Li Dapeng, Chang Wei, Zhu Hai Shan, Li Hui Xin, and Tian Yongqin
China National Offshore Oil Corporation Research Institute Co., Ltd.
Summary:A deepwater gas field in the South China Sea features long pipeline distances, high CO2 partial pressure, and high water content. The pipeline's high corrosion risk and single-pipe design pose stringent requirements and challenges for subsequent operations such as cleaning, corrosion inhibitor management, and maintenance. based on corrosion risk analysis and corrosion calculations, a corrosion control plan for the pipeline has been proposed. This plan involves using a carbon steel inner lining made of 625 alloy composite pipe for the first 1.5 km section, and using "carbon steel + 6 mm inner corrosion allowance plus corrosion inhibitor" for the 1.5~113 km section. During operation, regular assessments of the effectiveness of corrosion inhibitors should be conducted, and cleaning operations should be performed based on corrosion monitoring results to ensure that the corrosion inhibitor's corrosion inhibition efficiency exceeds 85%. Attention should also be paid to localized corrosion risks caused by the presence of H2S, sediment, and microorganisms. based on the operating status, corrosion monitoring results, post-inhibitor evaluations, and cleaning waste analysis, dynamic corrosion assessments should be conducted promptly, and subsequent detection and corrosion control measures should be developed based on the assessment results.
Keywords:Deepwater field; long-distance subsea pipelines; internal corrosion prevention; material selection; corrosion inhibitors
Driven by the optimization and adjustment of the energy structure and the dual carbon policy, the demand for natural gas in China has increased significantly, leading to accelerated development of deep, high-pressure gas fields. The South China Sea possesses abundant natural gas resources, accounting for 83% of the total oil and gas resources in the South China Sea. However, 70% of these resources are located in deepwater areas, making the development of deepwater gas fields a current trend in oil and gas exploration and development.
Deepwater field development faces numerous challenges, including deepwater environments, harsh sea conditions, complex routes, and the lack of supporting infrastructure. Subsea pipelines are critical production facilities that connect offshore oil and gas fields to downstream processing facilities. The cost of their installation and maintenance is very high. Therefore, it is necessary to consider all aspects of design, installation, commissioning, and post-operation maintenance, ensuring the reliability of subsea pipelines during production operations while minimizing investment costs based on technical safety.
A deepwater gas field in the South China Sea plans to use an underwater production system. The water depth is 850~1000m, and the produced gas will be transported via a newly constructed and mixed underwater pipeline with a length of 113km (diameter 508mm) to a new production support platform. To save on investment costs, the mixed underwater pipeline is designed as a single pipe and does not include a cleaning circuit. The design lifespan is 20 years. The natural gas from this field contains CO2Quality rating is 1.14%~4.45%, H2- Quality index is 6mg/kg (refer to on-site analysis results). Initially, the produced water is free water, while in the later stages, it becomes groundwater. The groundwater contains 7592~16085mg/L Cl.-putty powder-ready-mixed putty paste-peeling-detachment-substrate-interface treatment agentand 1596~2370mg/L HCO3-.
For this buried pipeline, a material selection scheme and comprehensive integrity management measures have been proposed based on corrosion risk analysis and internal corrosion calculations. These measures are intended to ensure that the new buried pipeline meets the requirements for safe production.
1 Corrosion Risk Analysis
1. 1 CO2/H2Corrosion
New mixed seabed pipeline for transporting goods containing CO2and H2S, CO2and H2S undergoes dissociation in water, producing H+It acts as a strong polarizing agent, attracting electrons and promoting the anodic dissolution reaction of metal pipes, thereby causing corrosion.
Carbon steel pipes are primarily affected by their corrosion rate and corrosion morphology, which are influenced by the corrosion products formed on their surface. In the presence of CO2In corrosive environments, the corrosion products formed on the carbon steel surface are primarily FeCO.3. Carbon steel initially undergoes anodic dissolution, forming Fe.2+When Fe2+with CO32-When the FeCO content exceeds the saturation limit,3Forms and deposits on the surface of the material. Therefore, Fe2+and CO32-/HCO3- Putty powder- Ready-mixed putty paste- Peeling- Detachment- Substrate- Interface treatment agentHigh supersaturation is crucial for the formation of protective corrosion product films. Uneven or localized degradation of the corrosion product film is the primary cause of localized corrosion in carbon steel pipes.
