The Complex Dynamics of Coprocessing

While oil refiners adding a small percentage of renewable feedstock to their operations sounds simple, the political, economic, technical, societal and market consequences are anything but.
By Ron Kotrba | October 24, 2018

In 2007, at the height of the biodiesel boom, ConocoPhillips and Tyson Foods announced a partnership to coprocess animal fats with petroleum crude oil at a number of U.S. oil refineries. Such partnerships between Big Oil and agriculture stand to threaten years of investment, feedstock, public policy and market developments by biodiesel producers. The future was uncertain, particularly since at the time, coprocessed renewable diesel produced from recycled feedstock such as pork fat qualified for the blenders tax credit at the reduced rate of 50 cents per gallon, just like biodiesel made from those same feedstocks at a standalone plant. In 2008, the National Biodiesel Board under the leadership of its former CEO Joe Jobe was successful in lobbying Congress to not only extend the tax credit for another year, but also in getting recycled feedstock to qualify for the full dollar. More importantly, Congress also closed the splash-and-dash loophole that was fleecing taxpayers, and it excluded coprocessed renewable diesel from qualifying for the blenders tax credit. Just months later, in 2009, the partnership between ConocoPhillips and Tyson was put on hold.

Much has changed in the past decade. Regulations for RFS2 were established and the program was implemented, helping grow production and use of biodiesel and renewable diesel in the U.S. to billions, rather than millions, of gallons. The compliance mechanism of RINs provided an economic stimulus to producers. State markets blossomed—most notably, California’s lucrative LCFS market, which is driven by increased demand for low-carbon fuels. And Big Oil stepped up its campaign to discredit and undermine the RFS through any means necessary. Of late, small refinery exemptions granted by the Trump administration’s EPA to large, profitable oil refiners that are obligated under law to blend renewable fuels have weakened demand for biofuels and caused RIN values to nosedive.

One notable development that has taken root over the past decade, since the emergence and dissolution of the ConocoPhillips and Tyson partnership, has been oil companies’ investment in renewable diesel. Finland-based Neste Corp. has become a major worldwide player, exporting hundreds of millions of gallons to the U.S. alone each year. Valero and Darling Ingredients developed a large, greenfield, standalone renewable diesel plant in Louisiana, which is expanding. Less-profitable oil refineries, such as those in France, Italy and the U.S., have undergone or are undergoing complete conversion from processing crude oil to lipids. And, once again, oil companies have begun, or have announced plans to coprocess fats, oils and greases. These include BP, Chevron, Andeavor (recently acquired by Marathon Petroleum Corp.), Sinclair and others.

Important Distinctions
Before articulating the complex issues surrounding the potential proliferation and consequences of coprocessed renewable diesel, there must be clear definitions of what’s at play. Biodiesel is a diesel fuel substitute consisting of mono alkyl esters that is similar to but different than petroleum diesel fuel. Renewable diesel is a hydroprocessed fuel that is chemically indistinguishable from and fungible with petroleum diesel fuel. Both can be made from the same pool of renewable feedstocks of fats, oils and greases, and both are considered by the EPA to be biomass-based diesel for purposes of administering the RFS. As a result, both can generate D4 RINs in the biomass-based diesel category of RFS.

Greenfield or standalone biodiesel and renewable diesel production facilities are distinguished from oil refineries that are converted to process renewable diesel, whether in whole or in part, and from oil refineries that coprocess renewable diesel. While some oil refineries have converted their entire site operations to process renewable diesel, others may co-locate renewable diesel production on-site, which is also different than coprocessing.

“The first important thing is how we define what coprocessing is,” says Scott Fenwick, NBB’s technical director. Fenwick says there are a couple of different ways an oil refiner could coprocess renewable diesel. One route, he says, is to blend a small percentage of renewable feedstock such as soybean oil with crude petroleum oil and move it through the entire refining process. “This is the least likely choice,” Fenwick says, as pushing renewable feedstock through the distillation process followed by a fluid catalytic cracker (FCC) or hydrocracker could cause catalyst fouling, increased product loss and other technical issues. A more likely route is blending a small percentage of renewable feedstock into middle distillate cuts after distillation and cracking, prior to the diesel hydrotreater. “That’s the least severe option,” Fenwick says. “That’s what a refinery would put diesel through to remove sulfur. With renewable feedstock, hydrotreating would convert the oxygen and glycerin into water and propane, and make everything else into a hydrocarbon while maintaining the length of the molecule.”

