PROCESS FOR H2S REMOVAL FROM LOW VOLUME GAS STREAMS TESTED

Sept. 13, 1993
Pilot tests of liquid-redox facilities for removing sulfur, less than about 10 tons/day, from natural gas streams should enable gas producers a better base line for comparing various commercially available technologies. These stand alone liquid-redox plants are believed to be practical for feeds of about 1-30 MMscfd of gas containing 0.05-5.0 mole % of H2S The pilot test is being conducted by the Gas Research Institute (GRI) with the Radian Corp. as the prime contractor and project operator.

Pilot tests of liquid-redox facilities for removing sulfur, less than about 10 tons/day, from natural gas streams should enable gas producers a better base line for comparing various commercially available technologies. These stand alone liquid-redox plants are believed to be practical for feeds of about 1-30 MMscfd of gas containing 0.05-5.0 mole % of H2S

The pilot test is being conducted by the Gas Research Institute (GRI) with the Radian Corp. as the prime contractor and project operator.

The pilot facility (Figs. 1 and 2) is next to a Natural Gas Pipeline Co. of America natural gas plant near Kermit, Tex.

The first technology to be tested is SulFerox a Dow Chemical Co. and Shell Oil Co. liquid redox process. Next year at the same site and using the same gas stream, plans are to evaluate the Lo-Cat 11 liquid redox process from ARI Technologies Inc.

Later, Bio-SR from NKK Corp. will possibly be the third liquid redox process tested at the West Texas location.

The major design basis of the pilot plant are:

  • Inlet pressure = 945 psig

  • Mechanical design pres- sure = 1,160 psig

  • Maximum pressure drop = 25 psi

  • Inlet gas temperature 100 F.

  • Inlet moisture content: Saturated

  • Inlet gas rate = 1.37 MMscfd

  • Sulfur rate 0.15 long tons/day

  • H2S content 0.3 mole

  • CO2 content = 1.17 mole %

  • Methane content 96.15 mole %.

The fundamental research, according to GRI, is aimed at the underlying mechanisms, technology transfer activities, and environmental and health-based research.

H2S REMOVAL

GRI estimates that at least 25% of the natural gas processed in the U.S. is sour (i.e., has H2S greater than 4 ppm). About 82% of this gas contains CO2 of 3% or less, which is typical of pipeline specifications for CO2 This gas traditionally has been treated at a high-volume facility in a two-step approach. First, the acid gases (CO2 and H2S) are separated from the natural gas with an amine plant. Then, either the H2S is vented or flared or the sulfur is recovered in a separate Claus plant.

GRI expects many more sour-gas streams will need additional processing because flaring of even low H2S content gas is becoming environmentally unacceptable and even with the Claus process, tail gas may require treatment,

GRI believes the liquid redox recovery processes have proven to be better in small-scale applications than the traditional amine-Claus scheme because of simplicity, less operator attention much higher sulfur recovery, and good turndown ratio.

The liquid redox technology uses a circulating solvent that reacts with the H2S in an absorber or in a subsequent reaction (holding) tank. The sulfur may float or sink, depending on the process and is washed and filtered prior to disposal or sale.

The solution is regenerated by bubbling air through the liquid in an oxidizer tank. Carbon dioxide is not removed from the gas to any great extent.

Some of the commercially available liquid redox processes include:

  • Takahax - Quinone based

  • Stretford - Vanadium based

  • Sulfolin - Vanadium based

  • Lo-Cat - Iron based

  • Lo-Cat - II Iron based

  • SulFerox - Iron based

  • Hiperion - Iron/naphthoquinone

  • Bio-SR - Iron based.

The liquid redox process can produce sulfur in a slurry, cake, or molten form, but the sulfur is subject to greater potential contamination than Claus sulfur. Possible contamination sources include feed-gas contaminants, chemical additives, and impurities from the wash water.

In all processes, expensive solution is lost by salt formation and imperfect washing of the sulfur.

Some of the advantages and disadvantages of the processes, according to GRI, are:

  • The Takahax process in Japan has an advantage because the gypsum resulting from the process is readily marketed in that country.

  • A disadvantage for Stretford and Sulfolin is that vanadium may appear in the Sulfur product, causing disposal problems.

  • Lo-Cat uses an iron chelate-based solution but the chemical costs are high because of chelate degradation and loss.

  • Lo-Cat II claims less stoichiometric iron concentrations in solution, thereby reducing power and chemical costs.

  • The solution formulation in the SulFerox process enables maintaining much higher concentrations of iron in solution than Lo-Cat. This results in reduced circulation power requirements but can involve higher chelate losses.

  • Hiperion is used primarily in odor control.

  • Bio-SR uses unchelated iron and offers a possible savings in chemical costs.

PILOT RESULTS

The first attempts to start the pilot project lasted from January to May 1993. Problems were encountered with the equipment, foaming, and plugging. After the vendor's proprietary tests identified solutions, the facility was modified and testing started in June.

Stable operations were achieved without foaming or detectable sulfur plugging. About 1 MMscfd of sour gas is being flowed through the SulFerox pilot plant. H2S Of about 2,500-3,000 PPM at the inlet is being reduced to 0.20.3 ppm at the outlet.

The pilot plant cost about $1.3 million. The plant is designed as a stand-alone facility that could process, depending on the H,S content, about 20-30 Mscfd. A similar type of plant should also be economical for 1-2 MMscfd gas streams.

To update the industry on the progress in evaluating small-scale liquid redox sulfur recovery, GRI plans to hold a conference during May 1994 in Austin.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.