64 Journal of Engineering, Mechanics and Architecture www. grnjournal.us AMERICAN Journal of Engineering, Mechanics and Architecture Volume 2, Issue 9, 2024 ISSN (E): 2993-2637 Understanding and Mitigating Corrosion in Pipelines: A Comprehensive Study for Mechanical Engineers Ameel Makki Abdulameer Alhakeem Iraqi Ministry of Oil, Basra Oil Company, Basrah, Iraq Mohammed Ridha H. Alhakeem Iraqi Ministry of Oil, Technical Directorate, Baghdad, Iraq Abstract: Corrosion in pipelines is one of the serious challenges in the field of mechanical engineering, particularly with regards to oil and gas, water distribution, and other chemical processes. This article addresses an in-depth effect of corrosion mechanisms, factors influencing corrosion rates, and the effect of corrosion on pipeline integrity. Additionally, the paper will explore advanced methods for detecting, preventing, and mitigating corrosion in pipelines. The study is supported by real-world case studies illustrating the consequences of pipeline failures due to corrosion and emphasizes the importance of regular maintenance and innovative material selection. The findings are intended to guide mechanical engineers in designing more durable and corrosion-resistant pipeline systems. This comprehensive study examines corrosion mechanisms, factors influencing corrosion rates, and advanced methods for detecting, preventing, and mitigating corrosion in pipelines, with real-world case studies underscoring the importance of regular maintenance and innovative material selection for mechanical engineers. Introduction The transportation of oil, gas, and chemicals relies heavily on pipeline infrastructure, making a significant contribution to the economy. Nevertheless, one of the primary challenges faced by these pipelines is corrosion ([21]). Corrosion is a natural process in which metals degrade due to electrochemical reactions with the environment. Without proper engineering and preventive maintenance, corrosion can lead to leaks and ruptures in pipelines, resulting in costly incidents and environmental damage ([14]). Pipeline integrity can be harmed by various degrees of corrosion mechanisms, for instance, chemical corrosion, electrochemical corrosion, and microbial corrosion ([19], p. 6-10). Chemical corrosion occurs when metals directly interact with their surrounding environment, leading to degradation ([5]). Electrochemical corrosion involves the flow of electric current between different areas on a metal surface caused by differences in electrical potential ([5]). Microbial corrosion is accelerated by microorganisms that deteriorate pipeline materials ([5]). Corrosion rates are influenced by factors such as environmental conditions (including soil composition and moisture levels), material properties (including alloy composition and surface finish), and operating parameters like temperature and pressure ([15]). The impact of corrosion on pipeline integrity is substantial, often resulting in leaks, ruptures, and potentially catastrophic failures. Utilizing advanced methods for detecting corrosion, such as non-destructive testing techniques and remote monitoring technologies, can help identify potential issues early on ([15]). 65 Journal of Engineering, Mechanics and Architecture www. grnjournal.us It is crucial to prevent and mitigate corrosion in pipelines to ensure their longevity. Coating and lining solutions offer a protective barrier between the pipeline material and its environment ([1]). Cathodic protection systems assist in preventing corrosive reactions through the application of outer electrical current to disrupt the original flow of electrons which seem to cause corrosion ([1]). Real-world case studies underscore the importance of regular maintenance practices in preventing costly failures due to corrosion. Innovative material selection plays a critical role in enhancing pipeline integrity and longevity ([26]). In conclusion, understanding the mechanisms of corrosion in pipelines is essential for their safe operation. By implementing preventive maintenance strategies, utilizing advanced detection methods, and selecting appropriate materials, the impact of corrosion on pipeline integrity can be minimized. Ongoing research into innovative technologies will continue to foster improvements in pipeline safety and reliability for years to come ([27]). 