August 2022

Special Focus: Refining Technology

Green refinery challenges: Small-scale sulfur recovery

As the gavel dropped, signaling a historic agreement at the conclusion of COP26 (2021 United Nations Climate Change Conference) in Glasgow, Scotland, leaders from 197 nations agreed to continue supporting the goal of limiting global warming to 1.5°C above pre-industrial levels. The race is on!

Echt, W., Merichem

As the gavel dropped, signaling a historic agreement at the conclusion of COP26 (2021 United Nations Climate Change Conference) in Glasgow, Scotland, leaders from 197 nations agreed to continue supporting the goal of limiting global warming to 1.5°C above pre-industrial levels. The race is on!

Two initiatives that emerged from COP26 were the Mission Innovation and Carbon Dioxide (CO2) Removal Projects. Mission Innovation—a collaboration among governments to unlock affordable decarbonization pathways—seeks to accelerate technologies that will reduce emissions by the sectors responsible for 52% of current global emissions. The Netherlands and India are leading a biorefinery program to make bio-based alternative fuels and chemicals economically attractive. The other initiative is the Carbon Dioxide Removal Project, which is led by Saudi Arabia, the U.S. and Canada. The project’s goal is to net an annual reduction of 100 MMtpy of CO2 by 2030. Other countries are following suit.

The biggest culprit

In November 2021, the Global Carbon Project, a Global Research Project of Future Earth and a research partner of the World Climate Research Programme, reported that global CO2 emissions from fossil fuels were 34.8 GtCO2, a decrease of 5.4% from 36.7 GtCO2 in 2019; however, projected global fossil CO2 emissions in 2021 were forecast to rebound close to their pre-COVID levels after an unprecedented drop in 2020. Emissions from coal and gas use are set to grow more in 2021 than they fell in 2020, but emissions from oil use remain below 2019 levels.

In the U.S. alone, the U.S. Environmental Protection Agency (EPA) reports that the transportation sector generates the largest share of greenhouse gas (GHG) emissions (~ 23%). The Intergovernmental Panel on Climate Change states that this sector presents the most challenges to mitigation.

Energy transition and refinery restructuring

In the context of fluctuating market conditions for traditional oil-derived fuel markets, refiners are increasingly focused on the energy transition to improve the profitability of their assets and secure long-term operations, in tandem with reducing GHG emissions and moving towards carbon neutrality. Many refineries around the world are considering renewable fuels production at either existing refineries that will continue to process crude oil, or at facilities that are idle with existing infrastructure to accommodate new processing units to refine (mainly) diesel and jet fuels from sustainable sources, such as used cooking oils (UCO), waste animal fats (tallow) and/or certified sustainable vegetable oils, such as rapeseed.

With the new processing technologies, there is a co-production of CO2 and the need to maintain active catalyst in the reaction system. A small amount of sulfur, usually in the form of liquid disulfide oils, is added to the conversion reactors to maintain catalyst activity. The sulfur is converted to hydrogen sulfide (H2S) in the reactor system. An amine unit can remove the unwanted CO2 from the process, but this also removes the H2S. The resulting acid gas stream contains far less sulfur than is practical to remove with a typical refinery sulfur recovery unit (SRU) using Claus technology.

In its continued contribution to improving sustainable mobility, a multinational oil and gas company based in Europe uses a proprietary sulfur recovery technologya to serve as the SRU. This technology is a patented, wet scrubbing, liquid redox system that uses a chelated iron solution to convert H2S to innocuous, elemental sulfur. It is designed to remove about 4 metric tpd (tonnes per day) of sulfur from an acid gas with up to almost 7 mol% H2S.

The processes

The hydrotreated vegetable oil (HVO) process produces renewable fuels via hydrogenation and hydrocracking of vegetable oils and animal fats using hydrogen and catalysts at high temperatures and pressures. The oxygen is stripped in a reactor with a catalyst that often requires sulfiding to promote conversion chemistry and avoid catalyst deactivation. Dimethyl-disulfude (DMDS), the most commonly used chemical for sulfiding the catalyst, is converted to H2S, and the oxygen from the feedstock is converted to CO2 and water during the deoxygenation reaction.

Hydrocarbon liquids exit the reactor and are routed to a three-phase separator, where the water is removed and vapors are collected for cleaning and recycling. The hydrocarbon liquids are routed to an isomerization reactor before being separated into various cuts to create light fuels, sustainable aviation fuels and renewable diesel.

The vapors from the separator are often routed to an amine unit to remove the H2S and CO2 formed in the deoxygenation reactor. The treated gas from the amine unit is rich in hydrogen and recycled to the HVO process. A slipstream may be used as fuel gas. Depending on what other units may be operating at the refinery, additional acid gases may be processed in other amine units at the site. The European refinery mentioned here utilized large Claus units that had been previously idled.

