The Hydrogen Wall: Looking at the prospects for drop-in biofuels

August 11, 2014 |

the-sunThink affordable, available, sustainable carbon is the biggest barrier to the growth of biofuels? Or, access to market via blender pumps?

In the case of drop-in biofuels, the biggest challenge might be finding enough hydrogen.

You might have heard of the Hydrogen Economy, the Hydrogen Miracle, the Hydrogen Car, or that free hydrogen (H2) is the most abundant molecule in the universe. The latter is true — but you’ll have to harvest by piloting your astro-combine into the interior of the Sun. (Er, good luck, keep me posted on your progress.)

Here on earth, hydrogen is trapped in a variety of compounds — most famously, water. Which is just fine for most people, but not for developers of renewable fuels and chemicals.

Is there a hydrogen barrier to drop-in fuels? As a trio of authors put it, part of the International Energy Agency’s Task 39 Group working on the development of a global biofuels industry, “One challenge that the development of drop-in biofuels shares with the global petroleum industry is the requirement for increasing amounts of molecular hydrogen.”


Why hydrogen?

As UBC’s Sergios Karatzos and Jack Saddler, along with NREL’s James D. McMillan explain: “Oil refineries use hydrogen to upgrade low-grade crude oil, both to remove problematic sulfur and other heteroatom impurities (hydrotreating) and to “crack” longer carbon chain molecules to shorter chain molecules while also enriching them with hydrogen (hydrocracking). In the case of petroleum, more hydrogen will be needed to upgrade crude oil feedstocks of declining quality (i.e., increasingly heavier and more sour, as in the case of heavy oils being sourced from Venezuela and Canada).”

So, that’s petroleum. What about biofuels?

“Similarly, greater amounts of hydrogen are generally needed to produce more energy dense and highly reduced drop-in biofuels…to remove oxygen from oxygenated lignocellulose intermediates or lipid feedstocks. Non-hydrogen-consuming processes such as catalytic or thermal cracking can also be used to increase the H/C ratio of petroleum feedstocks by removing carbon in the form of tars and char (coke). However, this approach consumes feedstock and reduces yields and so is generally avoided, particularly when prices for crude oil feedstocks are high.”

The report from Task 39 is “The Potential and Challenges of Drop-in Biofuels” and it’s a must-read for anyone in the field as a summary of the challenges and a primer to guide drop-in R&D moving forward.

The Report: A Must-Read

Though the 210-page report (available here) or the 21-page executive summary (available here) cover a range of topics — it zeroes quickly in on the hydrogen problem.

Or, rather, the two problems. First, with biofuels feedstocks, to get the hydrogen/carbon ratio right for drop-ins, you either are blowing off hydrogen and oxygen (reducing yield), or adding hydrogen (adding complexity and cost — for example, where do you get the free hydrogen in the first place?).

The exception “are the biomass-derived lipids and other oleochemical types of biomass feedstocks, which start much farther up the H/C staircase and are thus more readily suited for conversion to drop-in biofuels than other types of biomass feedstocks.”

But, er, “hydrotreating units processing oleochemical feedstocks have about an order of magnitude higher hydrogen demand than those processing conventional petroleum feeds…because biomass contains much more oxygen (approximately 10 wt% oxygen in vegetable oils and 40 wt% oxygen in lignocellulosics).”

Turns out, drop-in fuels offer a no-brainer market but quite a challenge in economics and technology.

So, let’s look at the report in a little more detail, via a condensed Digest version which is about 10% of the size of the executive summary.


What about co-processing biofuels and petroleum at refineries, to reduce capex and opex?

“Even at low biofeed blending levels, the disparity in hydrogen requirements can lead to problems in co-processing biofeeds with petroleum feeds. Reported difficulties include hydrogen starvation and excessive pressure drops within hydrotreating units, as well as poor desulfurization (of the petroleum feed fraction) through coking and deactivation of hydrotreating catalysts. As a consequence of these issues, HVO biofuels are currently produced in commercially significant volumes in stand-alone facilities using specialised conditions and catalysts.”

OK, is that the only reason that more HVO drop-in fuels are not yet available?

“One of the major reasons why there has not yet been more extensive deployment of HVO biofuel technologies is that the selling price of the vegetable oil feedstocks has historically been higher than the selling price of diesel and jet fuels. Vegetable oils such as palm and rapeseed are, at the time writing, priced in the range of USD $500-$1200/t (or $12-30/GJ) [compared to approximately USD $75-$125/t (oven dry basis, or $4-6/GJ) for lignocellulosic biomass] and their supply is often limited by competition from other value-added markets (e.g., food and cosmetics industries).”

