SULFUR, COKE AND CRUDE QUALITY - PART 1 COKE, SULFUR RECOVERY FROM U.S. REFINERIES CONTINUES TO INCREASE

Edward J. Swain
Consultant
Houston

The production of petroleum coke by U.S. refineries is expected to increase in the coming years as the trend toward producing transportation fuels increases slightly and the quality of crude oils processed deteriorates.

Current demand patterns for sulfur also are expected to continue through the next decade, with about half of the sulfur being used to produce phosphatic fertilizers and the other half used in some 30 chemically oriented industries.

The additional petroleum coke produced should be fuel-grade quality, because the markets for anode and needle grades of coke are limited. The availability of existing and additional quantities of fuel-grade coke provides a source of low cost energy and chemical raw materials to the U.S. chemical and utility power industries.

This first of two articles updates U.S. sulfur and coke production figures, including 1993 data. Part 2 will look at the changing quality of crude runs to U.S. refinery stills, which affects coke and sulfur production.

SULFUR SOURCES

Sulfur is produced or recovered mainly from Frasch, pyrites, and hydrocarbon operations. Before the mid-1950s, most sulfur production was of a discretionary nature (i.e., produced either as elemental sulfur by Frasch mining, or as sulfuric acid from pyrites). In the mid-1950s, the production of nondiscretionary recovered sulfur from natural gas treating facilities and petroleum refineries entered the scene as a source of elemental sulfur.

Historical U.S. production and recovery of elemental sulfur are shown in Table 1 (6111 bytes). Production of recovered sulfur from natural gas processing plants and petroleum refineries reached an all-time high in 1993. The production of sulfur from Frasch mines has become a swing source of sulfur to meet U.S. demand over the past decade. This role for Frasch sulfur should continue into the next decade.

FRASCH

All operating U.S. Frasch mines are in Louisiana and Texas. The 1993 average daily production of sulfur from them was 3,599 metric tons/calendar day (mt/cd). Frasch production has fluctuated during the past 10 years (Table 1) (6111 bytes). The wide swings in both sulfur production and shipments indicate the wide yearly fluctuations in phosphatic fertilizer demand.

In 1993, Texas Frasch mines were operated by Pennzoil Sulphur Co. and Texas Gulf (Elf-Aquitane), and Louisiana mines were operated by Freeport Sulfur Co.

Pennzoil's mine near Culberson, Tex., has been the leading producer of Frasch sulfur in the U.S. At the 1993 production rate, the mine has about 38.2 years of remaining life. At the 1993 Frasch sulfur price, however, the mine is operating well below break-even conditions.

Freeport Sulfur Co. is the second major producer of Frasch sulfur in the U.S. It has four Louisiana mines: at Garden Island Bay, Grand Isle, Caminada, and Main Pass. Freeport closed the Garden Island Bay mine in June 1991, then closed the Grand Isle mine in October 1991. The Caminada mine was closed at the end of 1993. The three mines had very short proven reserves left and were high-cost operations.

During the summer of 1988, Freeport and a consortium of firms purchased 11 U.S. government leases offshore of the Louisiana Coast. The consortium comprises Freeport (53.8%), IMC Fertilizer Corp. (25.0%), and Felmont Oil Co., a subsidiary of Homestake Mining.

Main Pass Block 299 has been explored and has estimated reserves of 67 million mt of sulfur. This has added about 39.1 million mt to Freeport's sulfur reserves. The Main Pass mine started operations in the Spring of 1992 and reached design production capacity of 5,500 mt/d (2 million mt/year) in December 1993.

Texas Gulf has been a minor Frasch sulfur producer from its mine at Boling, Texas. The mine was closed at the end of 1993.

NATURAL GAS

Sour, wet, acid gases are treated at natural gas plants, which remove NGL and prepare the raw natural gas for sale as a methane-rich gas stream. In sour natural gas, the sulfur occurs as free hydrogen sulfide. Desulfurization of sour gases yields a concentrated hydrogen sulfide gas (acid gas) stream. The hydrogen sulfide then is converted to elemental sulfur, usually by the Claus process.

The Claus process has been well developed, with three converter stages that obtain up to 98% sulfur recovery in the rich feed stream. To meet U. S. sulfur emission environmental standards, the gas stream leaving the Claus unit enters a tail gas treating unit, where total sulfur recovery for the system approaches 99.8%.

The recovered sulfur produced from natural gas plants between 1989 and 1993, grouped by Petroleum Administration for Defense (PAD) district, is listed in Table 2 (8890 bytes). The states in PAD district (PADD) No. 3 produce about 69% of the total U.S. marketed natural gas. Therefore, that district is expected to be a leader in recovering sulfur from natural gas.