Sinclair’s oil refinery in Casper, Wyoming, is moving forward with a renewable diesel project, but details are unclear and the oil company declined speaking with Biodiesel Magazine about the endeavor. This year in Blaine, Washington, BP’s Cherry Point refinery “launched a renewable diesel unit that can coprocess biomass-based feedstock alongside conventional feedstocks to produce ultra-low-sulfur diesel,” according to the refinery’s website. Representatives from BP were unable to speak about the project before press time.

Last year, another oil company with a renewable diesel project, Tesoro, changed its name to Andeavor. This fall Andeavor was acquired by Marathon Petroleum Corp., which owns a 70 MMgy biodiesel plant in Ohio called Cincinnati Renewable Fuels. In Dickinson, North Dakota, the company’s 20,000-barrel-per-day (bpd) oil refinery is entering the second phase of its renewable diesel project. Phase 1, coprocessing of vegetable oils with crude oil, was announced last year and began this summer, according to Ron Day, government and public affairs director for the Dickinson refinery. “Actual coprocessing began in June,” Day tells Biodiesel Magazine. He says modifications were made to offload vegetable oils into the facility, “including piping and connections to make that happen.” Day says the investments made in Phase 1 were a precursor to Phase 2, which is full conversion of the refinery to solely process biomass feedstock into renewable diesel. “It helped demonstrate that this was doable,” Day says of Phase 1. Construction work on the full conversion project in Dickinson began this fall, according to Day, and it is expected to be complete in late 2020. Day says the refinery will continue to coprocess renewable feedstock with petroleum crude oil until conversion is complete.

The converted oil refinery will utilize an existing hydrotreater and hydrogen plant as part of the process, Day says. “But we will also be adding another diesel hydrotreater process that is larger than the existing one, and a larger hydrogen plant,” he says. “Those are the two biggest pieces of the project. Everything else is in place—the tankage, truck offloading and the ability to get the product to the rail terminals.” The coprocessed renewable diesel produced while the conversion project is underway is staying in North Dakota, Day says, but once the site is producing renewable diesel exclusively, all of the 12,000 bpd of product will be railed to California to take advantage of the state’s LCFS credits. Today, those credits are trading at nearly $200 a ton.

The Issues
The strain of added feedstock demand from oil refiners is one of the biggest concerns the biodiesel industry has of coprocessing, but it certainly isn’t the only, or necessarily the most important, one. Fenwick says if PADD 5 (West Coast) oil refiners were to coprocess just 1 percent vegetable oil, this would create an additional annual feedstock demand of 482 million gallons. “That’s a huge volume,” Fenwick says. “It’s certainly not going to happen overnight, but it would create a significant demand of renewable feedstock.” According to Jobe, who left NBB in 2016 to start his own consulting firm called Rock House Advisors, there is approximately 314 billion gallons of annual petroleum refining capacity in the U.S. and Canada today. “If that capacity were to coprocess just 2 percent vegetable oil, this would create an additional demand of 6.28 billion gallons of lipids,” Jobe tells Biodiesel Magazine. “We don’t have that much. Keep in mind this is using the crude oil coprocessing route rather than middle distillate coprocessing, but it gives you an idea of the scale of this issue.

Even though agricultural productivity and new feedstock developments continue to increase, the entrance of oil refiners into the finite market of renewable feedstock does pose a threat, says Donnell Rehagen, CEO of NBB. “There’s a limited pool of feedstock used in production of biodiesel and renewable diesel, and they all rely on that same pool, which is only so big,” Rehagen says. “Our industry has built itself out with that in mind. We have not wanted to overbuild capacity. The scale of these oil refineries is exponentially larger than biodiesel plants, so if they step in and economically, easily and quickly begin coprocessing renewable feedstock, it would soak up a large amount—and that can be devastating to our industry.” Rehagen says the EPA and the petroleum industry define small refineries as those that process 3 million gallons of fuel a day. “That’s a billion gallons of fuel a year,” he says. “Converting just one ‘small refinery’ can have a huge impact on demand in the renewable feedstock pool.”