The presence of H2S complicates the corrosion process. On one hand, H2S is highly soluble in water, and its dissolution releases a large amount of H+ ions, which lowers the pH of the medium inside the pipe, increasing its acidity and promoting the dissolution of the pipe material, thereby increasing the corrosion rate. On the other hand, the corrosion products of H2S are mainly different crystalline forms of iron sulfide. The iron sulfide corrosion products form a protective film on the pipe surface, which can hinder the penetration of CO2Corrosion. Regarding H2There is still some debate regarding the understanding of the corrosive effects.
Pipe materials in CO2and H2The corrosion mechanism under co-existence conditions is not yet fully understood, but research results and field experience data from most domestic and international scholars indicate that H2The impact of S on corrosion is primarily manifested in the protective iron sulfide compounds formed on the pipe surface, which inhibit corrosion.2S will, to some extent, reduce the overall corrosion rate of the pipeline. However, H2S will also significantly increase the likelihood of localized corrosion. In H2When the content of S is low, the corrosion products mainly exist in the form of porous and loosely structured Makino mineral crystals enriched in iron, but these Makino mineral structures are very susceptible to transformation into other iron sulfide compounds, which have poor protective properties for the substrate. Under the action of fluid impact, some corrosion product films crack and/or detach, reducing the ability of the corrosion product film to hinder the diffusion of substances involved in the corrosion process, and increasing the activity points on the substrate surface. In other areas, the corrosion product film covers the metal substrate relatively completely, and the activity points of the metal substrate form electrochemical pairs due to the potential difference in these areas, and the electrochemical effect promotes corrosion to occur preferentially at the active points. Furthermore, the corrosion product film has ionic selectivity.-And Cl-Due to its strong ionic permeability, it can easily penetrate through the corrosion product film and reach the interface between the substrate and the corrosion product film. This interface possesses a double-layer structure.- Putty powder- Ready-mixed putty paste- Peeling- Detachment- Substrate- Interface treatment agentwith Cl- putty powder- ready-mixed putty paste- peeling- detachment- substrate- interface treatment agentEasily adheres to the interface, resulting in higher HS (hydrophilic/hydrophobic) values at the interface.-and Cl-Increased content. HS-and Cl-putty powder-ready-mixed putty paste-peeling-detachment-substrate-interface treatment agentCan accumulate and form a nucleus in certain areas, leading to accelerated anodic dissolution in those areas, as shown in reactions (1) ~ (3). This accelerates the formation of pitting corrosion. Cl-Capable of accumulating within pitting pits, accelerating the corrosion of the metal substrate within the pitting pits, and further developing the pitting pits.
H2Hydrogen atoms generated during the corrosion process can also cause hydrogen-induced cracking (HIC) and sulfide stress corrosion (SSC). Hydrogen atoms formed by the cathodic hydrogen evolution reaction are then affected by HS.-、S2-Ionic toxicity inhibits the formation of hydrogen molecules, making hydrogen atoms more easily penetrate into the metal, leading to hydrogen embrittlement or cracking. In newly manufactured pre-mixed marine pipelines, the H2S pressure should not exceed 0.3 kPa. Refer to ISO 15156-2009: "Materials and workmanship for on-offshore oil and gas production."2"Materials for Zone S Environment", new mixed marine pipelines in acidic environments are in Zone 0, which poses a low risk of mechanical-chemical corrosion to the pipeline materials. Therefore, these materials are not a primary consideration in the design and selection of new marine pipelines.
1.2 Top-side corrosion
The newly constructed prefabricated marine pipeline structure is a non-insulated single-layer pipe. There is a temperature difference between the marine pipeline inlet and the environment. The temperature of the liquid transported inside the marine pipeline is higher than the ambient temperature, while the outside is cold seawater. The water vapor in the transported liquid inside the pipeline cools and condenses on the inner wall, forming discontinuous condensate droplets, CO2and H2"Acids such as sulfuric acid can dissolve in the condensed liquid droplets, creating a low-pH corrosive environment. Due to the inability of the liquid phase corrosion inhibitor to effectively act on the pipe surface, severe corrosion occurs at the pipe top, with reported corrosion rates up to 5 mm/year."
