Low temperature and high pressure conditions in deep water wells and sub-sea pipelines favour the formation of gas clathrate hydrates which is very undesirable during oil and gas industries operation. The management of hydrate formation and plugging risk is essential for the flow assurance in the oil and gas production. This study aims to show how the hydrate management in the deepwater gas well testing operations in the South China Sea can be optimized. As a result of the low temperature and the high pressure in the vertical 3860 meter-tubing, hydrate would form in the tubing during well testing operations. To prevent the formation or plugging of hydrate, three hydrate management strategies are investigated including thermodynamic inhibitor injection, hydrate slurry flow technology and thermodynamic inhibitor integrated with kinetic hydrate inhibitor. The first method, injecting considerable amount of thermodynamic inhibitor (Mono Ethylene Glycol, MEG) is also the most commonly used method to prevent hydrate formation. Thermodynamic hydrate inhibitor tracking is utilized to obtain the distribution of MEG along the pipeline. Optimal dosage of MEG is calculated through further analysis. The second method, hydrate slurry flow technology is applied to the gas well. Low dosage hydrate inhibitor of antiagglomerate is added into the flow system to prevent the aggregation of hydrate particles after hydrate formation. Pressure Drop Ratio (PDR) is defined to denote the hydrate blockage risk margin. The third method is a recently proposed hydrate risk management strategy which prevents the hydrate formation by addition of Poly-N-VinylCaprolactam (PVCap) as a kinetic hydrate inhibitor (KHI). The delayed effect of PVCap on the hydrate formation induction time ensures that hydrates do not form in the pipe. This method is effective in reducing the injection amount of inhibitor. The problems of the three hydrate management strategies which should be paid attention to in industrial application are analyzed. This work promotes the understanding of hydrate management strategy and provides guidance for hydrate management optimization in oil and gas industry.

Construction blasting was proposed as a technique to create a trench for a new pipeline within the right-of-way (ROW) of an existing vintage pipeline where soil conditions consisted primarily of rock. Several field experiments were conducted to assess the potential loading conditions that the vintage pipeline could experience due to various blasting configurations as part of the nearby construction process. Two test pipe segments were constructed from segments removed from the vintage pipeline for use in these experiments. Each test segment contained two vintage bell-bell chill ring girth welds (GW) and were pressurized to operating conditions of the vintage pipeline for the duration of all blasting. Groups of eight resistive strain gages were bonded around the exterior surface of three distinct locations on each test segment. The three locations include one pipe body location and each of the two welds on each segment. Four separate experiments were conducted with each experiment focusing on a unique combination of trench backfill material, compaction level and separation distance from the test pipe segments and the explosive charges. The primary objective throughout these four experiments was to monitor and record the behavior of buried test pipe sections due to nearby blasting activities. Long range 3-dimentional (3D) laser scanning equipment was used to track movement of each test segment from test to test. High-speed video equipment was also employed to capture each blast. The high-speed video provided additional details on the blast energy transfer, verification of individual charge initiation as well as pipeline test segment movement where each pipeline segment was exposed. Peak particle velocity measurements were taken during each test blast. Strain data collected during each test was used to assess potential damage to the vintage pipeline test segments as a result of blasting. The combined information collected from the in-field testing showed that elevated strains and stresses may be observed during blasting activities near pipelines.

There has been a number of unexpected girth weld failures in newly constructed pipelines. Girth weld failures have also been observed in pre-service hydrostatic testing. Post-incident investigations indicated that the pipes met the requirements of industry standards, such as API 5L. The welds were qualified per accepted industry standards, such as API 1104. The field girth welding was performed, inspected, and accepted per industry standards, such as API 1104. Some of the traditional causes of girth weld failures, such as hydrogen cracks and high-low misalignment, were not a factor in these incidents. This paper starts with a review of the recent girth weld incidents. A few key features of a failed weld and their implications are examined. The characteristics of the recent failures is summarized, and the major contributing factors known to date are given. Some of the options to prevent future failures include (1) changes to the tensile properties of the pipes and enhanced hardenability, (2) welding options aimed at increasing the weld strength and minimizing heat-affected zone (HAZ) softening, and (3) reduction of stresses on girth welds. This paper focuses on the first two options. The trends of chemical composition and tensile properties of linepipe are reviewed. The potential contribution of these trends to the girth weld incidents is examined. Possible changes to the linepipe properties and necessary updates in the testing and qualification requirements of the linepipes are provided. Welding options beneficial to enhanced girth weld strain capacity are discussed. Possible revisions to welding procedure qualification requirements, aimed at achieving a minimum level of strain tolerance/capacity, are proposed. The application of previously developed tools in estimating the propensity of HAZ softening is reviewed.