2. Corrosion Mechanisms 2.1. Chemical Corrosion Chemical corrosion has been a serious danger poses in the oil and gas sector, especially within petroleum refineries, where it can lead to severe breakdowns and costly disruptions in operations. Naphthenic acid (NA) stands out as one of the most corrosive substances found in crude oil, capable of causing various types of corrosion within refinery equipment ([3]). Due to its aliphatic structure and terminal carboxylic acid group, NA can create shallow or deep pits within units like vacuum and atmospheric distillation columns ([3]). Furthermore, NA can result in metal thinning, uniform etching on stainless steel surfaces, as well as grooves and marks on transmission lines and heating tubes ([3]). These examples underscore the diverse ways in which chemical corrosion can manifest in refinery machinery due to specific corrosive elements present in the environment. To counteract chemical corrosion effectively, refineries depend on customized chemical inhibitors and scavengers tailored to address fluid properties, operational conditions, flow rates, and product variations ([36], pp. 11-15). These inhibitors are strategically introduced into the process at crucial points through dispersion or distribution systems to ensure accurate dosages are maintained ([36], pp. 11-15). By implementing these mitigation measures based on monitoring data, refineries can proactively combat the detrimental effects of chemical corrosion on their equipment. Furthermore, water chemistry plays a vital role in CO2-induced corrosion within pipelines by influencing speciation from simple to complex 66 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Figure 1: Above are of the instances of oil refineries menaces occurred being corroded. a. The G. Eagle Refinery, b. R. Refinery, c.C. Refinery. (source: reference [3]) Unit Temperature (oC) Corrosion Type Primarily effect Desalter 50 Contained pitting oxidization. Salt Atmospheric Cleansing 371 Located pitting erosion, and flow-fitted localized corrosion Sulfur, Naphthenic acid, HCl Vacuum Distillation 400 Localized pitting corrosion Sulfur, Naphthenic acid, HCl Catalytic cracking 600 Inter-granular corrosion, SCC, erosion-corrosion Hydrotreater 670 SCC, Hydrogen embrittlement, Pitting H2S, Ammonium salts, polythionic acid Sour water stripper 245 Localized pitting corrosion, erosion-corrosion H2S, flow velocity, chloride Table 1: A brief description of Refinery Units fitted with Corrosion Status. (Source: reference [3]) https://ars.els-cdn.com/content/image/1-s2.0-S1319610321001757-gr1.jpg https://www.sciencedirect.com/science/article/pii/S1319610321001757 https://www.sciencedirect.com/science/article/pii/S1319610321001757 https://www.sciencedirect.com/science/article/pii/S1319610321001757 67 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Constituent Chemical type Hydro-carbons: Paraffinic (Alkanes) Plain chain; split restraint Naphthenic Alkyl cyclopentanes; alkyl cyclohexanes Aroma entity Alkyl benzenes; aroma naphthenic fluorenes; polynuclear aromas Melted vapors Nitrogen (N2); carbon dioxide (CO2) Sulfur composites Elemental sulfur (S8), (H2S)sub-ref-a, mercaptans; Disulfides raw sulfides, polysulfides; sulfones thiophenes & hydrogen sulfide benzothiophenes; Natural nitrogen mixtures Pyridine, quinoline Natural oxygen composites Carboxylic acids (including naphthenic acids)sub-ref-b, alcohols, phenolssub-ref-b, aldehydes, ketones, esters, ethers, oxyacids Biological metallic mixes Porphyrins Colloidal particles Asphaltenes; resins; paraffin waxes Surfactants Sulfonic acids, sulfonates, sodium napthenates Metals Vanadium, nickelsub-ref-c, ironsub-ref-c, aluminum, sodium, potassium, calcium, copper Water (S &Wsub-ref-d or BS & Wsub-ref-d)sub-ref-e Fresh or saline Solids Sandy soil, dirty surface, silt, soil, mud, corroded products (metallic element, oxides, sulfides, salts) Table 2: Crude oil constituents. (Source: reference [3]) Key Structure Acyclic Z = 0 Moncyclic Z = −2 Bicyclic Z = −4 Tricyclic Z = −6 Table 3: These are some typical examples of aromatic as well as non-aromatic napthenic acids and their constituent structures [3]) https://www.sciencedirect.com/science/article/pii/S1319610321001757 https://www.sciencedirect.com/science/article/pii/S1319610321001757 https://www.sciencedirect.com/science/article/pii/S1319610321001757 https://www.sciencedirect.com/science/article/pii/S1319610321001757 68 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Figure 2: Resultant effect of naphthenic acid being corroded (NA),. (Source: reference [3]) Corrosion Form Refinery Unit Remarks It may be in deeper, Shallow, large and often round