Peng et al. BMC Chemistry(2024) 18:117
https://doi.org/10.1186/s13065-024-01225-z

BMC Chemistry

RESEARCH

Open AccessStudy of the corrosion behavior of N80
and TP125V steels in aerobic and anoxic shale
gas field produced water at high temperature
Lincai Peng1,2,3, Shaomu Wen4, Hongfa Huang1,2,3, Xi Yuan1,2,3, Jiahe Huang5, Yu He6 and Wen Chen1,2,3*
Abstract
In this study, the corrosion behavior of N80 and TP125V steels was delved firstly into produced water from shale
gas fields containing CO2-O2. Moreover, the localized corrosion of these steels was investigated to elucidate
the effects of aerobic and anoxic on steel corrosion. The results indicated that the corrosion rates of N80 and
TP125V steels under aerobic conditions were lower compared to those in the presence of CO2-O2. Specifically, attemperature of 100 °C and with dissolved oxygen (DO) concentration of 4 mg/L in the CO2-O2 environment, theN80 and TP125V steels exhibited the highest corrosion rate, with values of 0.13 mm/y and 0.16 mm/y, respectively,
as determined by specific weight loss measurements. Conversely, these rates decreased to 0.022 mm/y and0.049 mm/y under aerobic conditions. Furthermore, severe localized corrosion of N80 and TP125V steels with a DO
concentration of 4 mg/L was also observed in the CO2-O2 environment. Finally, it was evident that pitting corrosionis the predominant type of corrosion affecting N80 and TP125V steels in the produced water from shale gas fields.
Keywords Localized corrosion, Shale gas, N80 and TP125V steels, High temperature*Correspondence:
Wen Chenchen.wen@petrochina.com.cn
1Research Institute of Natural Gas Technology, PetroChina Southwest Oiland Gasfield Company, Chengdu, Sichuan 610213, China
2
National Energy R&D Center of High Sulfur Gas Exploitation, Chengdu,
Sichuan 610213, China
3
High Sulfur Gas Exploitation Pilot Test Center, China National Petroleum
Corporation, Chengdu, Sichuan 610213, China
4
PetroChina Southwest Oil and Gasfield Company, Chengdu,
Sichuan 610051, China
5
School of Chemical Engineering and Technology, Sun Yat-sen University,
Zhuhai, Guanggong 519082, China
6
Shunan Gas Mine, PetroChina Southwest Oil and Gasfield Company,
Luzhou, Sichuan 646001, China

Introduction
Shale gas, as a cleaner and more efficient form of natural energy, is at the forefront of oil and gas explorationand has been a hot topic of research in recent years [1, 2].
The estimated amount of recoverable shale gas is morethan 30 × 1012 m3 in China, of which the Sichuan Basinhas the highest reserves [3]. As the demand for shale
gas increases, the current challenge is how to improveshale gas recovery efficiency. The safety running of pipeline steel is the primary factor in guaranteeing shale gas
exploitation. Nevertheless, wellbores and gathering pipelines often suffer from severe corrosion due to the harshenvironment in shale gas wells [4, 5]. Especially once thewellbore fails due to corrosion, it leads to the shutdown
of gas wells for repairs, greatly restricting the high-efficiency exploitation of shale gas resources [6]. The corrosion of steel especially pitting corrosion is the principal
reason influencing the mechanical properties of pipelines© The Author(s) 2024. Open Access This article is licensed under a Creative Commons Attribution 4.0 International License, which permits use,sharing, adaptation, distribution and reproduction in any medium or format, as long as you give appropriate credit to the original author(s) andthe source, provide a link to the Creative Commons licence, and indicate if changes were made. The images or other third party material in thisarticle are included in the article’s Creative Commons licence, unless indicated otherwise in a credit line to the material. If material is not includedin the article’s Creative Commons licence and your intended use is not permitted by statutory regulation or exceeds the permitted use, you willneed to obtain permission directly from the copyright holder. To view a copy of this licence, visit http://creativecommons.org/licenses/by/4.0/. The
Creative Commons Public Domain Dedication waiver (http://creativecommons.org/publicdomain/zero/1.0/) applies to the data made available
in this article, unless otherwise stated in a credit line to the data.