- Condensation rate is a primary factor affecting corrosion at the top of wet natural gas pipelines, and is commonly used to predict the risk of top corrosion and the severity of top corrosion. In the presence of CO2In the case of wet natural gas transportation, when the condensation rate of water vapor is less than 0.15 mL/(m2·s) when the rate of condensation water formation at the top of the pipe is small, the corrosive solution is supersaturated, and a dense, protective FeCO layer forms on the pipe wall.3The resulting film exhibits minimal corrosion on the pipe surface; when the condensation rate exceeds 0.15 mL/(m2·s) When the corrosive solution at the top of the pipe does not reach a saturated state, it cannot form a protective corrosion product film, resulting in corrosion at the top, and the corrosion rate at the top is positively correlated with the condensation rate. Therefore, in engineering design, 0.15mL/(m2·s)のSetting rate is a key indicator of top corrosion.。
In wet natural gas transmission, the temperature difference between the inner and outer walls of the pipeline is relatively constant, and the droplet clusters formed on the top of the pipeline will also reach a steady-state distribution, with the number of droplets of a certain size per unit area essentially remaining constant. The number of cold condensate droplets at a certain radius on the top of the pipeline can be expressed using equation (4).
In the equation: Nr- Number of liquid droplets with a radius of r within a unit area; rmaximumFor the largest droplet size.
CO2Due to the low dew point, condensation generally does not occur, but instead, a non-condensable gas layer forms around the condensate droplets. Heat and mass transfer occur between the non-condensable gas layer and the condensate droplet group, following both heat and mass conservation principles. based on the principle of heat conservation, when the heat transfer reaches a steady state, the heat flux Q1 from the non-condensable gas layer to the droplets is equal to the heat flux Q2 from the droplets to the pipe wall. Q2 can be calculated using equation (5).
In the formula: hg- Thermal conductivity coefficient for non-heat-absorbing layers; Tg- For gas temperature; Ti- For the temperature of droplet clusters; Hv- For latent heat of phase change; q(r) is the heat absorbed by a single condensing droplet.
based on the principle of mass conservation, the mass of liquid droplets formed during condensation is equal to the mass reduction of water vapor in the gaseous phase. The condensation rate of water can be expressed as:
In the equation: ρg- for gas density; βg- For the quality transmission coefficient of water in a non-condensable air layer; xb- For the water vapor quality fraction in the gas phase within the pipe; xiFor the water vapor quality in the interfacial gas phase between adjacent liquid droplets.
By combining and solving the equations (5) and (6), the setting rate can be obtained.
1.3 Corrosion caused by dirt and debris
During the operation of newly constructed precast pipelines, the pipeline surface may be covered with a solid deposit layer. This deposit layer may contain inorganic salts, such as calcium2+、Mg2+、Ba2+、SO42-Calcium and magnesium salt deposits and/or BaSO deposits formed by the saturation of ion deposition on the substrate.4Organic contaminants, such as crude oil waxes and asphaltic residues, as well as inorganic contaminants like scale, corrosion products, and sand particles, can also accumulate on the surface of the pipeline. When these contaminants mix with organic contaminants, they create an ideal environment for microbial growth and proliferation. The presence of sulfates and organic matter in the liquid phase promotes the growth and development of bacteria, leading to the formation of various acids and localized corrosion in the affected areas.
As localized corrosion gradually develops into stable corrosion pits, the biocides and corrosion inhibitors injected into the pipelines are difficult to penetrate the accumulated corrosion products within the pits and reach the bottom of the pits, resulting in a significantly reduced effective concentration of the corrosion inhibitors and biocides at the bottom of the pits. Furthermore, even after cleaning, the deposits and bacteria at the bottom of the pits cannot be effectively removed, which further accelerates the corrosion of the pipelines and may even lead to severe localized corrosion and perforation.
The numerous factors affecting corrosion, the complex and diverse corrosion mechanisms, and the limited effectiveness of on-site corrosion control measures for existing localized corrosion under deposits, highlight the need for effective corrosion prevention strategies. Currently, Haiyuan's primary management and control measures involve implementing appropriate cleaning and maintenance procedures, as well as adding anti-corrosion agents, to prevent the formation of long-term, stable corrosion under deposits.
