Failure Along Spiral Welds in Gas Pipeline

A 16 km. long, 18” Gas pipeline (HP055) was in service to transport High Pressure Gas from an oil gathering center in West Kuwait (WK) area since 2001. The Pipeline carried wet sour gas. It was inspected in 2008 using high resolution MFL-ILI tool. No significant corrosion was found. In late 2012, a leak developed in the pipeline. The leak was due to a crack along a spiral weld on the bottom. Inspection during repairs revealed severe internal pitting on the bottom. The pipeline continued to leak several times in the next year, eventually resulting in decommissioning of the pipeline. Another ILI could not be carried out due to operational constraints and frequent leaks. The Pipeline was critical in the operation of the oil gathering center, and the loss of it severally affected the gas/oil export target and the flaring reduction commitment. An internal failure investigation was inconclusive, though indicating possibility of sulfide stress cracking. The failure investigation work was then entrusted to TWI, UK. A failed section of the pipeline was sent to their facilities and various tests including Chemical analysis, tensile test, residual stress measurement, SSC/HIC test, microstructure analysis, and analysis of corrosion products were carried out. The outcome of the tests and conclusion was very surprising. This paper describes in detail the leaks, inspection of leak locations, and the failure investigation findings and conclusions.

Graded EMAT Performance Specification Validated in Blind Test

The management of Stress Corrosion Cracking (SCC) represents one of the challenges for pipeline operating companies with pipelines potentially susceptible to SCC. In order to help better support the management of SCC, a graded performance specification for the high-resolution Electro-Magnetic Acoustical Transducer (EMAT) In-Line Inspection (ILI) technology is derived which provides higher levels of confidence for detection of crack-field anomalies with critical dimensions. This paper presents the process used to derive the graded performance values for the EMAT ILI technology with regard to SCC. The process covers the Probability of Detection (POD) and Probability of Identification (POI). A blind test was carried out to derive the graded performance specification. Test data set was compiled comprising EMAT data for several joints containing relevant anomalies and neighboring joints, some containing additional shallow SCC. These joints had been dug based on EMAT ILI data and all of the joints were evaluated with 360 degree Non-Destructive Examination (NDE) followed by destructive testing. For each target joint with relevant anomalies to be assessed, four additional joints were added in random order to generate a realistic density and distribution of anomalies. Furthermore, pipe joints with non-crack like anomalies, as well as pipe joints with mixed populations were included in the blind test data set to ensure a realistic feature population and to assess POI without side effects of a weighed feature population inside set of composed ILI data. The data set was then evaluated by multiple analysts and result from each analyst were evaluated and utilized to derive the POD and POI values for the graded specification. In addition, the full process of data analysis including team lead review was carried out for one of the analysts for comparison to the individual analyst results. Anomaly dimensions were compared against the true population to derive the POD and POI values. Furthermore, length and depth sizing performance was assessed.

Application of Load Sequence to Control Crack Growth in Steel Pipelines Under Near Neutral pH SCC

Pipelines are designed to operate below a maximum operating pressure in service. However, there are pressure fluctuations during operation. The presence of pressure fluctuations creates a drive for crack growth in steel pipes. In order to prevent catastrophic failure of pipelines, there is need for better understanding of the contribution of pressure fluctuations to crack growth rate in steel pipelines. Analysis of pressure fluctuation data in oil and gas pipelines shows that there are different types of fluctuations in a pipe due to friction loss with distance from the pump or compressor station. All these fluctuation types show a form of variable amplitude loading classified in this research as underload, mean load and overload. Studies of some structural systems shows that underload can cause acceleration of crack growth while retardation of crack growth is observed after an overload. This research aims to apply pressure fluctuations to manage integrity of steel pipelines through a novel approach of load sequence involving underload and overload in near neutral pH environment. Clear knowledge of the effect of load interaction involving load sequence of underload and overload is vital to control crack growth in steel pipelines under near neutral pH environment. The result of crack growth rate under different load sequence on X65 steel indicate that increase in overload ratio of 2, 3 and 4 caused an increase in crack growth rate of 1.68E−3, 1.89E−3 and 2.31E−3 mm/block respectively. These results are compared with results from other tests under variable amplitude without load sequence. Analyses were carried out on the morphology of the crack tip and the fracture surface after the test.

