Cleaning up the Gas Grid

In Germany electricity production from renewable sources is supported at a special rate as set out under the renewable energy law (EEG). This special rate applies to electricity produced from biogas transmitted through the natural gas grid, but is also increased by an additional bonus for use of innovative technology, such as biogas upgrading. In addition, a new law on heating with renewable energies came into effect in 2009, which requires new buildings to be heated with a share of at least 20% of renewable sources or combined heat and power (CHP). Furthermore, there is a negotiated environmental agreement by the gas utilities in Germany to add at least 10% biogas to natural gas for vehicle fuel (LPG) in 2010 and 20% by 2020.

The main operational advantages of biogas feed-in to the natural gas distribution grid are that the biogas can be used at higher energy efficiency where the waste heat can be used. In addition, by using the gas grid for virtual storage, time-decoupling between biogas production and consumption can also be achieved.

In spring 2008 the energy utility Energie Baden-Württemberg (EnBW), together with its gas grid subsidiary Erdgas Südwest (ESW), began operations at a new facility, upgrading biogas and feeding it into to the natural gas grid. The bio-methane is produced in co-operation with an agricultural company of 20 farmers who own and operate the fermentation biogas plant and procure the biomass. The gas is produced by the farmers and sold to EnBW-ESW, which ensures the quality necessary in the gas distribution system, the measurement required for invoicing and deals with transport to the customer. Around 5 million Nm3 of raw biogas is upgraded annually to around 2.8 million Nm3 of biogas at natural gas quality and fed into the gas grid.

In conventional biogas plants in Germany the biogas is burnt in a co-located reciprocating-engine. This is normally in a rural area, where heat demand is very restricted. While some 15%–20% of the exhaust heat is consumed by the fermenter, in most cases the rest is difficult to sell and, as a consequence, the efficiency of biogas plants is limited. However, even under EEG-tariffs for electricity production, without heat sales it is becoming more and more difficult to achieve the economic operation of a biogas plant. Conversely, if biogas can be transported to a heat sink, a CHP plant can utilize the bioenergy much more efficiently and can supply heat at a better value and so at a higher income. If the biogas is to be transported in the wider natural gas grid, it has to be upgraded to meet the quality needed for the grid.

Upgrading Biogas to Grid-Ready Quality

The process steps from biogas production to feed-in are: Drying; Desulphurisation; CO2 removal (adjusting heating value); Compression; Metering; Odourisation; and, Feed-In.

In Germany, the DVGW regulations G260 and G261 are the main rules controlling the requirements on fuel gases fed into gas grids. The main practical reasons for quality regulation are that gas applications are developed to work with these defined qualities, and because reliable invoicing from customers with respect to volume metering is required.

Drying can be done by cooling the raw gas before CO2 removal by pressure swing adsorption or with other wet processes after the CO2 is removed. Desulphurisation is simply done by an air injection directly into the fermenter, where H2S is reduced to elemental sulphur. However, to avoid gas dilution by N2, this desulphurisation measure must be minimized. Alternatively, an external NaOH-wash with biological solvent regeneration can be installed or the sulphur directly bound in the fermenter by the addition of iron salts, both of which avoid dilution of the biogas, but cause some extra operational costs.

The most important step of biogas upgrading is the removal of CO2 to raise the gas heating value. Here it is important not to lose too much CH4 with the removed CO2 and not to spend too much energy on CO2 removal. Compression brings the upgraded biogas to the grid’s operational pressure and eventually the heating value of biogas has to be increased to that of the gas in the grid. Metering, odourisation and the feed-in-station complete the upgrading and injection process.

Technology options for biogas upgrading were compared in order to find the optimal solution. However, at the time of process selection not all options were at a mature market status and the key step in biogas upgrading – CO2 removal – was commercially available only using pressure swing adsorption or pressurized water wash technologies.

Meanwhile, additional suppliers offer tested processes with chemical absorption and even membranes and cryogenic gas cleaning. Table 1 shows an evaluation of the different available technologies. Besides investment costs, important parameters are the costs of operating energy consumption and methane losses, and energy recovery. Differing product requirements may change the priorities, however.