What about technologies like fast pyrolysis? Aren’t they a low-cost route?

“Fast pyrolysis essentially exposes small biomass particles (ca. 3 mm) at a temperature of about 500 °C for a few seconds to produce a “bio-oil” (up to 75 wt% yield) at relatively low cost (estimated at ca. $10 USD/GJ based on a USD $83/t (oven dry basis) feedstock).”

So, what’s the hold-up with deploying pyrolysis?

“Pyrolysis bio-oils contain up to 40% oxygen and need to be extensively upgraded to produce deoxygenated hydrocarbon drop-in biofuel blendstocks. It is estimated that current US refinery hydrogen-generating capacity of 3 billion standard cubic feet per day, would need to be tripled to meet the 2022 US RFS advanced biofuel mandate of 15 billion gallons using pyrolysis. While hydrogen can be generated from the biomass feedstock itself, this process is costly from both capital and operating cost perspectives compared to hydrogen derived from natural gas. ”

What about co-locating pyrolysis technology within refineries?

“The dilemma in trying to identify refinery insertion points for renewable feedstock drop-in biofuel intermediates is to what extent should the intermediate be upgraded (deoxygenated) prior to insertion and to what extent should the refinery be adapted to accept less-upgraded, oxygen-containing intermediates.”

“Pyrolysis technologies have great potential to leverage existing oil refinery infrastructure to reduce biofuels production capital and operating costs. However, although existing hydroprocessing units (downstream in a refinery) can theoretically be used to co-process petroleum and hydrotreated pyrolysis oils (HPO), this practice is not yet commercial and it comes with challenges related to adapting hydrotreating catalysts to be able to perform well on blends of two disparate feedstocks (HPO and petroleum).”

What are the catalyst problems?

“For one, bio-oil hydrotreating catalysts with a lifespan exceeding 200 hours have not yet been demonstrated at scale (for comparison, the lifespan of current petroleum hydrotreating catalysts routinely exceeds 6 months). Catalysts using platinum and ruthenium are less prone to coking and more selective, but areorders of magnitude more expensive than conventional cobalt and molybdenum-based hydrotreating catalysts.”

Could a 2-step process help?

“It has been suggested that a two-step hydrotreatment process might be a more cost effective approach to bio-oil upgrading. The first step would stabilize the bio-oil by selectively hydrotreating its most reactive (unstable) organic species and, once stabilized in this manner, a second step would be used to complete hydrotreatment.”

If pyrolysis were integrated in an existing refinery, how could that happen?

“The present analysis concludes that there are two particularly favorable insertion points for pyrolysis oils, namely before either a refinery’s Fluid Catalytic Cracking units or its hydroprocessing units.”

What’s attractive about FCC units?

“The rationale is that FCC units have a similar configuration to the fluidized bed reactors used for pyrolysis. These units are at the heart of an oil refinery and are mainly used to crack heavy petroleum cuts and maximise production of lighter cuts such as gasoline blendstocks.

“As gasoline consumption continues to decrease relative to diesel consumption within global fuel markets, many refinery FCC units are becoming underutilized. In the US, fully 20% of FCC units were idle in 2013 and more are expected to be idle over the next decade or so. Inserting minimally upgraded pyrolysis oils into FCCs (e.g., in blends with vacuum gas oil) provides a strategy to put these “stranded” assets into productive use while also providing a “green credit” to a refinery’s product slate.

“The FCC insertion point for pyrolysis oils represents a “workhorse” approach where little hydrogen is used and the bio-oils are minimally preprocessed and then co-processed with heavy vacuum gas oils to produce a relatively low value hydrocarbon intermediate and large amounts of renewable power.”

What about the hydroprocessing units?

“The second, more “boutique” insertion point for bio-oils in a refinery is before the refinery’s hydroprocessing unit operations. Hydroprocessing is more sensitive to oxygen and impurities than FCC units and hydroprocessing insertion of pyrolysis oils relies on substantial hydrogen inputs, much costlier catalysts and extensively pre-processed bio-oils.

The good news?

Taking the hydroprocessing route “produces increased yields of higher value middle distillates such as diesel and jet fuels than the FCC insertion strategy.”