Hydrotesting and In-Line Inspection: Now and in the Future

Pressure testing of pipelines has been around in some form or another since the 1950s1–14. In its earliest form, operators used inert gases such as Nitrogen or even air to test for pipeline integrity. However, with the significant increases in pipeline pressures and inherent safety issues with a pressurized gas, the switch to using water happened in the late 1960’s15–17. Hydrostatic tests (referred to as hydrotests) have been used since then to set and reset the Maximum Allowable Operating Pressure (MAOP) for pipelines but as other technologies develop and gain acceptance will hydrotesting still play a key role in pipeline integrity in the years ahead? Currently, hydrotesting is a topic for the impending US Pipeline and Hazardous Materials Safety Administration’s (PHMSA) Proposed New Rule Making (PNRM)18. Under the NPRM, hydrotesting is required to verify MAOP on pre-1970s US “grandfathered” pipelines, as well as on pipelines of any age with incomplete or missing testing record and include a high level test with a “spike” in pressure. But hydrotesting may not be the only method. Alternative methods and new technologies — used alone or used in combination with hydrotesting — may help provide a more comprehensive way for operators to identify and address potential problems before they become a significant threat. This paper explores both sides of the argument. Before In-Line Inspection (ILI) technology was even available, hydrotesting was the absolute means of the proof of integrity. However, hydrotesting is under scrutiny for many reasons that this paper explores. ILI was introduced in the 1960’s with the first commercially available Magnetic Flux Leakage (MFL) tools that presented the industry with an alternative. Currently there are a huge array of available technologies on an ILI tool and so is the role of the hydrotest over? The paper looks at the benefits of the hydrotest and these are presented and balanced against available ILI technology. Furthermore, as pipelines are being developed in even more harsh environments such as deepwater developments, the actual logistics of performing a hydrotest become more challenging. The paper will also look at both applications onshore and offshore where regulators have accepted waivers to a hydrotest using alternative methods of proving integrity. The paper concludes with the current use and needs for hydrotesting, the regulatory viewpoint, the alternatives and also what the future developments need to focus on and how technology may be improved to provide at least a supplement if not a replacement to this means of integrity assurance.

Integrity Management of Ground Movement Hazards

Ground movements, such as landslides and subsidence/settlement, can pose serious threats to pipeline integrity. The consequence of these incidents can be severe. In the absence of systematic integrity management, preventing and predicting incidents related to ground movements can be difficult. A ground movement management program can reduce the potential of those incidents. Some basic concepts and terms relevant to the management of ground movement hazards are introduced first. A ground movement management program may involve a long segment of a pipeline that may have a threat of failure in unknown locations. Identifying such locations and understanding the potential magnitude of the ground movement is often the starting point of a management program. In other cases, management activities may start after an event is known to have occurred. A sample response process is shown to illustrate key considerations and decision points after the evidence of an event is discovered. Such a process can involve fitness-for-service (FFS) assessment when appropriate information is available. The framework and key elements of FFS assessment are explained, including safety factors on strain capacity. The use of FFS assessment is illustrated through the assessment of tensile failure mode. Assessment models are introduced, including key factors affecting the outcome of an assessment. The unique features of girth welds in vintage pipelines are highlighted because the management of such pipelines is a high priority in North America and perhaps in other parts of the worlds. Common practice and appropriate considerations in a pipeline replacement program in areas of potential ground movement are highlighted. It is advisable to replace pipes with pipes of similar strength and stiffness so the strains can be distributed as broadly as possible. The chemical composition of pipe steels and the mechanical properties of the pipes should be such that the possibility of HAZ softening and weld strength undermatching is minimized. In addition, the benefits and cost of using the workmanship flaw acceptance criteria of API 1104 or equivalent standards in making repair and cutout decisions of vintage pipelines should be evaluated against the possible use of FFS assessment procedures. FFS assessment provides a quantifiable performance target which is not available through the workmanship criteria. However, necessary inputs to perform FFS assessment may not be readily available. Ongoing work intended to address some of the gaps is briefly described.

