Natural Gas Transmission Pipelines Research Articles

A comparison of onshore oil and gas transmission pipeline incident statistics in Canada and the United States

This study analyzes the mileage and incident data between 1995 and 2016 corresponding to the onshore oil and natural gas transmission pipelines regulated by the Canada Energy Regulator (CER) and Pipeline and Hazardous Materials Safety Administration (PHMSA) of the United States. The analysis indicates that the material/weld/equipment failure is the leading failure cause for both CER and PHMSA pipeline incidents. The annual average incident rates of the CER and PHMSA pipelines are in the order of 10−3 per km except for the PHMSA gas pipelines, the annual incident rate of which is in the order of 10−4 per km. The annual average rupture rates of the CER and PHMSA pipelines vary from 3.5 × 10−5 to 4.5 × 10−5 per km. The F-N curves for the PHMSA pipelines are developed based on the mileage and incident data to quantify the societal risks posed by the pipeline in general.

Development of Landslide Fragility Functions for Natural Gas Transmission Pipelines

Development of Landslide Fragility Functions for Natural Gas Transmission Pipelines

Analysis of sensitivity to hydrate blockage risk in natural gas gathering pipeline

During the operational process of natural gas gathering and transmission pipelines, the formation of hydrates is highly probable, leading to uncontrolled movement and aggregation of hydrates. The continuous migration and accumulation of hydrates further contribute to the obstruction of natural gas pipelines, resulting in production reduction, shutdowns, and pressure build-ups. Consequently, a cascade of risks is prone to occur. To address this issue, this study focuses on the operational process of natural gas gathering and transmission pipelines, where a comprehensive framework is established. This framework includes theoretical models for pipeline temperature distribution, pipeline pressure distribution, multiphase flow within the pipeline, hydrate blockage, and numerical solution methods. By analyzing the influence of inlet temperature, inlet pressure, and terminal pressure on hydrate formation within the pipeline, the sensitivity patterns of hydrate blockage risks are derived. The research indicates that reducing inlet pressure and terminal pressure could lead to a decreased maximum hydrate formation rate, potentially mitigating pipeline blockage during natural gas transportation. Furthermore, an increase in inlet temperature and terminal pressure, and a decrease in inlet pressure, results in a displacement of the most probable location for hydrate blockage towards the terminal station. However, it is crucial to note that operating under low-pressure conditions significantly elevates energy consumption within the gathering system, contradicting the operational goal of energy efficiency and reduction of energy consumption. Consequently, for high-pressure gathering pipelines, measures such as raising the inlet temperature or employing inhibitors, electrical heat tracing, and thermal insulation should be adopted to prevent hydrate formation during natural gas transportation. Moreover, considering abnormal conditions such as gas well production and pipeline network shutdowns, which could potentially trigger hydrate formation, the installation of methanol injection connectors remains necessary to ensure production safety.

The hydrogen perspective for Türkiye, which is on the Asia-Europe energy transition route. Can Türkiye become hydrogen hub?

