US refiners’ potential response to tariffs
Recently, there has been much talk in the United States about tariffs on products from Canada and Mexico, including on crude oils imported by the U.S. Any such tariffs will inevitably impact the U.S. refining industry, with potentially significant impacts.
According to the U.S. Energy Information Administration, Canada and Mexico supply 4,300 kilobarrels per day (kbpd) and 733 kbpd of crude oil, respectively, to U.S. refineries, with domestic crudes representing most of the balance. We expect U.S. refiners to plan for both short- and long-term business ramifications in the face of tariffs on crude oil and exported products.
Here we examine the potential processing effects on a refinery and actions refiners can take to maintain profitability in light of changing crude prices. We acknowledge that there are several other factors at play such as exchange rates, logistical constraints for crude transportation on land and contracts, but our focus in this paper is on the processing impacts inside the battery limits of a typical refinery.
Background
Canadian crude is mostly from Alberta, much of it from the Oil Sands region around Fort McMurray. Borealis, Kearl, Cold Lake and Western Canadian Select are among the crudes that penetrate the U.S. market. Since the 1990s, refineries in the Petroleum Administration for Defense Districts II Midwest Region, PADD III Gulf Coast and PADD IV Rocky Mountain Region have significantly increased processing of Western Canadian crude via heavy investments in coking capacity, hydrogen production, metallurgy and sulfur processing.
Most of the Mexican crude including Isthmus, Olmeca and Maya is produced in the Gulf or nearby onshore. Maya is a heavy crude processed widely in the U.S., with many oil refineries in PADD III Gulf Coast geared to processes this crude.
Domestic crude, on the other hand, has more than doubled production since 2005 because of the shale-oil revolution. It is significantly lighter than the above crudes from Canada and Mexico. West Texas and New Mexico produce most crude from the Permian and Eagle Ford formations. Bakken in North Dakota and Wyoming is another region of growth. The current U.S. administration seemingly desires to build on that growth via tariffs.
Tariff impacts
Tariffs on Canadian and Mexican crudes are highly likely to increase their prices. Since these crudes tend to be heavier than domestic crudes, we expect the heavy-light differential to narrow, with a gradual shift from heavy crudes such as WCS and Maya to lighter crudes such as Eagle Ford and Bakken.
To complicate matters, the difference in refinery kit required to process these crudes is dramatic. A typical U.S. refinery coking refinery block-flow diagram is documented in Figure 1. For this configuration, Table 1 shows the unit capacities required for light domestic crudes as compared to their heavy counterparts. Likewise, Figure 2 illustrates the difference in gasoline and distillate production for the selected crudes.
We simulated various blends in the above refinery configuration and the resultant volume balances to illustrate the areas that will need revamping. Highlighted in yellow are the major focus areas.
The anticipated refinery impacts of switching to domestic crudes are the following:
More isomerization processing.
More naphtha-reformer processing.
More distillate processing required (applicable for Eagle Ford due to its composition, but not Bakken).
Less vacuum-tower processing.
Less fluid catalytic cracking (FCC) and alky processing.
Less delayed coker processing.
Less sulfur production.
Less hydrogen requirements.
How can refiners respond?
Refineries are generally operating in a capital-constrained environment, so large capital project solutions are not likely to be on the table. We recommend that customers focus on the following areas:
Optimization—Any significant changes in crude slate can leave the refinery in need of optimization, which should begin with workshops targeted toward debottlenecking, yield improvement, energy savings and CO2 savings that can provide no- to low-cost solutions. Optimization is accomplished with tools that are fit for purpose starting with base-case models tuned to current plant operation.
Preflash—More naphtha-range material in the crude-unit feedstock may justify the investment in a preflash tower as well as the middle-distillate side stripping columns.
Saturate-gas plant—Most refiners have not invested heavily in their gas plants. The ability to meet Reid Vapor Pressure specifications and make good fractionation splits may be challenged. A change in crude slate may require investment in separation equipment like bebutanizers and naphtha fractionators that will need to be debottlenecked for capacity. Investment in new pumps, state-of-the-art distillation-column internals, or heat-transfer equipment may be required. C3 recoveries and overall fuel-gas balance will need to be reviewed.
Distillate processing—If processing Eagle Ford, the ability to treat the larger volume of distillate may be challenging. Though the distillate should be easier to treat (fewer contaminants), hydraulic capacity may be bottlenecked. Jet-treater units, for example, may require debottlenecking.
Octane—With more isom and naphtha-reformer capacity required, the refinery may not be able to provide the octane required to produce premium product. Studies to debottleneck these units and improve molecule management may be warranted.
Intermediate feedstock—With spare capacity expected at the vacuum tower, delayed coker, FCC and alky unit, exploring purchasing intermediate feedstocks may be warranted along with projects to accommodate those purchases.
FCC utilization—FCC utilization peaked in 2009 at 6.3 million barrels per day (mmbpd) and has fallen to 5.5 mmbpd. This reflects the composition of domestic crudes as well as the dieselization of the transportation pool. Operational changes and improved distillation-tower hardware at the crude column, vacuum column and FCC column can offset the impact of crude slate changes.
Delayed coker utilization—Refiners may be challenged to operate the coker fractionator at low rates. Installation of heavy coker gas oil (HCGO) and light coker gas oil (LCGO) product-recirculation lines to the coker feed system can be reviewed at the expense of energy efficiency to increase rates. Operational changes and improved coker-fractionator internals can also help mitigate the impact of lighter feed. In extreme cases, some refiners may choose to idle their coking capacity seasonally or year-round and produce asphalt. Separately, solvent deasphalting can supply additional feedstock at the expense of petcoke quality.
Low-carbon fuels—An inescapable fact is that tariffs naturally increase the cost to produce a product. Depending on market conditions, refiners may reconfigure hydroprocessing units from hydrocarbon to renewable diesel production as the cost of production gap between fossil fuels and low-carbon fuels is narrowed.
Recommendations
Historically, our customers who have most successfully navigated periods of change or disruption have been those that adapt by recognizing and selecting the most advantageous crudes. While a commercial-planning department provides the long-term outlook and identifies the pinch points, we address the practical impacts on the actual refinery kit. We first facilitate workshops to generate ideas to address those issues. Ideas are modeled with refinery-wide modeling software and individual-unit process models. Conceptual cost estimates are generated for the most promising solutions including impacts on utilities and outside battery limits (OSBL) units. Given capex spend sensitivities, we prioritize low-cost solutions with capital breakpoint analyses. As geopolitical conditions change often, we recommend adding flexibility versus making a hard, irreversible change in a refinery’s processing capacities.
At Worley Consulting, we have the industry experts to supplement your team and address this new tariff challenge. We have extensive experience in working with customers to process opportunity crudes and make investments to increase flexibility.
Author: Dave Collings
Group Manager
Worley Consulting
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