Experimental and Numerical Investigation Into the Behavior of Buried Steel Pipelines Under Strike-Slip Fault Movement

Buried steel pipelines for water and hydrocarbon transmission in seismic regions may be subjected to large imposed deformations. When a buried pipeline crosses an active strike-slip fault, the relative motion of the two soil bodies in which is it embedded can lead to significant deformation of the pipeline and possibly to loss of containment. To be able to fully understand the effects of this movement and the interaction between pipe and soil on the strain demands in the pipeline, a novel full scale experimental setup has been developed. To allow accurate monitoring of the pipeline deformation, the pipe-surrounding soil has been replaced with appropriate nonlinear springs, leaving the pipe bare during the experiment. In a total of ten tests, the strain demand in a pipeline as a result of these ground-induced deformations has been investigated. The testing program includes variations of pipeline geometry, steel grade and internal pressure. Furthermore, cohesive and non-cohesive soils have been simulated in the tests. Observed responses of the pipeline include local buckling, high tensile strains (up to 5%) and, in one case, cracking of the pipeline. Based on experiences with these experiments, a numerical model has been developed that uses non-linear springs to model the pipe-soil interaction. By modelling the pipe and soil conditions that were simulated in the ten experiments, this model has been calibrated and validated. Comparisons between the model predictions and test results show that the numerical model is able to predict the deformational behavior of the pipeline accurately. Moreover, also the formation of local buckles is predicted with satisfying results. The results of the validation operation lead to the conclusion that the new model is performing well. By omitting the modelling of the full soil body, computation time is reduced, increasing practical use of the developed model.

Development and Implementation of a Risk Based Prioritization Methodology for MAOP Reconfirmation of Gas Transmission Facilities

As part of Pacific Gas and Electric Company’s (PG&E) on-going commitment to public safety, the company has begun a comprehensive engineering validation of its gas transmission facilities that will ultimately support the reconfirmation of maximum allowable operating pressure (MAOP) for these assets. In addition to 6,750 miles of line pipe, PG&E’s gas transmission system contains over 500 station facilities. Since this set of facilities is not only large but diverse, and the validation effort for these facilities is expected to be an extensive, multi-year process, a methodology for the prioritization of the facilities needed to be developed to facilitate planning of the process for the efficient mitigation of risk. As a result, DNV GL was retained to develop and implement a risk-based prioritization methodology to prioritize PG&E’s gas transmission facilities for the engineering validation and MAOP reconfirmation effort. Ultimately, a weighted multiple criteria decision analysis (MCDA) approach was selected and implemented to generate the prioritization. This MCDA approach consisted of the selection of relevant criteria (threats) and the weighting of these criteria according to their relative significance to PG&E’s facilities. Relevant criteria selected for inclusion in the analysis include factors that are important in order to assess both the short- and long-term integrity of the facility as a whole as well as the integrity of features for which design records cannot be located. The criteria selected encompass stable threats, time-dependent threats, as well as environmental impact. Enormous amounts of data related to design, operations, maintenance history and meteorological and seismic activity in addition to other environmental data were evaluated with this newly developed methodology to assess the relative risks of the facilities. Pilot field visits were performed to validate the selection of the various criteria and to confirm the outcome of the analysis. The novelty of this approach lies in the prioritization of facilities in a coherent risk-based manner. The described approach can be used by operators of oil and gas facilities, either upstream, midstream or downstream.

New Classification Approach for Dents With Metal Loss and Corrosion Along the Seam Weld

The ability to characterize metal loss and gouging associated with dents and the identification of corrosion type near the longitudinal seam are two of the remaining obstacles with in-line inspection (ILI) integrity assessment of metal loss defects. The difficulty with denting is that secondary features of corrosion and gouging present very different safety and serviceability scenarios; corrosion in a dent is often not very severe while metal loss caused by gouging can be quite severe. Selective seam weld corrosion (SSWC) along older low frequency electric resistance welding (ERW) seams also presents two different integrity scenarios; the ILI tool must differentiate the more serious SSWC condition from the less severe conventional corrosion which just happens to be near a low frequency ERW seam. Both of these cases involve identification difficulties that require improved classification of the anomalies by ILI to enhance pipeline safety. In this paper, two new classifiers are presented for magnetic flux leakage (MFL) tools since this rugged technology is commonly used by pipeline operators for integrity assessments. The new classifier that distinguishes dents with gouges from dents with corrosion or smooth dents uses a high and low magnetization level approach combined with a new method for analyzing the signals. In this classifier, detection of any gouge signal is paramount; the conservatism of the classifier ensures reliable identification of gouges can be achieved. In addition to the high and low field data, the classifier uses the number of distinct metal loss signatures at the dent, the estimated maximum metal loss depth, and the location of metal loss signatures relative to dent profile (e.g. Apex, Shoulder). The new classifier that distinguishes SSWC from corrosion near the longitudinal weld uses two orientations of the magnetic field, the traditional axial field and a helical magnetic field. In this classifier, detection of any long narrow metal loss is paramount; the conservatism of the classifier ensures that high identification of SSWC can be achieved. The relative amplitude of the corrosion signal for the two magnetization directions is an important characteristic, along with length and width measures of the corrosion features. These models were developed using ILI data from pipeline anomalies identified during actual inspections. Inspection measurements from excavations as well as pipe removed from service for lab analysis and pressure testing were used to confirm the results.

