Research on the Damage Mechanism of Oilfield Water Injection System Based on Multiple Operating Conditions

Abstract

Petroleum is an indispensable energy source in modern industrial society, and maintaining the safe and stable operation of its injection and production system is of great significance. To analyze the mechanism of pipeline damage caused by corrosion and scaling in the injection production system, taking a water injection pipeline in an oil field as an example, the causes of corrosion and scaling damage were studied by detecting pipeline samples and analyzing corrosion products and various service conditions of the pipeline. The results showed that there was more scaling on the inner wall of the pipeline, and there was local corrosion in the pipeline sections that had experienced water injection, shutdown, and gas injection conditions, while there was no significant corrosion thinning in the pipeline sections that had only experienced water injection and shutdown conditions. The scale layer formed under water injection conditions is mainly composed of barium strontium sulfate (Ba_0.75Sr_0.25SO₄), barium sulfate (BaSO₄) and a small amount of silica (SiO₂). The main reason for scale formation is the high content of barium ions (Ba²⁺) in the injected water. The corrosion products formed under gas injection conditions, including strontium ions (Sr²⁺) and sulfate ions (SO₄²⁻), are mainly composed of ferrous carbonate (FeCO₃) and ferric oxide (Fe₂O₃). The pipeline corrosion product FeCO₃ is mainly caused by carbon dioxide (CO₂) in the medium. In addition, the high liquid content, cecal position, high Cl⁻ (chloride ion) content, and slightly acidic environment in the pipeline also accelerate the occurrence of corrosion damage. The Fe₂O₃ in the corrosion products is formed when the pipeline is exposed to air after sampling, and is not the main cause of pipeline corrosion.

1. Introduction

At present and for at least the next 10 to 15 years, oil will continue to maintain its dominant position in the global energy system, and ensuring stable oil production is of profound significance for energy security [1,2]. Water injection is one of the most economical and effective measures for maintaining stable production in oil fields, and pipelines, as a common water transportation method, play a crucial role in the water injection process [3]. Although water injection technology can significantly improve the recovery rate of oil wells, it also brings some challenges and problems, one of which is the corrosion and scaling issues caused by the complex fluid composition within pipelines [4,5,6]. Corrosion and leakage of water injection pipelines will cause huge economic losses to oil fields and have serious impacts on their operations [4,5,7].

In order to effectively prevent similar accidents, reduce economic losses, and improve oilfield development efficiency, scholars in China and abroad have conducted in-depth analysis of the factors affecting the corrosion of oilfield water injection pipelines and proposed a series of effective corrosion protection measures. Lou Liangjie comprehensively investigated the water quality of sewage, corrosion monitoring data, and the composition of corrosion products. Combined with the use of corrosion inhibitors on site, they studied the causes of corrosion and proposed corresponding solutions [8]; Marí n-Cruz J conducted in-depth research on the corrosion and scale inhibition processes in cooling system media [9]; Defang Z conducted a study on a new type of composite environmentally friendly corrosion and scale inhibitor for steel surfaces in cooling water, and developed an efficient and environmentally friendly scale inhibitor that can effectively reduce corrosion and scale inhibition on steel surfaces [10]. Ying Xu synthesized polyaspartic acid/5-aminolactic acid graft copolymers and evaluated their scale and corrosion inhibition properties [11].

Previous studies have gained a certain understanding of the corrosion and scaling characteristics, influencing factors and anti-corrosion measures of water injection pipelines. However, the research mainly focuses on indoor simulation experiments, with relatively simple experimental conditions and a lack of analysis based on corrosion and scaling data under real on-site service conditions. This article analyzes the corrosion and scaling morphology, service conditions, physical and chemical properties of a water injection pipeline in a particular oilfield based on the actual situation of variable working conditions during pipeline on-site service. The reasons for the corrosion of the water injection pipeline in the well are discussed, aiming to effectively prevent similar accidents from happening again.