Peng et al. BMC Chemistry(2024) 18:117

and their service life [7]. However, the corrosion mechanism of steel is also indefinable but depends on the environmental conditions.
Corrosion is closely related to material types and environmental conditions [8]. Carbon steel has been commonly applied in oil and gas fields because of its favorable
mechanical properties as well as low costs [9]. The production tubing utilized in shale gas wells is commonly
fabricated from materials such as N80 and TP125V steel
grades [10]. However, carbon steel has a low corrosion
resistance, and localized corrosion is commonly found[11]. Many factors have a deep influence on steel corrosion, such as temperature, pressure, dissolved oxygen,
quality of produced water, and microorganisms [12–16].
Jiang et al. [17] discovered severe corrosion of mild steel
in a shale gas gathering condition, and microbiological corrosion connected with under-deposit corrosion(UDC) made a big contribution to steel corrosion. The
environments downhole in shale gas wells are complex,
following the high pressure, high temperature, a high salt
solution, and the maximum temperature can exceed 100℃ [18, 19]. Temperature as one of the important parameters that can directly influence the corrosion rates ofsteel, and there is an extreme value for steel corrosion
rates as the increase of the temperature in a sealed environment [20].
Furthermore, hydraulic fracturing in shale gas wells
can introduce dissolved oxygen (DO), which is also a significant factor in the corrosion of steel materials [21, 22].
DO interacts with iron in an aqueous medium to produce
Fe2O3 [23]. Compared with the condition containing
only CO2, the cathodic reaction rate could be accelerated, and reduce the formation probability of FeCO3 dueto the conversion of FeCO3 into Fe2O3 in the presence ofO2 [24]. Previous studies mainly focus on the influence ofCO2, microorganisms, temperature, and Cl− on steel corrosion [25, 26]. However, the impact of DO on the corrosion behavior of steel in a shale gas environment remains
uncertain. The presence of oxygen in a CO2-saturated
test solution has been shown to alter corrosion behavior
and mechanisms [27]. Tang et al. observed that the introduction of DO in the supercritical CO2 phase can expedite the corrosion of steel, resulting in the formation ofdual-layer corrosion products due to the presence of asmall amount of DO [28]. In a similar vein, Li et al. [29]reported that DO could reduce the corrosion rate of N80
steel by promoting the formation of a protective FeCO3
layer under supercritical CO2 conditions.
In our previous studies, we found that the corrosion of
TP125V and N80 steel was most extensive under conditions of 100 °C and saturated CO2 [30]. Consequently,
this work focuses on the corrosion behavior of these twosteels in a shale gas field produced water as the change of
DO was deeply studied in this work, using weight loss,

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surface analysis, and electrochemical measurements,
which provides insight into the possible influence of aerobic and anoxic shale gas environments on steel corrosion.

Experimental
Steel specimens

N80 and TP125V steels, commonly applied as the material for downhole tubing in the shale gas field, were used
to explore the corrosion behavior, and their chemicalcompositions are shown in Table S1. The C content wasdetermined using a Carbon-Sulfur Analyzer instrument(CS-3000, NCS Testing Technology Co., China), while
the other elements were measured by Atomic Absorption
Spectroscopy (iCE 300, Thermo Fisher Scientific, USA).
Steel specimens were applied in the experiment of weightloss and surface morphologies with the size of 10 mm ×
30 mm × 3 mm. Electrochemical experiments, including
open-circuit potential (OCP), electrochemical impedance spectroscopy (EIS), and potentiodynamic polarization studies, were conducted using working electrodes
with an area of 1 cm2 under stagnant. The samples wereconsistently polished with 400#, 600#, and 1200# siliconcarbide abrasive papers, rinsed with ultrapure water, acetone, and anhydrous ethanol in series, following sterilization of more than 30 min by ultraviolet (UV) light.
Test solution