The offshore oil and gas industry has seen a continual trend of conservatism in design for applications where a high level of strain is expected during the installation phase, leading to a tightening of the acceptable mechanical property performance of the linepipe. This is especially true with regards to longitudinal tensile properties in the strained and aged condition. Due to the expected change in data seen throughout previous projects, are the tightening expectations realistic for the manufacturers and cost effective for the client? The current condition that is widely accepted for the release of pipes suitable for high strain events is straining and ageing. However is this appropriate given that pipes are coated (aged), installed (strained) then left over time (aged)? These questions will be investigated through a series of tests and data analysis. For this project a conventional ageing as per the standard and a coating simulation were used, with all test pieces having either 0% or 1% applied strain. The test pieces for this project were tested in one of seven conditions; • As manufactured • Aged (at 200°C/5min or 250°C/1hr) • Strained and aged (1% strain applied then aged at 200°C/5min or 250°C/1hr) • Aged and strained (aged at 200°C/5min or 250°C/1hr then 1% strain applied) To ensure a direct comparison in the data the comparable test pieces were taken from the same circumferential position on the pipe. All testing for this project was carried out on material of a similar composition and future development of this work will comprise of documenting the effect on different microstructures, t/D ratios and levels of strain. It was clear from the project that changing the conditions used had an impact on the results. This could have implications for the industry in the future and has set up a scheme of development following on from this project to gain a greater understanding.

Excavation damage is one of the top causes of incidents in both the transmission and distribution pipeline sectors. Damage caused from insufficient notification of one-call centers or careless digging near gas pipelines can potentially result in property damage, significant injury, and/or loss of life. Pacific Gas and Electric Company (PG&E) and the Gas Technology Institute (GTI) have developed the framework for an Excavation Encroachment Notification (EEN) system to support damage prevention efforts to reduce damage from excavation activity. The research was funded by the California Energy Commission (CEC) and Operations Technology Development (OTD). The system utilizes real-time Geographic Information System (GIS) technology and cellular-connected location and motion sensors placed on excavation equipment. Controlled and field-based testing and training of machine learning algorithms were conducted to aid in characterization of excavation equipment. Additionally, a GIS system populated with pipeline information allowed operators of excavation equipment and utilities to receive an alarm and indication when equipment is adjacent to or excavating in the vicinity of a gas pipeline. More broadly, the utility stakeholder has increased situational awareness of excavation activities within its service territory with access to the real-time activity of excavation equipment through a mobile-compatible dashboard, reducing excavation damage risk and improving safety. Lastly, the project offers historical data archiving for data analysis and trend identification.

To assess the integrity of pipelines containing cracks, single edge-notched tension (SENT) specimens in the end-clamped conditions have been widely adopted in the oil and gas industry to measure fracture toughness or resistance curves in terms of the J-integral or crack-tip opening displacement (CTOD). The CTOD toughness is often utilized in the strain-based design, and thus its measurement is important to the pipeline industry. Two types of CTOD-R curve test methods are available for a single SENT specimen test: J-conversion method and double clip gage (DCG) measurement method. However, these two CTOD test methods often determine different R-curves, leading to a long-running dispute. To better understand the difference of the two CTOD test methods as well as the effect of material strain hardening rate on CTOD-R curves, a set of clamped SENT specimens are tested for two ductile steels with a high strain hardening rate (A36) and a low strain hardening rate (X80). Experimental R-curves are analyzed for the two steels, and results show that the CTOD-R curves determined using the J-conversion method and the DCG method are comparable for X80, but significantly different for A36. To study the root cause, elastic-plastic finite element analyses are performed for the SENT specimens of A36 and X80. With the numerical results of J-integral and CTOD, different CTOD estimation methods are evaluated, and the root causes of their differences are analyzed. On this basis, discussions are made on how to use the two types of CTOD-R curves in the pipeline design and integrity assessment.