A large quantity of sulfur is recovered in PADDs 4 and 5, however because several large natural gas plants have been installed to treat raw gases produced in the Over Thrust Belt region of Wyoming.

The distribution of the natural gas treating facilities, and their associated sulfur-recovery units (SRUs), in 1994 is:

PADD 1-11 gas plants, 1 SRU
PADD 2-161 gas plants, 6 SRUs
PADD 3-417 gas plants, 48 SRUs
PADD 4-106 gas plants, 7 SRUs
PADD 5 - 31 gas plants, 1 SRU
Total - 726 gas plants, 63 SRUS.

PETROLEUM REFINERIES

Sour gases produced at petroleum refineries are treated before entering the refinery fuel system to meet air quality standards for sulfur emissions from refinery process heater and boiler flue gases.

Increasing quantities of sour gases are produced in refineries because of:

Processing crude oils with medium-to-high sulfur content and medium-to-heavy API gravity (vs. light, low-sulfur crudes)
Hydrotreating virgin and cracked naphtha and light distillates
Thermally processing and catalytically cracking vacuum gas oils and reduced crude oils
Hydrodesulfurizing and hydrocracking atmospheric distillates, vacuum gas oils, and reduced crudes.

The recovered sulfur produced from U.S. refineries, grouped by PADD, for 19891993, is shown in Table 3 (9305 bytes). Because refineries in PADD 3 represent about 45% of the total U.S. refinery operating capacity, it is reasonable to expect that the district will be the leader in recovered sulfur from refinery gases.

Sulfur recovered by U.S. petroleum refineries has increased about 69% in the past 10 years, even though crude runs have increased only about 13%. The elemental sulfur recovered from refineries, expressed as mt sulfur/1,000 bbl crude oil input, has increased about 50% over the past decade (Fig. 1) (8510 bytes).

Table 4 (8049 bytes) summarizes the number of U.S, petroleum refineries, their crude oil distillation capacities, and their sulfur recovery capacities as of June 1, 1994, by PADD. Sixty-four percent, or 110 refineries, have sulfur recovery facilities. These 110 represent 87% of the total available crude oil distillation capacity and are mostly medium-to-large plants with complex downstream facilities.

Most recent U.S. refinery projects include either new sulfur recovery units or expansions. Sulfur recovery at petroleum refineries should continue to increase in the short and long-term to meet U.S. sulfur demand.

The 12,989 mt/cd of sulfur recovered from U.S. petroleum refining operations in 1993 represents about 60.2% of the sulfur contained in the crude oils processed. During the same year, sulfur recovery factors for each PADD were estimated to be:

PADD 1-41.7%
PADD 2-42.1%
PADD 3-72.0%
PADD 4-34.4%
PADD 5-56.5%.

These factors are based on the quality of crude oils charged to the U.S. refineries, which will be reported in the concluding article in this series.

As additional downstream units are installed in refineries to upgrade the bottom-of-the-barrel into clean-burning transportation fuels and meet the U.S. Environmental Protection Agency (EPA) SOx-emission regulations, the percentage of recovered sulfur should increase to about 65% of the sulfur in the crude oils charged by year 2000.

Asphalt, road oils, petroleum coke, and residual fuel oils account for minor portions of today's refinery product yields, and will continue to do so in the near term. A major portion of the unrecovered sulfur in the incoming crude oils will be found in these four minor petroleum products.

The five leading refining companies, in terms of 1993 sulfur recovery, are:

Chevron U.S.A. Inc.1,640 mt/cd
Exxon Co. U.S.A.-1,280 mt/cd
Amoco Oil Co.-1,265 mt/cd
Star Enterprise-870 mt/cd
Citgo Petroleum Corp. - 790 mt/cd.

The recovered sulfur from these five companies' refinery operations accounts for 45% of total recoverable sulfur from refineries.

PRICES

Sulfur shipment values are reported by the U.S. Bureau of Mines for both Frasch and recovered sources. In 1993, the reported sales value of sulfur shipments were: $51.60/mt for Frasch and $25.06/mt for recovered sulfur, for an average price of $31.86/mt (all FOB).

Sulfuric acid production is the largest sulfur end use in the U.S. and worldwide. In turn, the largest end use of sulfuric acid is phosphatic fertilizer production. Therefore, U.S. sulfur pricing normally follows the demand and pricing of phosphatic fertilizers in the U.S.