Non-Linear Corrosion Growth: A More Appropriate and Accurate Model for Predicting Corrosion Growth Rate

External metal-loss corrosion is one of the major contributing factors for pipeline failures in North America. Corrosion growth rate plays a crucial role in managing corrosion hazard for gas and liquid pipelines. Quantifying the growth of corrosion over time is critically important for the risk and reliability analysis of pipelines, planning for corrosion mitigation and repair, and determination of time intervals for corrosion inspections. Conservatism in predicting the growth rate has significant engineering implication as non-conservatism can lead to critical anomalies being missed by mitigation actions and may cause pipeline failure; whereas, over conservatism can lead to unnecessary inspections and anomaly mitigations that may result in significant unnecessary cost to pipeline operators. As more and more pipelines are now being inspected by in-line inspection (ILI) tools on a regular basis, the ILI data from multiple inspections provide valuable information about the growth of corrosion anomalies on the pipeline. Although the application of linear growth rate calculated by comparing depths from two successive ILI is a common practice in the pipeline industry, research has shown that the growth of corrosion anomaly is non-linear and anomaly-specific. The authors of this paper have previously developed anomaly-specific non-linear corrosion growth model based on multiple ILI data. The objectives of this paper are to demonstrate the appropriateness of anomaly-specific non-linear corrosion growth model, and to illustrate the advantages of using non-linear corrosion growth model in the integrity management program. Two case studies were performed to illustrate the application of non-linear growth model by incorporating the measurement errors associated with the ILI tools, which include both the bias (constant and non-constant) and random scattering error. The findings of these case studies are presented in this paper.

Longitudinal Stress Limits in Managing Spans and Other Longitudinal Loads

Stresses along the length of pipelines, termed longitudinal stresses, are generated by pipeline construction, service conditions, and changes in pipe support conditions. Although there are no explicit federal regulations limiting longitudinal stresses for in-service pipelines, pipeline operators typically reply on design requirements in established standards, such as ASME B31.4, B31.8, and CSA Z662, to manage possible integrity concerns arising from longitudinal stresses. In this paper longitudinal stress limits in existing standards are reviewed. These standards include CSA Z662, ASME B31.4, ASME B31.8, DNV RP F101 and API RP 1111. These standards provide various formulae or specific values for the longitudinal stress limits. These limits are compared under various levels of internal pressure. Although the potential failure modes addressed by the different standards may be similar, the specific limits on longitudinal stresses differ among the standards. One of the interesting findings is that the limit on compressive longitudinal stress can be very low when the combined stress criteria (von Mises or Tresca) are applied to pipelines operating at a pressure level equivalent to Class 1 design of gas pipelines, i.e., hoop stress being 72% SMYS. The resulting compressive stress limits, at 18–29% SMYS by some standards, are much lower than often quoted 90%, 80%, or 54% SMYS limits. These quoted limits refer to limits for tensile stresses, but sometimes mistaken for compressive stress limits. The low compressive stress limits can be quite difficult to manage for spans after the addition of possible compressive stresses from temperature differential, lateral bending, and other sources. Alternative stress limits that provide a consistent level of safety and in compliance with the spirits of standards are proposed. The new limits are sound from the viewpoint of safety, yet practical to apply. One possibility of increasing the compressive stress limit is reducing the hoop tensile stress by lowering operating pressure. The other possibility is setting a combined equivalent stress limit that is not overly conservative and preserves a sound level of safety. An Example is provided to illustrate the assessment of a span against the stress limits.