Journal of Pipeline Systems Engineering and Practice

This paper proposes a data-driven approach in determining an optimal inspection interval for a petroleum pipeline system. The approach accounts for the determination of both the probability of failure and its associated consequences. The probability of failure is estimated by fitting the historical data of failure of the pipeline into either a homogenous Poisson process or nonhomogenous Poisson process (power law). The analysis of historical data reveals the Poissoneous form that gives a better description of the failure process. The consequences of failure are calculated in terms of economic loss, environmental damage, and loss of human life. Both the failure probability and consequences are utilized to estimate the total loss of an operating pipeline system. A risk-based integrity maintenance optimization of the pipeline is achieved by minimizing the economic loss while taking the human risk and maintenance budget as constraints. The proposed framework is utilized in the maintenance planning of a very long cross-country petroleum pipeline system. The outcomes are robust and well validated. The framework can be applied to any engineering system that requires inspection and maintenance planning.

An acoustic emission (AE) method was used to detect leaks and discern their location under flow conditions in a 304.8-m-long, 305-mm-diameter buried steel pipeline at the New Jersey Institute of Technology/U.S. Environmental Protection Agency (NJIT/USEPA) Buried Pipeline Test Facility in Edison, New Jersey. A $16.2\mathrm{mL}/\mathrm{s}$ leak was successfully detected, and its discernible location was indicated to within 0.3 m, with a sensor separation of 65.5 m, and with water in the pipeline flowing at $11.4\mathrm{L}/\mathrm{s}$. Encouraging results were also obtained for a $1.3\mathrm{mL}/\mathrm{s}$ leak that was discernible at a sensor separation of 21.3 m under the same flow conditions. Previous static pressure leak testing on this pipeline detected a $12.6\mathrm{mL}/\mathrm{s}$ leak at sensor separations of up to 192.9 m, and it is expected that mitigating the effects of both externally produced and flow-induced background noise will allow for the detection of smaller leak rates under greater flow conditions. These results demonstrated that effective AE leak detection could be performed under flow conditions on water-filled buried metal pipelines in sandy soils.

This paper presents full-scale testing results of a 1,370-mm (54-in.) nominal diameter prototype rolled groove joint incorporated into a bar-wrapped concrete pressure pipe manufactured to American Water Works Association (AWWA) standard C303 specifications. The acceptance criteria for the prototype were no leakage or deformation at 1 MPa (150 psi) working pressure and 1.6 MPa (225 psi) transient pressure. The joint was also required to be watertight at 2 MPa (300 psi), which represented a factor of safety of 2 over working pressure. A 25.4-mm (1-in.) pull was used in the full-scale test to reflect the worst case scenario of an angularly deflected joint in the field to assess its ability to tolerate unsymmetrical fit. The test pipe was loaded in excess of its circumferential elastic limit, without any visible leakage at the joint. The three-dimensional (3D) nonlinear numerical simulation of the pipe joint was created by using software, resulting in acceptable comparisons with the experimental data. Data collection instrumentation included strain gauges, cable displacement transducers, and acoustic emissions (AE) technology. Joint design included an optimal stab depth for the spigot and appropriate rod-wrap termination design in both the bell and spigot to provide sufficient stiffness. The strain in the internal and external cement mortar layers remained below the ultimate strain of 0.2% up to 1.7 MPa (250 psi). A steel cylinder with complete-penetration helical butt welded seams, which will allow a groove to be roll-formed on the cylinder, with a minimum cylinder thickness of 3.4 mm ($\#10\mathrm{GA}/0.135\mathrm{in.}$), are noted as minimum requirements for the joint.

Since the early seventies, pipelines have become one of the main means of transporting oil and gas offshore in many parts of the world. In-service hydrocarbons must be transported at high temperature and pressure to ease the flow and prevent solidification of the wax fraction. The buckling of subsea pipelines occur because of the introduction of axial compressive forces caused by the constrained expansions set up by thermal and internal pressure actions. Such compressive forces can lead to either lateral buckling in the plane of the seabed or buckling in a vertical plane. To ensure minimal interference with other marine activities, the pipelines can be buried in a trench. In such cases, the lateral soil restraint exceeds the vertical uplift restraint created by the pipe’s submerged weight. Therefore, vertical buckling is of particular interest with respect to entrenched subsea pipelines. The possibility of upheaval buckling in subsea pipelines has been appreciated in the pipeline industry for over 30 years. The recent growth in interest in high-temperature pipelines in China is stimulated because of the frequent failures in Bohai Gulf. This paper describes the history of the theoretical and experimental studies on the subsea buried pipeline vertical buckling, as well as the authors’ experiences with this problem. Engineers could benefit from the literature reviews and summaries in this area. The paper also highlights the design of protective covers for the pipelines, and finally identifies areas for further development.