There’s no shortage of work to be done to revive Venezuela’s crude oil industry, much of which suffered from years of poor management and minimal investment. One rehabilitation effort that could deliver a lot of bang for the buck would be to repair and restart the industry’s crude upgraders.
Production of synthetic crude oil that is processed from Alberta’s oil sands reached record highs at the end of 2020 after touching on two year lows just four months earlier. However, these highs could be undermined and sink to four-year lows for a short period of time this spring with what appears to be a heavier than usual slate of maintenance work on three of Alberta’s four upgraders, the immense processing units that produce synthetic crude oil from bitumen. In today’s blog, we take a closer look at the upgraders, the timing of maintenance, and what this might mean for synthetic crude oil production and exports.
So far, 2020 has been another bad year for bitumen producers in Alberta’s oil sands. For the second year in a row, they have been forced to endure production curtailments, this time in response to COVID impacts on demand and the resulting record-low heavy oil prices. Still, there are at least glimmers of hope that the bitumen market will soon enter at least a modest recovery mode, and that further gains will be possible in 2021 and beyond. Moving all of that bitumen to market in pipelines and in rail cars is going to require even more diluent than the record amounts already consumed in late 2019 and early 2020. Today, we consider the outlook for bitumen production, what that outlook means for future diluent demand, and if that demand can — or cannot — be met by the various sources of diluent supply.
Producers in Alberta’s oil sands have been through good times and bad times the past few years. Sure, there’s been a lot of growth in output since 2010. But they’ve also seen wildfires that forced one-third of production offline. And pipeline takeaway constraints that sent prices tumbling and spurred government-imposed production cutbacks. And lately, they’ve been struggling through a global pandemic that slashed crude-oil demand and led to further curtailments. Despite it all, producers and the province of Alberta are hopeful about an oil sands rebound, and shippers are optimistic that they can source an increasing share of the diluent they would need to transport bitumen from Western Canada. There’s good news on that front: there appears to be plenty of diluent pipeline capacity already in place between Alberta’s diluent hubs and its oil sands production areas. Today, we continue our series by exploring the major pipeline systems that distribute diluent supply to the oil sands.
The folks who transport bitumen from the Alberta oil sands to faraway markets depend on light hydrocarbons collectively known as diluent to help make highly viscous bitumen flowable enough to be run through pipelines or loaded into rail tank cars. The catch is — or was, we should say — that Western Canada wasn’t producing nearly enough condensate and other diluent to keep pace with fast-rising demand, so a few years ago, two pipelines from Alberta to the U.S. Midwest were repurposed to allow diluent to be piped north. More recently, though, Western Canadian production of diluent has been soaring and new pipeline capacity has been built within Alberta to deliver it to the oil sands. That has the potential to reduce the need for imports from the U.S. and may soon lead to at least one of the import pipes being repurposed yet again. Today, we continue our series on diluent with a review of the pipeline systems that collect locally produced light hydrocarbons that are eventually employed in the oil sands.
Bitumen, the heavy, viscous form of crude oil associated with Alberta’s oil sands, has been the workhorse behind Canada’s ascent to near the top of oil-producing nations. However, it is impossible to get raw, near-solid bitumen to refiners by pipeline without either upgrading it to a flowable crude oil or blending it with lighter hydrocarbon liquids, a.k.a. diluents, to form the more diluted version of the product, referred to as “dilbit.” As for moving bitumen by rail, there are two main options: using heated tank cars or blending it with diluent to form “railbit.” The rapid rise in bitumen production in the past decade — interrupted only by wildfires and the recent price crash — has generated a large parallel market for diluents, whose fortunes are closely tied to the oil sands. U.S.-sourced diluent currently meets a substantial portion of the demand. But with Alberta oil sands development poised for renewed growth and in-province condensate production rising, the Canadian diluent market could be in for some big shifts. Today, we start a blog series considering the unique role that this special form of hydrocarbon plays in the oil sands.
Three months after a series of devastating wildfires wreaked havoc in Alberta’s oil sands region, production is essentially back to normal. Temporary shutdowns at several production sites initially reduced the oil sands’ output by more than 1 MMbbl/d –– or about one-third the area’s pre-fire production level –– which trimmed inventories and goosed world oil prices. But the short-term closures appear to have had little effect on the Canadian and U.S. refineries that process oil sands-sourced crude. Now, oil sands producers (stung more than many by the collapse in oil prices) are focused again on reducing production costs in an effort to stay profitable in a low-oil-price era. Today, we summarize the current, post-wildfires state of oil sands production and consider the region’s future in the new, tight-oil/Shale Revolution world.
Production in Alberta’s oil sands region is gradually rebounding after devastating wildfires that forced output scale-backs and temporary shutdowns of some production facilities, terminals and pipelines. It may be a while before life—and production—in the oil sands are back to normal, but Canada’s National Energy Board, producers and others expect the region’s output to continue to rise (if only gradually) the next few years, reflecting long-term oil sands expansion projects committed to when oil prices were more than double what they are today. There are very different views, though, about whether the oil sands will eventually need more takeaway capacity in the form of new or expanded pipelines. Today, we continue our look at the oil sands post-wildfires with a review of existing and proposed pipeline capacity.
Wildfires are notoriously unpredictable and, sure enough, as soon as the worst seemed to be over in the Fort McMurray, AB area, new flare-ups in mid-May threatened oil sands production areas north of the city. Thanks to heroic efforts by Alberta fire crews, no production area has experienced any significant damage (so far at least—fingers crossed), but a few work camps have been destroyed or damaged, and will need to be rebuilt. Good news is trickling in though, such as Imperial Oil’s May 19 announcement that it has restarted limited operations at its Kearl oil sands site. If, as everyone hopes, the wildfires are brought under control within the next few days, it seems likely that oil sands production will ramp up gradually over the next few weeks, and that by mid-summer Alberta’s output might be close to the 3.1 MMb/d that the province was producing before the fires were sparked.
It will take at least a few weeks, but it seems likely that production in the Alberta oil sands will return to near normal levels, setting the stage for continued incremental growth over the next few years as expansion projects committed to when oil prices were much higher come online. Although fires are still burning, the devastation in and around Fort McMurray, AB--the unofficial capital of the oil sands region—that forced tens of thousands of people from their homes, prompting oil sands staffing shortages, production scale-backs and a handful of temporary production shutdowns has moved beyond most oil sands operations. But the wildfires’ chain of effects didn’t end there; at one point, crude oil output declines were estimated at upwards of 1 MMb/d (about one-third of Alberta’s normal production of 3.1 MMb/d) caused world oil prices to inch up, some refineries in the U.S. Midwest that depend on Alberta-sourced oil have been forced to scramble for replacement crude, and natural gas prices fell to near zero for a brief period. Today, we begin a two-part look at post-wildfire prospects for the region, and—looking ahead--at the possible need for more pipeline takeaway capacity.