pits The vacuum from the within contains atmosphere and purification columns that is shell, wall shell, bubble caps and trays This may take place owing to the boil and reduction of NA on metal sub- surface and it may occur mainly in liquid that is mixed vapor streams The metal may be thin and sometimes uniform. It contains stainless steel coupled with the shell of the empty cleansing column https://ars.els-cdn.com/content/image/1-s2.0-S1319610321001757-gr7.jpg https://www.sciencedirect.com/science/article/pii/S1319610321001757 69 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Corrosion Form Refinery Unit Remarks Trenches, striations, and deeper confined attack In transmission lines and heating tubes (furnace) Serious NA corrosion may occur across the bends, elbows, tees, and pumps when there is disruption in the flow. overall corrosion Carbon steel trays and bubble caps This may also be witnessed through the unusual change of acid and non- acidic crudes in the refinery Table 4: the following are sorts of corroded units being used at various refinery units because of naphthenic acid. (Source: reference [3]) Grade Yield Stress Extreme Tensile Charpy Higher-Shelf Strain Solidifying Empty Cell (MPa) Strength (MPa) Energy (ft-Ib) Coefficient X52 411 508 32 0.0832 X65 483 625 122 0.0881 X70 525 601 70 0.0856 Table 5: Automated and breakage materials assigned used in offshore and pipeline projects. (Source: reference [2]) CO2 Solluble carbon dioxide H2CO3 Carbon acid HCO3- Bicarbonat ion CO32- Carbonate ion H+ Hydrogen ion OH− Hydro-oxide ion Fe2+ Iron ion Cl− Chloride ion Na+ Sodium ion K+ Potassium Ca2+ Calcium ion Mg2+ Magnesium ion Ba2+ Barium ion Sr2+ Strontium ion CH3COOH (HAc) Acetic acid CH3COO− (Ac−) Acetate ion HSO4- Bisulphate ion SO42- Sulphate ion https://www.sciencedirect.com/science/article/pii/S1319610321001757 https://www.sciencedirect.com/science/article/pii/S1319610321001757 https://www.sciencedirect.com/science/article/pii/S266714332100055X https://www.sciencedirect.com/science/article/pii/S266714332100055X 70 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Table 6: Other unique organisms obtainable in oilfield brines (source: reference [9]) Empty Cell Response Balance constant Dissoluble of carbon dioxide CO2(g) ⇔ CO2 Ksol=CCO2/PCO2 Aquatic separation H2O⇔Kb,waKf,waH++OH- Kwa=CH+COH- Carbon dioxide hydration CO2+H2O⇔Kb,hyKf,hvH2CO3 Khy=CH2CO3/CCO2 Carbon acid separation H2CO3⇔Kb,caKf,caH++HCO3- Kca=CH+CHCO3- /CH2CO3 Bicarbonate anion dissociation HCO3-⇔Kb,biKf,biH++CO32- Kbi=CH+CCO32-/CHCO3- Acetic acid dissociation HAc⇔Kb,acKf,acH++Ac- KHAc=CH+CAc-/CHAc Hydrogen sulphate anion dissociation HSO4-⇔Kb,HSO4-Kf,HSO4- H++SO42- KHSO4-=CH+CSO42- /CHSO4- Table 7: Again these are some chemical activity typical found in oil/gas field brines and as wel as their reaction constants (source: reference [9]) 2.2. Electrochemical Corrosion Electrochemical corrosion often sets a serious danger to the status and quality of pipelines especially in the domain of oil and gas where exposure to corrosive elements is common. As stated in [1], internal pipeline corrosion can arise from various factors including temperature fluctuations, corrosive gases like CO2 and H2S, water composition, flow velocity, and microbial activity. The synergistic interactions of these elements can hasten the deterioration of pipeline materials, potentially leading to disastrous failures if left unattended. Sweet corrosion, characterized by the acidic environment created by CO2 and water, accounts for a significant portion of pipeline failures. In addition to sweet corrosion, sour corrosion induced by H2S presence further complicates the corrosion process. According to [20], H2S influences corrosivity potential by impacting pH levels and corrosion product formation. The combined effect of H2S and CO2 on corrosion rates necessitates careful consideration during material selection for pipelines operating in hydrocarbon production settings. The mechanisms driving electrochemical corrosion involve intricate interactions between pipeline materials and their surrounding environments. As emphasized in [25], factors such as pH levels, temperature variations, and dissolved gases play pivotal roles in determining the speed and scope of corrosion. The dissolution of corrosive gases produced by CO2 and H2S can lead to the creation of less protective compounds on metal surfaces, hastening the degradation process. A detail analysis of these electrochemical project is vital for implementing effective