Carbon steel piping can be exposed to environments that contain various chemical and organic elements that induce corrosion and cracking events. This can lead to the loss of fluid into surrounding sensitive and remote environments. To minimize this inherent risk, various coating technologies have been utilized over the years in industry. These coatings typically suffer from complex application methods, high application cost, and vulnerabilities to environmental effects such as mechanical damage and cathodic disbondment. To overcome these challenges, a novel epoxy based composite coating that utilizes the properties of various nano-particulates such as graphene nanoplatelets (GnP), multi-walled carbon nanotubes (MWCNTs), chitosan, and hBN (Hexagonal boron nitride) is developed. These nanoparticles create a nano-scale “brick and mortar” type effect that is analogous to various natural structures such as the abalone shell (nacre). These nano-structures also enhance coating performance by increasing mechanical strength and anti-bacterial properties while simultaneously decreasing gas permeability. This performance enhancement serves to reduce overall corrosion-induced disbondment area. The dispersion of nanoparticles is verified using various microscopy methods such as scanning election microscopy and an optical 3D profilometer. To confirm the role of nanoparticles in the epoxy composite, the samples undergo rigorous testing to determine both mechanical properties as well as the feasibility of coating application, in particular, for use on girth welds. Using a dynamic mechanical analysis (DMA), the material strength of each combination of nanocomposites is tested and used to determine the glass transition temperature. The testing also includes abrasion, and both long-term mechanical and thermal behaviors of the coating. To test the feasibility of the coating, cathodic protection tests in an accelerated corrosive environment, and gas permeability tests are carried out. The results show that the composite coating made from these nanomaterials had a decrease in cathodic disbondment area and gas permeability and an increase the glass transition temperature and scratch resistance. Therefore, the nanocomposite coatings are found to be a significant improvement over standard epoxy-based coating.

An extensive experimental program to characterize the Charpy-V-notch (CVN) impact toughness of ten contemporary Electric Welded (EW) pipes was recently completed to establish a database to support the revision of the EW seam weld Charpy toughness testing requirements in Canadian Standards Association (CSA) Z245.1-14. The toughness in these welds is lowest at or near the weld bond line (BL) within a narrow zone ±≈0.5 mm wide. It is feasible and desirable to position the BL notch to a precision to match this width, i.e. ±0.5 mm from the BL. In this paper, typical results of microstructure, micro-hardness, CVN toughness (i.e. absorbed energy) as a function of temperature and notch location, and fractography will be presented. CVN absorbed energy requirements for EW welds in CSA Z245.1 have been determined using a failure assessment diagram (FAD) procedure. The values of required CVN estimated from the FAD are close to those specified in CSA Z245.1-14 but are higher than the specification in CSA Z245.1-18.

An intensive effort was undertaken to understand the fracture behavior in a recent TCPL pipe burst test. The 48-inch diameter X80 pipe was buried in soil at the Spadeadam Test Site, but since it was desired to have the gas and pipe cooled to the minimum service conditions of −5°C, a 50-mm thick polyurethane foam (PUF) insulation was sprayed on the entire pipe test section. This was a reasonable precaution since freezing of a high water content soil around a large-diameter pipe burst test can require significant cooling capacity or a much longer duration to get to the burst test conditions. In this burst test, the crack propagated much farther than anticipated by traditional predictive approaches such as using Charpy energy to predict the minimum ductile fracture arrest toughness, assuming that soil backfill conditions existed. To explore this burst test behavior, two aspects were examined. The first was an assessment of the properties of the PUF insulation relative to the soil properties, and the second was the toughness evaluated by instrumented DWTT testing. The 50-mm thickness of the PUF insulation corresponded to about 8.3% of the pipe radius. In past loose-fitting steel sleeve crack arrestor burst tests, if the radial clearance was greater than 5.5% of the pipe, then a ductile fracture propagated under the arrestor regardless of its length with no change in speed. Hence if the PUF could be easily compressed, then the pipe in this burst test would behave as if it was in a non-backfilled condition. Non-backfilled pipe requires much higher toughness to arrest a ductile fracture. So perhaps the pipe in this burst test condition acted somewhere between non-backfilled and backfilled conditions — an aspect that might need a much more comprehensive computational model to better assess. Additionally to assess how material toughness played a role in this burst test, detailed instrumented toughness testing was conducted on material taken from several of the pipe lengths in the burst test. The evaluations of the Charpy energy to the DWTT energy suggested that one of the pipe materials may have behaved more like an X100 steel than an X80 steel. Correction factors on the predicted arrest toughness are well known to be needed for the Battelle Two Curve method (BTCM) when applied to X80 and X100 pipes. However, even with these corrections on the Charpy energy, arrest was predicted with soil backfill in several cases where in the actual test, the crack propagated through the pipes. Hence toughness corrections by themselves did not explain the test results. Additional calculations were then done assuming a non-backfilled condition (as suggested from the PUF property evaluation) along with the appropriate grade effect correction from the DWTT testing, and propagation was properly predicted in each case consistently with the burst test. So the fracture behavior in this burst test was somewhere between those of backfilled and non-backfilled pipe. As a result of this investigation it appears that the PUF insulation played an important role in crack arrest behavior, and because of its presence may have required much higher toughness than was actually needed for the actual service conditions of pipe buried in actual soil backfill.