Keeping Methane Emissions Under Control

As the greenhouse gas intensity of methane is 21 times higher than that of carbon dioxide, it is important to avoid any methane emissions in order to keep biogas production climate friendly. Indeed, the effect of methane emissions from biogas production and upgrading can be as high as from electricity production from fossil fuels. In addition, a part of the saleable product is lost together with methane emissions.

The main sources of methane emissions from biogas plants are the storage of fermentation residues and the CO2-rich takeoff-gas from the biogas upgrading process. By closing the fermentation residue storage and collecting the produced gas, the first of these potential emission sources can be avoided. Methane emissions from the takeoff-gas can also be minimized by the choice of chemical or physical absorption, as shown in Table 1, where almost no methane is lost. For the other processes listed it is important to destroy the methane content in the takeoff-gas before emission to the atmosphere. In biogas upgrading with pressure swing adsorption the low methane content in the takeoff-gas, typically around 4%, prevents it from being combustible in a normal burner. In the case of the pilot plant operated by EnBW-ESW this problem was solved by a flameless oxidation burner where temperatures of more than 800°C can be reached, allowing combustion with a minimum of added fuel. Due to the high temperature, energy can also be recovered for heating.

With biogas upgrading and feed-in to the natural gas grid, the cheaply available waste heat from the engine exhaust is no longer available as a heat source for the fermenter.

As energy efficiency then becomes more important, using heat sources from the biogas upgrading plant can help to supply part of the heating energy, such as the expensive combustion of the takeoff-gas from pressure swing adsorption. As the fermenter heating requirement varies throughout the year, additional heating capacity must be prepared.

In Germany, a 400 Nm3 per hour gas upgrading project was operated in the main sewage treatment plant of Stuttgart in the late 1980s and early 1990s. Another such plant in Germany was operated at the sewage treatment plant in Mönchengladbach-Neuwerk.

In what became the first commercially and fully-operational biogas upgrading plant in southwest Germany, EnBW and ESW constructed an upgrading plant at Burgrieden near Laupheim and started continuous biogas feed-in in March 2008. As the first project of its kind by the company, great care was taken in the selection of an optimized technology which allows energy- and cost-efficient operation, high availability and strictly avoids additional methane emissions to the atmosphere.

The ball was started rolling by a group of farmers, who planned to build and operate a biogas plant but could not find a heat customer. The solution was co-operation with the utility to feed the biogas to the grid.

Farmers and Utility Working Together

Careful organization of the whole chain from substrate production to biogas production and fermentation residue use is essential, especially in terms of security of supply during times of high agricultural prices. A minimum production level of 300 to 500 Nm3 per hour is necessary for an economic process. In the region where EnBW is active, the agriculture is characterized by limited farm sizes and individual biogas plants, requiring the connection of several biogas producing plants to one larger upgrading plant or supply from several farmers to one biogas plant.

In this case the raw biogas is produced by the BLG (Biogas Laupheim Gesellschaft), founded and operated by 22 farmers. These farmers cover around 60% of the required cultivated area. The co-operation is based on a long-term contract and a price escalation clause that increases the price annually. The gas utility guarantees to buy all biogas produced and is solely responsible for the reliability of the upgrading plant. This means that the farmers do not need to be concerned with equipment maintenance or upgrading, gas sales or quality problems. The farmers take responsibility for secure substrate supply and biogas plant operation.

This concept of co-operation between local agriculture and energy utility offers all participants the chance to take advantage by covering the whole production and supply chain using the most appropriate individual competences. During the lifetime of a project it is presumed that operating costs on both sides will rise. The upgraded biogas in the gas grid is mainly used in decentralized CHP-plants where the German EEG-rate is paid for electricity production. As the EEG-rate is fixed over 20 years, additional income over that period can only be generated by rising prices for the additional heat sales. A part of the risk associated with rising income is shared with the biogas producers by the contracted annual price escalation for the raw biogas. In this way a stable economic basis for the future is created for both sides and risk is reduced.