The water injection pipeline of a particular oilfield was completed and put into use in November 2001. The pipeline specification is Φ140 mm × 22 mm, made of 20# steel, with a design pressure of 40 MPa and a total length of 1.81 km. The conveying medium is sewage, and there are no internal anti-corrosion measures. The failed sample is shown in Figure 1. The sample sent for inspection this time consists of two parts. One part is the pipe section cut in January 2022 (Figure 1a), marked as Sample 1, which has undergone water injection, shutdown, and gas injection conditions, with a length of 255 mm. The other part is the pipe section cut after the pressure test in September 2020 (Figure 1b), marked as Sample 2, divided into three sections with lengths of 145 mm, 87 mm, and 127 mm, which have undergone water injection and shutdown conditions. There are damage marks on the outer surface of Sample 1, and liquid accumulation marks can be seen at the 6 o’clock position on the inner wall, with multiple corrosion pits present (Figure 1c). Sample 2 has a rust yellow outer surface and a yellow brown scale layer visible on the inner wall (Figure 1d).

2. Physical and Chemical Performance Testing

2.1. Geometric Dimension Measurement

The outer diameter and wall thickness of the corroded pipe sample were measured using a vernier caliper (0.02 mm) and an ultrasonic thickness gauge (0.01 mm), respectively. The schematic diagram of the measurement location is shown in Figure 2. The procedure was conducted as follows: select one section every 5 cm at equal intervals along the axial direction on the pipe sample, and measure its outer diameter separately (with three measurement positions spaced 120° apart). The results are shown in

Table 1. Measurement results of the outer diameter of the tube sample (unit: mm).

	A	B	C	D	E	F	G	H	I	J	K
Outer diameter 1	139.98	139.9	139.9	140	139.96	139.94	139.88	140.02	139.9	139.96	139.94
Outer diameter 2	140.04	139.94	139.96	139.96	139.92	139.86	139.96	139.88	139.94	139.92	139.92
Outer diameter 3	140.12	139.82	139.82	139.88	139.8	139.92	140	139.8	139.88	139.88	139.84
Average value	140.05	139.89	139.89	139.95	139.89	139.91	139.95	139.9	139.91	139.92	139.9
GB 6479-2013	139.50~140.50

. In addition, the wall thickness was measured at four equidistant points on the circumference of each section, and the results are shown in

Table 2. Measurement results of the wall thickness of the tube sample (unit: mm).

	A	B	C	D	E	F	G	H	I	J	K
3 o’clock	22.18	21.96	21.98	21.84	21.84	21.98	21.94	21.96	22.36	21.86	21.84
6 o’clock	22.06	19.24	19.46	21.96	22.02	22.12	22.02	21.84	21.88	22.02	21.98
9 o’clock	21.86	21.98	22.08	22.02	21.74	21.88	21.66	21.86	21.84	22.2	21.8
12 o’clock	21.96	21.86	21.88	21.74	21.8	21.76	21.8	22.16	21.88	21.86	21.84
Average value	22.02	21.26	21.95	21.89	21.85	21.94	21.86	21.96	21.99	21.99	21.87
GB 6479-2013	19.98~24.75

. From Table 1 and Table 2, it can be seen that the outer diameter of the tube sample meets the requirements of GB 6479-2013 “Seamless Steel Tubes for High Pressure Boilers” for hot-rolled steel tubes [12]. Except for the corrosion pit, no significant corrosion thinning was observed in other parts.

2.2. Chemical Composition

Chemical composition analysis samples were taken from Sample 1 and Sample 2. According to the GB/T 4336-2016 standard [13], an ARL4460 direct reading spectrometer was used for testing, and the results are shown in

Table 3. Analysis results of chemical composition (Wt. × 10⁻²).