This study examines the potential for hydrogen to undertake a leading role in the transition to sustainable energy in Türkiye. Türkiye, with its well-established energy infrastructure and increasing focus on renewable energy, has the potential to undertake a significant part in the worldwide hydrogen market. The research uses a multi-level perspective to analyse the interactions between different region connected with Türkiye, and the processes and strategies within the national energy system. The findings suggest that hydrogen production and transport in Türkiye has the potential to significantly contribute to the decarbonization of the industry and flexibility services in Asia, Europe and Africa. However, the ongoing advancement in the field of hydrogen in Türkiye is at a critical juncture where coordinated efforts are necessary to fully realize its potential. Türkiye recently announced the Hydrogen Technologies Strategy and Roadmap. Under the new Hydrogen Technologies Strategy and Roadmap, Türkiye plans to significantly increase the production of hydrogen. Türkiye plans to significantly increase its installed electrolyser capacity to support the production of hydrogen. Specifically, the plan aims to increase the installed capacity to 2 GW by 2030, 5 GW by 2035, and 70 GW by 2050. Turkey's strategic investments and policy adjustments could propel its green hydrogen production to 3.4 million tons yearly by 2050. With an anticipated domestic demand for hydrogen at 1.9 million tons annually, Turkey could potentially export between 1.5 and 1.9 million tons yearly by 2050. Türkiye boasts an extensive network of transmission and distribution pipelines for natural gas, totalling 10,000 km, including those with large diameters. The existing pipelines could transport hydrogen in its pure form or blended with natural gas. The natural gas pipeline capacity in Turkey stands at 32 billion cubic meters. This infrastructure enables the transportation of an estimated 575 million tons of hydrogen yearly to neighboring countries by employing a mix of 20 % hydrogen and natural gas. With an extensive network of natural gas transmission and distribution pipelines, Turkey positions itself as an integral part of the interconnected hydrogen energy infrastructure, linking the nation with Europe and neighboring regions. The results of this study present new approaches into the dynamics of the energy system and contribute to ongoing discussions about transition routes and consider the current status of hydrogen in Türkiye, the country's renewable energy potential, the policy and regulatory framework, and the infrastructure and market conditions necessary in order to foster the growth of a hydrogen hub.

Consideration of risks to people and the environment related to accidents on natural gas transmission pipelines in LUP and SEA processes in Poland

ABSTRACT This study concerned the integration of gas pipeline safety issue into the LUP (Land Use Planning) and SEA (Strategic Environmental Assessment) processes in Poland. It focused on the early stage of natural gas transmission pipeline localisation, i.e. the preparation of land use development plans (the plans) and accompanying SEA documents. It aimed to analyse a set of selected plans and SEA documents taking into account risks to people and the environment resulting from accidents on gas pipelines. The results of the analysis showed that although the Polish legislation defining the content of these documents does not explicitly refer to these risks, they are included, but to a limited extent, in the documents examined. It is proposed to modify the EU and Polish legislation for the control of major accident hazards on gas pipelines. In particular, in addition to the generic-distances approach currently used in Poland for maintaining the separation distances between the gas pipeline and other buildings it is suggested to introduce a risk-based approach to support LUP decisions near gas pipelines in Poland.

Analysis of Occupational Safety and Health (K3) Risk Management in Construction Industry (Case Study: Construction of Natural Gas Transmission Pipelines)

The need for gas in Indonesia is currently quite urgent, but the infrastructure to provide natural gas supplies for industry is inadequate, so the government is encouraging the development of national natural gas infrastructure. In this project, build facilities including Tie-in at the Onshore Receiving Facilities (ORF) and then build a pipeline. The ORF consists of various large instruments, the installation process of which requires the assistance of heavy equipment such as a crane. Instrument installation work at ORF using a crane is included in the critical & extreme risk because the placement will use more than one crane and this work is carried out on a platform. Apart from that, the ORF was built next to an existing LPG station, so this condition has its own potential danger. To find out the source of the biggest risks, risks that may occur, methods of risk mitigation, and the level of effectiveness of the mitigation provided, occupational safety and health risk management analysis could be carried out using the House of Risk (HOR) and Hazard Identification, Risk Assessment & Determining Control (HIRADC) method. Lifting activities on the ORF platform was the biggest source of danger and there were 15 possible risks that may occur, 3 risk agents were in the mobilization of heavy equipment activities (cranes), 5 risk events were in the crane placement activities and 7 risk events were from material transport activities and there were 36 risks agents in it, 9 risk agents for mobilization activities, 11 risk agents for crane placement activities and 14 risk agents for material transport activities. Of the 36 risk agents, 16 of them have high potential, so suggestions for risk mitigation actions were given using the HOR phase II method. By conducting discussions, there were 48 mitigation action plans that were able to reduce the potential of risk agents with 36 main preventive actions, namely suggestions for mitigation actions that had difficulty value 3 or easy to implement. After assessing the recommended preventive actions, an assessment is carried out that there was a reduction in the level of risk using the Hazard Identification, Risk Assessment & Determining Control (HIRADC) method, where there were 3 medium risk categories and 13 low-risk categories. Before recommendations for risk mitigation actions, there were 3 extreme risk categories and 13 high risk categories.

