The new tanks-each standing three to four storeys high and as much as 250 feet across-range in capacity from 250,000 to 530,000 barrels (bbl) apiece. When the $600-million project is finished, Enbridge’s expanded Hardisty Contract Storage facility will be able to hold 12.5 MMbbl, equal to five full days of Canada’s total crude oil production.

Hardisty sits along the Enbridge trunk pipeline system, which links Edmonton as well as northern Alberta’s bitumen producers to eastern Canada and the United States. The big-inch lines can efficiently feed all grades of oil to refineries as far away as Oklahoma and the Gulf. From Hardisty, Edmonton is a two-hour drive to the northwest, the Saskatchewan border lies one hour eastward.

Overseeing the Hardisty tank farm expansion is Lee Monthei, director of upstream terminals for Enbridge’s major projects division. Although American-raised, Monthei is no stranger to sub-Arctic conditions. As a young consulting engineer, Monthei migrated from the Lower 48 to Prudhoe Bay, Alaska. “My wife and I went to Alaska for two years,” he recalls, “and we ended up staying 27.” He holds a master’s degree in engineering management and worked at crude oil terminals at Valdez and elsewhere along Alaska’s famed crude oil pipeline. But even for an engineer who’s been involved in major transportation and storage projects for 25 years, the new Hardisty facility stands tall. “We’ve never built this many tanks all in one shot,” Monthei says. “Typically, we’ll build two or three, and then these sites kind of grow. This is the first time we’ve come out and built 19 all at once.” Eighteen of these vessels will be used for crude storage and one for diluent. Customer demand drove this project from its inception. “Particularly with oilsands development, customers were lined up. There were long-term [storage] contracts with Enbridge established before we ever started construction,” Monthei recounts. Engineering began in 2006 and tank construction in early 2007. With completion scheduled for late this year, the project has remained on time despite stiff engineering and construction challenges. Procurement began just as materials costs were escalating, but Enbridge managed those issues using sophisticated cost-control systems and projection analysis. “We were able to see from other projects that steel was moving up, and how much, and we were able to incorporate that information into this project’s final control budget,” says Monthei. Although Alberta’s skills supply in 2007-2008 was intensely tight, “we didn’t have any labour shortages, and we got very good productivity which we’re very pleased with,” Monthei reports. A good construction camp and a shuttle service to the site were pivotal to that success. “They had a comfortable place to stay while they worked,” the project manager says. “During the peak of construction, which was when labour was really scarce, we had contingency plans for attraction and retention, bonuses for the crews, and so forth. That helped us get over the hump.” At the peak of activity, 580 workers were on site, and logistical planning required months of careful work before breaking ground. “We had a list of vendors that literally goes a hundred pages,” Monthei says. “Not only have we finished the central tank farm on schedule and within our control budget, we’ve accelerated the other two areas by as much as a couple of months. We were able to maintain good productivity during the winter months, which is something we were concerned about.” Bringing tanks into operation is a slow, meticulous procedure. Simulations with empty lines are run to check the instrumentation. Operators must have a full understanding of real-world scenarios before the first drop flows. “It’s a fairly complicated process in which we fill the lines to the tanks,” Monthei says. “We have a comprehensive program for verifying all of our instruments and controls. We do what we call dry commissioning. Then we flood the lines and verify that our controls are working properly under wet conditions. Then we do what we call floating the roofs: we introduce crude into the tanks and slowly bring the roofs up-these are all floating roofs, except for the diluent tank.” Completion of the project’s second phase is scheduled for the end of June. A third group of tanks should be built and start online testing in September. By year-end, all roofs should be floating. Stantec provided the design engineering, for which it won an award of excellence from the Consulting Engineers of Alberta. Greg’s Contracting handled the civil work. Lockerbie & Hole was the primary mechanical contractor, performing much of the on-site mechanical work and offsite prefabrication. Chemco Electric built many of the electrical modules offsite, in addition to doing the on-site electrical work. Because of their size, the tanks themselves had to be built on site. TIW Steel Platework, the primary tank contractor, supplied the steel in rolled sections which