	C	Si	Mn	P	S	Cr	Mo	Ni	Nb	V	Ti	Cu	B	Al
Sample 1	0.18	0.25	0.52	0.015	0.012	<0.005	0.0042	0.018	<0.0008	<0.0007	0.0024	0.096	0.0005	<0.001
Sample 2	0.19	0.27	0.46	0.0091	0.0088	<0.005	0.0013	0.013	<0.0008	0.0007	0.0016	0.067	0.0002	<0.001
GB 6479-2013	0.17~0.23	0.17~0.37	0.35~0.65	≤0.025	≤0.015	/	/	/	/	/	/	/	/	/

. According to Table 3, the chemical composition meets the requirements of GB 6479-2013 for 20# steel.

2.3. Mechanical Performance Test

For longitudinal tensile specimens from Sample 1 and Sample 2, room temperature tensile tests were conducted according to the GB/T 228.1-2010 standard [14]. The test results are shown in

Table 4. Room temperature tensile test results.

	Tensile Strength/MPa	Yield Strength/MPa	Elongation After Fracture/%
Sample 1	505	408	27
Sample 2	485	357	36
GB 6479-2013	410~550	≥235	≥24

. According to Table 4, the tensile performance of the pipeline meets the requirements of GB 6479-2013 for 20# steel. Longitudinal impact specimens (10 × 10 × 55 mm) were taken from Sample 1 and Sample 2. According to the GB/T 229-2020 standard [15], the specimens were subjected to Charpy impact testing using the PIT752D-2 (300J) impact testing machine (Tubular Goods Research Institute, China National Petroleum Corporation, Xi’an, China). The test results are shown in

Table 5. Impact test results.

	Impact Energy (J)
Sample 1	9.8, 13.0, 18.0
Sample 2	15.0, 37.0, 26.0
GB 6479-2013	≥40

. According to Table 5, the impact performance of the pipeline is lower than the requirements of GB/T 229-2020 standard for 20# steel.

2.4. Metallographic Analysis

Metallographic analysis samples were taken from Sample 1 and Sample 2. According to the GB/T 13298-2015 “Method for Inspection of Metallic Microstructure” [16], GB/T 6394-2017 “Method for Determination of Average Grain Size of Metals” [17], and GB/T 10561-2023 “Method for Determination of Non-metallic Inclusion Content in Steel” [18], an OLS4100 laser confocal microscope (Tubular Goods Research Institute, China National Petroleum Corporation, Xi’an, China) was used to detect and analyze the microstructure, grain size, and non-metallic inclusions of the samples. The results are shown in

Table 6. Metallographic examination results.

	Non-Metallic Inclusions	Microstructure	Grain Size
Sample 1	A0.5, B0.5, D0.5	F + P (Figure 3)	7.5
Sample 2	A0.5, B0.5, D0.5	F + P (Figure 3)	7.0

, and the metallographic photos are shown in Figure 3. The metallographic analysis results show that the microstructure of the pipeline is F + P (ferrite + pearlite), and the non-metallic inclusions are A0.5, B0.5, D0.5, Sample 1 has a grain size of 7.5, while Sample 2 has a grain size of 7.0.

3. Micro Analysis

3.1. Scanning Electron Microscopy and Energy Dispersive Spectroscopy Analysis

The corrosion pit was taken from Sample 1 to test the sample, and a scanning electron microscope (SEM) and its built-in energy dispersive spectrometer (EDS) were used to analyze the corrosion morphology and corrosion product composition. Figure 4 shows SEM images of corrosion pits at different locations. At low magnification, the macroscopic morphology of the corrosion pit is shown in Figure 4a. At high magnification, it was observed that there were many corrosion product crystals visible at the bottom of the corrosion pit (region A), on the walls of the corrosion pit (region B), and outside the corrosion pit (region C). Further analysis of their composition using EDS (see

Table 7. Results of EDS mapping analysis (wt.%).