For almost 30 years composite repair technologies have been used to reinforce high pressure gas and liquid pipeline transmission systems around the world. The backbone of this research has been full-scale testing, aimed at evaluating the reinforcement of anomalies including, corrosion, dents, vintage girth welds, and wrinkle bends. Also included have been the assessment of reinforced pipe geometries including welded branch connections, elbows, and tees. Organizations sponsoring these research efforts have included the Pipeline Research Council International, regulatory agencies, pipeline operators, and composite repair manufacturers. Many of these efforts have involved Joint Industry Programs; to date more than 15 different industry-sponsored programs and independent research efforts have been conducted involving more than 1,000 full-scale destructive tests. The aim of this paper is to provide for the pipeline industry an updated perspective on research associated with composite repair technologies. Because of the continuous advance in both composite technology and research programs to evaluate their effectiveness, it is essential that updated information be provided to industry to minimize the likelihood for conducting research efforts that have already been addressed. To provide readers with useful information, the authors will include multiple case studies that include the reinforcement of dents, wrinkle bends, welded branch connections, and planar defects.

There are many options available to pipeline operators when addressing anomalies or integrity threats. Repairing integrity threats requires an understanding of both the anomaly to be repaired, and the repair system itself. This can be challenging as pipeline repair systems come in a wide variety of materials, application techniques, and designs. Operators have similar challenges when performing maintenance activities on operating pipelines. Maintenance activities can take many different forms and often involve welding or other high temperature processes on the outside pipe surface. These processes can result in elevated temperatures on the inside surface of the pipeline and must be seriously considered before undertaking to ensure the safety of personnel performing the tasks and to protect the integrity of the pipeline. This study aimed to provide a greater understanding of pipeline reinforcement systems and maintenance activities as they relate specifically to thin-walled pipelines. To evaluate systems reinforcing thin-wall pipes, five different repair systems were investigated using 12.75-inch × 0.219-inch, Gr. X65 pipe that had been removed from service. The systems included a Type B steel sleeve, an epoxy-filled, interference fit, Type A steel sleeve, a hybrid steel sleeve-fiberglass based composite repair system, epoxy-filled oversized Type A steel sleeves, and a rigid coil, pre-cured, fiberglass-based composite repair system. Each system was used to reinforce a simulated 50% wall loss anomaly and was installed with the pipe samples maintained at an internal pressure equal to 33% of the pipe’s specified minimum yield strength (SMYS). The samples underwent pressure cycling and hydrostatic testing while strains in the simulated wall loss region were continually monitored. As a final step, the samples were burst tested. Monitoring of strain gages installed in the simulated wall loss anomaly allowed for comparisons to be made between the tested repair systems. It was observed that the recorded strain magnitudes and strain ranges were higher in some samples than others during testing. This allowed the systems to be ranked according to the recorded strains. Although differences were observed in the recorded strains, burst testing showed that all reinforcement systems were able to force failure to the base pipe outside of the simulated wall loss region. Maintenance procedures were also evaluated to identify those that could produce unacceptable temperatures on the inside surface of the thin-wall pipe. The maintenance procedures included installation of Type A steel sleeves (non-pressure containing), Type B steel sleeves (pressure containing), cad welds, and pin brazing cathodic protection (CP) test leads. Temperatures were monitored on the internal pipe surface using thermocouples and an infrared (IR) camera while the maintenance procedures were being performed. An internal surface temperature of 500 °F (260 °C) was set as the threshold for suitability. Monitoring of the Type B steel sleeve installation showed temperatures on the inside surface of the pipe that exceeded 1,200 °F (648 °C) when performing the circumferential weld at each end of the steel sleeve. A maximum temperature of 280 °F (137 °C) was recorded when making the longitudinal welds that included a backing strip. For the application being considered, this indicated that Type A steel sleeves (longitudinal welds only) could be installed within the required temperature limits. A maximum internal temperature of 936 °F (502 °C) was recorded during cad-welding. Pin-brazing was slightly lower, but also exceeded the 500 °F threshold. This testing confirmed that the installation of Type B steel sleeves, cad welding, or pin brazing should receive scrutiny before being performed on operating thin-wall pipelines.