In this work, the test solution was prepared based on
the chemical components of the shale gas field produced
water from Sichuan Changning Natural Gas Development Co., Ltd., and the chemical components of theartificial shale gas field produced water were as shownin Table S2. To simulate the natural shale gas produced
water, the field used drainage aid of 0.1 wt%, drag reducerof 0.1 wt%, and biocide of 0.05 wt% which were added
to the test solution. The drainage aid, drag reducer andbiocide, obtained from Chengdu Nengte Technology
Development Co., Ltd., with respective product numbers
CT5-12 A, CT1-20D, and CT10-4B, serve as the principal
materials for hydraulic fracturing gas extraction in shale
gas wells in the Sichuan-Chongqing region. The experiments were divided into two parts. For the first part, theconcentration of dissolved oxygen was 2, 4, and 6 mg/L,
respectively, adjusted by sparging CO2 gas to investigate the influence of DO on steel corrosion. For the second part, the corrosion study of steel was conducted in
an aerobic condition at 60℃ and 100 ℃ to instigate theinfluence of temperature on steel corrosion.
Weight loss

After a specific time of testing, all specimens applied
were taken out and were slightly washed with a pickling solution containing corrosion inhibitors. Then thewashed specimens were further rinsed with distilledPeng et al. BMC Chemistry(2024) 18:117

water, acetone, and absolute ethyl alcohol, respectively.
Subsequently, all specimens were dried using N2. The
weight loss was calculated based on the change in thespecific mass of specimens. The following equation wasused to calculate the corrosion rates of different steel
specimens.

CR =8.76 × 104 × (M1 − M2 )
(1)
Atρ

Where CR, A, t and ρ are corrosion rate (mm/y), theworking area of steel (cm2), testing time (h) and the density of steel (kg/m3), respectively. M1 and M2 are the specific mass of the specimens initially and after corrosion(g).
Characterizations of surface films

The surface films of two steel specimens caused by corrosion under different test conditions were conducted byscanning electron microscopy (SEM, JSM-IT200, JEOL,Japan), and their chemical compositions were measuredby X-ray diffractometer (XRD) (Ultima IV, Rigaku, Japan)
and energy disperse spectroscopy (EDS) (JSM-IT200,
JEOL, Japan). Before SEM observation, a thin gold film
coated on the specimen aims to increase the quality of
the images. The corrosion morphologies of bare specimens were observed by a three-dimensional microscope(Leica DVM6, Germany) to characterize the localized
corrosion.
Electrochemical measurements

Electrochemical tests in this work were conducted basedon a three-electrode system via a CS350 electrochemical workstation, while steel specimens were the working
electrode, Ag/AgCl electrode, and Pt plate corresponding to the reference and counter electrodes, respectively. OCP was scanned at a scan rate of 0.5 mV/s toachieve a stable state, and EIS was performed subsequently by applying sinusoidal voltage signal of 10 mV
corresponding to the frequency range of 105 ~ 10− 2 Hz.

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Potentiodynamic polarization curves with a potential
range of -250 mV to + 350 mV vs. corrosion potential at
a potential sweep rate of 0.5 mV/s. Zview2 and Cview2
software (Scribner, Inc.) were used to analyze the measured impedance and polarization data, respectively. Allof the tests were repeated at least three times to ensure
the reproducibility of experimental data.

Results and discussion
Effect of DO concentration on the corrosion of N80 and
TP125V steels at 100℃
Corrosion rates based on weight loss

The corrosion rates of N80 and TP125V steels calculated
from the specific weight loss are depicted in Fig. 1 at 100℃ with different concentrations of DO and a test time of
3 d. As can be seen from Fig. 1, N80 and TP125V steels
both have the biggest corrosion rates at the DO of 4 mg/L
corresponding to the values of 0.13 and 0.16 mm/y
respectively. Therefore, the changes in DO have an influence on steel corrosion in shale gas field conditions. The
existence of O2 can change the components and structure of corrosion products thus then causing the change
in steel corrosion behavior [31]. At this intermediate concentration, there is enough dissolved oxygen to promote
the formation of corrosion products, such as oxides,
which can enhance the rate of metal dissolution. However, at higher concentrations of DO, the formation ofa more protective oxide layer can inhibit further corrosion, leading to a lower corrosion rate. Furthermore, it isalso found that the corrosion rates of TP125V steel at 100℃ are slightly higher than those of N80 steel, which may
be due to the composition of the material and its uniquemorphological characteristics [30].
Corrosion product morphology analysis