	C	O	Si	Fe	S	Ba	Cl	K
Area A	19.51	27.85	3.5	24.98	5.48	4.74	/	/
Area B	25.46	25.66	3.61	16.24	6.95	7.54	0.85	/
Area C	28.84	25.25	6.45	7.62	6.86	2.77	/	2.1

) shows that the product mainly contains Fe, O, C, S, Si, Ba elements, with small amounts of Cl, K and other elements present locally.

3.2. XRD Phase Analysis

The inner wall scale samples were scraped from the top and bottom of Sample 1 and Sample 2 pipelines, and their phase composition analyzed using X-ray diffraction (XRD). The detection results are shown in Figure 5. From Figure 5, it can be seen that the phase composition of the scale sample at the bottom of Sample 1 is mainly Ba_0.75Sr_0.25SO₄, BaSO₄, Fe₂O_3, FeCO₃ and SiO₂, the phase composition of the top scale sample in Sample 1 is mainly Ba_0.75Sr_0.25SO₄, BaSO₄ and Fe₂O₃; the phase composition of the bottom scale sample in Sample 2 is mainly Ba_0.75Sr_0.25SO₄, BaSO₄, Fe₂O₃ and SiO_2; the phase composition of the top scale sample in Sample 2 is mainly Ba_0.75Sr_0.25SO₄, BaSO₄ and SiO₂. Among these, Ba_0.75Sr_0.25SO₄ is a sulfate solid solution (solid solution phase) of barium (Ba) and strontium (Sr), with a crystal structure similar to that of BaSO₄ and SrSO₄. Because BaSO₄ and SrSO₄ have similar structures, they can form continuous solid solutions, such as Ba_1−x Sr_x SO₄, where x is the proportion of strontium, which is a common scaling product in oil and gas field water.

From the phase composition of the scale samples on the inner wall of the failed pipes, it can be seen that the chemical components of the scale samples on the inner wall of the pipes in Samples 1 and 2 are mainly corrosion products of sulfates, silica, and iron. Among these, sulfates are mainly barium sulfate and strontium scale, silicon dioxide is mainly deposited and attached to pipelines, and only Sample 1, which has undergone gas injection conditions, contains FeCO₃ in the corrosion products of the pipeline bottom. Fe₂O₃ is the result of oxidation of the corrosion products on the inner wall of the pipeline after exposure to air.

4. Discussion

From the macroscopic analysis and geometric dimension measurement of the pipe sample, it can be seen that there is a lot of scaling on the inner wall of the pipeline. The pipe section that has experienced water injection, shutdown, and gas injection conditions has local corrosion in the 6 o’clock direction, while the pipe section that has only experienced water injection and shutdown conditions has not shown significant corrosion thinning. Based on these characteristics and the service history of the pipeline, the reasons for local corrosion from the aspects of pipeline material and service conditions are analyzed below.

Firstly, from the perspective of pipeline material, its chemical composition meets the requirements of GB 6479-2013 for 20# steel; The metallographic structure consists of pearlite and ferrite, with non-metallic inclusions of A0.5, B0.5, and D0.5. Sample 1 has a grain size of 7.5, sample 2 has a grain size of 7.0, and no abnormalities are found in the metallographic structure. The tensile performance meets the requirements of GB 6479-2013 for 20# steel, but the impact performance does not meet the requirements of GB 6479-2013. The impact performance has a significant impact on the anti-cracking performance of pipelines, but has no direct effect on pipeline corrosion and scaling. It can be seen that a material problem in the pipeline is not the cause of local corrosion.

Secondly, from the perspective of pipeline service conditions, the pipeline was a water injection pipeline from November 2000 to April 2018, and the transport medium was treated wastewater from the joint station. There is a scaling phenomenon on the inner wall of the pipeline section that has only experienced water injection, shutdown, and gas injection conditions. According to the XRD analysis results of the scale samples, the chemical composition of the scale samples is the same, mainly barium sulfate, strontium scale, and a small amount of silicon dioxide. Combined with the analysis results of the injected water sample (

Table 8. Injection water assay results.