1.4 Seawater Corrosion
During the laying and installation of newly constructed pre-fabricated marine pipelines, avoiding the installation of expansion bends or saddles may lead to seawater entering the pipeline. Similarly, during the commissioning process, seawater may be introduced into the production flow. The high salt content and the presence of dissolved oxygen and microorganisms in seawater, combined with various corrosive factors, pose a corrosion risk to the pipeline.
Research indicates that the South China Sea contains a large number of sulfate-reducing bacteria (SRB), iron-oxidizing bacteria, and iron-bacteria, and in some seawater samples, thermophilic and archaeal bacteria have also been detected. In service conditions, microorganisms must be active, and a suitable physical environment for microbial attachment, proliferation, and growth is essential for microbial corrosion of pipelines. Existing research has shown that the number of microorganisms increases dramatically when they are in a stagnant or deposited state. These microorganisms can consume oxygen, sulfate, and chlorides, and produce various byproducts, which are concentrated in pitting and cracking areas and/or beneath the sediment, and accelerate corrosion through various mechanisms. For example, SRB can participate in cathodic hydrogen depolarization, producing S2-Further formation of corrosion products FeS & Fe(OH)2Accumulating on the metal pipe walls, it accelerates the cathodic corrosion of the metal and promotes the growth and reproduction of SRB, which further produces more FeS and Fe(OH).2The resulting cycle accelerates the formation of corrosive pitting at the bottom of the rust layer. Microbial corrosion ultimately results in a typical localized corrosion pattern with distinct circular erosion features. Dissolved oxygen introduced into the seawater can directly participate in the corrosion process, and under suitable conditions, can also stimulate microbial activity, promoting microbial corrosion.
For saltwater corrosion of carbon steel pipelines, the primary control method is to prevent the entry of untreated seawater. Prior to the initial cleaning, it is advisable to avoid the entry of untreated seawater as much as possible. If entry is unavoidable, the duration of seawater immersion should be minimized. During the initial cleaning and subsequent operation, it is crucial to prevent seawater from entering the underwater pipeline. If entry is unavoidable, the seawater must undergo treatment, including sterilization, deoxygenation, corrosion inhibition, and anti-scaling, before being introduced.
2 Internal Corrosion Prevention Plan
The new buried underwater pipeline is approximately 113km long, with a design lifespan of 20 years. based on the underwater pipeline process and the typical operational parameters provided, the ECE5 corrosion prediction software was used to simulate and calculate the corrosion rate inside the underwater pipeline. The calculation results are shown in Figure 1. If the corrosion inhibitor has an 85% corrosion inhibition efficiency, the pipe material is carbon steel, and the corrosion amount of the new underwater pipeline within the design lifespan is shown in Figure 2. The corrosion amount in the first 1.5km of the pipeline exceeds 6mm within the design lifespan, requiring the use of corrosion-resistant pipe material. Considering the special operating conditions and the risk of condensation, the first 1.5km of the new buried underwater pipeline adopts carbon steel inner lining corrosion-resistant pipe material. The maximum corrosion amount in the 1.5~113km section of the underwater pipeline within the design lifespan is 5.43mm, and this section of the pipeline can be used with the "carbon steel + internal corrosion allowance + corrosion inhibitor" anti-corrosion scheme, with a corrosion allowance of 6mm for the carbon steel pipe section.
Figure 1: Calculation results for the corrosion rate of newly constructed marine pipelines.
Figure 2: Corrosion amount of newly constructed offshore pipelines over their design lifespan.
Referencing ISO 15156 standards, 316L stainless steel can meet the corrosion resistance requirements for corrosion-resistant pipes in production fluid environments. However, 316L stainless steel is highly susceptible to pitting corrosion in seawater. Therefore, freshwater must be used during the pre-commissioning process. Due to the large diameter and length of the offshore pipeline, a significant amount of freshwater is required for pre-commissioning. This freshwater needs to be transported by ship, which increases overall costs. Considering the corrosion protection requirements for the installation and pre-commissioning phases of the offshore pipeline, the first 1.5km section will use a carbon steel pipe with an inner lining of 625 corrosion-resistant alloy composite pipe.
