Barnacles, which become partially or totally detached from their substratum in a natural environment, produce a secondary cement secretion. Laboratory experiments demonstrate that the secondary cement can successfully reattach the barnacle to a new substratum. Similar secondary secretion was found at the site of minor injuries to the barnacle basis. The secondary cement usually has a looser, more cavernous structure than the primary cement, but both secretions have similar staining characteristics. Microscope preparations indicate that occasionally barnacles are capable of developing new secondary cement ducts leading into the injured or detached areas to secrete secondary cement. In most cases, however, the existing primary cement duct network is used for the secondary secretion. This is possible only because most of the once used ducts are not plugged by hardened cement, in spite of the fact that the cement can harden inside the ducts. Chemical analysis suggests that the cement is an organic biopolymer and indications are that the cement hardening is initiated inside the organism. A unique flushing mechanism seems to be responsible for keeping the cement ducts open and ready for reuse. A nonhardening flushing fluid forces the still liquid cement out of the ducts. The cement hardens outside the duct openings sealing the flushing fluid inside the duct network. In case of detachment or injury. the cement seal breaks; the flushing fluid drains out leaving the duct open for the secondary cement secretion. The vesicles in conjunction with the main channel control the flow of the flushing fluid and the cement. The permeable wall of the main channel portion inside the vesicle reduces the convection and diffusion between the vesicle and the main channel, thus bypassing of vesicles and duct networks not affected by detachment is possible. The wall of the main channel inside the vesicle is also collapsible, thus acting as checkvalve when the vesicle is under pressure and allowing the cement to be pumped only into the ducts toward the secretory orifices.

Alliance Pipeline (Alliance), an integrated Canadian and U.S. high-pressure rich natural gas transmission system administers a Geohazard Management Program (GMP) which identifies, investigates, monitors and assesses sites subject to risks from geohazards. Within the pipeline industry, recent flood events have shown that pipelines with a seemingly adequate depth of cover can become exposed and fail in a single flood event. As such, it is important to understand which water crossings could result in a pipeline failure if the pipeline were to become exposed in a flood (termed vulnerability). Two complimentary methods were developed for evaluating the vulnerability of pipelines at water crossings. The first method is a mechanistic approach that compares the maximum allowable free span length (MAFSL) of an exposed pipeline to simple geomorphic properties of the water crossing. The MAFSL was determined by calculating the strain and fatigue limits of the pipeline from hydrodynamic loading and vortex shedding. The second approach is based on a statistical regression of historical pipeline performance, hydrotechnical inspection records and actual exposure rates to calculate a probabilistic estimate of pipeline vulnerability. Utilizing the developed approaches, the vulnerabilities were combined with probability of exposure values to provide an improved risk estimation of the water crossings. Further analysis shows the calculated likelihood of failure at the water crossings has no correlation to the depth of cover (DOC). This suggests that the designation of an arbitrary DOC requirement at water crossings is incongruous with risk management principles. Instead, the DOC at water crossings should be maintained at a safe level based on the specific hydraulic and geomorphic characteristics of the site.

In the light of recent experience of wildfires in Alberta and British Columbia, Alliance Pipeline has strengthened their emergency preparedness in dealing with external fire events that have the potential to affect above-ground facilities connected with their high pressure natural gas pipeline system. As part of this initiative a quantitative methodology has been developed that enables the effects of a wildfire on an above-ground pipeline facility to be assessed. The methodology consists of three linked calculations which assess: 1. the severity of the wildfire, based on information from the Canadian Wildland Fire Information System, 2. the transmission of thermal radiation from the wildfire to the facility, and, 3. the response of equipment, structures and buildings to the incident thermal radiation. The predictions of the methodology agree well with the actual damage observed at a lateral block valve site following a wildfire in 2016. Application to example facility types (block valve sites, meter stations and compressor stations) has demonstrated that, in general, damage is only predicted for more vulnerable items such as cables. The sensitivity of the predictions of the methodology to the input parameters and key modelling uncertainties has been examined. This demonstrates that the results are sensitive to the distance of the facility from the tree line and the assumed vegetation type. This shows the importance of verifying the location relative to the vegetation and selecting the appropriate vegetation type from the Canadian Wildland Fire Information System for site specific assessments. The predictions of the methodology are particularly sensitive to the assumed flame temperature. However, a value has been chosen that gives good agreement with measured thermal radiation values from wildfires. Of the mitigation options considered, the most effective and practical is to increase the distance to the tree line. This measure has the advantage of reducing radiation levels for all items on the site. Even though the work shows that failure of exposed pipework due to wildfires is unlikely, maintaining the flow within pipes is recommended as this increases the radiative flux at which failure is predicted to occur. However, as failure of cables and hence control systems would occur at a lower flux levels the fail-safe actions of such systems needs to be confirmed. Shielding of cables or items of equipment in general is likely to be impractical but could be considered for particularly vulnerable equipment or locations.

The Wapiti River South Slope is located 25 km southwest of Grande Prairie, AB. The slope is 500 m long and consists of a steep lower slope and a shallower upper slope, both of which are located within a landslide complex with ground movements of varying magnitudes and depths. The Alliance Pipelines Ltd. (Alliance) NPS 42 Mainline (the pipeline) was installed in the winter of 2000 using conventional trenching techniques at an angle of approximately 8° to the slope fall line. Evidence of slope instability was observed in the slope since the first ground inspection in 2007. Review of the available geotechnical data indicates two different slide mechanisms. In the lower slope, there is a shallow translational slide within a colluvium layer that is draped over a stable bedrock formation. In the upper slope, there is a deep-seated translational slide within glaciolacustrine and glacial till deposits that are underlain by pre-glacial fluvial deposits. Both the upper and lower slope landslide mechanisms have been confirmed to be active in the past decade. Large ground displacements in the order of several meters between 2012 and 2014 in the lower slope led to a partial stress relief and subsequent slope mitigation measures in the spring and summer of 2014, which significantly reduced the rate of ground movement in the lower slope. Surveying of the pipeline before and after stress relief indicated an increase in lateral pipeline deformation (in the direction of ground movement) following the stress relief. This observation was counter-intuitive and raised questions regarding the effectiveness of partial stress relief to reduce stresses and strains associated with ground movements. Finite element analysis (FEA) was conducted in 2017 to aid in assessing the condition of the pipeline after being subject to the aforementioned activities, and subsequent ground displacement from July 2014 to December 2016. This paper presents the assumptions and results of the FEA model and discusses the effect of large ground displacement, subsequent stress relief and continued ground displacement on pipeline behaviour. The results and findings of the FEA reasonably match the observed pipeline behaviour before and after stress relief. The FEA results showed that while the lateral displacement of the pipeline that was caused by ground movement actually increased following the removal of the soil loading, the maximum pipeline strain was reduced in the excavated portion. The results also indicated that ground displacement in the upper slope following the stress relief had minimal effect on pipe stresses and strains in the lower slope.