Component	HCO3−	Cl−	SO42−	Ca2+	Mg2+	Ba2+	Sr2+	Na+ + K+	Total Mineralization Degree	pH	Water Type
Content (mg/L)	193	100,000	235.7	600.2	916.9	18.66	496.2	56,130	164,000	5.82	CaCl2

), the SO₄²⁻ content in the medium is 235.7 mg/L, the Ba²⁺ content is 18.66 mg/L, and the Sr²⁺ content is 496.2 mg/L, indicating that the scale layer on the inner wall of the pipeline was formed during the water injection condition. From the morphology of the inner wall of the pipeline section that only experienced water injection and shutdown conditions, no obvious corrosion was observed. XRD analysis of the scale layer on the inner wall showed that the corrosion product was mainly Fe₂O₃. However, there were corrosion pits in the 6 o’clock direction of the pipeline section that experienced water injection, shutdown, and gas injection conditions. The main corrosion products on the inner wall were FeCO₃ and Fe₂O₃. According to the analysis of the injected gas composition (

Table 9. Natural gas fractions from source wells.

Component	CH4	C2H6	C3H8	C4H10	C5 + C6	N2	O2	CO2	H2S
Molar content (%)	85.69	5.507	1.838	0.490	0.0792	4.823	0.1889	1.332	0.0003

), the gas contained corrosive media such as CO₂ and trace amounts of hydrogen sulfide (H₂S), with CO₂ content of 1.332% and H₂S content of 0.0003%. The operating pressure of the pipeline was about 10 MPa. The calculated CO₂ partial pressure of the pipeline was about 0.1332 MPa and H₂S partial pressure was about 0.03 KPa. The corrosion caused by the low H₂S partial pressure can be ignored. Therefore, the pipeline section that experienced gas injection conditions was corroded mainly by CO₂. The partial pressure of carbon dioxide has a direct impact on the corrosion rate of pipelines. An increase in CO₂ partial pressure will lead to more CO₂ dissolution, lower pH, and decrease the concentration of CO₃²⁻, thereby reducing the stability of FeCO₃. Especially under high flow rate conditions of multiphase flow, the scouring effect will further damage the protective film, leading to intensified corrosion. It is generally believed that moderate corrosion will occur in pipelines when the CO₂ partial pressure is between 0.021 MPa and 0.21 MPa [19,20]. In addition, a GLCC gas–liquid separator is installed at the injection gas source well site to perform simple separation of the produced raw gas. Due to the small size of the GLCC gas–liquid separation device and the large amount of plug flow in the gas source section, the gas–liquid separation effect is poor, which can lead to increased entrainment of liquid droplets in natural gas, exacerbating gas–liquid phase slip (increasing velocity difference) and result in a sustained high liquid content in the injection pipeline. High liquid holdup significantly increases the nucleation rate of FeCO₃ by elevating the interfacial concentrations of Fe²⁺ and CO₃²⁻ while reducing mass transfer efficiency. Additionally, the pipeline operates at a pressure of 10 MPa, where the high pressure markedly enhances the solubility of CO₂ in the liquid phase. This promotes the hydration of CO₂ to form H₂CO₃, which subsequently dissociates into HCO₃⁻ and CO₃²⁻. The resulting increase in CO₃²⁻ concentration directly raises the supersaturation (S) of FeCO₃—a critical driving factor for nucleation kinetics.

However, dense FeCO₃ corrosion product films typically form at temperatures above 60 °C. At the pipeline operating temperature of ~40 °C, the FeCO₃ film tends to be porous and poorly adherent. When combined with Cl⁻-induced localized attack and flow fluctuations, the high nucleation rate may translate into localized corrosion risks rather than providing protective effects. This underscores the importance of mitigating factors such as chloride ingress, optimizing flow conditions, and considering material upgrades or corrosion inhibitors to address the compromised film integrity at lower temperatures.