SEM images of the surface morphologies of N80 steel
and the corresponding EDS after 3 d of testing at 100 ℃
in artificial shale gas field produced water with different
concentrations of DO are presented in Fig. 2. There is athin corrosion product film for the specimen with DO

Fig. 1 Corrosion rates of the specimens calculated from weight loss in artificial shale gas filed produced water containing the DO of 2, 4, and 6 mg/L at
100 ℃ after 3 days of testing: (a) N80 steel; (b) TP125V steel

Peng et al. BMC Chemistry(2024) 18:117

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Fig. 2 SEM images of surface films on N80 steel and the corresponding EDS after 3 days of testing at 100 ℃ in shale gas field produced water with different concentrations of DO: (a, b and c) 2 mg/L; (d, e, and f) 4 mg/L; (g, h and i) 6 mg/Lof 2 mg/L (Fig. 2a), and the polish lines and some particles of corrosion products are also seen (Fig. 2a and b).
The appearance of polish lines suggests slight corrosion.
When the DO increases to 4 mg/L and 6 mg/L, corrosion
products on the surface of the specimen have noticeably
increased and there are also some larger particles covering the surface of the specimen, which further indicatesthat the corrosion should be severe. A loose and porous
corrosion product film appears (Fig. 2d and e) with DOof 4 mg/L which is conducive to the acceleration of steel
corrosion due to the easy diffusion and transfer of corrosive ions, such as Cl− [32]. As the DO further increases to
6 mg/L, a similar porous film structure is also found but
the size of corrosion product particles is small (Fig. 2g
and h). The smaller corrosion product particles and thedense structure can inhibit the erosion of corrosive ions,leading to a reduced corrosion rate. From the EDS analysis results, the dominating elements in corrosion products consist of C, O, Ca, Mg, Fe, and Cr. (Fig. 2c, f and i,
and Table S3, and the contents of these elements under
different test conditions are similar. Therefore, the primary corrosion products are FeCO3 and iron oxides on
account of the coexistence of O2 and CO2 [33, 34].
Figure 3 presents the SEM images of the surface morphologies of TP125V steel and the corresponding EDS
after 3 d of testing at 100 ℃ in shale gas field produced
water with different concentrations of DO. For TP125V
steel, the surface morphologies are similar to N80 steel

when the DO are 2 and 4 mg/L (Figs. 2 and 3), and thepolish lines as well as the porous corrosion product films
both can be observed. This also further explains the reason for the higher corrosion rate with a DO of 4 mg/L.
Referring to Fig. 2b, the greater amount of corrosion
products (Fig. 3b) also indicates that the corrosion of
TP125 is more severe than that of N80 when the DO is
2 mg/L. When the DO is 6 mg/L, the denser corrosion
product film can be recognized (Fig. 3g and h) and caninhibit the erosion of corrosive ions. This is also thereason for the decrease in the corrosion rate. The EDS
analysis results also demonstrate that the elements incorrosion products include C, O, Fe, Ca, and Mg (Fig. 3c,f, i, and Table S4, also corresponding to the corrosion
products of FeCO3 and iron oxides.
Analysis of the bare corrosion morphology of steels

The bare corrosion morphologies of N80 steel after
removing the surface corrosion products with a test timeof 3 d at 100 ℃ are depicted in Fig. 4. From the overall
point of view, the specimens suffer from different degrees
of localized corrosion under different test conditions. For
the specimen with DO of 2 mg/L, the polish scratcheson the sample surface are still clearly visible, and somesmall and shallow corrosion pits can be observed with amaximum depth of about 10.09 μm (Fig. 4a-a2). When
the DO increases to 4 mg/L, serious pitting corrosion on
steel surface having a maximum depth of about 24.40 μm

Peng et al. BMC Chemistry(2024) 18:117

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Fig. 3 SEM images of surface films on TP125V steel and the corresponding EDS after 3 days of testing at 100℃ in artificial shale gas field produced waterwith different concentrations of DO: (a, b and c) 2 mg/L; (d, e, and f) 4 mg/L; (g, h and i) 6 mg/L

