Changes in internal oil flows
With such a rapid and major increase in crude production in North Dakota and Texas, crude delivery infrastructure has been overwhelmed. Additionally, Canadian exports are flowing into the same US areas where the shale boom is already expanding local supply. The internal oil flows have changed drastically as new supplies have wended their way to refineries, often backing out other crudes as they go, which in turn must find other homes. As Figure 4 illustrates, PADD 3, the US Gulf Coast, historically had been a significant source of crude to PADD 2, the Midwest and Great Lakes. Yet when tight oil production began to boom, and Canadian exports to PADD 2 also rose, transfers of crude from PADD 3 to PADD 2 were cut by more than half, dropping from 2.054 million bpd in 2000 to 908 000 bpd in 2013. Transfers of refined product from Gulf Coast refiners to PADD 2 also fell from 981 000 bpd in 2000 to 723 000 bpd in 2013.The US Gulf Coast is the main refining centre in the country, regularly supplying fuel to other regions. But as shown in Figure 5, PADD 2 has raised its transfers of refined product to other PADDs, chiefly PADD 3, with volumes also to the Rocky Mountains (PADD 4) and the East Coast (PADD 1). PADD 2's product transfers were typically in the 300 000 – 400 000 bpd range during the 2000 - 2007 period, but they have risen to 600 000 – 700 000 bpd in recent years.
PADD 2's transfers of crude to other PADDs has risen even more dramatically. As Figure 6 shows, PADD 2 historically sent very little crude to other PADDs. Transfers of crude were typically less than 100 000 bpd until Bakken crude production began to come onstream. Once it did, crude transfers soared, reaching 557 000 bpd in 2013. The majority of this flowed south to PADD 3.
Although pipelines are not immune to leaks and accidents, pipelines are still regarded as the safest and least expensive transport mode for crude delivered to refineries, and the US is crisscrossed with a complex network of pipelines. Some of the new tight oil production is far from these pipelines, however, and many lines are running at capacity already. A variety of pipeline expansions, connections and reversals have been undertaken and others are underway or planned. However, since many of the pipeline rights of way merely increase crude flows to the same end markets, pipelines are not always the best option. Expanding Bakken crude deliveries to the US Gulf Coast merely carries it into a market already becoming saturated with Eagle Ford crude. Yet planning, permitting and paying for entirely new pipeline systems to new market outlets in the East Coast and the West Coast is difficult and risky. Although there have been proposals made for crude pipelines to California, for example, there have not been enough committed shippers and enough committed buyers to warrant such a massive undertaking, which would have to traverse the Rocky Mountains. This vast mountain range forms a natural barrier that isolates the US West Coast from the rest of the US. This same mountain range stretches north through Canada as well, and it is a key factor limiting the transport of Canadian crudes and bitumen products to the Pacific Coast and from there, to Asia. Only one major crude and product pipeline currently crosses this range, the 715 mile long Trans-Mountain Pipeline, which connects Alberta province with British Columbia province on the Pacific coast. From there, Canadian crude can reach refineries in the US state of Washington, and it also may be barged further south to California. This line currently has a capacity of 300 000 bpd, and there is a proposal to expand it to 890 000 bpd, since many produces hope to gain access to the markets of Asia as well.
Impacts on refining
Anticipating a ‘dumbbell’ distillation curve
The expression ‘dumbbell’ crude came into wider use when Canadian oilsands production began to rise. Today, it is heard even more frequently, since Canadian production is growing, and exports to the US are set to grow even further. Canadian bitumen products are often sold as dilbits, which are blends of diluent and bitumen at a ratio of roughly 30:70. Dilbits are called dumbbell crudes because of the distillation pattern, where the diluent contributes a range of light hydrocarbons and the bitumen contributes a range of heavy hydrocarbons, but the middle distillate range (kerosenes and diesels) is visibly lacking. Upon being heated to boiling in a crude distillation tower, the distillation fractions range from gases and naphthas, which have boiling points between ambient temperature and approximately 330 °F/165 °C, to middle distillates, which have boiling points between approximately 330 °F/165 °C to 620 °F/327 °C, to vacuum gasoil and vacuum bottoms, which have boiling temperatures above 62 °F/327 °C. 78% of the sample diluent is lighter than swing kerosene, while 0% of crude bitumen is. Therefore, the majority of the diluent in a dilbit boils off before the middle distillate range is reached. The bitumen also contributes very little to the middle distillate fraction, being concentrated at the other extreme of the barrel.