Gene Gebolys, founder, president and CEO of World Energy, has chaired the NBB’s RFS working group for a number of years. “There are indeed ample supplies of lipid feedstock for robust growth in the D4 and D5 categories,” Gebolys says. “Over its 10-year life, the RFS has driven biomass-based diesel production from about half a billion gallons to approaching 3 billion gallons, or 5 percent of the distillate supply. The U.S. has become the leading biomass-based diesel producer in the world, yet feedstock prices are as low as they’ve been since RFS implementation 10 years ago. And with a bumper crop of oilseeds being harvested as we speak, availability of feedstock has never been stronger.”

For Gebolys, the issue with coprocessing is less about which process will outcompete the other for feedstock and more about which process will outcompete the other to fill D5 volumes—the undifferentiated advanced biofuel volumes above specified biomass-based diesel (D4) and cellulosic biofuel (D3, D7) volumes in annual RFS quotas. Coprocessed renewable diesel cannot generate D4 biomass-based diesel RINs, but it can produce D5s. “Biomass-based diesel and coprocessed renewable diesel will be competing to fill the volumes of the D5 or undifferentiated advanced category of the RFS, which is the category that the EPA has historically shown a preference for in terms of leading most of the growth in advanced biofuel,” Gebolys says. “The renewable volume obligations (RVOs) in the D5 category will determine how many gallons of fuel will be generated by biomass-based diesel and coprocessed renewable diesel and, therefore, how many gallons of lipid feedstocks will be used to fill those RVOs. In other words, the determining factor for the amount of fats and oils feedstock that will be used to make biomass-based diesel and coprocessed renewable diesel will be the D5 RVOs, and not which process will prevail in the competition to generate those D5s.” Gebolys adds that coprocessed renewable diesel will soon be able to generate LCFS credits in California.

Another real concern is Big Oil’s perceived lack of commitment to renewable fuels. Rehagen says NBB will invite anyone into its organization provided they see biodiesel and renewable diesel as viable well into the future. Even though some oil companies have invested in standalone biodiesel and renewable diesel capacity while others are looking into coprocessing, the vast majority of current oil refiners naturally produce petroleum-based fuels. “We need committed companies, individuals and organizations in the NBB,” Rehagen says. “If they want to demonstrate their commitment to the future of our industry, the renewables industry, we welcome that conversation.”

The problem, however, is that even though some oil companies are investing in renewables, many of those same firms—and certainly the associations representing them, including the American Petroleum Institute and the American Fuel and Petrochemical Manufacturers—want to dismantle the RFS and thereby destroy demand for renewable fuels. “The biggest proponents of coprocessed renewable diesel are on record as strongly opposing the RFS,” Gebolys says. “They are also advocating significantly lighter compliance requirements for coprocessed renewable diesel than is currently required for biomass-based diesel, which, if accepted by regulators, would greatly advantage coprocessed renewable diesel.”  

Biomass-based diesel is one of the most heavily regulated set of fuels. “It is regulated by robust compliance measures to meet precise specifications of the finished fuel and must be tracked through the supply chain to make sure it is not exported or used in nonqualifying applications,” Gebolys says. “Biodiesel gets no credit for its byproducts such as glycerin, only credit for the finished product. Coprocessed renewable diesel advocates are trying to persuade regulators that when they blend off small percentages of lipids into their crude oil feedstock, that they be allowed to use a mass-balance approach. In other words, they want to be able to get credit for a full gallon of finished fuel for every gallon of lipid they blend into the frontend of their process. They don’t want the finished fuel to be tracked through the supply chain, which would allow it to end up in exports and nonqualifying applications. They also don’t want to have their finished product tested for renewable content or to meet a renewable fuel specification.”

Lipids are 11 percent oxygen and 10 percent glycerin. Through coprocessing, those compounds end up as what Gebolys calls “nonqualifying, nontransportation fuel byproducts” including propane, water and other chemicals. “Yet they want to receive full credit for their finished fuel based on the amount of feedstock in rather than the finished fuel out,” Gebolys says.

“I think the biodiesel industry is happy to compete on a level playing field,” Fenwick says, “but what we want to see is how these regulating agencies—California Air Resources Board and EPA—are going to allow these credits to be generated. The argument for those who want to coprocess is that it’s difficult to determine what actual renewable content is in the fuel when leaving the gate—so difficult that it should be able to generate credits up front on the volume of feedstock.” One option, however, would be to subtract out the average losses. “But that wouldn’t be fair,” Fenwick says, “since no two refineries are the same.” He adds that NBB has commissioned a study of the ASTM D6866 test method for radio carbon dating, which can identify the biogenic content of fuel. “The method was originally written for the USDA’s BioPreferred Program,” Fenwick says. “We’re wrapping up our study and will be presenting it soon to CARB for its Oct. 19 webinar.” Items the study addresses include how low a level of detection the technique can measure, and how repeatable, reproducible and accurate it is. 

