Horizontal directional drilling (HDD) has become the preferred method for trenchless pipeline installations. Drilling pressures must be limited and a “no-drill zone” determined to avoid exceeding the strength of surrounding soil and rock. The currently accepted industry method of calculating hydraulic fracturing limiting pressure with application of an arbitrary safety factor contains several assumptions that are often not applicable to specific ground conditions. There is also no standard procedure for safety factor determination, resulting in detrimental impacts on drilling operations. This paper provides an analysis of the standard methods and proposes two alternative analytical models to more accurately determine the hydraulic fracture point and acceptable drilling pressure. These alternative methods provide greater understanding of the interaction between the drilling pressures and the surrounding ground strength properties. This allows for more accurate determination of horizontal directional drilling limitations. A comparison is presented to determine the differences in characteristics and assumptions for each model. The impact of specific soil properties and factors is investigated by means of a sensitivity analysis to determine the most critical soil information for each model.

This paper analyzes a pipeline construction project in which the horizontal directional drill (HDD) technique for pipe installation was heavily utilized. The paper focuses on the benefits and risks of using directional drills, versus open cut installation, from an environmental perspective. The paper also contains recommendations, in a lessons-learned format, that might be useful in planning a pipeline construction project that includes the use of HDD techniques, especially under wetland areas.

This paper will discuss how the project team planned, designed and constructed a unique and innovative casing sleeve as one of the key solutions to overcome a major threat to the completion of a horizontal directional drilling (“HDD”) project (“Fraser River South Arm Crossing Upgrade Project” or “Fraser River Crossing”). In 2009 FortisBC Energy Inc. (“FortisBC”) started construction to upgrade its NPS 20 and NPS 24 pipeline crossings of the Fraser River, the largest river in the province of BC, Canada via HDD. Due to the poor surface geology at this location on the Fraser River, temporary surface casings were required on both sides of the crossing to get drilling activities into a formation suitable for conducting an HDD crossing. As a result, the Fraser River Crossing required an HDD rig to drill concurrently from either side of the crossing in order to create a continuous borehole (also known as an intersect crossing). During the pullback of the NPS 24 - 1.35 km crossing section, a major mechanical failure occurred when over 95% of the length had been pulled through. After multiple attempts to resume pullback by the HDD rigs and other onsite equipment were unsuccessful, the project team was left with the major challenge(s) of determining how else the crossing could be completed and the pipeline tied in on both sides of the river without incurring major business interruption in a busy industrial section of Richmond, BC. Moreover, FortisBC was faced with the possibility of having to abandon the project and the millions spent up to that point in time with no value. This paper will focus on how the project team overcame the challenge and mitigated long term operational issues that included maintaining adequate cathodic protection. Learn how the combined efforts of a multi-disciplined project team planned, designed, fabricated and ultimately successfully inserted an innovative casing sleeve, although unproven at the time and with its share of additional risks, after reviewing an extensive assessment of numerous alternatives as the optimum solution in order for FortisBC to finally complete the upgrade of its pipeline system.

There are several methods for pressure isolating pipelines. Along with hot tapping and stopple and freeze plugging, there is another common method known as remote controlled (tether-less) pipeline plugging, whose use is increasing — both offshore and onshore. This paper will review piggable tether-less plugging technology, provided by TDW Offshore Services using the SmartPlug™, and case histories whereby a bi-directionally piggable, remotely actuated (tether-less) plug is deployed to allow pipeline operators to perform repair work, modifications, or tie-ins on pipeline systems without interrupting production in the remaining part of the pipeline system, i.e., while operating live and at production pressure. Specifically this paper will address two new technologies: First, allowing high pressure isolation of thin wall pipe, and second, of spiral wound pipe, both without welding, tapping or leaving any trace of the fact that an isolation occurred. Some advantages of tether-less plugging technology are: • Plugging tools have higher pressure containment capacity than other plugging methods, typically up to 3,000 psi. • Bi-directionally piggable, able to negotiate as small as 1.5D bends, operated and monitored entirely via remote control (tether-less through-wall control and communication system). • Compared to hot tapping, welding a fitting on the pipeline is not required, and no need to hot tap (drill) into the pipeline, no future leak path and no issues regarding cuttings or coupon. This latest frontier of pressure isolation allows for plugging tools that are fail-safe (the higher the differential pressure the harder they set) with zero leakage tolerance. They can be configured for job specific requirements such as double or single block, and can allow for hydrotesting the completed work. The most important advantage is that they eliminate the time needed and lost production cost of displacing pipeline product, flaring, depressurizing, emptying the line, and re-commissioning the line. In addition, specifically this paper will address the latest technology advances allowing high pressure isolation of thin wall (8mm/0.32 inch) spiral wound pipe using external pressure reinforcement clamps over the pressure isolation tool during an onshore project on a 24 ″ methane gas pipeline. During the isolation, a portion of the upstream pipeline was removed and replaced while the entire pipeline downstream of the pressure isolation remained under full operating pressure, thus requiring no loss of production from downstream assets during the repair. Once complete the tools were released and pigged from the line, leaving no holes, no welds, no future leak path and no trace that any event occurred on the pipeline in that location.

