410
log(Kw ) = −4.098 −
+
−
+ 13.956 −
+
log(ρ),
T
T
T2
T3
T2
log(Ka2 ) =
(10)
(11)
(12)
where T is the temperature of the system, K; P is the partial pressure of CO2 in the system, bar; and ρ
is the density of the system, g·cm−3 .
Materials 2018, 11, 1765
11 of 15
Wiebe et al. [31,32] calculated the solubility of CO2 in water at 12–100 ◦ C, and assumed that the
solubility of CO2 in water was not related to the concentration of solution and pH value. Ziegler [33]
fitted the solubility data of Wiebe to the following empirical formula:
SCO2 = 4.11 −
5
+ 9.20T×2 10 − 2.5 × 10−3 P + 3.75 TP − 951.30 TP2
−1.52 × 10−7 P2 + 0.34 ln( P)
4329.91
T
(13)
where SCO2 is the total concentration of CO2 dissolved in water, mol·kg−1 .
The first ionization of the carbonated solution is the main reaction, and Ka1 is much larger than Kw
and K 2018,
. When
estimating the pH of the CO2 –H2 O system, the ionization of water and the secondary
Materialsa2
11, x FOR PEER REVIEW
11 of 14
ionization of carbonic acid can be neglected. Carbonic acid is a weak acid, and its xCO2 is much larger
than its
xH+than
. In carbonate
for CO
, theCO
concentration
of other ions
is negligible.
2(aq) for
much
larger
its xH+ . Insolution,
carbonateexcept
solution,
except
2(aq), the concentration
of other
ions is
Carbonic
acid
is
a
dilute
solution
with
an
ionic
activity
coefficient
of
about
1.
The
density
of
carbonic
negligible. Carbonic acid is a dilute solution with an ionic activity coefficient of about 1. The density
is similar
of pure
water,
and the
density
of pure
water
varies
with temperature,
ofacid
carbonic
acidtoisthat
similar
to that
of pure
water,
and the
density
of slightly
pure water
slightly
varies with
then xH+ ≈ Sthen
In +this
x
pH
are
calculated
as
follows:
+ and
CO2 . x
+
temperature,
≈ Sway,
.
In
this
way,
x
and
pH
are
calculated
as
follows:
H
CO
H
H
2
q
q
+ = Ka1 ×
= =Ka1 K×a1
SCO
xHx+H=
×2S, CO2 ,
CO
CO
a1 ×xx
2(aq)
2(aq)
(14)
(14)
+ ×γγ ++) =log x (+x −
log γH(+γ =+−) log
pH−=log
- log
pH =
= −xlog
( xHx+H×
H+ (. xH+ ).
HH = − logH
H+ ) − log
H
(15)
(15)
Figure
Figure14
14shows
showsthe
theaverage
averagecorrosion
corrosionrate
rateand
andestimated
estimatedpH
pHvalue
valueas
asaafunction
functionofofCO
CO2 2partial
partial
pressure
in
30%
crude
oil/brine
mixtures.
The
system
pH
decreased
with
increasing
CO
2
partial
pressure in 30% crude oil/brine mixtures. The system pH decreased with increasing CO2 partial
pressure.
2 partial
pressure.When
Whenthe
theCO
CO
pressurewas
wassmall,
small,the
thesystem
systempH
pHdecreased
decreasedsignificantly
significantlywith
with
2 partialpressure
increasing
CO
2
partial
pressure.
When
the
CO
2
partial
pressure
was
high,
the
pH
of
the
system
increasing CO2 partial pressure. When the CO2 partial pressure was high, the pH of the system
decreased
2 ininwater
decreasedinsignificantly
insignificantlywith
withincreasing
increasingCO
CO2 2partial
partialpressure.
pressure.The
Thedissolution
dissolutionofofCO
CO
watertoto
2
achieve
toincrease
increasethe
theCO
CO
2 partial
pressure
but
the
pH
value
almost
no
achieveequilibrium
equilibrium continued to
partial
pressure
but
the
pH
value
almost
no
longer
2
longer
increased
[25].
Therefore,
the
different
average
corrosion
rates
in
30%
crude
oil/brine
with
increased [25]. Therefore, the different average corrosion rates in 30% crude oil/brine with CO2 partial
CO
2 partial
pressure
were
not only
caused
by pH
but of
bychemical
a series ofchanges.
chemical changes.
pressure
were
not only
caused
by pH
changes
butchanges
by a series
7.0
Average corrosion rate
pH value
6
Ⅰ
Ⅱ
Ⅲ
6.5
Ⅳ
6.0
5
5.5
4
5.0
3
4.5
pH value
Average corrosion rate / mm·y-1
7
4.0
2
3.5
1
3.0
0
0
2
4
6
8
10
12
14
16
CO2 partial pressure / MPa
Figure 14. Average corrosion rate and estimated pH value as a function of CO2 partial pressure in 30%
Figure 14. Average corrosion rate and estimated pH value as a function of CO2 partial pressure in
crude oil/brine mixtures.
