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INTRODUCTION
The hydrogen embrittlement phenomenon is a costly failure in the upstream oil and gas sector [1]–[2].
Crude oil pipelines containing H2S (Hydrogen Sulfide) cause an electrochemical reaction between the base metal and the fluid. Hydrogen sulfide is colourless, flammable, extremely hazardous, and lethal to humans. It has mainly existed in all oil wells. The H2S decreases the pipeline life span by reducing its toughness and making it more brittle and corrosive, as shown in Figures 1a to 1d. Hydrogen-pressure cracking causes a significant increase in volume as molecular
hydrogen is much larger than atomic hydrogen. This causes two problems: the molecular hydrogen is too large to remain interstitial in a solid solution and can no longer diffuse out of the structure. Hence, that leads the material to lose ductility and become more brittle, as demonstrated in Figure 2. This paper aims to review the significant contributors affecting pipeline corrosion and pipeline cracking due to hydrogen embrittlement as well as to discuss the standard test methods (physically and computationally) to investigate this corrosion-diffusion issue. Therefore, further recommendations and improvements could be suggested for economic-wise reasons.
A REVIEW ON DESIGN OF CRUDE OIL PIPELINE WALL OPTIMIZATION DUE TO CORROSION AND HYDROGEN
EMBRITTLEMENT
Hamdan H. Aljneibi, Sharul S. Dol*
Department of Mechanical Engineering, Abu Dhabi University, Abu Dhabi, United Arab Emirates
*Email:: [email protected]
ABSTRACT
Crude oil pipeline infrastructures represent a high capital investment, and pipelines must be free from the risk of degradation due to corrosion and hydrogen embrittlement, which could cause environmental hazards and potential threats to human life. Pipeline integrity design, monitoring, and management become crucial, especially in subsea pipelines. Corrosion risk assessment is necessary to track pipeline reliability and life prediction effectively. The pipeline inspections cost a lot of money since the pipeline are hundreds of thousands of kilometres, and the maintenance process interrupts the production rates. Moreover, this cost will triple for the subsea pipeline as it requires special personal qualifications and tools, causing the oil and gas company to pay millions for frequent checks. It is proposed to utilize Finite Element Analysis (FEA) modelling technique and Computational Fluid Dynamics (CFD) to optimize the design and preventive maintenance prediction. Hence this paper aims to review the current work on this pipeline design problem, especially in the Tropical region, and discuss the factors that cause the deterioration of structural properties due to the presence of hydrogen within the crude oil.
Keywords: Crude oil, corrosion, hydrogen embrittlement, H2S, maintenance, pipeline, subsea
Received: 3 March 2023, Accepted: 20 June 2023, Published: 30 June 2023, Publisher: UTP Press, Creative Commons: CC BY 4.0
DESIGN AND MAINTENANCE ISSUES
There is no accurate reference in international standards such as the National Association of Corrosion Engineers (NACE), the American Society of Mechanical Engineers (ASME), or others to manufacture pipelines. The most appropriate standard is was ANSI/NACE MR0175/ ISO 15156-3 (International Standard ISO 15156-3:2015 Technical Circular 3-Petroleum and natural gas industries -
Figure 1 Hydrogen-assisted deformation and crack propagation on steel [3]
Figure 2 Schematic diagram of hydrogen-induced cracking mechanism [4]
Materials for use in H2S-containing environments in oil and gas production). However, the NACE MR0175 ACE MR 0177 gives a generic term to select suitable crude oil line service material. It was only limited to two case scenarios (i.e., above 0.3 kPa H2S partial pressure and below 0.3 kPa H2S partial pressure), and the maximum allowable corrosion rate is 0.2 mm/
year. Otherwise, the Carbon steel cannot be selected unless the crude oil has been chemically treated to reduce the corrosion rate.
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The distribution of oil pipelines has two main issues, the overdesigned wall thickness and the frequency of periodic maintenance, which cause an increase in the manufacturing and maintenance costs to millions of dollars [5]-[6]. To design the wall thickness calculation, it is needed to follow ASME B31.4 for wall thickness calculation, NACE MR 0175, and NACE MR 0177 for material selection. Both standards are generic and have many precautions. Since the pipelines are manufactured in huge quantities, they reach hundreds of kilometres and consider an affordable and safer way to transport oil and gas, as shown in Figure 3 of the Caspian Sea pipeline.
The most recent studies in this field aim to develop a simulation that can calculate the wall thickness more efficiently and predict the life span for in-
Figure 3 Gas pipeline delivering natural gas from the Caspian Sea to European markets [7]
service pipelines to reduce the material usage by the manufacturers and reduce the required maintenance, such as a smart or intelligent pigging system. Smart pigs (Figure 4) can work on detection as they propel along the pipe and measure deformations. The sensors use nondestructive techniques (NDT) such as ultrasonic and magnetic flux leakage testing to identify erosion-corrosion, metal loss, pitting, dents, weld irregularities, and hydrogen-induced cracking for pipeline integrity [8]. The intelligent ultrasonic system used by the petroleum industry is a fast and accurate technique to examine the properties of a material, pipe component, structure, or system for characteristic differences or welding defects and breaks without severely restricting the operation or production outage. They can also gather data on the pipeline’s diameter, curvature, bends, and
Figure 4 SMART pig sensors to check the interior condition of pipe walls [9]
temperature. The cost of smart pigging can vary, but it almost costs $1 million.