Monitoring and Preventing Failures of Transmission Pipelines at Oil and Natural Gas Plants

In recent years, the increase in energy prices and demand has been driven by the post-pandemic economic recovery. Of the various energy sources, oil and natural gas remain the most important source of energy production and consumption after coal. Oil and gas pipelines are a key component of the overall energy infrastructure, transporting oil and gas from mines to end users, so the reliability and safety of these pipelines is critical. The oil and gas industry incurs large expenses for the removal of failures related to, among others, corrosion of pipelines caused by the presence of Hg, CO2 H2S, carbonates and chlorides in reservoir waters. Therefore, pipeline operators must constantly monitor and prevent corrosion. Corrosion failure losses are a major motivation for the oil and gas industry to develop accurate monitoring models using non-destructive NDT methods based on test results and failure frequency observations. Observing the locations of frequent pipeline failures and monitoring and applying corrosion protection to pipelines play an important role in reducing failure rates and ultimately increasing the economic and safety performance of pipelines. Monitoring and prevention efforts support the decision-making process in the oil and gas industry by predicting failures and determining the timing of maintenance or replacement of corroded pipelines. We have presented methods of prevention through the use of corrosion inhibitors in crude oil and natural gas transmission pipelines, as well as various factors that influence their application. In this article, a review of corrosion rate monitoring systems is conducted, and a range of control and monitoring scenarios is proposed. This knowledge will aid scientists and practitioners in prioritizing their policies, not only to choose the appropriate monitoring technique but also to enhance corrosion protection effectiveness.

The optimum use of high-strength steel in the construction of gas transmission pipeline

PurposeThe aim of this study is to assess the opportunity for the development of hydrocarbon transportation using high-strength steel (HSS) in pipeline construction in terms of cost savings and reliability.Design/methodology/approachSeveral optimizations of pipeline design and operations were performed to estimate the total life-cycle cost variation associated with different grades of high-strength steel. The generalized reduced gradient (GRG) method was used in an Excel table to determine optimal total life cycle each pipeline. Variables used in this optimization with respect to each steel grade were as follows: pipeline external diameter, wall thickness, number of compression stations and installed power in each compression station. The reliability of a pipeline with optimal cost was assessed to highlight the impact of steel grade on pipeline reliability.FindingsThe study showed that the cost reduction is strongly dependent on the adopted gas pipeline configuration. The number of compression stations and external diameter are the main factors influencing the pipeline total life cycle cost, while the steel price seems to have a minor effect, the reduction of the gas pipeline total life cycle does not exceed 5% even with a 50% difference in pipe steel prices between X70 and X100 steels. On the other side, for the same external diameter, X100 steel presents better pipeline reliability against carbonic corrosion compared to X70 steel.Practical implicationsThe main contribution of this study is to provide a decision-support tool to help pipeline constructors enhance the profitability of natural gas transmission pipelines. The optimization method used is simple to use for design engineers during a feasibility study.Originality/valueThe present study presents one step to fill the gap concerning the question of balancing the trade-off between cost savings and structural reliability in high-strength steel pipelines during the early stages of feasibility studies. The optimal design and operations parameters ensuring cost savings on total life cycle costs are identified via an optimization method. The impact of selected optimal parameters on the long-term pipeline service life was estimated via a structural reliability analysis.

