ENERGY-CYCLE ANALYSIS OF A GASIFICATION-BASED MULTI-PRODUCT SYSTEM WITH CO2 RECOVERY

The DOE is investigating CO2 recovery from fossil-fuel cycles as a greenhouse gas mitigation strategy. Recognizing this, we used life-cycle analysis tools to compare two integrated gasification combined-cycle (IGCC) plant designs based on the Shell entrained-flow gasifier. One option, called the “co-product case,” uses high-sulfur Illinois #6 coal to produce electricity and hydrogen (H2) as energy carriers. At the same time, 90% of the carbon dioxide (CO2) is recovered for disposal in geological storage or for use, such as enhanced-oil recovery (EOR). The second option, called the “base-case,” is a conventional IGCC power plant releasing CO2 by combustion of the synthesis gas in a gas turbine. The life-cycle analysis task has been aided by use of LCAdvantage TM . Process design has been aided by the use of ASPEN © simulation for critical design areas. Special attention was paid to the transport issues for the CO2 product, because transportation technology is a determinant of product specifications, which affect plant design. Separating and purifying the H2 for fuel cell use should yield an impressive gain in overall process efficiency that can offset the losses in efficiency from recovery and compression of CO2 to supercritical conditions. GASIFICATION CYCLES Plant Design Basis The Shell (entrained-flow) coal gasification system has been selected as the basis for this co-product plant. The energy and environmental performance of the co-product plant are compared with those of a base case plant that also uses the Shell gasification technology but produces only electricity as a salable product. The base case IGCC plant and the co-product plant are substantially different in design. The most significant common elements are the use of the Shell gasifier and the consumption of the same amount and type of coal. Principal features and differences are summarized in Table 1. Co-Product Plant Description Figure 1 presents an overview of some of the critical process areas of the co-product plant, clarifying the differences noted in Table 1. The front end of the plant is nearly unchanged through Area 2000; gasification; heat recovery; particulate removal; and COS hydrolysis. Area 3000 is new. Here a shift reactor uses steam to convert the CO component of the raw gas to CO 2 and hydrogen (H2). In Area 4000, significant modifications are necessary. Hydrogen sulfide (H2S) is removed from the stream and processed by the Claus and SCOT units to produce marketable sulfur. The Claus Plant converts H2S to elemental sulfur but leaves a residual of SO2 and unconverted H2S, which must be treated by the SCOT process. In the base case, filtered raw gas is used in the SCOT process as a reagent to reduce SO2 to H2S, which is then recycled to the Claus Plant. H2 is the active reductant in the raw gas. The remaining CO from the raw gas reagent is flared and released as CO2. We propose to use the purified H2 as reagent, eliminating the need for a flare and associated CO2 emissions while also reducing equipment costs . Following H2S recovery, CO2 is removed from the remaining gases in a glycol-based process. The end use specifically targeted for the CO2 is EOR. EOR requirements drive the CO2 product specifications. The gas stream after CO2 recovery is processed via pressure swing adsorption (PSA) to recover H2 at high purity so that fuel cell efficiencies are maximized, although there is no restriction on the actual hydrogen end use. The pure hydrogen stream is transported to end users via pipeline. Area 5000 employs the residual gas from PSA – a combination of hydrogen, methane, and others – to generate electricity by combustion turbine combined cycle. Part of the electricity generated supplies the internal needs of the plant, and the excess represents a fourth marketable plant product. Air separation is integrated with the balance of plant through use of N2 as a diluent in the combustion turbine.