Flue gas CO 2 capture using a Ca-based chemical looping system has been shown to be potentially more cost-effective than traditional amine-based systems in bench-scale testing. The results of these initial tests are projected, using an Excel-based economic model, to estimate the 30-year levelized cost of CO 2 capture per metric ton (t) for a utility-scale power plant. An order of magnitude capital and operating estimate for a 360 MW pressurized fluidized bed combustor (PFBC) is presented, assuming a western Canadian location. Additional costs for calciners, O 2 plant, and related equipment necessary to create a Ca-based CO 2 chemical capture loop are presented separately. These costs are evaluated in a series of spreadsheets, and the impact of process flows, as well as capital, operating/maintenance, and feedstock costs are determined in a sensitivity analysis. The financial results for CO 2 capture are found to compare favorably with amine-based capture systems.
The identification and quantification of individual physicochemical forms of mercury (Hg)
emissions from coal-fired systems is imperative for addressing questions concerning atmospheric
fate and emission control. The flue gas composition and ash characteristics can have a significant
impact on Hg speciation. Unfortunately, there is a lack of information available on mercury
behavior under gasification conditions, which are different from combustion conditions. A bench-scale test apparatus was designed and built to simulate the synthesis gas conditions. The primary
goal of this bench-scale work was to determine which gas constituents typical of gasification
(CO, CO2, HCl, Cl2, NH3, HCN, COS, and H2S) affect the oxidation of elemental mercury, which
was delivered to the system via temperature-controlled permeation tubes. There appear to be a
number of interactions between various synthesis gas constituents that affect mercury speciation.
The results indicated that the reducing environment is not favorable for Hg oxidation via gas-phase reactions alone and that more elemental mercury is expected to remain in the syngas
from coal gasification. However, depending on the temperature and concentration, there is clearly
an interaction between fly ash and gas combinations to promote the mercury oxidation rate.
Bench-scale tests also indicated that the chemistry of mercury is very complex. Further
verification of this study has been planned at a pilot-scale entrained-flow gasifier.
Petroleum coke is quickly becoming the fuel of choice for many FBC boiler operators, due to
its low cost, high availability and high heating value. However, these inherent benefits come
with a price, as the high sulfur content of coke requires limestone use as a sorbent for sulfur
capture. In some cases, operational problems associated with limestone use have arisen. Fouling,
in terms of solid deposits in such boilers are normally thought to occur as a result of interaction
with various fuel-ash-derived species within the system. However, detailed examination of the
solid deposits demonstrated that the fouling was, most generally, associated with an agglomeration
mechanism we have called extended sulfation, i.e., sulfation to near quantitative levels of the
limestone sorbent. Carbonation and hydration have also been found to play a role in the
agglomeration process at lower temperatures. This paper describes the fouling mechanisms in
three circulating fluidized bed boilers firing petroleum coke as the only fuel.
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