Fig. 4 The bare corrosion morphologies of N80 steel without corrosion products after 3 days of testing at 100℃ in shale gas field produced water withdifferent concentrations of DO: (a, a1 and a2) 2 mg/L; (b, b1, and b2) 4 mg/L; (c, c1, and c2) 6 mg/L

Peng et al. BMC Chemistry(2024) 18:117

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Fig. 5 Corrosion rates of N80 steel (a) and TP125V steel (b) calculated from weight loss after 14 days of testing in CO2 saturation and air saturation in airsaturated artificial shale gas field produced water at 60℃; corrosion rates of N80 steel (c) and TP125V steel (d) calculated from weight loss after 14 daysof testing in air-saturated artificial shale gas field produced water at 60 and 100 ℃

is observed (Fig. 4b-b2). However, both the density anddepth of corrosion pits decrease for the specimen withDO of 6 mg/L, with the maximum depth of the corrosion
pits reaching approximately 14.99 μm (Fig. 4c-c2). The
test results of bare surface morphologies are in accordance with the corrosion rates (Fig. 1a), the corrosion of
N80 steel is significantly enhanced when DO is 4 mg/L.
The bare corrosion morphologies of TP125V steel
without corrosion products after 3 d are presented in Figure S1. From Figure S1 a-a2, the corrosion is slight with
the DO of 2 mg/L, but some small areas corresponding
to the black color can be attacked by corrosion. However,
severe pitting corrosion is observed on steel specimens
with the DO of 4 mg/L, and the maximum depth of corrosion pits is about 45.42 μm (Figure S15b-b2). When
the DO furtherly increases to 6 mg/L, the corrosion ofsteel has an apparent mitigation and pitting corrosion has
a maximum depth of about 26.93 μm (Figure S1 5c-c2).
Similarly, these results are consistent with the corrosion
rate findings presented in Fig. 1b. It can be concluded
that the appearance of DO in the test solution has a
deep influence on the corrosion process, and the uniform and pitting corrosion is more serious when the DO
is 4 mg/L. Furthermore, the corrosion rate of TP125V
steel has exceeded N80 steel in artificial shale gas field
produced water. The generation of pitting corrosion canderive from the addition of field-used drainage aid, dragreducer, and biocide which have a corrosion inhibition
effect on steel corrosion [12]. During the exploitation ofoil and gas fields, large amounts of corrosion inhibitors
are widely applied but pitting corrosion dominates one of
the main corrosion types [35–37].
Corrosion behavior of N80 and TP125V steels underaerobic and anoxic conditions
Corrosion rates derived from weight loss

Figure 5 depicts the uniform corrosion rates of N80 and
TP125V steels calculated from weight loss after 14 d oftesting in CO2 saturated and in air-saturated artificial
shale gas field produced water at 60℃ and in air-saturated artificial shale gas field produced water at 100 ℃.
In the CO2-saturated environment, the corrosion rate of
N80 steel reaches 0.038 mm/y, whereas in the air-saturated environment, the corrosion rate is only 0.009 mm/y,significantly lower than in the CO2-saturated environment (Fig. 5a). A similar result is observed for TP125V.
The corrosion rate of TP125V steel is 0.013 mm/y in theCO2-saturated environment, while the corrosion rateis merely 0.008 mm/y in the air-saturated environment(Fig. 5b). This substantial reduction in the corrosion ratein the air-saturated environment compared to the CO2saturated environment further indicates that CO2 has agreater promoting effect on metal corrosion than O2.
Thus, it is evident that the corrosion rates of both steels

Peng et al. BMC Chemistry(2024) 18:117

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Fig. 6 SEM images of surface films on N80 steel and the corresponding EDS after 14 days of testing at 60 ℃ and 100 ℃ in aerobic shale gas field produced water: (a, b, and c) 60 ℃; (d, e, and f) 100 ℃

