Biogas Contaminants

Due to the additional components listed in Table 1.1, biogas often requires some processing prior to its use. The removal of minor contaminants (all components except CH4 and CO2) is hereinafter called biogas treatment. The removal of carbon dioxide is often referred to as biogas upgrade and the resulting gas biomethane. An overview of issues caused by the dierent biogas contaminants in typical biogas applications is presented in Table 1.3.

It is essential to discuss about the potential implications of the contaminants towards the application intended within this thesis. Water, nitrogen, oxygen, and carbon dioxide are already present in the OCM system and are not con-cerning. Dust is undesired, but can be easily ltered out. Therefore, siloxanes, ammonia, and hydrogen sulde are the most concerning contaminants.

1.1 Biogas

Table 1.3: Major biogas contaminants and the issues associated with them ac-cording to (Ryckebosch, Drouillon, and Vervaeren, 2011)

Contaminant Issues

Carbon Dioxide Low caloric value

Water Corrosion due to acid formation Hydrogen Sulde Corrosion and toxicity

Dust Deposition and clogging of equipment Siloxanes Formation of SiO₂ in combustion chamber Oxygen or Air Formation of explosive atmospheres

Ammonia Corrosion

Siloxanes are organic compounds containing SiO bounds, which are em-ployed in hygiene products, pharmaceuticals, cosmetics, textiles, and paper coatings due to its low-ammability, low surface tension, thermal stability, hy-drophobicity, compressibility, and low toxicity (Abatzoglou and Boivin, 2009).

Siloxanes, due to their origin, are present in landl gas or biogas from urban treatment facilities, but not in agricultural biogas. Therefore, they are not a concern for biogas derived from vinasse AD.

Ammonia (NH₃) is formed through AD of nitrogen-containing molecules in substrates. Although several authors mention the presence of ammonia in bio-gas, very little is discussed about its implications on the biogas utilization and possible removal methods. This is mainly because most of the processes re-quired to remove other components, mainly H2S, can simultaneously remove NH₃. The same is valid for other trace components like benzene, toluene, chlo-rine compounds, and heavy hydrocarbons, which are only mentioned by Rasi, Veijanen, and Rintala, 2007. The relevant literature on biogas treating, dis-cussed in Chapter 1.1.3, focuses largely on H₂S and CO₂ removal.

Hydrogen Sulde (H2S) is formed through the AD of any sulfur-containing molecules in the substrate. Due to its highly corrosive, toxic, and malodorous nature, it must be removed from biogas prior to most applications. Besides that, if biogas is combusted, H2S is oxidized into SOx (Equations 1.2 and 1.3), which has strictly regulated emissions in most regions. Therefore, for the complex heterogeneous catalytic process investigated in this thesis, it is likely that a ne H2S removal is required. This can be achieved through the methods described in Chapter 1.1.3. However, even traces of H₂S (fewppm_v) can potentially still be harmful to the catalyst, reaction, or the process.

H₂S_(g)+3

2O_2(g) −−→SO_2(g)+ H₂O_(g) (1.2) SO_2(g)+1

2O_2(g) −−↽−−⇀SO_3(g) (1.3) Eects of Hydrogen Sulde to OCM Catalyst and Process

A single reference has been found in literature dealing with the eect of sulfur components to OCM reactors (Campbell et al., 1992). Experimental investi-gations have been carried out with 6 ppmv to 200 ppmv of H2S at750°C and 900°C with a CH₄:O₂ ratio of 9:1 and dierent space velocities on a lab-scale quartz glass reactor packed with lanthanum oxide (La₂O₃) catalyst. The main conclusions of the study are reported below:

ˆ H₂S and all other sulfur components are likely oxidized to sulfur dioxide (SO₂) and sulfur trioxide (SO₃)

ˆ At750°C, the catalyst is poisoned by the SOx species due to the formation of surface sulfates (La₂(SO₄)₃)

ˆ The selectivity towards C2 products is almost unaected by catalyst poi-soning until methane conversion drops signicantly

ˆ The catalyst poisoning is controlled by temperature, contact time, and sulfur concentration

ˆ The poisoning could be reversed by increasing the reactors' temperature to 900°C

It is, therefore expected that even low concentrations of H₂S will slowly reduce catalytic activity and reduce methane conversion during process operation. The upstream biogas treatment unit must therefore ensure a very ne sulfur removal in order to mitigate this eect. If the catalyst performance drops signicantly, catalyst re-activation (re-oxidation) can be achieved by operating the reactor at a higher temperature.

A small amount of SOx species would also be present in the reactor outlet stream. Among those, SO₃ is more concerning due to the formation of sulfuric acid (H2SO4) in the presence of water (Equation 1.5). At the high temperatures for OCM (700°Cto 900°C), the SO₂ oxidation reaction equilibrium (Equation 1.3) is largely shifted towards the educt side (Campbell et al., 1992). Cooling of the gases in the downstream shifts the equilibrium towards SO3, but the kinetics are rather slow and typically require a catalyst, e.g., vanadium(V) oxide (V₂O₅) is employed industrially for sulfur dioxide oxidation in sulfuric

1.1 Biogas acid plants. This means that the sulfur components in the reactor outlet would be largely comprised of SO₂ with smaller amounts of SO₃, H₂SO₃, and H₂SO₄ all in gaseous form.

SO2(g)+ H2O(g)−−↽−−⇀H2SO3(g) (1.4) SO_3(g)+ H₂O_(g)−−↽−−⇀H₂SO_4(g) (1.5) In the OCM reactor downstream, the gas stream is usually quickly cooled down in a transfer-line heat exchanger by generating high-pressure steam fol-lowed by additional heat recovery steps in gas-gas heat-exchangers. A similar problem has been described for a coal-based oxy-fuel combustion process (Belo et al., 2014). In that particular case, recycling the ue gases to the combustion step leads to a four-fold increase in SOx concentrations compared to regular air combustion. The higher SO3 concentration increases the gas' dew point tem-perature, which reduces the amount of heat that can be recovered in the boiler prior to acid condensation. Hence, special care must be paid to the design and operation of the heat-exchangers in the downstream of the OCM reactor in or-der to avoid acid condensation and corrosion issues. The nal gas cooling step is achieved in a quench column (direct contact heat-exchanger) with process water. The wash and cooling to around 45°Cwould ensure the removal of the trace sulfur components from the gas stream, but this column and internals should be constructed in acid-resistant materials and the water purge stream must be dealt with accordingly.

Further experimental studies regarding the eect of dierent H2S concentra-tions to various OCM catalysts under varying operating condiconcentra-tions are required in order to further investigate potential issues. This is also relevant for natural gas-based OCM given that traces of this component may also be present.