Carbon steel pipes and inner-lined pipes are insulated using a specially designed insulated section to avoid electrochemical corrosion caused by dissimilar metal connections. The insulated section structure is shown in Figure 3. A non-conductive coating should be applied to the surface of the insulated section. The inner surface of the insulated section should be flush with the inner surface of the connected metal pipe section to minimize the erosion of the coating during fluid flow and ball passing.
Figure 3: Schematic diagram of the insulation pipe segment structure
3. Complete Corrosion Integrity Management of Piping Systems
3. 1 Application of anti-corrosion agents
According to the design requirements, the newly constructed prefabricated steel pipe section requires continuous injection of corrosion inhibitors to control corrosion. Prior to commissioning, a targeted evaluation of corrosion inhibitor selection should be completed. During operation, the residual content of corrosion inhibitors in the outflow should be regularly monitored, and the type, dosage, and application method of suitable corrosion inhibitors for the operating conditions should be periodically evaluated to ensure that the corrosion inhibition efficiency reaches 85%.
NORSOK STANDARD M-001-2014 clearly states that solid deposits inside pipelines can impede the reach of corrosion inhibitors to the pipeline surface, thereby reducing their effectiveness. For systems containing corrosion inhibitors, the design should consider the effective removal of these deposits. In production conditions where deposits are present, effective cleaning is an important technical measure to ensure corrosion protection, while also mitigating the risk of localized corrosion caused by the deposits.
By reviewing domestic offshore oil and gas field development and underwater production system connection pipelines, it is evident that pipelines that have undergone cleaning operations are designed with dual-pipe cleaning circuits. This project involves a single-pipe retubing line for deepwater and long-distance applications. The difficulty in cleaning operations during maintenance poses significant challenges and stricter requirements for subsequent maintenance operations. Currently, there are no reference standards for cleaning these types of offshore pipelines.
The survey of Technip, Shell, and Husky, among others, regarding the cleaning of subsea pipelines both domestically and internationally revealed that the cleaning of subsea pipelines poses a higher risk. Unlike the cleaning strategies for shallow water pipelines, the cleaning frequency of subsea pipelines is generally lower. The most commonly used cleaning tools include bowl-shaped cleaning tools, bidirectional cleaning tools, and foam balls.
The initial production operating conditions for this project are similar to those of the LW3-1 underwater return pipeline. Therefore, the cleaning requirements for this project can be based on the cleaning procedures for the LW3-1 underwater return pipeline. The LW3-1 underwater return pipeline, which was put into operation in 2014, underwent two cleaning operations in 2017 and 2021, with the first cleaning involving the use of 2 foam balls (without using straight balls), and the second cleaning involving the use of 1 foam ball followed by 1 straight ball. In both cleaning operations, there was no significant debris removed, which indicates that excessive cleaning is unnecessary when maintaining the efficiency of the corrosion inhibitor.
Considering the project's construction of a new pre-fabricated marine pipeline, which has a long distance and CO2Due to its high pressure, high water content, and other characteristics, the seawater pipe presents a high risk of corrosion. Furthermore, it can support both on-site operations and cleaning operations from the initial stage. Therefore, it is recommended to increase the cleaning frequency during the initial stage to monitor the corrosion condition of the seawater pipe and guide the optimization of the corrosion inhibitor injection system, providing a basis for formulating subsequent actual cleaning frequencies. After the operating conditions stabilize, the cleaning frequency should be appropriately optimized while ensuring the efficiency of the corrosion inhibitor. If the operating status of the seawater pipe changes significantly or monitoring data indicates a significant increase in corrosion risk, the cleaning frequency should be adjusted based on the assessment and analysis results.
For marine pipe installation, trial operation, and potential microbial contamination risks during operation, it is recommended to conduct regular testing for bacteria and H2Analyze microbial characteristic parameters such as S content, and based on the analysis results, evaluate whether to add a fungicide, and adjust the dosage and frequency of the corrosion inhibitor.