preventive measures against pipeline corrosion. Techniques like cathodic protection systems highlighted in [14] can aid in mitigating the effects of electrochemical deterioration by actively preventing corrosive reactions at vulnerable points along the pipeline. Furthermore, coating and lining solutions as discussed in [21] provide additional protection against external factors contributing to electrochemical corrosion. Moreover, as underscored in various references ([2], [20]), thorough studies on material characteristics, environmental conditions, and operational parameters are crucial for evaluating and managing risks associated with electrochemical corrosion effectively. By integrating advanced methods for detecting corrosion such as non-destructive testing techniques ([2]), https://www.sciencedirect.com/science/article/abs/pii/S0010938X07001539 https://www.sciencedirect.com/science/article/abs/pii/S0010938X07001539 https://www.sciencedirect.com/science/article/abs/pii/S0010938X07001539 https://www.sciencedirect.com/science/article/abs/pii/S0010938X07001539 https://www.ncbi.nlm.nih.gov/pmc/articles/PMC7601364/ https://onepetro.org/NACECORR/proceedings/CORR06/All-CORR06/NACE-06121/118069 https://www.mdpi.com/2071-1050/16/4/1661 https://matcor.com/pipeline-corrosion/ https://www.corrosionpedia.com/an-intro-to-pipeline-corrosion-and-coatings/2/1383 https://www.sciencedirect.com/science/article/pii/S266714332100055X https://onepetro.org/NACECORR/proceedings/CORR06/All-CORR06/NACE-06121/118069 https://www.sciencedirect.com/science/article/pii/S266714332100055X 71 Journal of Engineering, Mechanics and Architecture www. grnjournal.us operators can proactively monitor pipeline integrity and pinpoint potential areas of concern before they escalate into critical challenges. In summary, a comprehensive grasp of electrochemical corrosion mechanisms is imperative for safeguarding pipeline infrastructure against premature deterioration and ensuring sustained operational reliability. By combining advanced detection methods with proactive maintenance strategies, operators can adeptly manage risks linked to electrochemical deterioration while bolstering the overall integrity of their pipelines. Figure 3: As presented above, are various incidents occurred to numerous pipelines from 1990-2005. for crude oil: there are:(3826 incidents) for natural gas piplines leakage there are (411 incidents). [25]) https://www.mdpi.com/sustainability/sustainability-16-01661/article_deploy/html/images/sustainability-16-01661-g001.png https://www.mdpi.com/2071-1050/16/4/1661 72 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Chemical CaO MgO K2O Na2O composition 0.92 1.54 2.17 0.60 Table 8: Dissoluble chemical property of soil sample (wt.%). (Source: reference [42]) Chemical CaCl2⋅2H2O MgSO4⋅7H2O KCl NaHCO3 composition 0.036 0.190 0.069 0.540 Table 9: the natural mixture in tempered soil solutions (g/L). (Source: reference [42]) 2.3. Bacterial Rust Micro-biologically Influenced Corrosion (MIC) asserts an essential risk to the status, safety, and dependability of pipelines, as emphasized in [13] p. 21-25. This form of corrosion is mainly attributed to sulfate-reducing bacteria (SRB), which may lead to local can result in pitting corrosion over time. The colonies of bacteria formed within pipelines generate substances that corrode the metal, making it challenging to prevent, detect, and mitigate the corrosion effectively. Monitoring various pipeline properties is essential for addressing these tasks. Understanding the mechanisms underlying MIC is crucial for effectively combating its adverse effects. As highlighted in [4], biofilms play a key role in initiating pitting corrosion by compromising the protective layer on certain materials. Additionally, aerobic bacteria present in biofilms can create an anaerobic environment conducive to the growth of anaerobes like SRP and NRP. Grasping these mechanisms is critical for devising successful strategies to manage MIC. Detecting and preventing MIC entails monitoring the physical, chemical, and biological aspects of pipelines. [24] p. 46-50 outlines different techniques for detecting internal corrosion in gas pipelines, such as visually inspecting the pipeline's interior, measuring the thickness of the pipe cover, and to assess corrosion probes, and to use in-line examination tools. By employing these methods, pipeline operators can identify areas of pitting or metal loss early on and implement appropriate measures to prevent further