Fig. 7 SEM images of surface films on TP125V steel and the corresponding EDS after 14 days of testing at 60 ℃ and 100 ℃ in aerobic shale gas field
produced water: (a, b, and c) 60 ℃; (d, e, and f) 100 ℃

in the anoxic condition are significantly higher than thosein the air-saturated environment. This finding suggeststhat in shale gas environments, CO2 corrosion is morecritical to consider than oxygen corrosion. The increasein temperature can accelerate the corrosion rates of steel
belongs to the kinetics of electrochemical corrosion.
Therefore, temperature is one of the considerable factors
influencing steel corrosion in shale gas conditions. Thereis a low corrosion rate for N80 steel at 60 ℃ with a valueof 0.009 mm/y, but the value increases to 0.022 mm/y at
100 ℃ (Fig. 5c). For TP125V steel, the corrosion ratesof the specimen reach 0.008 and 0.049 mm/y at 60 and
100 ℃, respectively (Fig. 5d). Therefore, it can be concluded that the corrosion of N80 and TP125V steels has
a little difference at a low temperature, but the corrosionof TP125V steel is more serious compared to N80 steel
at a high temperature, i.e., TP125V steel has a lower corrosion resistance under high-temperature conditions.
Higher temperature can increase the migration of corrosive ions and accelerate both the anodic and cathodic
reactions. Thus then, the corrosion rate on both steel
increased as the temperature increased. Furthermore, it

is also discovered that steel corrosion in the air-saturated
test solution has a decrease compared to that in the CO2O2 solution. Therefore, the individual oxygen corrosionof pipeline steel in shale gas produced water does notneed to be paid more attention.
Corrosion product morphology analysis

SEM images of surface films on N80 and TP125V steels
and the corresponding EDS after 14 d of testing at 60
and 100 ℃ in aerobic shale gas field produced water are
displayed in Figs. 6 and 7. For N80 steel, there is a thinfilm caused by corrosion on steel at 60 ℃ (Fig. 6a), andsome agglomerate corrosion product particles coveron steel surface (Fig. 6a and b). When the temperature
increases to 100 ℃, only little corrosion products arefound (Fig. 6c and d), and some corrosion pits are also
observed (Fig. 6d), suggesting a weak uniform corrosion.
When the steel changes to TP125V steel, the morphologies of the surface film have a little change compared to
N80 steel. Some loose corrosion products can also befound at 60 ℃, and the surface corrosion products havedecreased when the temperature is 60 ℃ (Fig. 7d and e).

Peng et al. BMC Chemistry(2024) 18:117

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Fig. 8 XRD analysis results of the corrosion products on N80 (a) and TP125V (b) steels after 14 days of testing at 60 and 100 ℃ in aerobic shale gas field
produced water

Fig. 9 The bare surface corrosion morphologies of N80 steel after 14 days of testing at 60 and 100 ℃ in aerobic shale gas field produced water: (a-a2)
60 ℃, (b-b2) 100 ℃

Furthermore, EDS analysis results demonstrate that themain corrosion products focus on iron oxides (Tables S5and S6), the typical products of oxygen corrosion.
SEM images in Figs. 6 and 7 show that the surface
scratch lines of N80 and TP125V steels are easily recognized no matter whether the temperature is 60 or 100 ℃
which demonstrates that the uniform corrosion is notsevere for steel specimens corresponding to the weightloss (Fig. 5). The key factor in this work causing a low corrosion rate is the adding of some chemicals with corrosion inhibition effect as stated above. Furthermore, steel
corrosion rates in the aerobic condition are smaller thanthat in the CO2-O2 environment (Figs. 1 and 5). Therefore, the presence of CO2-O2 in the test solution can considerably promote steel corrosion but the corrosion will
alleviate when only in the O2 environment.
XRD analysis results

Figure 8 shows the specific components of the corrosion products formed on N80 and TP125V steels after
14 d of testing at 60 and 100 ℃ in aerobic shale gas field
produced water. As exhibited in Fig. 8a, the typical corrosion products of N80 steel at 60 ℃ are mainly composedof CaCO3, FeOOH, and CaMg(CO3)2, while Fe2O3 isdominated at 100℃. For TP125V steel, Fe2O3 and Fe3O4
dominate the primary corrosion products (Fig. 8b). The
peak intensity of the corrosion products is low and Fe
has a high peak in XRD spectra, which demonstrates thatthe contents of surface corrosion products are low corresponding to SEM images of surface films (Figs. 6 and 7).
Analysis of the bare corrosion morphology