SRU process selection

In the European refinery example, the existing higher capacity Claus SRU had been shut down when oil processing ceased. The typical minimum H2S content for a feed to a Claus unit is 35 mol%, but that condition cannot be met when the HVO process is operating. Modified Claus units can operate with less H2S in the feed stream, but to achieve >99.9% sulfur recovery, a tail gas treating unit is required downstream of any Claus SRU, which increases cost. Turndown conditions can also negatively affect Claus unit sulfur recovery efficiency.

A highly flexible sulfur recovery process was needed to account for the range of feed gas conditions. The selected process also needed to achieve high recovery percentages over a wide range of operating flowrates and H2S concentrations. The refiner required:

  • Maintaining sulfur removal efficiency at turndown conditions
  • No minimum H2S concentration in the feed acid gas stream
  • A fully guaranteed product to meet customer requirements.

The sulfur recovery processa

The author’s company’s processa is a liquid redox system that converts H2S to solid elemental sulfur (FIG. 1). The process utilizes an aqueous iron solution with a catalytic performance that is enhanced by a proprietary blend of chemicals. The H2S is converted to elemental sulfur by redox chemistry according to the following overall reaction (Eq. 1):

Direct oxidation reaction: H2S + 1/2 O2 → H2O + S°                 (1)

The redox reaction is conducted in separate sections of the process, as summarized in Eqs. 2 and 3:

Absorber: H2S + 2Fe+++ S° + 2Fe++ + 2H+                        (2)

Oxidizer: ½ O2 + H2O + 2Fe++ 2OH– + 2Fe+++                   (3)

FIG. 1. Anadarko Petroleum Corp.’s Pinnacle Bethel Gas Plant,  near Bethel, Texas, with the addition of the proprietary sulfide treatment system<sup>a</sup>.
FIG. 1. Anadarko Petroleum Corp.’s Pinnacle Bethel Gas Plant, near Bethel, Texas, with the addition of the proprietary sulfide treatment systema.

The exothermic absorber reaction represents the oxidation of H2S to elemental sulfur and the accompanying reduction of the ferric iron state (active) to the ferrous iron state (inactive). This reaction is irreversible and not equilibrium dependent. The oxidizer reaction (also exothermic) represents the oxidation of the ferrous iron back to the ferric iron state.

Liquid redox technology produces a sulfur “cake” that contains approximately 65% sulfur, 35% moisture and trace amounts of proprietary chemicals. It does not produce any other products or byproducts, so no additional treatments are required. Because the reaction occurs in the aqueous phase at near-ambient temperatures, the process is inherently safe. The removal of sulfur is not affected by turndown conditions, and the process can be applied to almost any vapor stream containing H2S.

Liquid redox is an economical process for H2S removal and sulfur recovery within a given range. On the low end of sulfur recovery, non-regenerative chemical absorbents (scavengers) are likely to be more economical due to the low capital cost of a two-vessel design. As the sulfur removal requirement increases, operating costs become prohibitive using scavengers. This is when a liquid redox process is advantageous due to lower operating costs. The higher capital cost of a liquid redox unit is quickly paid out in operating savings vs. replacement of the non-regenerative scavenger. An amine unit + Claus SRU is advantageous for high-end sulfur recovery. Excessive loss of sulfur recoverya chemicals when removing more than 20 tpd of sulfur cake, however, drives up costs.

The first milestone

A proprietary sulfur recovery unita went into commission at the European refinery in August 2019. The refinery installed a rectangular autocirculation unit enabled by the dilute concentration of H2S in the feed to the SRU. In the summer of 2020, the liquid redox unit underwent its first turnaround. The working solution was drained and stored for further use. The autocirculation vessel was opened, cleaned and inspected. A small amount of sulfur buildup was detected on the vessel’s floor. The unit was cleaned with a warm water wash and no corrosion was noted. The shutdown for maintenance took 1 wk—the equivalent to 98% availability in the first year of operation.

In 2020, the biorefinery reached full operation with a five-fold increase in biofuels production compared to 2019.


The rising demand for sustainable and reliable energy is driving biofuel production around the world. Analyst firm Precedence Research predicts the global biofuels market will exceed $200 B by 2030.

Slight reconfigurations of existing petroleum refineries enable a seamless and lower-cost entry into the biofuels production business at scale. Refineries that will continue to process crude oil will typically utilize existing Claus units to handle any increased demand for sulfur recovery. In facilities without a working Claus unit or where the Claus unit is overloaded, bio-refiners can manage the low-tonnage sulfur recovery with the proprietary liquid redox technologya, which addresses low-tonnage sulfur recovery and achieves very low SO2 emissions. The systems are reliable and have high availability, the operating cost is low, and bio-refiners can consistently achieve sulfur removal guarantees while taking a solid stance on sustainability. HP



   a  Merichem’s LO-CAT® process (Liquid Oxidation CATalyst)

   b  Merichem’s FIBER FILM®

The Author

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