30% crude oil/brine mixtures.
4.2. Formation Mechanism of Localized Corrosion
4.2. Formation Mechanism of Localized Corrosion
With the change in CO2 partial pressure, the corrosion rate of the J55 carbon steel changed
With the in
change
in COoil/brine
2 partial pressure,
corrosion
ratethat
of the
carbonmechanism
steel changed
significantly
30% crude
mixtures, the
which
indicated
the J55
corrosion
also
significantly
in 30%
mixtures,
which
indicated
that
theincorrosion
also
changed. Figure
13crude
showsoil/brine
the partition
graph
of the
corrosion
rate
CO2 /30%mechanism
crude oil/brine
changed.
13 shows
the
partition
graphWater-in-oil
of the corrosion
rate in CO
2/30% crude
oil/brine
mixtures Figure
as the change
in CO
pressure.
and oil-in-water
emulsions
coexist
in 30%
2 partial
mixtures
as the change
in CO
partial
Water-in-oil
andisoil-in-water
coexist
crude oil/brine
mixtures,
and2 the
ratiopressure.
of oil-in-water
emulsion
large. Crudeemulsions
oil and water
canin
all
30%
crudethe
oil/brine
mixtures,The
andcrude
the ratio
of oil-in-water
large.
oiladsorbed
and water
moisten
metal surface.
oil with
corrosion emulsion
inhibitioniswas
notCrude
evenly
oncan
the
all
moisten
the metal
surface.
Thecorrosion.
crude oil with
corrosion
inhibition
was notmodels
evenly adsorbed
on theto
metal
surface,
causing
localized
As shown
in Figure
14, corrosion
were proposed
metal surface, causing localized corrosion. As shown in Figure 14, corrosion models were proposed
to clarify the influence of CO2 partial pressure on the mechanism of localized corrosion. The four
stages describing the formation of localized corrosion are as follows:
Model I (shown in Figure 15a): At Pco2 = 0–1.5 MPa, the corrosion rate increased rapidly with
the increase in CO2 partial pressure. When the CO2 partial pressure was small, the system pH
Model III (shown in Figure 15c): At Pco2 = 5.0–9.0 MPa CO2, the corrosion rate increased with
increasing CO2 partial pressure, which is in good agreement with the literature [28]. With the increase
in CO2 partial pressure from 5 to 9.0 MPa, CO2 phase changed to a supercritical state, and the
solubility of CO2 in crude oil increased rapidly [35]. When the decrease in pH value promoted the
dissolution
protective layers, CO2 possibly transferred from crude oil to the aqueous 12
phase,
Materials 2018, of
11, 1765
of 15
supplemented with consumed H+ dissolving the product layer [36]. Thus, the surface of carbon steel
was exposed to corrosive medium, and corrosion reaction was promoted [13,16]. The dissolution rate
clarify
the influence
of CO
pressurethan
on the
ofrate
localized
The
four stages
2 partial
of
the corrosion
product
layer
was greater
themechanism
precipitation
as thecorrosion.
CO2 partial
pressure
was
describing
the
formation
of
localized
corrosion
are
as
follows:
increased.
Model IV
I (shown
inin
Figure
15a):
AtAt
Pco
MPa, the corrosion rate increased rapidly with the
2 = 0–1.5
Model
(shown
Figure
15d):
Pco
2 = 9.0~15.0 MPa, the corrosion rate was almost constant
increase
in
CO
partial
pressure.
When
the
CO
partial
was small,
system pH decreased
2 in CO2 partial pressure. This result
2
with the increase
canpressure
be attributed
to thethe
almost-constant
system
significantly
with
increasing
CO
partial
pressure,
similar
to
the
estimated
pH
value
shown
in
Figure
14.
2
pH value (about 3.10–3.14), as shown in Figure 14. At the initial stage of the experiment, the metal
The concentration
of H2localized
CO3 increased
withThe
increasing
CO2 and
partial
pressure,ofwhich
accelerated
the
surface
suffered strong
corrosion.
production
dissolution
corrosion
scale were
2+ content. The
cathodic
reactions,
increased
the
corrosion
rate
[13–16],
and
finally
increased
the
Fe
carried out simultaneously. Finally, a dense, complete, and protective corrosion product layer
corrosion
scale precipitated
the scattered
corrosion
scale
appeared
on the surface,
the solubility
formed
rapidly
on the metaland
surface.
Yoon-Seok
Choi et
al. [18]
also obtained
similarbut
results,
i.e., the
products
of
FeCO
and
CaCO
increased
because
the
pH
decreased,
as
shown
in
Figure
Pitting
3
3
corrosion rates of L80 in 25 wt.% NaCl solution started out high but ended up being very6b.
low
at 90
− [9].
may
also
occur
locally
due
to
the
presence
of
crude
oil
and
Cl
°C and 12 MPa CO2 pressure. Pitting may occur under dense protective layer, as shown in Figure 13.