The most followed standard for offshore fix structure is EEMUA 158 [10]. This standard is developed to accommodate the North Sea environment. However, it has been used all around the world. The issue is
Figure 5 Fractographic images showing the macroscopic fractures of a notched weld metal surface due to hydrogen embrittlement [11]
Figure 6 Pipeline corrosion management [12]
that EEMUA 158 is very stringent for a Tropical region since the weather is not as harsh as in the North Sea. EEMUA 158 is a specification defining the basic requirements for fabricating the primary structures of offshore installations. The standard is required to do the non-destructive test (NDT) after 48 hours
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of welding, regardless of the size of the materials oryield strength. Hence, the fabrication process lingers, making it hard to comply, especially offshore, and the main reason to do the NDT after 48 hours is the cold crack (Hydrogen crack), which occurs within 48 hours (Figure 5).
Also, oil and gas industries take the RBI (Risk-based inspection), which requires more inspections for the lethal lines. The RBI is a process of developing a scheme of inspection based on knowledge of the risk of failure, as shown in Figure 6. The essential process is a risk-integrated analysis based on a cost-effective manner. It is the mixture of evaluating the likelihood (probability) of failure due to design flaws, facilities damage, materials losses, or degradation to evaluate the consequences of such failure. The priorities and frequencies of inspections will be suggested based on the analysis.
What is lacking in the previous research is mainly due to the gaps in full understanding of the diffusion modeling in the hydrogen embrittlement, which occurs when metals become brittle due to hydrogen diffusion into the material. The degree of embrittlement is influenced by the amount of hydrogen absorbed and the material’s microstructure, as explained in Olden et al. [13]. In large pipeline networks and high production rates, the mechanical stresses amplify the embrittlement issues, promoting more corrosion problems, especially at the pipeline components and joints.
STANDARD TEST METHOD
The purpose is to have an accurate estimate of the pipeline life span and to have accurate results
in designing the pipeline. Also, it is intended to reduce the number of SMART pigging. This can be achieved by studying the diffusion of the main phenomenon in the pipelines, which is the HIC (Hydrogen Induced Crack). The HIC test according to ANSI/NACE MR0175/ ISO 15156-1 and following NACE TM0284 can be conducted by exposing unstressed test specimens to the specified environment saturated with hydrogen sulfide gas at 1 bar pressure for 96 hours for the standard test. Fitness for testing may also be performed using reduced partial pressures of hydrogen sulfide and for durations of up to 30 days [14].
Normally, the test specimens are evaluated by the following equations;
Crack Sensitivity Ratio, CSR =
(1) Crack Length Ratio, CLR = (2) Crack Thickness Ratio, CTR =
(3) where a = crack length
b = crack thickness W = section width
T = test specimen thickness
However, such tests will interrupt the pipeline operation hence the production rates. The main parameters to stop the operation of the pipeline are as the followings;
1. Massive reduction in pipeline wall thickness 2. Crack length exceeds the allowable
3. Hardness levels exceed the allowable
Table 1 Corrosion allowance
Class Average corrosion rate,
mm /year Corrosion allowance (mm) for 30 years
A (mild) - without H2S 0.05 1
B (medium) - H2S partial pressure < 300 Pa 0.1 3
C (severe) - H2S partial pressure > 300 Pa 0.2 6
The corrosion allowance is categorized into three categories [15]; the first category is for the pipelines containing water, which means no H2S. The second category is the pipelines containing crude oil with H2S partial pressure below 300 Pa, and finally, the pipelines containing crude oil with H2S partial pressure over 300 Pa, as shown in Table 1.
MODELLING
After having all the results from the HIC test and the H2S partial pressure (i.e., this partial pressure decreases over time unless there will be water or gas injection into the well to increase the pressure), the amount of hydrogen that dissolves into the pipeline material can be determined. The simulation process can be initiated using the given information. Then, the crack will appear if it exceeds the acceptance criteria for the HIC. The velocity pattern will be taken in two places, at the beginning of the line and the end. The simulation will be done in both patterns to identify the most severe effect on the pipeline. Consequently, this input will be given to the pipeline engineer to optimize the design, reduce the pipeline thickness, or even make the thickness bigger.
The main constraints to simulation are indicated as the followings;
1. H2S partial pressure effect 2. pH level effect
3. Temperature 4. Flow
5. Material hardness
Most of the literature has put considerable effort into investigating the factors mentioned above;
however, the effects of pipeline flow behaviours are largely unanswered [16]-[17]. The diffusion rates depend on the microstructures of the metallic phase (Figure 7) [17]. The flow patterns are believed to play a significant role in the corrosion rates and hydrogen embrittlement, especially near the walls.
The shear stress equation exhibited as follow:
[4]
The shear stress is a product of dynamic viscosity 𝜇, and the shear rate [18]. As the walls get rougher due to the material deterioration (Table 1), the flow patterns will be modified; therefore, the wall shear stresses
Figure 7 Hydrogen diffusivity in martensite matrix [18]
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become non-uniform [19]-[20]. The effects of this on the corrosion rates and hydrogen embrittlement will be interesting to observe in the coming work. The problem normally focuses on pipeline lifespan using FEA ANSYS, while the corrosion rate will be calculated using the ECE Software (Electronic Corrosion Engineer).
CONCLUSION
Corrosion is a very challenging phenomenon and has cost the world more than a trillion dollars yearly, occasionally and non-occasionally. Hence, the review discusses the significant contributors affecting pipeline corrosion and pipeline cracking due to hydrogen embrittlement, especially in the Tropical subsea. The design process for the new pipeline can be summarised as Figure 8. The input contains Data Sheet, Internal pressure, Temperature, H2S partial pressure, and pH level. The process used was ASME B31.4, NACE MR0175, corrosion allowance, while the output result contains the calculation of pipelines wall thickness to manage corrosion.
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Figure 8 Design process for the new pipeline
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