In the oil industry liquid pipelines are very important for the transport of liquids, particularly in long offshore pipelines. The operation of these oil pipelines is susceptible to the occurrence of leaks in the system. Localizing a leak in a very long oil pipeline is an important piece of information that needs to be obtained before mitigating actions can be taken. These pipelines are usually subject to the temperature gradients that exist in the bottom of the ocean, and the resulting heat transfer process may lead to wax formation and deposition. The single-phase flow that occurs in this type of offshore pipeline that presents one leak point and suffers the effects of an external temperature gradient is numerically simulated in this paper. We consider a one-dimensional mathematical model that includes conservation equations of mass, momentum and energy, and its associated numerical method to calculate the transient liquid flow inside the pipeline. We are particularly interested in testing a leak localization model based upon the intersection of the hydraulic grade lines emanating from the pipeline ends under the influence of a non-zero temperature distribution. This paper proposes to compare the results for a non-isothermal flow with the corresponding isothermal flow to study the influence of the temperature distribution upon the leak localization strategy. The flow that develops along the entire pipeline, upstream and downstream of the leak, strongly affects the pressure gradient and has a significant influence on the location of the leak. Our numerical simulations show results that allow the model sensitivity to be studied by changing the leak magnitude, for a given leak position. From this analysis, we may observe how these parameters affect the pressure gradients along the pipeline that develop upstream and downstream of the leak and the model’s ability to predict the leak location.

This paper presents the results of the testing of an oil-on-water leak detection technology for isolated locations without power or communications infrastructure. A special attention was paid to the ability of the sensors to detect hydrocarbon leaks under freezing conditions, with thick ice formed on the surface of the water. A viable solution for remote locations and large water crossings needs ultra low-power solution and/or cyclic operation. The technology evaluated was a fully passive impedance polymer-absorption sensor (PAS) featuring “zero-power” consumption. This technology also provides an additional advantage, “an event memory”, and is perfectly suitable for cyclic operation for detecting moving oil stains. In October 2017 three polymer-absorption sensors of different lengths were placed in outdoor location in Ontario, Canada for long-term testing of reliability in freezing conditions. The sensors were connected to cellular modem for generating alerts. Another battery of three sensors of same lengths was installed in outdoor testing facility near Ottawa, ON, Canada and connected to real-time data acquisition equipment. A preliminary series of leak tests performed in October/November 2017 confirmed the initial assumptions of excellent sensitivity of the hydrocarbon oil-on-water detection based on polymer absorption. The average power consumption of the sensor excitation and its measurement frontend during the first two months of testing were found to be extremely low, a fraction of the power needed for the wireless modem itself. The leak tests were extended to oil under ice detection performed with 5 North-American crude oils and with 3 refined products from Mid-December 2017 to Mid-February 2018. The sensitivity, the sensor excitation/measurement front end power consumption, and the reliability of the sensors were assessed at freezing temperatures, with thickness of the ice comprised between 80 and 100 mm. The paper also presents the availability of stand-alone communication equipment suitable for integrating oil-on-water sensors, as well the energy harvesting or energy storage technologies for different climatic conditions.