The bare surface corrosion morphologies of N80 and
TP125V steels after 14 d of testing at 60 and 100 ℃ in
aerobic shale gas field produced water are exhibited in
Figs. 9 and 10. At 60 ℃, both the corrosion of N80 and
TP125V steels is slight especially localized corrosion, andonly some minute-sized corrosion pits are found (Fig. 9aa2 and 10a-a2). When the temperature increases to 100℃, the density and depth of corrosion pits have a considerable increase compared with those at 60 ℃. For N80
steel, the maximum depth of pitting corrosion is about
18.49 μm at 100 ℃ (Fig. 9b2). However, the size of thecorrosion pits of TP125V steel (Figure S2) is higher thanthose for N80 steel, and its maximum depth is about
20.69 μm (Figure S2 b2). Therefore, the localized corrosion of TP125V steel in aerobic shale gas field produced
water at a high temperature is more serious comparedPeng et al. BMC Chemistry(2024) 18:117

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Fig. 10 Nyquist and Bode diagrams of N80 (a and b) and TP125V (c and d) steels after 14 days of testing at 60 ℃ in aerobic shale gas field produced water

Fig. 11 Equivalent circuit (a) used to fit EIS data and the corresponding fitted results of TP125V steel (b), i.e., Rp, the sum of Rf and Rct

with N80 steel, which is also in agreement with weightloss (Fig. 5). The formation of pitting corrosion can derivefrom the formation of some defects in corrosion inhibitor
film as well as the erosion of Cl− [38].
EIS analysis

The Nyquist and Bode diagrams of N80 and TP125V
steels with a test time of 14 d at 60 ℃ in aerobic shale
gas field produced water are shown in Fig. 10. To do theelectrochemical analysis, 60 ℃ is chosen as a typical temperature. For N80 steel, the diameters of Nyquist plots
have a gradual increase as time overall, but the impedance values change little after 7th d (Fig. 10a). Two timeconstants are easily found in Bode plots, demonstrating
the formation of a protective film limited the diffusion
process of corrosive ions [39]. The two time-constants

are formed initially on the first day. Therefore, the formed
surface film cannot be the corrosion product film, but anadsorption film of corrosion inhibitor coming from thefield used drag reducer, drainage aid and biocide. Thisagrees with the SEM observation in Fig. 9a and b, i.e.,
no apparent corrosion product film formation. A similar
situation is also found in the Bode plots of TP125V steel(Fig. 10d). Furthermore, the impedance values of TP125V
steel also have a similar tendency to N80 steel.
EIS diagrams are fitted well based on the equivalentcircuit presented in Fig. 11a, and the corresponding
Rp values, the sum of Rf and Rct, i.e., the fitted results of
EIS data are exhibited in Fig. 11b. Rp values are inversely
proportional to steel corrosion rates. In the equivalentcircuit, Rs, Rf, and Rct are assigned to the resistances ofsolution, surface film as well as charge transfer, while

Peng et al. BMC Chemistry(2024) 18:117

Fig. 12 Polarization curves of N80 (a) and TP125V (b) steels after 14 daysof testing at 60 ℃ in aerobic shale gas field produced water

Qf and Qdl correspond to surface film and double-layer
capacitance. From Fig. 11b, the changes of Rp values of
N80 and TP125V steels with time have a similar law, but
the Rp values of TP125V steel are higher than N80 steel
before 7 d. There is a small difference in the Rp valuesof N80 and TP125V steels after 7 d of testing but the Rp
values of TP125V steels are smaller overall. These demonstrate that the corrosion behavior of N80 and TP125V
steels at 60 ℃ has a little difference and their corrosion
difference is related to the test time.
Polarization curves