Operational Experiences of Biogas Feed-In

Since the first biogas feed-in into the gas grid in March 2008, production and feed-in has steadily risen. In the first phase the aim was to produce 300 Nm3 of raw biogas per hour (7200 Nm3 per day). After week 32, an even higher biogas production rate was attained but the acid value in the fermenter had also increased. After slightly reducing the substrate feeding and correcting the trace element balance with some additional nutrients, the biogas production was slowly increased and at the beginning of 2009 around 550 Nm3 per hour of gas was being produced. The aim of 600 Nm3 is expected to be exceeded after additional storage for fermenter residue becomes available. The performance of biogas production during this initial period can also be attributed to additional monitoring by researchers from the agricultural university of Stuttgart-Hohenheim. Some operational disturbances could be further reduced by better coupling of the two control systems of the biogas production plant and the upgrading plant. Also, the automation of the gas flare had to be improved in order to quickly react to interruptions without lasting effects on production.

The balance of the internal energy consumption, the methane loss and heat recovery in the plant shows an energy efficiency of biogas upgrading of 92%. However, there is an energy loss or unused share of the bioenergy of the original substrate, which is contained in the losses of organic matter in the fermentation residue. All energy losses are significant sources of costs of biogas production and upgrading which at the same time represent important potential for improvement.

Typical costs of the steps of producing biogas in the gas grid are as follows: biogas production, 3.3–7.9 ct/kWh gas; biogas upgrading, 1.2–6.3 ct/kWh gas; net transport, 0–3.5 ct/kWh gas; CHP engine O&M, 0.9–1.0 ct/kWh gas. With these costs, it is still difficult to create an economic project earning enough from the electricity and heat sales to cover the additional cost of gas upgrading and transport. From a cost analysis, it is evident that the largest share of costs is caused by the biomass substrate production, followed by upgrading costs and the cost of the biogas plant.

Considering biogas upgrading, operating costs may potentially be lowered if energy consumption can be further reduced. There is hope considering that the partial pressure of the CO2, which is removed from the biogas, is higher than in the ambient air to where it is released. If a simplified plant, for example with improved membranes, is feasible in the future then this might also help cost reduction. For the overhead costs associated with the biomass substrate and the biogas plant, it would help if a higher fraction of the organic matter could be converted to gas.

At present, however, biogas upgrading to natural gas quality is very expensive. Therefore other utilization routes have to be considered which might be more competitive in some cases. Alternatives include a local biogas grid (though in a direct grid, not all boilers or engines would be able to operate on biogas), a gas grid with lower gas quality (cheaper upgrading) and biogas for filling stations. Another important factor would be a solution that enabled biogas upgrading in smaller scale plants.

The concept gives a basis for co-operation between biogas producers and gas utilities. Farmers can profit from a higher production potential as well as a secured income at a reduced operation risk. For utilities, customer relations can be improved or even new markets opened. Biogas upgrading is technically proven and commercially available. However, improvements in efficiency and further cost reduction will be necessary.

Gerold Göttlicher is research manager for Energie Baden-Württemberg (EnBW). Armin Bott works for Erdgas Südwest.

A Twin-Track Approach to Cleaner Gas

Key features of the biogas production plant owned and operated by the 22 farmers who make up BLG:

  • Two-stage fermentation, mesophilic/thermophilic 38°C/ 52°C
  • Input: 20,000 tonnes energy crops per year, approximately 80% corn-silage, 20% wheat plants, no manure
  • Two fermenters, one post-fermenter, three residue storages
  • All tanks are gas-tight, including residue storage
  • Biogas production: maximum 600 Nm3 per hour, 3 MW gas
  • Fermenter heat consumption 250 kW, electrical auxiliaries 80–100 kW

Key features of the biogas upgrading plant owned and operated by EnBW-ESW:

  • Desulphurisation with iron salts in the fermenter (in the part belonging to the BLG farmers group)
  • CO2 removal process: pressure swing adsorption
  • Raw gas volume flow: up to 600 Nm3 per hour
  • Outlet pressure: approximately 5 bar
  • Methane content in upgraded biogas approximately 97%
  • Methane content in weak take-off gas 2%–5%
  • Methane losses: approximately 3%
  • Utilization of takeoff-gas in Flox-combustor without climate harm for fermenter heating
  • Feed-in station
  • Metering of volume flow of upgraded biogas and mixed gas in the grid
  • Quality metering with calorimeter and IR-measurement
  • Electricity consumption 140–170 kWh per hour


Previous articleBC To Proceed with Site C Hydropower Project
Next articlePV industry pricing: The good, the bad, and the confusing

No posts to display