damage. Prevention of MIC involves regulating the quality of gas entering the pipeline and regularly analyzing gas samples for corrosive impurities and signs of corrosion products. Through the implementation of corrosion-mitigation strategies and monitoring microbial activity on pipe walls, operators can effectively manage the risks associated with internal corrosion ([24] p. 46- 50). Furthermore, maintaining suitable operating conditions for pipelines is essential to keep internal corrosion in check. In conclusion, Microbiologically Influenced Corrosion poses a significant danger to pipeline integrity due to sulfate-reducing bacteria's actions. Understanding the mechanisms behind MIC and implementing efficient detection and prevention measures are vital for ensuring the long- term safety and reliability of pipelines. By actively monitoring the physical, chemical, and biological features of pipelines and taking proactive steps to mitigate corrosive elements, operators can reduce the impact of MIC on pipeline integrity (as mentioned in [13] p. 21-25 & [24] p. 46-50). https://onlinelibrary.wiley.com/doi/10.1155/2016/5808372 https://onlinelibrary.wiley.com/doi/10.1155/2016/5808372 https://onlinelibrary.wiley.com/doi/10.1155/2016/5808372 https://onlinelibrary.wiley.com/doi/10.1155/2016/5808372 https://www.clarion.org/catalog/coursesbrochure.pdf https://www.ncbi.nlm.nih.gov/pmc/articles/PMC10479746/ https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR0301.pdf https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR0301.pdf https://www.clarion.org/catalog/coursesbrochure.pdf https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR0301.pdf 73 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Ref. Publication year Research focus Spark et al.12 2020 This study focused on soil factors that caused MIC as a result of buried movable water pipelines. They include essential soil features, bacteria, as well as biochemical systems. Wasim et al.17 2018 The focus here is on soil factors in relation to corrosive activity of metal pipes. In this case, soil resistivity, pH as well as moisture position, temperature, in addition to numerous aeration, particle content, presence of bacteria and other soil type. Lee and Schwab18 2005 This paper addressed factors in connection with drinking water distribution techniques deficiency in the third-world countries. Thus, pipeline corrosion, insufficient disinfection substance, minimal water power, epileptic service, massive leaks, unbalanced water pricing, and excessive water usage. Imran et al.19 2006 This critical review was mainly on the impact of rationing water generation sources on the water quality and water allocation criteria. Similarly, it explains guide for the source water blends to prevent corrosion. Emerson and De Vet20 2015 This study in on Iron-oxidizing bacteria. This instance, often cause corrosion in water allocation within pipelines. Bachmann and Edyvean21 2005 Again, this research addressed the major causes, outcome and affirming biofoul in portable water systems to avoid potential corrosion. McDougall et al.22 2001 The main discussion of this paper is recent developments towards perceiving the role of biofilms on copper corrosive facilities that affect consumption water. Percival23 1998 The microbial biofilms and long-term approach should be dealt with directly on pipe covers is the focus of this study which seeks to cause severe issues affecting consumption water systems, that is corrosive and bacterial build-up. Table 10: As presented above, are brief studies on the causes of corrosive effect in subsurface metal pipelines. (Source: reference [26]) https://www.nature.com/articles/s41545-023-00275-5#ref-CR12 https://www.nature.com/articles/s41545-023-00275-5#ref-CR17 https://www.nature.com/articles/s41545-023-00275-5#ref-CR18 https://www.nature.com/articles/s41545-023-00275-5#ref-CR19 https://www.nature.com/articles/s41545-023-00275-5#ref-CR20 https://www.nature.com/articles/s41545-023-00275-5#ref-CR21 https://www.nature.com/articles/s41545-023-00275-5#ref-CR22 https://www.nature.com/articles/s41545-023-00275-5#ref-CR23 https://www.nature.com/articles/s41545-023-00275-5 https://www.nature.com/articles/s41545-023-00275-5 74 Journal of Engineering, Mechanics and Architecture www. grnjournal.us MIC mechanisms Description Diagram Beneath deposit corrosion, oxygen gradient corrosion A type of “localized corrosion associated with, and taking place under, or immediately around, a deposit of corrosion products or other