Tensile testing on large diameter line pipe is generally done using strap samples obtained in the transverse to pipe axis (TPA) orientation of a pipe. The strap samples are then flattened and machined prior to testing. Although the standardized tensile testing is well documented, the variability in the reported TPA tensile properties of the same material tested within a lab or at different labs has always been an issue. Recent work conducted at EVRAZ NA research lab has identified flattening as the main source of the variability in reported yield strength (YS) values for line pipe. The lack of a standard procedure for flattening TPA strap samples is a major obstacle to obtaining consistent results. Therefore, the main objective of this current study was to establish a standardized flattening procedure for TPA strap samples. Both finite element analysis (FEA) and experimental approaches were adopted. Various flattening methods and fixtures were studied. Extensive flattening experiments were conducted on TPA samples from different line pipe products. Results showed that the spring back after flattening in a TPA sample is different for pipes with different gauge and grades. It was established that consistent flattening can be achieved using appropriate fixtures for differerent ranges of tubular products defined by grade, diameter and gauges. Evaluation of the flattening fixture designs and experimental results are discussed in this paper.

To guarantee the structural integrity of oil and gas transporting pipelines, a detailed analysis of the pipe’s structural response has to be performed. This is of particular importance for offshore applications. As large scale testing is costly and time consuming, one often relies on FE (Finite Element) modelling to accomplish, at least, part of this task. Properties that typically need to be evaluated are compressive strain capacity, collapse resistance and ovalization during reel-lay installation. Furthermore, it can be assumed that those properties are influenced by the pipe forming process, as pipe forming will change the mechanical properties and the level of anisotropy and will modify/introduce residual stresses. Therefore, a first logical step is to simulate pipe forming before evaluating the pipe’s structural performance, to account for these effects. The reliability of FE simulations largely depends on the capability of the constitutive model to accurately describe the mechanical behaviour of the material being studied. Most commercial FE codes only offer combined kinematic-isotropic hardening models. Those models cannot capture the so-called cross-hardening effect and can therefore not predict the evolution of anisotropy during pipe forming. The present paper discusses the implementation and calibration of a more advanced constitutive model, more specifically the Levkovitch-Svendsen model, which accounts for isotropic, kinematic and distortional hardening. The model was implemented in Abaqus/Implicit through a UMAT user subroutine. An inverse modelling approach was applied to calibrate the constitutive model, whereby an extensive set of mechanical tests, involving cyclic tension-compression tests and tests with changing strain paths, was conducted. To assess the model’s performance, it was used in two case studies. The first study focused on the evolution of mechanical properties during spiral pipe forming. The results show that the Levkovitch-Svendsen model allows prediction of the properties in both the transverse and longitudinal direction on pipe. When applying a kinematic-isotropic hardening law only, the properties in the longitudinal direction are significantly underestimated. In the second study, different hardening models were used to predict the evolution of ovality during reel-lay installation. It was observed that the predictions made with the Levkovitch-Svendsen model were much closer to the experimental values than the results obtained by means of a kinematic-isotropic hardening model.