Because both the U.S. and worldwide phosphatic fertilizer industries have been weak, prices of sulfur have been decreasing drastically over the past several years, from a high in the 1985-1986 period (average price about $106/mt). It is doubtful that U.S. sulfur prices will reach $75/ton over the next 5 years.

The average value, FOB plant, for shipments of recovered elemental sulfur varies widely by geographic region. Low values are common in the Rocky Mountain states (PADD 4) and on the West Coast (PADD 5). Somewhat higher values have been common in the Midcontinent states (PADD 2), Eastern states (PADD 1), and the Southern states (PADD 3).

The 1993 recovered sulfur prices in PADDs 1, 2, and 3, however, approach a common price of about $30/mt. These low sulfur prices do not help defray the costs of operating an SRU in a U.S. petroleum refinery to meet air quality standards, or in a natural gas plant to meet product quality requirements.

Current listed sulfur prices are:

Recovered, Houston-$48. 00/ton
Frasch, New Orleans $58.00/ton.

IMPORTS

About 2.3 million mt of elemental sulfur were imported into the U.S. during 1993. The two major sources of these imports were Canada and Mexico. In 1993, 4,195 mt/cd were imported from Canada at an average price of $17.80/mt, and 1,380 mt/cd were imported from Mexico at an average price of $42.30/mt.

Canada is the world's largest sulfur exporter, with nearly 90% of its production leaving the country. Sulfur recovered from natural gas processing represents about 77% of total Canadian production-nearly 7.3 million tons in 1993. All production in Canada is from recovery operations; the country has no Frasch mines.

Imports of sulfur from Canada in 1993 were down about 17% from 1992; the price paid for Canadian sulfur was at an all time low of $17.80/mt. In contrast, the 1989 price for Canadian sulfur at the border was at $70.13/ton.

The majority of Canadian sulfur is recovered in Alberta and British Columbia and exported from the Port of Vancouver. At the 1993 export price, Canadian sulfur producers may be stockpiling sulfur at the recovery plants. The sulfur price at Vancouver recently was quoted at $28.00 per ton.

Sulfur imported from Mexico is from Frasch mines, accounting for the price difference compared to Canadian sulfur. All three of Mexico's existing mines are old, have high operating costs, and may therefore be closed in the next several years. The price of sulfur from Mexico was at a high of $115.25/ton in 1989. Sulfur imported into the U.S. from Mexico may be a minor source in the short and long-term.

EXPORTS

Exports of U.S. elemental sulfur were 1,800 mt/cd at an average price of $60.47 in 1993. U.S. sulfur is exported to countries in Western Europe, South America, Africa, and the Far East. Export sulfur prices have declined over the past 5 years because of decreased worldwide sulfur demand and competition from a number of major sulfur-producing countries like Canada, the former Soviet Union, Poland, and Saudi Arabia.

It is doubtful whether the U.S. sulfur export market will reach I million tons/Year in 1995.

NEW TECHNOLOGY

Energy BioSystems Corp., The Woodlands, Tex., is developing a new biocatalytic desulfurization (BDS) process that uses bacteria to selectively cleave the sulfur bonds in crude oil and a wide range of oil products. The technology is the focus of a major research and development effort.

It should be noted, however, that the idea of using bacteria to reduce sulfur content in coal and oil is not new. A major research effort, sponsored by the U.S. Department of Energy (DOE) and the coal industry, to reduce sulfur in coal was carried out in the early 1970s. No commercial technology resulted from the research.

Energy BioSystems' first BDS pilot plant (5 b/d of diesel fuel) is currently under construction in the St. Louis area. The plant is being funded by Petrolite Corp. and Energy BioSystems, and being fabricated by the M.W. Kellogg Co., Houston. The plant was scheduled to be on-line in fourth quarter 1994. BDS will be tested on selective petroleum fractions, as well as whole crude.

The BDS process operates at atmospheric pressures and ambient temperatures. Current catalytic hydrotreating and hydrorefining involve high temperatures and pressures, and also major capital expenditures. The capital is required for the hydrotreater, hydrogen plant, sulfur-recovery facilities, and support facilities. Energy BioSystems reports that compared to hydroprocessing technology the BDS capital investment and operating costs would be respectively 50% and 10-20%.

It is reported that the BDS process produces inorganic sulfur compounds and creates no major environmentally detrimental waste streams. BDS technology could have a major impact on the petroleum refining industry, as well as the sulfur industry. Also impacted would be the catalyst industry and heavy wall vessel fabricators.

