Larry Linguist,Refiners faced with the dilemma of reducing the sulfur content of diesel fuel while also lowering carbon dioxide emissions may benefit from biodesulfurization (BDS), a proprietary process that uses enzymes to remove sulfur from petroleum.
Energy BioSystems Corp.
Biodesulfurization is expected to provide refineries a cost-effective method of meeting the new lower-sulfur standards while providing lower energy consumption and, thus, lower CO2. Recent studies show that energy requirements and CO2 generation will be significantly lower if BDS is used instead of hydrodesulfurization (HDS) to remove sulfur.
The difference is most dramatic at very low desulfurization levels.
Double challengeIn 1990 the U.S. ushered in a new era in the petroleum refining industry with the enactment of regulations mandating a significant increase in the quality of on-road diesel fuel by 1993. Since that time, environmental-driven trends have tightened specifications on distillate fuels across much of the international petroleum marketplace, and these trends are continuing.
As the U.S. Environmental Protection Agency (EPA) concentrates on diesel fuel as part of its Tier 2 vehicle emissions proposed regulation, there is widespread belief that the most appropriate fuel sulfur target will be 30-50 ppm (0.03-0.05 wt %). Severe hydrotreating required to attain these low-sulfur levels will result in substantial increases in capital, energy, and maintenance costs.
Frank Gerry, manager-fuels development for British Petroleum, commented at last fall's Society of Automotive Engineers (SAE) Fuels & Lubes meeting that the potential cost to U.S. refiners of investing in low-sulfur diesel could reach $30 billion.
Even without the extra energy required for deep desulfurization, petroleum refining is one of the most energy-intensive industries in the U.S., accounting for approximately 7% of the total energy consumed in the U.S. in 1994.
While refiners are being told to lower sulfur levels of the fuels they produce, they are also being told to lower their CO2 emissions as part of a worldwide move to reduce greenhouse gases.
At the United Nations Framework Convention for Climate Change conferences in Kyoto, Japan, in 1997 and Buenos Aires, Argentina, in 1998, the world's industrialized nations agreed to an overall cut by 2012 of 5.2% in emissions of six gases linked to purported global warming, most notably CO2. This places a further strain on refineries, which are a major source of CO2 emissions in the industrial sector.
Bernard Damin of Elf Aquitaine, who also spoke at the SAE Fuels & Lubes fall 1998 meeting, said that refinery CO2 emissions will increase as refiners further desulfurize diesel.
HDS and BDSHydrotreating is the conventional technology for removing sulfur from diesel fuel.
During HDS, petroleum fractions are subjected to high temperature and pressure in the presence of an inorganic catalyst and hydrogen. Organic sulfur molecules are converted to hydrogen sulfide, which is further processed to yield elemental sulfur. HDS becomes increasingly expensive and less efficient in handling sulfur removal as lower sulfur levels are reached.
BDS is a proprietary process based on naturally occurring aerobic bacteria that can remove organically bound sulfur in sulfur heterocycles of petroleum with minimal degradation of the fuel value of the hydrocarbon matrix. Enzymes in the bacteria selectively oxidize the sulfur, then cleave carbon-sulfur bonds. BDS will operate at ambient temperatures and atmospheric pressure and thus will require substantially less energy than conventional HDS methods to achieve sulfur levels below those required by current regulatory standards.
BDS generates a fraction of the CO2 that is generated in association with HDS, and it does not require hydrogen. Additionally, BDS can effectively remove some key sulfur-containing compounds that are among the most difficult for HDS to treat. BDS can be used instead of, or complementary with, HDS.
Comparison studiesComparison studies were recently conducted for the energy consumed and the CO 2 generated for BDS and HDS processes.
Two cases were considered: desulfurization of diesel from 0.2% to 0.005% sulfur, which represents a refinery without a hydrotreater (i.e., BDS replaces HDS); and desulfurization from 0.05% to 0.005%, which represents use of BDS downstream of a hydrotreater. The comparison is summarized in Table 1 [9,935 bytes].
The energy consumed was calculated as the sum of all energy in the form of electricity used for pumps, compressors, and other equipment; fuel used in direct-fired heaters; fuel converted to biological energy for BDS; and the equivalent energy of methane consumed in hydrogen production for HDS. Conversion of energy from methane combustion to other utilities was assumed to be 100% efficient.
The CO2 generation was calculated as the sum of CO2 from methane combustion for energy production, hydrogen generation for HDS, and biological activity for BDS. CO2 generated from methane combustion for energy was assumed to be 100% efficient.