3.2 Corrosion Monitoring and Dynamic Corrosion Assessment
To ensure the safety of underwater pipelines, a set of online internal corrosion monitoring devices are installed in newly constructed mixed pipelines, along with a set of bypass internal corrosion monitoring devices, and corrosion coupons and probes. The online internal corrosion monitoring device utilizes dynamic ultrasonic technology to monitor wall thickness loss in the target pipe section, thereby monitoring the overall corrosion condition of the pipeline. Furthermore, the wall thickness loss can also reflect the effectiveness of corrosion inhibitor application, providing feedback to optimize the addition of anti-corrosion agents and improve the reliability of the pipeline's operational lifespan. Considering the corrosion risks generated by pipeline operating parameters, the risk of accumulation caused by high elevation, the effectiveness of the corrosion inhibitor, and installation feasibility, the online internal corrosion monitoring device is installed between the underwater isolation valve (SSIV) and the expansion bend. This location is near the platform, with complex fluid flow and a higher likelihood of accumulation. Additionally, the residual concentration of corrosion inhibitor at the pipeline outlet is lower than that of the upstream section, allowing for better characterization of the effectiveness of the corrosion inhibitor throughout the entire pipeline.
This project involves the construction of a new pre-fabricated offshore pipeline with a long span and CO2Due to high pressure and high water content, the corrosion risk of the offshore pipeline is high. Furthermore, this project is designed for a single pipeline, which necessitates stricter requirements and challenges for subsequent operations, such as cleaning, corrosion inhibitor management, etc. New offshore pipelines should refer to the recommended practices in Q/HS2091-2021《Steel Offshore Pipeline Integrity Management Specification》during operation and maintenance, and strictly comply with the relevant requirements for offshore pipeline integrity management. The following measures are recommended:
(1) Regularly conduct inspections and analyses of corrosion-related data, including but not limited to inlet and outlet temperatures, inlet and outlet pressures, oil, gas, and water flow rates, and CO2/H2Compare and analyze the detection data for S content, water chemistry, microbiological information, total iron content, scale, and sand, etc.
(2) Regularly obtain corrosion monitoring data from online monitoring systems, coupons, probes, bypasses, etc., including uniform and localized corrosion rates, corrosion morphology, corrosion products, and scale, to issue corrosion warnings and adjust corrosion protection measures.
(3) Select appropriate corrosion inhibitors, conduct regular post-application assessments of the inhibitors, and perform cleaning operations based on the corrosion monitoring results to ensure that the corrosion inhibition efficiency exceeds the designed requirement of 85%.
(4) After each cleaning operation, apply a pre-treatment with a corrosion inhibitor, and analyze the removed materials, including their quality, composition, and microbiological analysis, to provide a basis for optimizing the cleaning and corrosion inhibitor application system.
(5) When significant changes in operating conditions are observed, a corrosion assessment must be performed. New prefabricated marine pipelines should undergo dynamic corrosion assessments based on operating conditions, corrosion monitoring results, evaluations after the application of corrosion inhibitors, and analysis of cleaning and flushing processes during operation and maintenance. The results of these assessments should be used to develop subsequent inspection and evaluation plans and corrosion control measures.
4 Concluding Remarks
(1) Considering the corrosion risks throughout the entire lifecycle, including installation, commissioning, and maintenance of offshore pipelines, the new mixed offshore pipeline within the first 1.5 km adopts a carbon steel inner lining made of 625 alloy composite pipe. The pipeline segment from 1.5 km to 113 km employs a corrosion protection scheme of "carbon steel + corrosion allowance + corrosion inhibitor." If the corrosion inhibitor achieves an 85% reduction in corrosion rate, the inner diameter of the carbon steel pipe section will be 6 mm.
(2) Conduct regular assessments of the effectiveness of corrosion inhibitors and perform maintenance operations based on the corrosion monitoring results, ensuring that the corrosion inhibition efficiency of the inhibitor exceeds the designed requirement of 85%.
(3) During operation, pay attention to H2Risk of localized corrosion due to the presence of sediment, microorganisms, and related factors.
(4) During operation, dynamic corrosion assessments should be conducted promptly based on operating conditions, corrosion monitoring results, post-corrosion inhibitor evaluations, and cleaning and removal analysis. Subsequent inspection and evaluation plans, as well as corrosion control measures, should be developed based on the assessment results.
Source: Corrosion & Protection, Vol. 2, Issue 2, 2024