were then assembled in place. TIW, more than a century old, considers Hardisty its largest single project to date. Monthei says that doing as much modular design and prefabrication as possible played a crucial role in ensuring things went according to plan. “We used a fast-track approach on this. We actually started construction before the design was completed, in order to reduce the overall schedule,” he comments. “That’s a risky thing to do on a large project like this. A lot of owners get in trouble doing that. But this project lent itself very well. We were able to compartmentalize the design very effectively and manage its interfaces.” Created for both short- and long-term storage, the design had to take into account the massive volumes of crude being stored, the often frigid weather conditions through which the oil has to sit, as well as the ease with which it can be sent down the pipe when customers come calling. In 2007, Enbridge partnered with the University of Alberta to study how the crude would perform after being stored for long periods in a cold environment. “The university simulated that cooling [process] at various tank depths, and we came up with methodologies for heating the tank,” Monthei said. Such methodologies were a major innovation in Enbridge’s facility design, he adds. “The heating system is very unique.” The study determined the oil’s maximum cooling temperature, coming up with a surprising finding. While researchers expected that a heavy crude would chill as low as -23°C, they found that it got no cooler than -5°C. “As the oil cools, it thickens and collects along the side and bottom of the tank. That thickened oil acts as insulation as it starts to build. As it continues to thicken, it tends to stabilize [the temperature], or not allow the crude in the interior to get excessively cold,” Monthei says. Knowing that the oil itself did much of the insulating allowed for greater flexibility in the heating design. With traditional heating systems, says the project director, “you put heating coils inside the tank. But this gets to be a real maintenance problem, because if water settles out, that can make for a corrosive environment…. It could be a potential source of leaks. “What we came up with was a system of injection. We actually pull oil out of the tanks and take it down [the line] to where it’s heated. Then we bring it back and re-inject it into six or eight jet ports, jet mixers that re-inject the hot crude and mix it up inside the tank.” The combination of injection and mixture of the heated crude raises the temperature of the total contents and stabilizes it, in addition to leaving the tank free from corrosion-prone mechanical maintenance. Another major technical complexity for the Hardisty project is collective secondary containment within a 1.3-kilometre site. Tanks are typically individually separated by dikes and require a large footprint. But there were tight constraints on the amount of available land: not only were the 19 tanks built adjacent to existing storage, but there had to be a buffer strip 100 metres wide between the construction site and the nearby wetlands. Construction design resolved the space issue. “We put several tanks in a cell,” Monthei says. “We used concrete walls as retainers and attached an impermeable liner to the wall and on the ground, so that we have 100 per cent secondary containment wherever there’s potential for a leak or spill. A concrete wall takes up a lot less space than an earthen dike, which allowed us to squeeze this group together.” The concrete walls enabled further design integrations such as hanging power cable trays. Spatial issues were refined by 3-D computer modelling, which helped designers configure the massive structures within complex networks of external infrastructure such as piping and manifolds. Tight clustering introduced another potential problem: the risk of fire spreading. According to Monthei, in rare cases where fires do occur, the most common type is a ring-wall fire that breaks out between the floating roof and the side wall when a vapour leakage ignites. “What we have is a fire suppression system that supplies fire-foam to the specific location,” he says. “Doing this allowed us to put the tanks closer together than we otherwise would.” Much of the total system is designed to be automated and remotely controlled. “All the valves, the pumps, everything is controlled in Edmonton, from our control centre,” the Enbridge manager says. At its core, the Hardisty tank farm is designed to protect producers. Abruptly shutting in flowing oil wells can cause permanent damage to reservoirs. Yet downstream demand may vary unexpectedly in a recessionary economy. “Whether it’s oilsands or conventional, what producers really need to have is constant flow,” says Monthei. “These facilities provide a place where [producers] can put the crude, and their production can stay fairly constant, even though the market might go up and down.”