What about gasification?

“The other major thermochemical route to drop-in biofuels is through gasification. Gasification of biomass or bio-oil produces synthesis gas, which can be upgraded (catalytically condensed) to drop-in liquid biofuels via the Fischer-Tropsch process. However, biomass syngas needs to be enriched in hydrogen and cleaned of impurities. Hydrogen is typically produced from the syngas itself, but this reaction consumes feedstock carbon and thus reduces the overall biomass-to-fuel yields. Generally, gasification technologies entail high capital costs. ”

What about biochemical pathways — fermentation?

“Depending on the microorganism used, the “biochemical drop-in pathways” can produce highly reduced biohydrocarbon molecules such as sesquiterpenes and fatty acids thus minimizing the degree of final hydroprocessing needed to bring the biofuel product up to diesel, gasoline or jet fuel specifications.

“However, most of these advanced biological pathways require more energy and carbon intensive metabolic processes, and the metabolic pathways are typically activated under conditions of stress, thus industrial stability of these biological systems can be problematic.

And, drop-in biofuels might not be the best value proposition for the biochemical processing of biomass and sugars. Biochemical platform routes are already well suited to make oxygenated products such as carboxylic acids, alcohols and polyols that can generate substantially higher revenues in the rapidly growing bio-based chemicals markets. Until these value-added markets are saturated, there is little economic incentive for the biochemical platform companies to focus on drop-in fuels. ”

What about upgrading fuels made with traditional fermentation, like alcohols, to drop-ins like jet fuel?

“Though ATJ and acid-to-alcohol technologies are technically proven, the drop-in intermediates and many of the proposed feedstocks, such as ethanol, acetic acid, ethyl acetate, etc., are typically more valuable (on an energy basis) as chemicals than as jet or alcohol fuel products.”

What are the areas where R&D could address some or all of these challenges?

• Development of economically viable processes to produce renewable industrial grade hydrogen;

• Establish more cost effective and area efficient terrestrial or aquatic based systems to produce oleochemical feedstocks;

• Improve the cost, performance, lifespan and recyclability of hydroprocessing catalysts for oxygenated biomass feedstocks;

• Create economically viable small scale gasification and syngas cleanup processes;

• Produce biofuel intermediates that are miscible and better able to be co-processed with petroleum feeds;

• Improve the productivity and product recovery methods of biochemical platforms;

• Develop the potential synergies of co-processing bio-oil and fossil liquids in thermochemical processes and in existing petroleum refineries.”

What kind of strategic, logistic recommendations does the Task 39 Group make?

• Use of pyrolysis oils as intermediates for gasification (logistics benefits);

• Utilize idle Fluid Catalytic Cracking (FCC) and hydrogen generating capacity located within current oil refineries;

• Incorporate value added chemicals in all drop in biofuel platforms, particularly in the case of biochemical platforms;

• Develop and implement policy measures that differentiate and enhance drop-in biofuels RD&D and reduce regulatory hurdles limiting the co-processing of bio-oils in oil refineries;

• Include and consult with the aviation sector in the development of drop-in biofuel promoting strategies (i.e. development of drop-in aviation biofuel mandates and tax incentives as well as transportation GHG reduction strategies such as those described in the EU ETS and the US RFS).

The Bottom Line

The hurdles are varied — starts with the economic challenge that the intermediates are sometimes more valuable than the drop-in fuel. R&D and markets may address those — or not. But they affect certain pathways more than others.

Then, there are the logistic challenges — that is, how to drop-in the process to existing infrastructure — not just create a drop-in fuel.

Finally — and the most daunting — the hydrogen problem. Cheap hydrogen generally is sourced from petroleum, so that imposes sustainability and logistic constraints. There’s hydrogen in biomass itself — but using it for processing rather than within the finished fuel reduces yield, and causes more stress on feedstock costs.

Two possible solutions?

First, the biorefinery model where a combination of high-margin, low-volume chemicals generate 20% of the volume and 80% of the profits, while low-margin, high-volume fuels generate 20% of the margin and 80% of the volume. Works generally only in markets where the chemical demand is relatively saturated, or easy to do so.

Second, the two-step processing approach. Small-scale pyro units process biomass locally, and do a preliminary upgrade, to make a biocrude out of bio-oil. The resulting product is shipped to refineries, which can more easily integrate it either into a blend of feedstocks, or process it effectively using modified FCC units.

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