The development of complex engineering models using artificial neural network-based proxy models for life cycle assessments of energy systems

The energy industry has been using life cycle assessment (LCA) to determine the environmental impact of projects. Obtaining accurate data of certain industrial activities requires complex engineering models that have long computing times, are difficult for non-experts to use, and may contain confidential data. This work examines using proxy models based on quadratic and artificial neural network (ANN) regression to create an accurate, easy-to-use, black-box model that can be easily shared. Generating target values from the engineering software needed for training can be time-consuming, hence, adaptive sampling methods are examined (random, spread, high error, and the combo method [50/50 random/high error]). Two case studies were examined: a transportation fuel LCA of Maya, Bow River, and mined bitumen crude oils; and an LCA of a natural gas transmission pipeline (NGTL). This work found that ANN proxy models are more accurate than quadratic regression, and the high error sampling method reduced the maximum error but increased the average error. The combo and high error methods using 3000 to 4000 samples achieved similar maximum errors to the random method using 10,000 samples. Because of uncertainty in LCA input values, reducing average error is less valuable than reducing extreme errors. For the NGTL case study, the ANN model was able to reduce the average and max error by 67% and 68%, respectively, while using 35% fewer coefficients; ANN models are more appropriate for complex nonlinear models.

A review of hydrogen embrittlement in gas transmission pipeline steels

Abstract Hydrogen transport by blending hydrogen into natural gas transmission pipelines and by pure-hydrogen pipelines is a prospective mode of energy transmission during the transition to renewables. The risk of hydrogen embrittlement (HE) in pipeline steels must first be quantified to ensure safe pipeline operation. This review provides an overview of HE in pipeline steels. Most pipeline steels have reduced ductility when exposed to hydrogen partial pressures of 100 bar and above. Higher-strength pipeline steels (X80 and X100) have been found to undergo HE at ∼50 bar hydrogen. Hydrogen-induced subcritical crack growth in pipeline steels has not been reported in the literature. There are few articles on HE in pipeline welds, with some indications that the weld is more susceptible to HE, and some indications that it is less. The relationship between hydrogen pressure and absorbed hydrogen concentration has not been evaluated. Gaps in knowledge are identified in the conclusions.

Hydrogen blending in existing natural gas transmission pipelines: a review of hydrogen embrittlement, governing codes, and life prediction methods

Abstract Existing natural gas pipelines provide an economic alternative for the transport of hydrogen (H2) in an envisioned hydrogen economy. Hydrogen can dissolve in the steel and cause hydrogen embrittlement (HE), compromising pipeline structural integrity. HE causes subcritical cracking, decreases ductility and fracture toughness, and increases the fatigue crack growth rate (FCGR). This work analyzes the testing standards in gaseous hydrogen used to quantify those effects. Design code ASME B31.12 applicable to hydrogen pipelines has more stringent requirements than ASME B31.8 code commonly used for constructing natural gas pipelines. Differences in materials requirements specified by those codes are summarized. ASME B31.12 pipeline code applies for H2 at a concentration greater than 10% molar. However, recent testing programs acknowledge that H2 degrades steel mechanical properties regardless of its percentage in the blend. This paper discusses how the hydrogen degraded mechanical properties affect pipeline integrity. Decreased mechanical properties cause a drop in the failure pressure of a flawed pipeline, calculated following a fitness for service methodology. There is an increasing risk of subcritical crack growth in H2 as the hardness of base metal and welds increases. This paper analyzes where zones with high hardness and susceptible microstructures are expected in existing pipelines.

Internal leakage rate prediction and failure diagnosis of buried pipeline ball valve based on valve cavity pressure detection

— Ball valve is a key fluid control equipment used extensively in oil and gas pipelines. The online detection and failure diagnosis of the internal leakage of the ball valve is of great significance to ensure the safety operation of natural gas transmission pipelines. This paper proposes a prediction method of the internal leakage rate and a diagnosis method of the failure mode of the buried pipeline ball valve based on valve cavity pressure detection. Firstly, the valve cavity pressure signal generated by the internal leakage of the ball valve is detected by the pressure sensor, and the valve cavity pressure signal is denoised by wavelet threshold denoising. Then, the back propagation (BP) neural network has the disadvantage of unstable learning ability, so the BP neural network is optimized by chaos sparrow search optimization algorithm (CSSOA-BP). Finally, the prediction model of the ball valve internal leakage rate and the diagnosis model of the ball valve failure mode are established by using CSSOA-BP neural network and the characteristic parameters of the valve cavity pressure signal. To verify the performance of the prediction model and the diagnosis model of CSSOA-BP neural network, the predictive results and diagnostic results are compared with those of the sparrow search algorithm optimization BP (SSA-BP) neural network and BP neural network. The experimental results show that the maximum prediction error of CSSOA-BP neural network is the smallest, which is 13.6%. The accuracy of the diagnostic results of CSSOA-BP neural network is the highest, which is 83.3%. It indicates that the proposed method can achieve better predictive results of the ball valve internal leakage rate and more accurate diagnostic results of the ball valve failure mode.