substance” (ISO 2020), for instance, biofilm or metal accumulation by metal- oxidizing bacteria which seems to be found in a uneven provision. Crevice corrosion A type of “localized corrosion associated with, and taking place in, or immediately around, a narrow aperture or clearance formed between the metal surface and another surface (metallic or non-metallic).” (ISO 8044)The composition of chloride and other unfamiliar anions in the hole increases corrosion. Direct EMIC Metal corroding can also be achieved through extracellular electron movement by living organisms directly as a result of contact with the metal subsurface, while the electron may consume the surface of be cell enzymes. Indirect EMIC Corrosion of metals on the other hand has been increased by dissoluble electron transfer mediators which will release it from biological elements in connection with electrons received from the metallic elemen for metabolism. Metabolite MIC (MMIC) Corrosive elements lost directly or otherwise by metabolic elements obtained by microorganisms all in aerobic and anaerobic situation. Table 11: Brief explanation of the basic mechanisms related to MIC of metals. (source: reference [4]) https://www.ncbi.nlm.nih.gov/pmc/articles/PMC10479746/ https://www.ncbi.nlm.nih.gov/pmc/articles/PMC10479746/ 75 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Engineering/Design Information Operational Information The item size and the major dimensions. Corrosive allowance The period of installation / authorization The type of material and the manufacturer, in this sense, the manufacturer should be suitable in terms of the materials and channel of processing fluids and conditions. Functional problems – solids concentration, flow limitation, expected outages Fabrication procedure, connecting e.g. welding methods, weld strength. affirmation and observation, heat remedy; use of flanged joining (crevice formation) Fluid features and chemical concentration; which include sample tracing and means of sample accummulation and preserving field and analytical procedures employed. Design label; engineering images, procedures, flow diagram Field changes to real design; managing the change of records System operating window (temperature, inflow and outflow) The real operating window (temperature,and in-flow should be maintained within range) Pipeline raising profile This may be the results of several any flow modelling that was conducted Inputs and outputs; systems and circuits Actual procedure inputs and outputs Microbiological observation data,which include sample locations, sampling and improvement methods, field and lab procedures used. Corrosive elements and real danger assessment plan should be found Corrosion observation results from coupons and probes To identify dead legs, no-flow entities Leakage/failure and fixing history List of proposed corrosion observation areas Corrosion reduction – actual activities, chemical management, pigging, flushing, etc. First identification of corrosive mitigation should be made The need to inspect and maintain accurate recourds and also of integrity evaluation records. Means of initial commission and experimentation; hydrostatic test records, procedures, actual test media used Procedure upsets, emergency shut down records-Test Table 12: Execution and engineering information that can prevent the potential danger the MIC appraisal. (source: reference [4]) 3. Factors Influencing Corrosion Rates 3.1. Environmental Conditions Environmental factors have a profound impact on the corrosion rates experienced by pipelines. As indicated in [9], the composition of the water surrounding pipelines can greatly influence the corrosion mechanisms at play. The presence of various dissolved species, including carbon dioxide, bicarbonate ion, chloride ion, and others, can lead to intricate corrosion processes. In a situation where the density of melted salts is high, the resolution may become non-ideal, exacerbating the corrosion even further. Furthermore, as highlighted in [19] p. 11-15, fluctuations in oxygen levels, moisture content, and soil composition along the pipeline's route can act as concentration cells that accelerate corrosion. The quality of coatings applied along the pipeline is crucial in shielding against environmental factors that hasten corrosion. If coatings become disbonded, not only does this expose the steel to corrosive elements but it also hinders cathodic protection currents. https://www.ncbi.nlm.nih.gov/pmc/articles/PMC10479746/ https://www.ncbi.nlm.nih.gov/pmc/articles/PMC10479746/ https://www.sciencedirect.com/science/article/abs/pii/S0010938X07001539 https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65341/finalreportpipelinecorrosion.pdf 76 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Additionally, external elements such as temperature variations, humidity levels, and overall environmental conditions can contribute to the deterioration of pipelines. Population density and incidents of mechanical damage also factor into assessing defect risk and determining maintenance strategies for pipelines. Moreover, according to [31], environmental aspects like H2S concentration, humidity levels, temperature fluctuations, and pH changes are critical for monitoring and mitigating corrosion in sewage pipelines. These factors can impact microbial corrosion rates and affect biochemical processes that contribute to pipeline deterioration. Lastly, as noted in [7], chloride ions found in soil moisture, humidity levels, and resistivity can fuel corrosion propagation within gas pipelines. The presence of chloride ions boosts bacteria activity within electrochemical cells and speeds up surface oxidation processes. In conclusion, a comprehensive understanding of the environmental conditions surrounding pipelines is essential for effectively managing corrosion rates. Variables such as water chemistry, soil composition, temperature shifts, and humidity levels all significantly influence the extent of corrosion damage. By considering these environmental factors and implementing suitable mitigation measures like coatings and cathodic protection systems (as detailed in other parts of this document), pipeline operators can bolster the integrity and longevity of their infrastructure. See also [5]. Indicator type Indicator description Impact of using degradation models Lagging indicant Pipeline leakage Reactive solution to past incidents Spills Data usage for model activity and substantiation Corrosion-related failures Historical information for purification degradation models Functional integrity problems This will help to identify areas susceptible to degradation Regulative fines and penalties Costly consequences of integrity failures Reputation damage Long-term impact on stakeholder trust Table 13: Some major lagging indicators of pipeline status. (source: reference [5]) Indicator type Indicator description Impact of using degradation models Leading indicators Impact and consequence on environment Resultant impacts on ecosystems and public awareness CP system status Early indicators of possible corrosion issues Flow rate and pressure Identifies abnormal flow patterns and pressure drops Temperature state and thermal gradient Detection of overheating in the system and temperature-aligned stresses Pipeline coating integrity Early detection of coating damage https://www.sciencedirect.com/science/article/abs/pii/S0957582020317262 https://www.mdpi.com/2071-1050/16/13/5789 https://www.sciencedirect.com/science/article/pii/S2667143324000064 https://www.sciencedirect.com/science/article/pii/S2667143324000064 https://www.sciencedirect.com/science/article/pii/S2667143324000064 77 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Indicator type Indicator description Impact of using degradation models or degradation Soil and groundwater monitoring Tracks soil corrosivity and potential leaks Review of information (e.g., ILI, MFL, visual inspections) Integration of inspection results into potential models External factors (e.g., weather, seismic activity) Include external factors which influence pipeline position Maintenance , support and repair history Enhances maintenance periods according to the historical data Table 14: Leading signs of pipeline state. (source: reference [5]) Figure 4: Relationships between corrosion-provoking conditions. (source: reference [7]) Figure 5: Fault tree diagram. (source: reference [43]) https://www.sciencedirect.com/science/article/pii/S2667143324000064 https://www.sciencedirect.com/science/article/pii/S2667143324000064 https://www.mdpi.com/sustainability/sustainability-16-05789/article_deploy/html/images/sustainability-16-05789-g004.png https://www.mdpi.com/2071-1050/16/13/5789 https://ars.els-cdn.com/content/image/1-s2.0-S1995822621000649-gr2.jpg https://www.sciencedirect.com/science/article/pii/S1995822621000649 78 Journal of Engineering, Mechanics and Architecture www. grnjournal.us Symbol Description Symbol Description X1 pH value X10 Construction quality issues X2 Resistence X11 