The cost, design, and in some instances, feasibility of directional drilling large diameter or lengthy pipeline river crossings is primarily dependent on ground conditions encountered during construction. Geotechnical investigations are commonly used to explore and assess subsurface conditions at proposed crossings. Ground conditions are determined using borehole drilling and near surface geophysics. Borehole drilling provides subsurface sediment stratigraphy and depth to bedrock information. Geophysics is used to provide information between borehole locations or where borehole drilling is determined to be too difficult or too costly. When used to augment borehole results, geophysical surveys provide more complete geologic cross-section models throughout the length of a proposed directional drill path. This paper presents an overview of the more common geophysical methodologies used to profile subsurface conditions at proposed pipeline crossings. The methods discussed include ground penetrating radar (GPR), seismic refraction profiling and electrical resistivity tomography (ERT). The appropriateness and feasibility of each method is discussed in terms relating to investigation objectives of geotechnical and pipeline design engineers. All three methods were applied to two survey lines at a typical river crossing site on the Bow River, downstream from Calgary, Alberta. Results from the overlapping surveys are presented and the capabilities and limitations for each method compared. Borehole information obtained within the survey area is used to corroborate the interpreted geophysical results.

In the fall of 2001, Enbridge Consumers Gas proposed to install a 190 mm extra-high pressure steel pipeline in proximity to an artesian well on the Oak Ridges Moraine in southern Ontario. This well is located within the Regional Municipality of Durham and it is used by over 300 persons per day as their drinking water source because of very high water quality. Potential impacts to drinking water quality have taken on greater importance because of the Walkerton tragedy, in which a number of people died from drinking contaminated municipal water. The Region of Durham was especially concerned because of the large number of people who use this artesian well as their drinking water source. The Region did not want to close the well during construction as this could be taken as an admission that construction might negatively impact water quality. At the same time, they wanted to ensure that water quantity and quality was maintained. SENES Consultants Limited (“SENES”) was retained to develop and implement an environmental management plan to ensure that no negative impacts would occur during construction. The plan involved characterization of the water-bearing zone in terms of depth, type of deposit and direction of flow, relative to the drinking water source. This was undertaken through the use of test pits, boreholes and piezometers. Potential construction impacts were identified. In this case, the natural gas pipeline was to be installed by a directional drill that injects bentonite (drilling mud) to provide lubrication and to keep the drill hole from collapsing. Mitigation measures related to containment of bentonite and fuel handling in the vicinity of the artesian well were prescribed. The rationale for directional drilling this section of the pipeline was to prevent erosion of the steep slopes and to undercross a watercourse. The water-bearing deposit consisted of a sandy-gravel layer that was found to occur at a depth of 3.65 meters. Every effort was made to maintain the drill hole for the pipeline above this depth. In addition to sampling the artesian well for chemical and bacterial parameters in advance of construction and upon completion of work in the vicinity, water from the artesian well and one of the piezometers was checked for turbidity every two hours. Other contingency plans included digging “burp-holes” to reduce the potential for bentonite frac-outs and having a water supply truck on stand-by should turbidity levels reach unacceptable levels. Construction proceeded smoothly. Minor frac-outs occurred and were appropriately contained. The turbidity readings and water quality samples taken before, during and post-construction confirmed that there were no negative impacts on the artesian well. The methods used on this project are directly applicable to other pipelines that may be constructed in the vicinity of artesian wells.