A dynamic fracture finite element model of the buried gas transmission pipeline combining soil constraints and gas decompression

A long-distance natural gas transmission pipeline is the primary solution for natural gas resource distribution. In fact, the longitudinal crack propagation of gas transmission pipelines has always been a concern of the natural gas industry. Because it will cause disastrous accidents once the ductile crack in the pipeline propagates rapidly. Most natural gas transmission pipelines are buried underground to improve the safety of pipeline operation as the backfill soil can absorb energy during the fracture process and restrain the displacements of the flaps. Fracture control is a fundamental requirement for the safe operation of underground pipelines. In this study, the dynamic fracture finite element model of the buried gas pipeline is developed to simulate the actual fracture process instead of the costly full-scale burst experiments. The finite element model incorporates different external soil constraints and internal gas decompression behaviors during pipe rupture in which soil constraints are represented by discrete soil springs, and a user-defined subroutine realizes the gas decompression behavior. The explicit dynamic analysis is employed to simulate the high-speed dynamic fracture process of the pipeline, and the crack propagation is simulated by using the cohesive zone model. Finally, the crack propagation velocity is calculated by this model, and the influence of different internal pressures on the fracture velocity is studied; the crack tip opening angle (CTOA) is predicted, and the effect of soil spring stiffness on CTOA is evaluated.

Binary Sacrificial Coatings for Internal Corrosion Protection of Natural Gas Transmission Pipelines

One of the top reasons for the leaks in natural gas transmission pipelines is related to the internal corrosion of steel pipelines, mainly due to the presence of incidental H2O and CO2 in the line. Adding a protective coating or liner to the inner pipe surface reduces internal corrosion; however, conventional coatings (e.g., paint, epoxy, polyethylene, etc.) are insufficient to provide long-term corrosion resistance due to the permeation of the corrosive species such as H2O, CO2, Cl-. This research aimed to investigate the corrosion behavior of binary sacrificial coating for the protection of pipeline steel in a CO2-saturated aqueous electrolyte under natural gas pipeline conditions.Two types of the cold spray binary metallic coatings (ZnCr, ZnNb) were studied using electrochemical techniques: potentiodynamic polarization (PDP), linear polarization resistance (LPR) and electrochemical impedance spectroscopy (EIS). The evaluation of the corrosion resistance of cold spray binary metallic coatings (ZnCr, ZnNb) was carried out in an environment containing 3 barg CO2 pressure, simulating the partial pressures that are found in gas transmission over a solution of 3.5 wt.% NaCl heated to 40 ºC. Post-corrosion surface characterization was performed using scanning electron microscopy (SEM) equipped with energy-dispersive X-ray spectroscopy (EDS).The EDS mapping analysis and XRD results revealed the presence of ZnCO3 layer. EDS analysis showed that no Cr was detected on the surface of ZnCr coating after 24 hours of exposure. This may be due to a thick layer of ZnCO3 formed on top of the ZnCr coating. The obtained data showed that cold spray binary metallic coatings (ZnCr, ZnNb) can be used as sacrificial anodic materials to protect the interior of the steel pipeline against CO2 corrosion in a natural gas transmission environment. Furthermore, self-healing properties of the binary metallic coatings were demonstrated as protective corrosion products formed on the damaged regions of the coating.Keywords : CO2 corrosion, natural gas pipelines, cold spray coatings, zinc alloy, sacrificial coatings, self-healing coatings, electrochemical reaction autoclave