The CO2SAFE-ARREST joint industry project (JIP) aims to (1) investigate the fracture propagation and arrest characteristics of steel pipelines carrying anthropogenic CO 2 , and (2) to investigate the dispersion of CO 2 following its release into the atmosphere. The project is supported by two full-scale burst tests, each based on a layout of eight X65 grade 24″ line pipes filled with a dense-phase CO 2 -N 2 mixture. The tests were conducted over the 2017–2018 period at the DNV GL testing site at Spadeadam, UK. An overview of both the CO2SAFE-ARREST JIP and the first full-scale burst test is provided in a companion paper (IPC2018-78517). The dispersion aspect is covered in another companion paper (IPC2018-78530). This paper presents the material properties, the design layout and the results of the first full-scale burst test. Material characterisation of the pipes available to the project and the motivation leading to the design of the layout are first presented. Six pipes had a nominal wall thickness of 13.5 mm and the remaining two pipes had a nominal wall thickness of 14.5 mm. Laboratory testing was conducted on the material at the end of each pipe section. The testing consisted of Charpy impact and Drop Weight Tear tests, capturing the upper shelf fracture energy, load-displacement curves and an assessment of the fracture surfaces. Charpy and Drop Weight Tear test energies as well as strength data are provided. The layout reflects the research focus of the project with both conventional and less conventional pipe arrangements. The test was primarily designed around 13.5 mm nominal wall thickness pipes with a 1m depth backfill and laid East-West. The design was telescopic and introduced an asymmetry with respect to the mid-point by arranging pipe sections with increasing Charpy toughness on one side and increasing yield strength on the opposite side. The fracture was initiated at half-length, across the girth weld between the ‘west’ and ‘east’ initiation pipes. A running ductile fracture ensued, followed by an arrest in the third pipe on either side of the test section. Experimental data relevant to fracture velocity, decompression wave speed of the CO 2 -N 2 mixture and pressure at the crack tip are presented. The discussion is driven from the perspective of traditional running ductile fracture control technology applied to dense-phase CO 2 carrying pipelines. Emphasis is put on the analysis of the fracture velocity and transient pressure data relative to the properties of the material and CO 2 mixture. The limitations of the Battelle Two-Curve Method (BTCM) traditionally used in the analysis of running ductile fracture are discussed. The design of this test was different from that used in the three full-scale burst tests conducted as part of the COOLTRANS project. The conclusions drawn here support those from the COOLTRANS project and apply to larger D/t ratios. The first CO2SAFE-ARREST test provides additional evidence that the original Battelle Two-Curve Model is not applicable to dense-phase CO 2 carrying pipelines. A shift in prediction tool technology is called for.

Double submerged arc welding is an efficient process used during the production of longitudinally-welded large-diameter pipes. It is well known that the associated high heat input has a negative influence on the toughness of the heat-affected zone (HAZ). The toughness drop is related to changes in the HAZ microstructure compared to the base metal. The austenite grain size increases significantly and larger carbon-rich martensite/austenite particles (M/A-particles) are formed within a coarse bainitic matrix during the phase transformation compared to the as-rolled base material. The exact relationship between the microstructure, the processing conditions, base metal composition and the weld metal are at the focus of attention of materials development efforts at EUROPIPE and Salzgitter Mannesmann Forschung GmbH (SZMF). In the present study, scanning electron microscopy (SEM) and electron backscatter diffraction (EBSD) were used to investigate the HAZ of X70 large-diameter pipe material as well as tested Charpy specimens from the same material. Secondary cracks in the direct vicinity of the primary fracture surface of tested Charpy specimens from the HAZ were analyzed by EBSD and SEM to investigate the damage mechanism in detail. It was found that these cracks originate at M/A-particles and that the dominant crack path depends on the crystallographic orientation of the surrounding matrix. The analysis of several EBSD measurements and a 3D-analysis of the propagation direction of the crack showed that secondary cracks frequently propagate parallel to {100} and rarely along {110}-planes. It is known from literature that these are preferred cleavage planes in ferritic steels. The SEM analysis performed in the HAZ of the investigated steel showed that the volume fraction of elongated M/A-particles is elevated close to the fusion line and decreases within the first few hundred micrometers distance from the fusion line. The EBSD measurements illustrate that the geometrically necessary dislocation density is significantly increased in the neighborhood of M/A-particles. This indicates that the bainitic matrix is work-hardened around the M/A-particles during testing and is therefore more prone to the formation of microcracks than other surrounding regions.

Toughness testing of the heat affected zone (HAZ) of longitudinal welds is increasingly often required in pipeline standards and specifications. This includes simple tests such as the Charpy impact test that was designed to serve as quality test as well as enhanced methods including crack tip opening displacement (CTOD) tests that are necessary to conduct an engineering critical assessment (ECA). If occasional low toughness values are observed, the question turns towards assessing the impact of such numbers and how representative they are of the behavior of a pipe in service. The significance of low toughness values measured in laboratory testing can be judged on basis of ring expansion and hydraulic burst tests. The current study summarises an extensive test series to quantify the toughness of submerged arc welds (SAW) obtained by different test methods. The tested pipes cover a wide range of material including medium strength X70 up to high strength X100. Their welds are characterized in terms of fracture toughness properties with single edge notch tension (SENT) and single edge notch bending (SENB) tests. Different constraint levels are obtained within each series by introducing notches of standard depth as well as shallow notches. Structural behavior is characterized with burst tests as well as ring expansion tests containing notches in the longitudinal weld. The experimental results are assessed within dedicated finite element studies. The assessment is conducted for pipes serving as pressure containment, thus having circumferential stress resulting from internal pressure. Based on the results achieved the conclusion can be drawn that the standard route including high constraint CTOD leads to overly conservative results concerning the integrity of longitudinal welds. A better representation of structural behavior is observed in ring expansion tests.