Service time of the pipe X3 Moist soil X12 Coating quality issues X4 Redox possibility X13 Insufficient inspection frequency X5 Salinity of soil X14 Improper selection of coating X6 Texture of soil X15 Line failure X7 Free corrosive elements X16 Part failure X8 Chloride composition X17 Stray current X9 Third party actions X18 Failure of stray current protective measures Table 15: Basic events of FT. (source: reference [43]) Figure 6: Tafel plot typical of pipe borne in the water stage drew from the crude oil. (source: reference [8]) Material icorr (μA/cm2) NEQ EW D (g/cm3) Corrosion position Empty Cell Emp. Cell Emp. Cell Emp. Cell Emp. Cell mpy mm/year Pipeline 18.62 0.03630 27.55 07.68 08.616 0.2184 Table 16: Corrosive possibility of pipe bornes under study. (source: reference [8]) 3.2. Material Properties The susceptibility of pipelines to corrosion in challenging environments, such as offshore systems, is heavily influenced by the properties of the materials used. Literature ([2]) emphasizes the impact of both microstructural and alloying elements on the integrity of steel pipelines. Various material microstructures, thus, baintic steel, pearlitic steel, spheroidized steel, martensitic steel, and numerous, have shown different corrosion rates (Katiyar et al., 2019). This underscores the significance of considering material composition when evaluating corrosion vulnerability. When it comes to subsea pipelines, material selection is crucial for ensuring operational efficiency and longevity. The classification and numbering systems of steels are based on their chemical composition, which dictates their performance in corrosive settings ([16]). While carbon steel is commonly utilized for subsea pipelines, highly corrosive environments may require the use of corrosion-resistant alloys with superior resistance. The selection process involves assessing corrosion rates and comparing mechanical and corrosion resistance properties to identify the most appropriate material for a specific project. Additionally, various empirical, probabilistic, and semi-empirical types were to addres the dissemination rate of corrosion effects in complex microenvironments ([2]). These models take https://www.sciencedirect.com/science/article/pii/S1995822621000649 https://www.sciencedirect.com/science/article/pii/S1995822621000649 https://ars.els-cdn.com/content/image/1-s2.0-S2213290213000503-gr6.jpg https://www.sciencedirect.com/science/article/pii/S2213290213000503 https://www.sciencedirect.com/science/article/pii/S2213290213000503 https://www.sciencedirect.com/science/article/pii/S2213290213000503 https://www.sciencedirect.com/science/article/pii/S266714332100055X https://uis.brage.unit.no/uis-xmlui/handle/11250/2438600 https://www.sciencedirect.com/science/article/pii/S266714332100055X 79 Journal of Engineering, Mechanics and Architecture www. grnjournal.us into account aspects related to microstructure and natural conditions to evaluate the probability of pipeline failure. This will lead to the combination of semi-empiricalconstituents with Monte Carlo simulations which offers a risk-founded instrument for selecting suitable materials and managing pipeline integrity in corrosive environments. The interplay between environmental factors and material properties can either exacerbate or alleviate a pipeline's susceptibility to corrosion ([26]). Other factors like composition, air quality, moisture content, temperature fluctuations, and bacterial activity can impact the corrosion process. Furthermore, older or lower-quality pipes lacking protective coatings may be more prone to corrosion due to manufacturing flaws or inherent material characteristics ([41]). In conclusion, comprehending how material properties influence corrosion rates is vital for choosing appropriate materials for pipeline construction. By taking into consideration microstructural elements, alloying elements, and environmental factors during material selection processes, pipeline operators can mitigate corrosion risks and ensure the long-term integrity of their assets. Model Application Source Southwell’s linear model: d(t)=0.076+0.038t Steel structure (sub-ref-Schumacher, 1979) Southwell’s bi-linear model: d(t)={0.09t0≤t<1.46y0.76+0.0 38t1.46≤t<16y Steel structure (sub-ref-Schumacher, 1979) Melchers-Southwell’s nonlinear model: d(t)=0.84t0.823 Marine structure (sub-ref-Melchers, 1999) Melcher’s power law model: d(t)=0.1207t0.6257 Marine structure (sub-ref-Melchers, 1999) Melcher’s tri-linear model: d(t)={0.170t0≤t