U.S. COKE CAPACITY

As of Jan. 1, 1994, DOE reports 171 operating and idle refineries with 15.86 million b/sd crude oil distillation capacity. Of these, 56, with 8.9 million b/sd of crude oil capacity, have coking facilities.

Although only 33% of U.S. refineries have coking units, these 56 represent 56% of the total crude oil distillation capacity. They are mostly medium-to-large, complex facilities.

PADD 3 has the largest number of refineries with coking capacity (21), and PADD 5 contains the next largest group (15 refineries). Coking capacity, grouped by PADD, is presented in Table 5 (8796 bytes).

U.S. refineries utilize three types of coke processing technology: delayed, fluid, and Flexicoking. The majority of the U.S. coking facilities are of the delayed type:

Delayed - 49 refineries, 1,572,000 b/sd
Fluid - 5 refineries, 134,700 b/sd
Flexi - 2 refineries, 54,500 b/sd
Total - 56 refineries, 1,704,200 b/sd.

The 10 leading U.S. petroleum refining companies ranked by coker feed capacity are listed in Table 6 (5178 bytes). Chevron U.S.A. Inc. is first. It has delayed cokers in five of its refineries. In early 1993, one of the three delayed cokers at Exxon's Baton Rouge, La., refinery had a fire that destroyed the unit. The 30,000 b/sd unit is being rebuilt by Fluor Corp. and is scheduled to be online in 1995.

TECHNOLOGY

Delayed coking technology is "open art" technology. Although the process is offered by several licensors, fundamentally no major differences exist between their technologies. Most of the differences are related to each licensor's design and commercial experience.

One exception is Conoco Inc.'s technology, which involves a specific scheme for increasing liquid yield, relative to the other technologies. The Conoco scheme can result in reduced coke make.

Fluid and Flexicoking technologies are offered by Exxon Corp.'s research and development division, and a licensing fee is paid for each technology. The seven fluid and Flexicokers operating in the U.S. account for 189,200 b/sd feed capacity.

U.S. COKE PRODUCTION

Coke production from U.S. refineries has increased about 51% during the past 10 years, although crude runs have increased only about 1.57 million b/cd (13%). The 10-year history of coke production is presented in Fig. 2 (8692 bytes). With recent announcements of several new cokers and coker expansion projects coming on-line over the next several years, coke production could reach 90,000 tons/cd by 1998.

Refinery coke production, grouped by PADD, during 1989-1993 is shown in Table 7 (5969 bytes). Because PADD 3 refineries represent about 45% of U.S. coke capacity, it is reasonable to expect that those refineries will be the leaders in coke production. The heavy fuel oil market is very limited in PADD 3; therefore, refineries in the district have installed coking units to reduce the production of heavy fuel oil.

The 1993 coke production from U.S. refineries of 78,430 tons/cd represents more than 100% of U.S. coking capacity. The 1993 coke production factors for each PADD were estimated to be:

PADD 1-94.6%
PADD 2 -102.7%
PADD 3 - 98.7%
PADD 4-92.0%
PADD 5-103.2%.

These production factors are based on the coke production capacity, as reported by DOE. According to Oil & Gas journal's capacity figures, this 1993 production level corresponds to 100.8% of capacity utilization (OGJ, Dec. 21, 1992, p. 41).

Petroleum coke production, expressed as tons coke/1,000 bbl crude input has increased more than 33% over the past 10 years (Fig. 3) (9033 bytes). There was limited growth in coke production during the 1986-1990 period.

There has been major growth, however, from 1990 to 1993, as new coking units came on stream.

One of the driving forces for increased petroleum coke production in the coming years is the declining quality of crude oils processed by U.S. refiners, as will be discussed in the second article in this series. The trend in the API gravities of the crude oil processed over the 1984-1993 period is shown in Fig. 4 (10526 bytes). If this trend continues, coupled with additional downstream processing capacity installed to upgrade the bottom-of-the-barrel fraction to light transportation fuels, production levels of 90,000 tons/cd of coke will be reached easily by 1998.

As the sulfur content of the crude oil processed increases, as illustrated in Fig. 5 (10298 bytes), the sulfur content of fuel-grade petroleum coke will increase from an average 4.5 wt % to about 5.5 wt % over the next 10 years.

Low-sulfur petroleum coke is produced by refineries in Kansas and Oklahoma. It is estimated that fuel-grade coke produced by delayed cokers at refineries in these two states will have a sulfur content of 2.25-2.60 wt %.