Figure 12 presents the polarization curves of N80 and
TP125V steels after 14 d of testing at 60 ℃ in aerobic
shale gas field produced water, and the fitted electrochemical parameters including the anodic and cathodic
Tatel slopes (Ba and Bc), the corrosion potential (Ecorr),the corrosion current density (Icorr) and the corrosion
rate are exhibited in Table S7. The cathodic reaction of
TP125V steel is inhibited while its anodic reaction isslightly enhanced compared with the N80 steel. The corrosion potential of TP125V steel has a little negative shift.
However, the polarization curves of N80 and TP125V
steels have a small difference. From the fitted electrochemical parameters in Table S7, the corrosion current
densities of N80 and TP125V steels are close, and thevalues are 3.44 × 10− 6 and 2.40 × 10− 6 A/cm2, respectively.
The values of corrosion current density show a positive
correlation with steel corrosion rates. Therefore, it isalso concluded that the corrosion behavior of N80 and
TP125V steels at 60 ℃ are similar, and the corrosion rateof N80 steel is slightly higher than TP125V steel. Furthermore, a passivation phenomenon can be seen from thepolarization curve of N80 steel, which is probably formed
due to the corrosion product film.

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Conclusion
The introduction of DO in CO2-saturated artificial
shale gas filed produced water has a deep influence on
steel corrosion behavior, and N80 and TP125V steels
both have the biggest corrosion rates with the DO of
4 mg/L at 100 ℃ corresponding to the values of 0.13
and 0.16 mm/y respectively. Serious localized corrosion
is also found for N80 and TP125V steels at the DO of
4 mg/L, and the maximum depths of pitting corrosion
are about 24.40 and 45.42 μm, respectively. When the
DO is 2 and 6 mg/L, both the uniform and localized corrosion are slight. The increase in the content of DO leads
to an intensification of corrosion to a certain extent, but
further increases do not exacerbate corrosion, which canbe relate to the characteristics of the corrosion products.
Localized corrosion is the main corrosion type for N80
and TP125V steels deriving from the addition of somecorrosion-inhibitive components.
N80 and TP125V steels have high corrosion rates inCO2-saturated test solution with values of 0.038 and0.013 mm/y, and the values turn out to be 0.009 and0.008 mm/y in air-saturated test solution at 60 ℃. It isevident that the corrosion rates of both steels in theanoxic condition are significantly higher than those in
the air-saturated environment. Besides, the corrosion
rates of N80 and TP125V steels with values of 0.022 and0.049 mm/y at 100 ℃ are higher compared to their rates
at 60 ℃, which indicates that temperature is also a key
factor influencing the degree of oxygen corrosion. In
addition, weight loss, the bare corrosion morphologies,
and the analysis results of electrochemical measurements
demonstrate that the corrosion difference between N80
and TP125V steels at 60 ℃ is small. Localized corrosion
is also the typical corrosion type in aerobic conditions,and the main corrosion products are iron oxides, the typical products of oxygen corrosion. EIS data confirm theadsorption and formation of a corrosion inhibitor film on
steel thus leading to slight uniform corrosion.
Supplementary Information

The online version contains supplementary material available at https://doi.
org/10.1186/s13065-024-01225-z.
Supplementary Material 1
Acknowledgements
The authors gratefully acknowledge the assistance of Hongwei Liu of Sun Yatsen University, who provided invaluable results of SEM and XRD for this study.
Author contributions
Lincai Peng: Conceptualization, Investigation, Methodology, Writing – originaldraft. Shaomu Wen: Conceptualization, Formal analysis, Methodology,
Supervision. Hongfa Huang: Validation, Formal analysis, Supervision, Xi Yuan:
Conceptualization, Formal analysis, Supervision. Jiahe Huang: Investigation,
Methodology. Yu He: Supervision, Validation. Wen Chen: Conceptualization,
Formal analysis, Writing – review & editing, Supervision.

Peng et al. BMC Chemistry(2024) 18:117

Page 11 of 12

Funding
This research was funded by the Science and Technology Project ofPetroChina Southwest Oil and Gasfield Company (No. 20230305-13).

13.

Data availability
All data generated or analyzed during this study are included in this publishedarticle.

14.

Declarations

15.

Ethics approval
Not applicable.
Consent to participate
Not applicable.
Consent for publication
Not applicable.

16.

17.

Competing interests
The authors declare no competing interests.
Received: 26 January 2024 / Accepted: 13 June 2024

18.

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