Furthermore, Gebolys says while biomass-based diesel plants are heavily regulated by EPA for various steps in the process for purposes of RFS registration and permitting compliance, coprocessed renewable diesel advocates wish to avoid detailed evaluation of the carbon intensity of their processes, which vary from refinery to refinery. “And if coprocessed renewable diesel is treated in a way that it is given an unfair compliance advantage—amounting to significantly higher levels of public policy support—while providing significantly lower levels of public policy benefits, we should all be concerned,” Gebolys says.

Lower societal and public policy benefits associated with coprocessed renewable diesel are significant sticking points for the biomass-based diesel industry. These encompass a wide range of important considerations, such as whether coprocessed renewable diesel creates jobs, investment in rural and green economies, and added gallons to the marketplace. Gebolys says not only can coprocessed renewable diesel and its D5 RINs unfairly squeeze out biomass-based diesel from fulfilling those volumes, but “refiners could begin these projects with little investment in their existing refineries and no long-term commitment to renewables,” he says. “This translates to little economic or public-policy benefit.”

Henri-Jean Bardon, a director and investor in Solfuels USA, a 40 MMgy biodiesel plant in Helena, Arkansas, says dissemination of coprocessed renewable diesel can cause markets to go haywire. “It could double the price of soybean oil in the marketplace,” thereby squeezing biodiesel producers out of the market, he says. “Then, oil companies could just drop coprocessing. It’s a crazy situation, to be honest. It doesn’t add jobs, and my personal point of view is I think we are walking away from the tailpipe emissions benefits of biodiesel that started this whole renewables movement in the first place. It gets lost in the overall politics of it all. To me, on both sides of the Atlantic, they’ve been trying to kill traditional biodiesel for the past few years. That seems to be the trend, and I don’t understand why. Maybe it’s coming from the fossil fuel industry, I don’t know. To me, it doesn’t seem logical. If there is a threat to the fossil fuel industry, it’s definitely the electric car—not biodiesel and ethanol. Ethanol and biodiesel are assisting the fossil fuel industry with continuing to sell its gasoline and diesel products. So I don’t get it.”

Rehagen says, “First and foremost, part of the interest Americans had in renewable fuels was rejuvenation in rural economies and investment in jobs by new facilities. So for existing refineries to retool their plant to process different input products than crude oil, there’s no new jobs created by that. It’s a significant difference.”

Furthermore, neither the conversion of oil refineries to produce renewable diesel nor coprocessing of renewable feedstock with crude oil provide additional gallons to the marketplace. “They’re simply not making a gallon of what they were before and are now making a gallon of this,” Rehagen says. “That’s where we’ve viewed biodiesel plants as adding to the energy infrastructure, creating jobs, energy security and independence.” In some instances, like the Dickinson refinery, the oil refinery could process 20,000 bpd. In 2020, once its conversion project is complete, the site will be able to produce 12,000 bpd—a reduction of 8,000 bpd. “Those are better gallons than what was produced before,” Rehagen says, “but investments are not lost to these large refiners who are able to retool and take off from there, compared to our investments, which are from the ground up. A brand new biodiesel plant or renewable diesel plant is going to be a huge economic injection in the community and region. In the case of retooling an existing refinery, we’re unlikely to see new jobs come out of that. It may have a short-term impact on the local economy, but long-term there would not be a significant economic impact compared to what it had before. That’s where the models of building additional plants to increase biodiesel and renewable diesel production is preferable to us. And it’s consistent with our promise to lawmakers to increase fuel availability in the marketplace. New plants add gallons. Retooled refineries do not.”