High-sulfur petroleum coke is produced by refineries in California, the Louisiana Gulf Coast, and the Texas Gulf Coast. It is estimated that fuel-grade coke produced by delayed cokers at refineries in these three regions will have a sulfur content of 4.30-4.95 wt

EXPORTS

A major portion of the petroleum coke produced by U.S. refineries in 1993 - about 66% - was exported. This is slightly higher than the 5-year average of about 65%. Although U.S. industries are learning that petroleum coke is a low-cost energy source for chemical feedstock and power generation, coke production is increasing at a faster rate than are new projects that utilize coke.

PADD 3 refiners exported 26,705 tons/cd in 1993, and PADD 5 refiners exported 22,545 tons/cd. The other three PADDs combined exported only 2,445 tons/cd of coke.

Seven countries receive about 75% of the exported petroleum coke. Table 8 (6840 bytes) gives a 5-year (1989-1993) pattern for countries importing U.S. petroleum coke. Japan is the largest importer, with the coke being used by the processing industries and as boiler fuel, blended with coal.

As the refined petroleum-product mix shifts further toward transportation fuels, and as the crude oils processed decline in quality, foreign refineries will install cokers and reduce coke exports from the U.S.

PRICING

Fuel-grade coke is priced at a discount against the delivered price of coal to a potential user like an electric power plant or cement kiln. This reflects the ability of a refiner to sell his coke at a low price and the willingness of a customer to use coke only when it is priced below coal. At a minimum, the discount must be large enough to yield a rapid (less than 3 years) return on a dual energy-handling investment.

The 1993 price of coke ($19.03/ton) is reported on the sales of 3,025 tons/day to 15 public utility companies - a rather small sales quantity (less than 4% of 1993 production).

Pace Consultants Inc., Houston, stated that the current market export price of coke is about $5.00/mt, FOB vessel, for a 5.0 wt % sulfur coke at Gulf Coast ports (OGJ, April 26, 1993, p. 34). This nets back to Gulf Coast refineries $2.00-4.00/mt.

U.S. COKE PROJECTS

Texaco Refining & Marketing Inc. will build a gasification power facility at its El Dorado, Kan., refinery. The unit will convert petroleum coke and refinery wastes to 40 mw of electricity - enough to meet the full needs of the refinery. Exhaust heat from the turbine will be used to produce 180,000 lb/hr of steam, roughly 40% of the refinery's requirements.

Construction of the $75 million facility is expected to begin in first quarter 1995, with start-up projected for second quarter 1996. The gasification power plant will convert about 170 tons/day of noncommercial petroleum coke and refinery waste streams into syngas using Texaco's gasification process.

Nelson Industrial Steam Co., a joint-venture of Citgo Petroleum Corp., Conoco Inc., Gulf States Utilities, and Vista Chemical Co., started up its coke-fueled cogen plant in August 1992 at Westlake, La. (OGJ, Sept. 28, 1992, p. 103). Citgo and Conoco supply 1,500 tons/day of coke from their refineries in Lake Charles, La. Coke price at the plant site is approximately $0.20/MMBTU ($5.60/ton).

Destec Energy Inc.'s cogen facility, adjacent to Lyondell-Citgo Refining Co.'s Houston refinery, is in financial trouble. Texas Utilities Electric Co.'s contract with Destec for 350 mw of power expired in April 1994. Two other contracts with HL&P and Texas Utilities were scheduled to expire on Dec. 31, 1994, and Apr. 30, 1995, leaving Destec with 775 mw of excess energy.

The City of San Antonio has agreed to purchase 200 mw of power from Destec on a temporary basis; however, Destec has been unable to find firm replacement buyers. As Texas has excess power-generating capacity and the inability to get cost-effective rates to transmit its own power, Destec is likely to have trouble finding buyers.

ENVIRONMENTAL ISSUES

Off-specification product and fines from thermal processes (petroleum coke) is one of 25 refinery residual streams under review by EPA to be listed as a hazardous waste under the Resource Conservation and Recovery Act (RCRA). The final rule determining whether off-spec product and coke fines will be listed as a hazardous waste is expected in August 1995.

If listed as a hazardous waste stream, the immediate impact on refiners with coking units will be in the handling, storage, and shipment of coke. Capital spending will be required and coke-handling costs will increase.

THE AUTHOR

Edward J. Swain is an independent consultant in Houston. He is retired from Bechtel Corp., Houston, where he was a process planning engineer. Swain also worked for UOP and Velsicol Chemical Corp. He has a BS degree in chemical engineering and an MS in business and engineering administration from Illinois Institute of Technology, Chicago.