(a)
(b)
(c)
(d)
Figure 15. Schematic models for the localized
localized corrosion of
of J55
J55 steel
steel in
in the
thedifferent
differentCO
CO22/30%
/30% crude
oil/brinemixtures:
mixtures:(a)
(a)model
modelI:I:generating
generatingscattered
scatteredcorrosion
corrosionscale
scale (Pco
(Pco22 == 0.5–1.5
0.5–1.5 MPa);
MPa); (b) model
oil/brine
gradually generating
generating protective
protective corrosion
corrosion scale (Pco22 == 1.5–5.0
1.5–5.0 MPa); (c)
(c) model III: dissolving
II: gradually
MPa);
and
(d)(d)
model
IV: generating
protective
corrosion
scale
5.0–9.0
MPa);
and
model
IV: generating
protective
corrosion
protective corrosion
corrosionscale
scale(Pco
(Pco
2 2= =5.0–9.0
(Pco2 (Pco
= 9.0–15.0
MPa).MPa).
scale
2 = 9.0–15.0
Model II (shown in Figure 15b): At Pco2 = 1.5–5.0 MPa, the corrosion rate decreased with
increasing CO2 partial pressure. At the initial stage of the experiment, the metal surface suffered
strong localized corrosion. This result is consistent with the conclusions of many researchers [5,13–16].
The Fe2+ concentration increased and acidic concentration decreased rapidly on the steel surface. The
nucleation and growth of FeCO3 typically start on the steel surface where the pH and FeCO3 saturation
values are the highest [34]. The FeCO3 layer restricted the transport of H+ in and Fe2+ out; thus, the
corrosion rate decreased with the increase in CO2 partial pressure. The reduction of the system pH
value also dissolved the corrosion scale, but the dissolution rate of the corrosion product layer was
lower than the precipitation rate as the CO2 partial pressure was increased.
Model III (shown in Figure 15c): At Pco2 = 5.0–9.0 MPa CO2 , the corrosion rate increased with
increasing CO2 partial pressure, which is in good agreement with the literature [28]. With the increase
in CO2 partial pressure from 5 to 9.0 MPa, CO2 phase changed to a supercritical state, and the solubility
of CO2 in crude oil increased rapidly [35]. When the decrease in pH value promoted the dissolution
of protective layers, CO2 possibly transferred from crude oil to the aqueous phase, supplemented
Materials 2018, 11, 1765
13 of 15
with consumed H+ dissolving the product layer [36]. Thus, the surface of carbon steel was exposed to
corrosive medium, and corrosion reaction was promoted [13,16]. The dissolution rate of the corrosion
product layer was greater than the precipitation rate as the CO2 partial pressure was increased.
Model IV (shown in Figure 15d): At Pco2 = 9.0~15.0 MPa, the corrosion rate was almost constant
with the increase in CO2 partial pressure. This result can be attributed to the almost-constant system
pH value (about 3.10–3.14), as shown in Figure 14. At the initial stage of the experiment, the metal
surface suffered strong localized corrosion. The production and dissolution of corrosion scale were
carried out simultaneously. Finally, a dense, complete, and protective corrosion product layer formed
rapidly on the metal surface. Yoon-Seok Choi et al. [18] also obtained similar results, i.e., the corrosion
rates of L80 in 25 wt.% NaCl solution started out high but ended up being very low at 90 ◦ C and
12 MPa CO2 pressure. Pitting may occur under dense protective layer, as shown in Figure 13.
5. Conclusions
Based on the observed corrosion behavior of J55 carbon steel in different CO2 /30% crude oil/brine
mixtures at 65 ◦ C, we conclude the following:
(1) The corrosion rate sharply increased as the CO2 partial pressure was increased from 0 to
1.5 MPa, decreased from Pco2 = 1.5 MPa to Pco2 = 5.0 MPa, increased again at Pco2 = 5.0 MPa, and
then reached a constant value after Pco2 = 9.0 MPa.
(2) In 30% crude oil/brine mixtures, the surface of J55 carbon steel was covered by FeCO3 and
CaCO3 . The surface of the J55 carbon steel suffered localized corrosion in different CO2 /30% crude
oil/brine mixtures at 65 ◦ C.
(3) The system pH initially decreased, rapidly increased, and then stabilized as CO2 partial
pressure was increased. The CO2 partial pressure changed the system pH and CO2 solubility in crude
oil, which further affected the formation and protection performance of the corrosion product layer.
Author Contributions: H.B., Y.W. and Q.Z. conceived and designed the experiments; H.B. and Y.M. analyzed the
data and wrote the paper; H.B., Y.W., H.B. and N.Z. proposed the corrosion model.
Acknowledgments: This research was funded by the Natural Science Foundation of China, grant number
51504193 and the Key Laboratory Research Project of Shaanxi Education Department, grant number 15JS090.
Authors are thankful to Experiment Center of Petroleum and Natural Gas Engineering, Xi’an Shiyou University
for providing all necessary facilities to undertake the work.
Conflicts of Interest: The authors declare that they have no conflict of interest.
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