Geophysical surveys map variations in physical properties of subsurface materials, many of which can have a direct impact on pipeline design and construction. This paper provides an overview of complementary geophysical methods available in the geophysical toolbox and shows, through the use of case histories, examples of the applicability of the methods for specific pipeline design and construction scenarios. In the context of pipeline design and construction, the objectives of a geophysical survey typically include one or more of the following applications: • muskeg mapping (thickness, lateral extent); • permafrost delineation (variations in ice content, frozen/unfrozen boundaries); • depth to bedrock; • rippability of bedrock; • soil type delineation (corrosion protection, granular inventories); • subsurface conditions at water crossings for horizontal directional drill planning using detailed investigations (boulder horizons, abandoned workings, depth to bedrock). To successfully address these objectives, it is often necessary to utilize more than one geophysical technique. Geophysical methods commonly employed in pipeline investigations include the following: • seismic refraction (marine and land based); • seismic reflection (marine and land based); • electromagnetics; • electrical imaging; • ground penetrating radar (marine and land based); • sonar. The fullest utility of geophysical information is achieved when combined with complementary approaches to provide the end-user with a value-added, cost effective approach. These other method include: airphoto interpretation, satellite imagery, and drilling. The incorporation of auxiliary data sets results in geophysical sections that provide a means of interpolating subsurface conditions between drill holes and reducing the risk associated with encountering surprises. These sections can also be used to provide for more accurate cost estimates by their inclusion in bid documents while at the same time ensuring a better data base for pipeline design. In addition to the advantages of using a geophysical toolbox, the ramifications of the pitfalls of geophysical approaches will also be discussed through the use of case histories illustrating situations in which an inappropriate geophysical technique was applied.

A primary design requirement for onshore pipelines is a need to demonstrate that hoop stress associated with the internal pressure loading is less than a prescribed allowable value. In addition to this management of the hoop stress (design factor) there is also a requirement to manage the magnitude of other stress components that may arise due to the interactive effects of soil friction and thermal gradients. It is quite a straight forward matter to determine the magnitude of such stress components using non-linear finite element techniques with the pipeline represented as a series of beam elements. A complexity arises when the pipeline contains fittings, such as bends and tees, since these components give rise to stress concentrations that cannot be addressed by simple beam elements. In some situations, it is possible to apply standard (handbook) values of the stress concentrations to the nominal stresses obtained from the beam element analyses and to assess the resulting stress levels against allowable values. However, stress concentration factors are not available for all components and in these situations the stresses can only be determined using 3D finite element analyses. The computational methods associated with these procedures have previously been undertaken in two stages. The first stage involved the determination of forces and moments, using beam elements, that act at the location of the fittings. The second stage involved the 3D finite element analysis with the previously computed forces and moments applied to the fitting. The process involved considerable effort and some accuracy was lost due to the approximate nature of the applied boundary conditions as described above. In order to mitigate both of these effects, AFAA have recently developed a method in which the two stages are integrated giving both a more accurate result, thus saving time and cost. The first part of this paper describes the modelling approach adopted by AFAA in some detail. Considerable focus is then given to the application of the technique. Working in close collaboration with Laing O’Rourke (UK), the technique was successfully applied to demonstrate the fitness-for-purpose of a number of hot-tap encirclement split-tees that were to be installed in close proximity on an operational pipeline. Both the installation procedure and subsequent operation were assessed in detail, taking account of the installation loads, pilot drill holes and the operational loads that would be encountered in the future. It was shown that installation process would not pose a threat to integrity of the existing pipeline and nearby components and that the system could be safely operated over the proposed design life period.

A 1,050 km long 20” pipeline was constructed to transport natural gas from northern Argentina to the coast of Chile. On the Argentine side, significant portions of the route traverse rugged mountainous terrain subject to landslides, debris flows, flash floods, and earthquakes. On the Chilean side (situated up to 5,000 m above sea level), the pipeline crosses active faults and terminates at locations historically subject to tsunami. The pipeline began operation in 1999. An outburst flood in a steep mountain stream caused the pipeline to rupture in 2001. Reactivation of a large rock slide in 2002 caused a second rupture. It appeared that the original design had underestimated the route’s exposure to geohazards, and efforts were required to improve pipeline safety and reliability. A geohazard risk management program was initiated in April 2002. Geohazards were identified and characterized through airphoto interpretation and field inspection. Sites were initially ranked using semi-quantitative risk estimates. Risk cost-benefit analyses were used to select optimal risk control measures at high ranking geohazard sites. These included monitoring programs, reconstruction of stream crossings, reroutes, and in one instance, landslide avoidance using a horizontal directional drill. Risk control measures were implemented between 2002 and 2006, and additional efforts are ongoing. An updated assessment of geohazard exposure was completed in 2005 with the objective of quantifying the level of risk reduction that had been achieved and prioritizing further risk reduction efforts. This paper describes implementation of the geohazard risk management program using a case history format. It highlights the techniques used to control the range of hazard that were identified in 2002 and to quantify the improvements achieved by 2006. The paper concludes with an overview of additional risk reduction initiatives that are in progress or under consideration.