Refinery Operations Logo

Process Complexity Increases with Unconventional Crudes

According to the latest International Energy Agency (IEA) World Energy Outlook (WEO) report, the IEA now sees all forms of oil, conventional and unconventional, hitting a high of 99 million bpd by 2035, including 3.0 million bpd of ‘refinery gains.’ However, this represents a growth rate in oil of only around 0.5% per year between now and then.

New oil and gas sources give refiners flexible options.

New oil and gas sources give refiners flexible options.

This means that over the next 20 years, the global economy will have to make do with less than half the rate of growth in oil that it enjoyed over the prior 20 years.  The IEA noted that conventional crude oil peaked in 2006. Any gains from here are due to contributions from unconventional oil and natural gas sources. Under no scenario envisioned will future growth in fossil fuel supplies be equal to prior rates of growth.

Between now and 2035, total energy demand grows by 36%, or 1.2% per year, according to the IEA. This is significantly less than the 2% rate of growth seen over the prior 27 years, and renewable fuels will be contributing very little to the overall energy landscape, just 14% of the total. 93% of all the demand increase comes from non OECD countries (mainly China and India). Oil remains the dominant fuel (although diminishing in total percentage).

How can projected oil growth slow down to only 0.5% per year when we all know that China and India have been growing their oil consumption by massive percentages in the recent past? It is expected that China, India and other non-OECD countries will be increasing their consumption by rates much higher than 0.5%. It therefore stands to reason that some other countries, primarily OECD countries, will have to consume at negative rates in order for the equation to balance. Of course, recent environmental disasters such the Fukishima nuclear reactor crisis in Japan may have predicated some reduction in energy consumption in that regions.

However, just as it seemed that the world was running out of oil and gas, giant oil fields were beginning to be exploited, such as the Permian Basin Petroplex in Texas and Canadian oil sands projects. They expanded so fast, they now provide North America with more oil than Saudi Arabia. Not only has the U.S. has increased domestic oil production for the first time in 40 years, gas production, such as from the Eagle Ford Shale formation, that energy and utility costs have significantly reduced the cost of refinery operations, such fired heaters can run at maximum rates and hydrogen production can be ramped up for high severity hydrotreating and hydrocracking operations.

It is nonetheless important to note that it’s not the amounts that matter (e.g., 100 years of natural gas available in U.S. at current rates of consumption), but the rates at which the oil can extracted. In any event, no matter how efficient the upstream industry is in exploiting shale based light tight oils and other unconventional hydrocarbon sources, the rate at which these hydrocarbons can be economically upgraded at downstream processing facilities could be a challenge. For example, while no new major delayed coker projects are expected to be announced in North America for the foreseeable, Middle East refiners and even one European refiner (ExxonMobil Antwerp refinery) are building cokers to process heavy crudes with high CCR and refractory properties.

Processing unconventional hydrocarbons requires more hydrogen, higher conversion temperatures and higher overall plant complexity to yield clean transportation fuels, lubricants and petrochemical intermediates at the other end. In between the front end and back end of the plant, higher probabilities of corrosion and fouling are to be expected, such as the higher percentages of heavy Canadian crudes being processed by Midwestern refiners in the U.S.

Oil companies will be compelled to increase their downstream capital and operating budgets to accommodate whatever types of low quality crudes that they can get. Looking at budget outlays of refiners that that many of us have access to, it looks like 2016 looks to be neither a bumper year, nor one of drought, in terms of downstream capital expenditures.

Leave a Reply

Posted by: Rene Gonzalez

Rene G Gonzalez is the Director for and contributing editor for As a chemical engineer (Texas A&M University: 1982), Gonzalez has worked in various engineering capacities throughout the energy industry value chain, primarily in refinery processing and operations.

Refinery Operations