Not only would coprocessing not add additional gallons, but some say it could actually negate the entire volume of vegetable oil put into the process. “My opinion is, if they are putting 2 percent vegetable oil into coprocessing, they can end up losing most of that in the refining process,” Bardon says. “Essentially the vegetable oil can become a pure loss. As long as vegetable oil prices are low, maybe that’s a calculation some refiners will make.” Gebolys agrees, saying oil refineries are optimized to produce petroleum fuels while biofuels production facilities are optimized in processing renewable feedstock. “In a coprocessed renewable diesel project, it is possible that an injection of 1 percent lipids into a refinery stream could result in a 1 percent reduction in refinery efficiency,” Gebolys says. “This would have a net result in producing nothing. This could be one reason why coprocessed renewable diesel advocates are resisting receiving the kind of process examination that biomass-based diesel producers receive, beyond just having the incentive of a reduced compliance burden.”

Related to losses, technical considerations exist as well. Renewable feedstock can offer new challenges that were not considered when oil refineries were originally built. “Issues like corrosion,” Fenwick says. “They’ll need to take into account the metallurgy, as the oxygen molecules in renewable feedstock are converted into water, which can be corrosive. And there are significant losses depending on the process technology.” A biodiesel producer cleaves the glycerin backbone of triglycerides and coproduces crude glycerin. A refiner turns that into C3, or propane, so whether they have the ability to capture it or send it straight to the flare as a loss, or recover it for heat and power in cogeneration, has to be taken into account. For these reasons, Fenwick says, some refiners may not want to jump into coprocessing with both feet.

Beyond actual volume output of renewable fuel content from coprocessing, the carbon and emissions benefits, if any, are less than clear. “People are not talking about emissions benefits of coprocessing,” Bardon says. “Do you get the same benefits through coprocessing as through blending?”

Fenwick says, “We have a wealth of data on the quantifiable health, emissions and performance benefits of biodiesel and renewable diesel that a truly coprocessed fuel may not have yet.” Numerous studies have looked at emissions from RD100 or B100. “Even coprocessed fuels can achieve better emissions,” Fenwick says, “but I haven’t seen any results to validate that.”

Biodiesel is one of the most tested fuels on the planet, with nearly two dozen iterations of its ASTM D6751 quality standard, allowance of up to 5 percent biodiesel in the diesel fuel spec (ASTM D975), a separate ASTM D7467 standard for B6 to B20 blends, allowance of blends up to 20 percent in the heating oil spec (ASTM D396), and much more. “It is accepted by almost all OEMs in blends up to B20 and in higher blends by some,” Gebolys says. “Biodiesel in blends of B5 to B20 offer a range of premium characteristics that are superior to ULSD, including performance, with high lubricity and cetane; safety, with high conductivity that reduces static discharge and high flashpoint; and emissions, with low sulfur and aromatics, and overall reduction in virtually all regulated emissions.” Furthermore, biodiesel is less expensive to make and usually has a higher blend margin than renewable diesel, Gebolys adds.

Biodiesel advocates say there is room in the market for both renewable diesel and biodiesel, and perhaps a harmonious blend is some concoction of the two in which biodiesel can add much needed lubricity to renewable diesel. “Biodiesel, we know, is very suitable for blending with renewable diesel from a technical standpoint, so a blend of biodiesel and renewable diesel can be even better than straight renewable diesel,” Rehagen says. “There are lots of opportunities to sort through all of this. Where we find ourselves now is, demand is high and growing fast.”

Gebolys reiterates what many biodiesel advocates argue—investments made in biodiesel plants are critical. “Imagine partnerships between traditional refiners and agriculture,” he says. “Is that symbiotic? Absolutely not. What I mean is that some agricultural producers of biodiesel feedstocks—farmers, ranchers, renderers—might be tempted to support more coprocessed renewable diesel projects by traditional refiners under the misconception that it will just lead to more demand for their products. This is not the case. The amount of agricultural lipids used to make biofuels will be determined by the RVOs set in the D4 and D5 categories, and not by how many different biofuel technologies are competing to meet those volumes. So agricultural stakeholders who cheer on coprocessed renewable diesel projects by traditional refiners are doing so at the expense of standalone biomass-based diesel companies that have invested billions to build up their plants and their industry. They are committed to the long-term health and growth of this industry. Traditional refiners advocating favorable coprocessed renewable diesel treatment are making little to no investment, have little skin in the game, and mostly oppose the RFS. Conversely, standalone biomass-based diesel producers inject $11 billion annually into the economy and support more than 64,000 jobs. Coprocessed renewable diesel adds almost nothing to the economy and supports nearly zero new jobs.” 

Author: Ron Kotrba
Editor, Biodiesel Magazine
[email protected]

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