1. Introduction
Carbon dioxide (CO
2) corrosion, which will cause damage to the downhole pipelines, is one of the main restricting factors that disturb the normal production of the oil and gas fields [
1]. In recent years, the increased occurrence of CO
2 corrosion issues can be attributed not only to the CO
2 generated during the deposition and formation of hydrocarbon source rocks but also to its presence in gas storage and development applications, such as CO
2 burial and CO
2 injection for enhanced recovery [
2,
3]. High CO
2 concentrations in reservoir hydrocarbons have become an undeniable reality, which is highly corrosive to metal components. This can lead to the deterioration of pipelines, wellhead equipment, and downhole tubulars [
4,
5].
In hydrocarbon production processes, a mechanical screen is a widely employed technique for preventing the influx of formation sand into the wellbore. This method utilizes screen tubing as a physical barrier that effectively filters out sand particles, akin to the function of the kidneys in the human body. The mechanical screen, typically made of perforated metal or woven wire mesh, is strategically placed within the wellbore to intercept the sand-laden production fluids. As the fluids flow through the screen, the sand particles are captured and retained on the exterior surface of the screen while the fluids, typically oil or gas, are allowed to pass through. This separation process prevents the sand from entering the wellbore and potentially causing a multitude of problems, including equipment damage, reduced production efficiency, and safety hazards [
6,
7,
8]. However, as the vital component of the wellbore, mechanical screen pipes commonly experience CO
2 corrosion failure, which significantly impacts their lifespan [
9,
10]. In the subterranean realm, the confluence of elevated temperatures and immense pressures conspire to exacerbate the corrosive assault on the screen pipe, relentlessly compromising its integrity and structural stability [
11]. Consequently, it is of paramount importance to conduct a comprehensive investigation of the various components of screen pipe.
In the 1940s, the petroleum industry began to focus on the corrosion of oil and gas well pipelines and implemented the use of coatings as an anti-corrosion measure [
12]. Numerous studies have also been carried out on CO
2 corrosion behavior [
13,
14]. Currently, domestic and international researchers are conducting indoor experiments to simulate the corrosion caused by primary factors such as carbon dioxide, materials, flow rate, and water/gas content. These studies aim to investigate the impact of these factors on the corrosion of petroleum pipelines and identify trends in corrosion behavior [
15,
16,
17,
18,
19]. It is now well established that the CO
2 corrosion behavior of steels is dominated by the precise environmental conditions such as temperature, CO
2 partial pressure, flow structure, and corrosion film, etc. [
20,
21,
22,
23,
24].
For CO
2 partial pressure, studies have consistently shown that the trend of CO
2 corrosion rate under unscaled conditions is an increasing CO
2 partial pressure [
25,
26,
27]. This is attributed to the fact that as the partial pressure of CO
2 increases, the concentration of H
2CO
3 in the aqueous phase increases, leading to a decrease in solution pH. This acidic environment accelerates the cathodic reaction, and, consequently, the overall corrosion process. However, this trend is not universally observed, and increasing the CO
2 partial pressure does not necessarily lead to accelerated corrosion [
28,
29]. At high partial pressures of carbon dioxide, the concentration of bicarbonate and carbonate ions in solution tends to increase, leading to supersaturation of FeCO
3. This promotes the formation of protective scales, which can hinder corrosion [
30]. Therefore, the effect of CO
2 partial pressure on corrosion is complex and depends on various factors.
Temperature is also a key factor influencing CO
2 corrosion. It directly affects the electrochemical reactions occurring on the steel surface. In general, between 25 and 40 °C, the corrosion rate increases with increasing temperature [
31]. At low temperatures (below 40 °C), the corrosion products (mainly of Fe
3C and some FeCO
3) formed on the steel surface are typically very loose and porous, providing little protection against further corrosion [
32,
33]. However, at elevated temperatures (above 60 °C), the behavior of CO
2 corrosion changes. This is due to the lower solubility of FeCO
3 at high temperatures, changing the type and protectiveness of the corrosion products formed on the steel surface [
34,
35,
36,
37]. Evidence from several experimental studies has established that the temperature range between 40 and 60 °C is a critical region where the corrosion rate transitions from being relatively high to being relatively low [
38,
39,
40,
41]. In addition, temperature has a strong influence on corrosion scale formation and determines corrosion scale properties such as density, porosity, and permeability [
42].
In the oil and gas industry, the Norsok model is widely used to calculate the surface corrosion rate of carbon steel [
43]. However, this model may not be directly applicable to screen, which has a more complex structure and material composition compared to conventional casing and tubing. Mechanical screens typically consist of a base pipe, sand retaining media, and an outer protective shroud. The base pipe is usually made of carbon steel, while the sand barrier media and outer protective shroud can be made of different materials, such as 13Cr, 316L, N80, and other materials of stainless steel. It is not clear how to accurately predict its corrosion rate. Additionally, the downhole environment where the screen is installed can vary significantly, making it difficult to assess its corrosion rate and evaluate its life downhole. Despite extensive research on the mechanism of CO
2 corrosion, limited attention has been paid to the corrosion behavior of downhole mechanical screen in harsh environments characterized by a high temperature, high pressure, and high production conditions.