Preventing the Formation of Methane Hydrates in Natural Gas Transmission Pipelines–A Comprehensive Review

Hydrates are usually formed during the transportation and treatment of natural gas, resulting in hydrate plugging of pipelines. Hydrates are crystal like structure being formed from the mixture of gas and water. They occur at low temperature and highpressure conditions. These hydrate plugs cost the oil and gas industry significant amounts in revenue cuts and is a major problem for the industry. There are many preventive measures that can be implemented such as inhibitors to avoid the formation of hydrates. This paper aims to highlight the different measures and analyse their effectiveness for hydrate-plug prevention. One such method for the reduction of hydrate formation is the removal of existing hydrates by using different types of inhibitors. The most common method of hydrate prevention in deep-water developments is injection of thermodynamic inhibitors, which include methanol, glycols, and others. If hydrate prevention methods are unsuitable and hydrates are liable to form, the process of dehydration can be used wherein the water gets removed from the gas stream. Electrical heating is also used as a way to dehydrate the pipe. This paper compares a variety of inhibitors and various hydrate preventive methods and discusses their influence in the mitigation of hydrate formation in gas pipelines.

Development of a consequence-based decision-making framework for natural gas transmission pipeline

Development of a consequence-based decision-making framework for natural gas transmission pipeline

Insights into the perforation of the L360M pipeline in the liquefied natural gas transmission process

The cause of the failure of a liquefied natural gas transmission pipeline that has experienced internal corrosion during the water injection, idle and transmission processes, is fully investigated in this work. There are two significant features of pipeline failure, namely, the perforated location at the 6o’clock position and under scales deposit. Hence, the 2# leakage point and corrosion scale character were investigated in this research. The perforation of pipeline is attributed to three consecutive stages: (a)corrosion scale formation and pitting initiated, (b) the thickening of the scales and pitting propagation, and (c) the deposit of scales and pitting growth. Among of that, the deposited scales accelerate the pits growth during the LNG transmission process. Meanwhile, the premise cause of the failure was the scales deposit and pits initiation, pits propagation caused in water injection and idle processes.

Comprehensive numerical analyses of the seismic performance of natural gas pipelines crossing earthquake faults

Coseismic fault displacement has been recognized as a critical hazard to natural gas transmission pipelines crossing earthquake faults. Prior studies on pipeline response to fault displacement were limited to specific types of pipes and faults, which were indeed constrained by the computational resources. As part of an effort to develop a Bayesian model to relate ground displacement in pipeline strain, we analyze more than 217,000 finite element models of gas pipeline fault crossings, which consider the pipe–soil interactions with both pipe and soil material nonlinearities. Such an enormous number of simulations are selected based on comprehensive sensitivity analyses and cover the most important parameters of gas pipelines in terms of combinations of the following: (1) pipe dimensions and materials, (2) soil properties, and (3) style of faulting and characteristics of fault movements. We devise an automated workflow for input generation–simulation submission–output extraction, by utilizing more than 10,000 cores high-performance super-computing facilities. Finally, we examine the pipeline response for every combination, by investigating the evolution of maximum compressive and tensile strains in the axial direction along the pipe over the fault displacement. These numerical analyses resulted in a comprehensive database of pipeline fragilities crossing earthquake fault for seismic risk analysis of natural gas infrastructure in an earthquake region.

Failure of a Natural Gas Transmission Pipeline—Material or Sabotage

Failure of a Natural Gas Transmission Pipeline—Material or Sabotage

Prospects of utilizing unloaded parts of natural gas transmission pipelines in technologies of carbon dioxide capture and storage

The gas transportation system (GTS) of Ukraine is one of the most complex systems of main gas pipelines in Eurasia. Prospects for the use of unloaded parts of transportation and storage of CO2 in carbon capture and storage (CCS) systems are considered. The mathematical model for estimating the main parameters of the process of filling the pipeline with carbon dioxide with their subsequent optimization is proposed. According to the simulation results, the regularities of the pipeline filling process are established.