In-ditch/in-service characterization of pipelines using nondestructive evaluation (NDE) can provide valuable data for confirming operating pressure and qualifying pipelines for transporting natural gas of different quality or gas mixture, as well as for determining repair criteria for integrity management programs. This is especially relevant for vintage pipelines that may not have material test reports (MTR) available, and for aging infrastructure that have been subjected to suspected or unknown integrity threats. However, measurement of material fracture toughness currently requires the removal of large samples for laboratory testing, such as compact tension (CT) fracture testing or Charpy impact testing. The present work introduces a new concept, the Nondestructive Toughness Tester (NDTT), that provides a NDE solution for measuring the fracture toughness of pipeline steel in a superficial layer of material (∼0.005 inches). The NDTT uses a specially designed wedge-shaped stylus to generate a Mode I tensile loading that results in a ductile fracture response. NDTT tests are performed in multiple orientations on 8 different pipeline steel samples covering 3 different grades to compare the NDTT material response with the fracture toughness measurements from laboratory CT specimens. Analysis of these results indicate that the height of a fractured ligament that remains on the sample surface after NDTT testing exhibits a linear relationship with traditional CT J-integral measurements normalized by its yield strength. This type of behavior is analogous to the crack-tip-opening-displacement (CTOD) calculated through elastic-plastic fracture mechanics. Tests conducted on the pipe outer diameter and in the longitudinal direction near the pipe mid-wall indicate that the NDTT can measure differences in fracture toughness for different crack orientations. Furthermore, the results show that outer diameter tests provide a conservative estimate of the overall steel fracture toughness. These observations indicate that the NDTT is a viable method for assessing toughness properties of steel materials. Additional research is required to further refine the implementation of the NDTT concept and understand the relationship with laboratory test results on pipe cutouts, but the progress is already a significant step towards obtaining additional material toughness data for integrity management.

High pH Stress Corrosion Cracking (HpHSCC) is a significant threat to the buried pipelines, which are protected through simultaneous coating and cathodic protection strategies. In the past decades, extensive research has been devoted to assessing the influence of environmental and metallurgical factors on the susceptibility to HpHSCC. With reference to mechanical factors, previous studies employed either slow strain rate or constant amplitude testing methods. However, the pressure fluctuation data extracted from pipeline operations has indicated that pipelines experience highly variable amplitude loading conditions during their service. Accordingly, an important consideration in managing HpHSCC is load interaction. Statistics show a higher probability of HpHSCC failures within the 30 km downstream from pump/compressor stations where the pipeline steels experience elevated service temperatures, with incipient higher susceptibility to HpHSCC. However, the pipeline sections within the 30 km downstream from pump/compressor stations also experience the underload-type of pressure fluctuations that feature a maximum pressure close to the design limit, frequent and large amplitudes of depressurization, resulting in low stress ratio, R (minimum stress/maximum stress), and many smaller pressure fluctuations (minor cycles) with R ratio closer to +1.0. It has been well characterized that the underload-minor-cycle-type of pressure fluctuations has the significant acceleration effect on crack growth rates in near-neutral pH (NNpH) environments. However, the effect of the underload-type of pressure schemes on HpHSCC crack growth has not been well developed. In this research work, a cathodically protected X65 steel specimen in the developed high pH solution, composed of 1N Na 2 CO 3 and 1N NaHCO 3 , was subjected to different loading conditions. These loading waveforms simulate underload cycles (R = 0.5), minor cycles (R = 0.9) and variable amplitudes consisting of both underload and minor cycles, respectively. The HpHSCC test results showed that the highest and lowest crack growth rates were obtained in high and low R ratio constant amplitude loading conditions, respectively. Furthermore, an intermediate crack growth rate was obtained under variable amplitude loading condition. These results indicate that the underload cycles retard crack growth rate in high pH environments.