Fig. 1 [57,188 bytes] and Fig 2 [57,188 bytes] illustrate the difference in CO2 emissions and energy requirements for HDS and BDS. The energy and CO2for the HDS unit are dominated by the energy and CO2 associated with the hydrogen plant and, to a lesser extent, the heating fuel required to heat the diesel up to HDS temperature.
HDS calculationsFig. 3 [39,589 bytes] illustrates the boundaries of the energy and CO 2 calculations for HDS.
It was assumed that a hydrogen plant would be needed to produce the hydrogen necessary to run the HDS reaction. Hydrogen would be produced from methane through the steam reforming and chemical shift reactions, which are as follows:
Reforming reaction: CH4 + H2O <-> CO + 3H2
Chemical shift reaction: CO + H2O <-> CO2 + H2
Hydrogen requirements assumed for the two cases were different. A value of 680 scf/bbl was used for desulfurization of diesel from 0.2% to 0.005%, and 430 scf/bbl was used for desulfurization from 0.5% to 0.005%.
These values were determined from data presented by Mario Baldassari, technology manager, hydroprocessing, ABB Lummus Global Inc., and others at the AIChE 1997 Spring National Meeting. The methane required for hydrogen generation was reported as 251 BTU/scf of hydrogen, as reported in the 1994 third edition of Petroleum Refining Technology and Economics.
Steam, power, and heating fuel requirements for hydrotreaters were also reported in the 1994 third edition of Petroleum Refining Technology and Economics. For the second case, no heating fuel was assumed, as the refinery would most likely expand an existing hydrotreater's capabilities with no additional heat needed.
Energy used in operation of a cooling tower to support HDS was assumed to be negligible in this calculation.
CO2 from hydrogen production was calculated under the assumption that the steam reforming and chemical shift reactions were carried to completion, and the balance of the methane consumed was for energy in the hydrogen plant. CO2 generation from methane combustion for other utilities was also calculated.
BDS calculationsFig. 4 [29,734 bytes] illustrates the boundaries of the energy and CO 2 calculations for BDS.
As with the HDS unit, methane was assumed for production of energy and steam for the BDS unit. An additional fuel, identified as "carbon source," is provided to the unit as fuel to drive the biochemical reactions.
Utility requirements for a refinery-scale BDS unit were calculated through use of a process simulation created with SuperPro Designer, a software package developed for the biotech industry by Intelligen Inc. Utilities reported were electrical energy for mixers, compressors, and pumps; and chilled water. Chilled water was converted to energy under the assumption of a 15° C. temperature difference in the chilled water through the BDS unit.
CO2 produced biologically was calculated on the basis of experimental observations of BDS reactors in operation and projected operating parameters for a refinery-scale BDS unit. CO2 generation from other utilities was determined in the same manner as the HDS calculations.
Current workAs the studies presented here illustrate, the CO 2 generation and energy requirements for the BDS process are substantially lower than the HDS process.
Based on results such as these, Energy BioSystems Corp. is aggressively pursuing methods to further improve the efficiency and reduce the cost of BDS processes. Additionally, the company is developing business alliances for hydroxy phenyl benzene sulfinate (HPBS), a product of the desulfurization process that promises to be a lower-cost and potentially biodegradable building block for the manufacture of detergents.
Work is currently under way to install a 5,000 b/d BDS unit for Petro Star Inc.'s Valdez, Alas., refinery. The unit represents the first commercial license of this BDS technology. Petro Star is a wholly owned subsidiary of Arctic Slope Regional Corp. The Valdez refinery is a major supplier of military jet fuel, marine diesel, and other middle distillate products.
In addition to the Petro Star unit, Total Raffinage Distribution SA has announced its intention to build and operate a BDS pilot plant in one of its European industrial facilities.
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Larry Linguist is a research engineer in the Process Development Group for Energy BioSystems Corp. of The Woodlands, Tex. His work includes recovery of chemical byproducts of the biodesulfurization process and process simulation of biodesulfurization units. He previously worked for RMT/Jones and Neuse Inc. as an environmental specialist. Linguist has a BS in chemical engineering and an MS in environmental engineering, both from the University of Texas at Austin.
Michael A. Pacheco is vice-president, process development, for Energy BioSystems Corp. He is responsible for commercialization of the company's biodesulfurization process and oversees the process development and engineering, pilot plant, and advanced technology groups. Prior to joining Energy BioSystems, Pacheco worked for 13 years in research and development in the Refining Business Group of Amoco Corp. and was previously a research engineer for Conoco. A registered professional engineer in California and a member of AIChE, Pacheco holds three patents for novel processes for producing oxygenates for gasoline.
He holds a BS in chemical engineering from Clarkson University and a PhD in chemical engineering from the University of California at Berkeley.
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