In this work, the target object is D-X gas field, which is a typical representative of high temperature and high-pressure gas field in the South China Sea, with a well depth of 5000 m, and is a medium and low permeability reservoir. The pressure coefficient of the field is 1.82 and the temperature is 152 °C. The highest field temperature can reach 188 °C and the highest pressure coefficient can reach 2.08, which is a typical HTHP gas reservoir. At present, the development of horizontal wells and large displacement wells is being implemented, and the production rate of a single well is higher than 1.2 million m
3/d, which is a kind of high-yield gas well [
44]. This environment poses unique challenges for material durability and corrosion resistance, necessitating a detailed and methodical evaluation. To address this challenge, a new type of dynamic corrosion experimental apparatus for the screen was developed, and carbon dioxide corrosion experiments specifically for the mechanical screen were carried out. Combined with the results of the corrosion experiments, a life prediction model of screen is proposed, and a case study is carried out. This model, considering the unique structural and material properties of screen tubing, as well as the specific downhole conditions where it is installed, is an effective method for evaluating integrity of the screen.
5. Wellbore Screen Optimization Applications
5.1. Typical Gas Reservoir Conditions and Screen Data Used
Typical conditions in the South China Sea gas field were used for application, and the fluid physical conditions are shown in
Table 5. Four gas samples were obtained from the gas wells, and their CO
2 contents were 3.41%, 3.44%, 3.61%, and 3.85%, respectively, with reservoir pressure of about 53 MPa and CO
2 partial pressures of about 1.80–2.05 MPa.
According to the base data of Well X, the production section of the typical well is about 498.4 m long, with a daily production of 106.71 × 104 m3/d and a temperature of 142 °C. A multi-layer metal mesh screen was used in the well, and its base pipe, outer protective shroud, and sand retaining media are made of N80, 304, and 316L steel. The thickness of the base pipe is 9.17 mm, the thickness of the protective shroud is 1.25 mm, and the diameter of the screen wire is 0.3 mm, which corresponds to the critical damage ratios taken as 25%, 45%, and 75%, respectively.
5.2. Evaluation Results of Corrosion Resistance for Screens in HTHP Environments
The corrosion rate prediction was performed using the newly fitted model, and the prediction results are shown in
Figure 17.
According to the corrosion rate with CO2 partial pressure change curve, the corrosion rate of different materials is positively correlated with the CO2 partial pressure. When the CO2 partial pressure rises from 1.0 MPa to 15 MPa, the corrosion rate of N80 material base pipe rises from 0.069 mm/y to 0.37 mm/y, the corrosion rate of 304 material outer protective cover rises from 0.019 mm/y to 0.102 mm/y, and the corrosion rate of 316L steel sand blocking medium rises from 0.016 mm/y to 0.086 mm/y. Under the typical conditions, the CO2 partial pressure is 2.0 MPa. Under the typical conditions of CO2 partial pressure of 2.5 MPa, the corrosion rate of N80 base pipe, 304 outer protective cover, and 316L sand barrier medium is 0.122, 0.034, and 0.028 mm/y respectively.
As for temperature, when the temperature is low, the corrosion rate of different materials will be positively correlated with the ambient temperature, and reach the maximum value at the ambient temperature of about 140 °C. In the typical conditions of 142 °C, N80 material, P110 material, 304 material, 316L material, Ni material, have a corrosion rate of 0.125, 0.110, 0.035, 0.030, 0.022 mm/y. When the ambient temperature rises to 140 °C or more, the corrosion rate of the different materials will coincide with the temperature increases and decrease.
The corrosion life evaluation indexes of each part of a typical screen under different CO
2 partial pressure conditions were calculated. The lowest corrosion life of each component is selected as the overall corrosion life (Ts) of the screen. The relationship between the corrosion damage rate of each component under different CO
2 partial pressures and temperatures is shown in
Figure 18.
As CO
2 partial pressure increased from 1.0 MPa to 15 MPa, the corrosion rate of the base pipe, indicated by the evaluation index Vrc, increased from 0.046 to 0.237, which is an 80.6% increase. Similarly, the corrosion rate of the outer protective shroud increased from 0.062 to 0.337, representing an 81.6% increase. The corrosion rate of the sand retaining medium also increased from 0.134 to 0.72, which is an 81.4% increase. These results demonstrate the impact of higher CO
2 partial pressure on the corrosion of the different components of the screen. The corrosion life of the screen components showed a negative correlation with the partial pressure of CO
2. When the reservoir temperature is 142 °C and the partial pressure of carbon dioxide exceeds 2.12 MPa, the predicted life of the screen tube is less than 5 years. According to these corrosion life predictions, the screen is rated as having a moderate to poor result in terms of its corrosion resistance. It can also be seen from the predicted results in
Figure 18b that the evaluation of the screen corrosion life in different temperature ranges is of moderate level when the partial pressure of the CO
2 is 2 MPa.
According to the results of corrosion studies, 316L screen media, although the slowest corrosion rate in materials, its wire diameter is thin, and it has the shortest corrosion life. Therefore, the following optimization recommendations are provided: (1) Under the premise of maintaining the mesh size and sand-blocking precision, increase the wire diameter by 1.5 times (0.4–0.5 mm), to improve the corrosion resistance of the medium and extend the life. (2) Optimize the structure of corrosion products that does not affect the circulation, reducing the impact of corrosion on functionality.
Using materials with higher corrosion resistance, applying chemical inhibitors to form protective layers, and using protective coatings to act as barriers against corrosive agents can reduce corrosion. Additionally, controlling the environment by reducing CO2 partial pressure and adjusting temperature and pressure to fewer corrosive levels can also mitigate corrosion.