Restrictions on crude exports and impacts on refining
The rapid rise in tight oil output and the rise in Canadian exports to the US have concentrated in the centre of the country, and crude refining activity has risen in these areas. As noted, there are serious constraints on crude transport options to refiners in PADD 1 and PADD 5.
There have been numerous references made to the ‘US crude export ban’. This is a misnomer, since a variety of crudes are allowed to be exported, such as certain volumes of Alaskan and Californian crude, plus exports to Canada, while other crude cargoes may be exported if properly licensed and considered to be in the national interest. In 2013, the US exported 120 000 bpd of crude oil. Nonetheless, these are serious restrictions to free trade, and there is no doubt that these restrictions produce market inefficiencies. General exports require a specific license granted by the Bureau of Industry Security within the Department of Commerce. The policies are long standing, having their roots in the 1970s, when there were concerns over energy supply security. The restrictions on crude exports fall under the Energy Policy and Conservation Act of 1975 and the Export Administration Act of 1979. The efficacy of these laws has been a topic of debate more or less continually since the 1970s, but the shale boom has made the debate much more timely and interesting. In a free market, the light, sweet crudes now being produced could command premium prices as export grade crudes, while less expensive heavy sours (including the Canadian resources) could be imported. Depending on price differentials and transport costs, there could be a major net benefit to the US economy. In terms of changing public policy, however, the question always arises, to whom does this economic benefit flow? These laws will be difficult to change unless a clear public benefit isproven.
The shale boom has caused a major turnaround in the direction of the US crude oil balance. After falling for decades, US crude output is rebounding. The official forecast of the US EIA calls for an additional 1.89 million bpd of crude production between 2013 and 2019. Many petroleum geologists believe that production could rise to the point that the US could become fully self sufficient in energy supply, and could even become a net exporter. Yet there are many who oppose fracking activity, believing that it may cause earthquakes or water contamination. Because the widespread use of hydraulic fracturing is relatively recent, the full impacts are not known, and public opinion will be very important. Public policy will also play a role in determining whether long standing regulations such as the Jones Act, the Energy Policy and Conservation Act of 1975, or the Export Administration Act of 1979 might be changed to accommodate the shale boom. Transport infrastructure is strained, and recent pipeline and railcar accidents have led to concerns that Bakken crude is more explosive and corrosive than initially believed.
It is also worth noting that many environmental groups strongly oppose the development of Canadian oil sands, as well as the pipeline construction to carry additional volumes. Canadian production has been rising strongly, and exports to the US are rising as well. The cautionary notes are important, but in most base case scenarios, it is likely that US tight oil production and Canadian oilsands production will continue to rise. The Canadian resources are expected to be chiefly bitumen based products such as dilbit. The US shale oils are light and low in sulfur. Both will contribute to what is known as a ‘dumbbell’ distillation pattern, with a concentration of light ends and heavy ends and a relative paucity of middle distillates. The slate is not entirely suitable for the US refining industry, nor for the pattern of demand, but there is no denying the fact that the upsurge has created great activity and vitality across essentially every facet of the industry. In this article, the author has discussed the increase in production from the Eagle Ford and Williston Basin areas, the reduction in imports from distant sources, the rise of Canada, the immense changes in internal oil transport and oil flows, the impacts on refining and refinery utilisation, and the changes in product trade. Yet although these topics cut a wide swath, they provide only a brief overview of the impact of the shale boom, which truly is revolutionising the US oil industry.
The full article can be found in the June issue of Hydrocarbon Engineering
Edited by Claira Lloyd
Read the article online at: https://www.hydrocarbonengineering.com/gas-processing/27052014/shale_revolution_nancy_pt2/