In addition, the pipeline with local corrosion in this section is located in the cecum section. At the cecum section of the pipeline system, fluid stagnation may lead to a local increase in the concentration of Cl⁻ or other corrosive substances. Due to limited mass transfer, concentration batteries may form, exacerbating local corrosion. Meanwhile, the retention zone may experience pH changes due to poor material exchange, such as the accumulation of acidic substances, which further affects the corrosion process [21]. The morphology of the inner wall of the pipeline also shows traces of liquid accumulation at the bottom of the pipeline. According to the test results of the produced water from the gas source well (

Table 10. Assay results of extracted water from gas wells.

C3H8	HCO3−	Cl−	SO42−	Ca2+	Mg2+	Ba2+	Sr2+	Na+	K+	Total Mineralization Degree	pH	Water Type
Content (mg/L)	80.8	94,800	27.08	628	372.5	46.34	236.2	55,000	1311	158,200	6.12	CaCl2

), the Cl⁻ content of the produced water is 94,800 mg/L, with a pH value of 6.12. Higher Cl⁻ content and an acidic environment will accelerate the occurrence of corrosion [22,23,24]. This is because the presence of Cl⁻ usually accelerates the corrosion of carbon steel, especially at low pH levels. In a weakly acidic environment with a pH of 6.12, the corrosiveness of Cl⁻ further damages the passivation film, causing the corrosion potential to shift towards a more negative direction and accelerating the anodic reaction. In this case, as the corrosion rate increases, the driving force for electrochemical corrosion also increases. The pipeline was injected with gas from September 2020 until local corrosion was discovered in January 2022, a total of 16 months of gas injection operation. The maximum depth of the pipeline corrosion pit is about 3 mm, and the maximum corrosion rate is about 2.25 mm/a, which indicates an extremely severe degree of corrosion.

In summary, the Sample 1 pipeline sent for inspection is located in the cecum section. Under gas injection conditions, due to poor gas–liquid separation, the pipeline contains a high amount of liquid. There is liquid accumulation at the 6 o’clock position of the pipeline, which causes local corrosion under the action of CO₂ in the medium. The high Cl^- content and acidic environment in the medium accelerate the occurrence of corrosion. In addition, microbiologically influenced corrosion (MIC) may also be a potential factor that accelerates corrosion, especially in the relatively static environment of the cecal section of the pipeline, which is more conducive to the growth and metabolism of microorganisms. Fe₂O₃ is the result of oxidation of corrosion products on the inner wall of pipelines exposed to air, and is not the main cause of pipeline corrosion. In addition, the pipeline did not adopt anti-corrosion measures such as adding corrosion and scale inhibitors or using anti-corrosion and anti-scaling coatings on the inner wall, resulting in rapid corrosion and scaling of the pipeline [25,26,27,28].

5. Conclusions

(1)

According to the physical and chemical performance test results of the submitted samples, the chemical composition of the pipeline meets the requirements of GB 6479-2013 for 20# steel, with a metallographic structure of ferrite + pearlite and non-metallic inclusions of A0.5, B0.5, D0.5. Sample 1 has a grain size of 7.5, sample 2 has a grain size of 7.0, and no abnormalities are found in the metallographic structure. The tensile performance meets the requirements of GB 6479-2013 for 20# steel, but the impact performance does not meet the requirements of GB 6479-2013.

(2)

Sample 2 has only experienced water injection and shutdown conditions, and there is no obvious corrosion on the inner wall of the pipeline. The scale layer on the inner wall was formed during the water injection period, and the high content of sulfate ions, barium, and strontium ions in the water injection medium is the reason for its scaling.

(3)

Sample 1 has undergone local corrosion under the action of CO₂ in the medium under gas injection conditions. Fe₂O₃ is the result of oxidation of corrosion products on the inner wall of the pipeline after exposure to air, and is not the main cause of pipeline corrosion.

(4)

It is recommended to carry out process modifications such as pipe cutting and excision on the cecal section of the pipeline under gas injection conditions to reduce the risk of pipeline corrosion and perforation.