state of biogas injection to the gas grid in...

STATE OF BIOGAS INJECTION TO THE GAS GRID IN GERMANY

Frank Graf 1, Uwe Klaas 2

1. DVGW Research Station at Engler-Bunte-Institut, Universität Karlsruhe (TH) 2. DVGW e.V.

Keywords: 1. biogas injection; 2. biogas upgrading 3. technical standards; 4. R&D activities 1 Background

Biomass and especially biogas is deemed to be part of the desired substitution of fossil energy. The majority of biogas systems in Germany have an electric power output below 500 kW (Fig. 1). They are generally installed in rural areas where the efficient use of the co-produced heat is hardly possible and approximately 50 % of the energy content of the biogas is dissipated. Fig. 1 shows explicitly the push effect of the German act on granting priority to renewable energy sources (EEG) in 2004 [1]. The purpose described in article 1 of this act is to protect the climate by facilitating the use of renewable energies. This is achieved by paying a guaranteed price for the produced electric energy which includes a bonus if compared to conventionally produced electric energy. From the beginning of 2009 new payment provisions have been applied [2].

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Fig. 1 Development of number and electrical output of biogas plants in Germany [3,4] Because of the insufficient use of co-produced heat mentioned above injection of purified biogas in

the natural gas grid is a reasonable alternative. The main advantage of this application is the separation of the biogas production from the decentralized power conversion at locations with permanent heat demand. Furthermore, upgraded biogas can be used as transportation fuel for CNG cars. Due to the advantages the German federal government pursues the objective to supply 10 % of the German gas demand by biogas. To achieve this, approximately 1.500 plants have to be built. By the end of 2008, 14 biogas injection projects have been realized in Germany. Approximately 16 further projects are scheduled to start injection in 2009 (Fig. 2). Up to now, approx. 16,000 m3/h (NTP) upgraded biogas are injected into the German gas grid (Fig 3). By the end of 2009 32 plants should be operated with a total biogas injection flow of 22,730 m3/h which corresponds to approximately 2 % of the political objective.

In Germany, the DVGW (Deutsche Vereinigung des Gas- und Wasserfaches e. V. - Technical and Scientific Association for Gas and Water) has been providing technical and scientific support for the German gas and water industry since 1859. All the activities of the DVGW focus on safety, hygiene and environmental protection, taking efficiency and cost-effectiveness into consideration. As a technical standardization organization, the DVGW promotes technological development in its sector. The production, transportation, distribution and use of energy and drinking water always call for technical processes and plant. The technical standards of the DVGW lay the foundations for technical self-regulation under the

responsibility of the German gas and water industry and ensure safe gas and water supplies at the highest international levels. Therefore, DVGW masterminds the development of technical conditions for biogas injection into the gas grid in Germany. Quality and safety aspects are discussed in several task forces and working groups and technical standards are revised and developed. Furthermore, gas and water specific aspects are examined in a perennial research program.

Fig. 2 Realized and planned biogas injection projects in Germany (red dots) [5]

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2 Objectives of the paper To guarantee a successful introduction of a new technology various technical details have to be

clarified. In this article an overview of the DVGW activities in the field of biogas injection will be given and first experiences will be discussed.

3 Technical aspects for biogas injection in Germany

3.1 Quality aspects Since April 2008, a federal ordinance, granting upgraded biogas preferred access to the natural gas

grid, is in force, referring to some DVGW standards in regard to the gas quality and billing issues. First of all, the DVGW standard G 260 “Gas quality” shall be complied with. In this standard the most important quality parameters as heating value, Wobbe index or sulphur content limits are defined. Gas components which are specific for gases from renewable sources (e.g. CO2) are considered in the DVGW standard G 262 “Usage of gases from renewable sources in the public gas distribution”. Currently, this standard is under revision with respect to new developments and opening for components found in some gases as e.g. sewage gases by defining threshold values. For example the maximum allowed CO2-content which currently is limited to 6 vol.-% is under discussion in order to minimize the expenses for biogas purification and conditioning. Technical standards for billing are established in the DVGW standard G 685 “Gas billing” which was adapted in 2008. According to this standard, fluctuations in the heating value of 2 % are allowed with respect to the standard heating value in the particular grid. To fulfil this requirement biogas has to be conditioned with LPG and/or air in most cases. An overview on this topic is given by Burmeister et al. [6]. If injected biogas is used in CNG car filling stations DIN 51624 has to be taken into account additionally. Especially the compliance with the limit for the total sulphur content is a current topic in German gas industry. In Tab. 1 the most relevant requirements are summarized.

Tab. 1 Quality requirements for biogas injection in Germany

parameter unit value standard

condensation temperature DVGW G 260

dew point °C soil temperature (at pipeline pressure)

DVGW G 260

water mg/kg 40 DIN 51624

dust, particles - technical free DVGW G 260

O2 (dry grids) vol.-% 3 DVGW G 260

mg/m3 30 (exclusive odorization) DVGW G 260 total sulphur

mg/kg 10 (CNG, inclusive odorization) DIN 51624

mercaptan sulphur mg/m3 6 DVGW G 260

H2S mg/m3 5 DVGW G 260

CO2 vol-% 6 DVGW G 262

H2 vol-% 5 DVGW G 262

propane vol.-% 6 DIN 51624

butane vol.-% 2 DIN 51624

superior calorific value kWh/m3 (NTP) 8.4 - 13.1 DVGW G 260

relative density - 0.55 - 0.75 DVGW G 260

Wobbe number

(natural gas L) kWh/m3 (NTP) 10.5 - 13.0 DVGW G 260

Wobbe number

(natural gas H) kWh/m3 (NTP) 12.8 - 15.7 DVGW G 260

3.2 Safety precautions

Up to 2008 no technical standard for the coupling of a biogas plant with gas treatment to the gas grid was available in Germany. This data gap was closed with the new DVGW standard VP 265-1 “Biogas treatment plants for the injection of upgraded biogas to gas grids - Part 1: Fermentative generated gases; Design, manufacturing, construction, testing and commissioning” which defines all safety relevant aspects for the total process chain from outlet digester to the gas grid (Fig. 4). Beside others the following topics are covered:

requirements on materials and piping safe handling of biogas avoidance of unwanted backflows into the upgrading plant or into the biogas plant protection against undesirable operating conditions prevention from air introduction construction and equipment checking and inspection explosion prevention bringing into service

BGUP BGCP BGIP

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BGCP: biogas conditioning plant

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Fig. 4 Area of application VP 265-1 In the near future a second standard for the operating of biogas injection plants will be designed.

Beside the standardisation activities authorized DVGW-experts for biogas plants will be skilled in 2009/2010. Furthermore, a DVGW Technical Safety Management System which is already in use for gas and water supply should be created for biogas injection plants to assess all relevant safety aspects with respect to organisational structures.

4 R&D-activities

2007 a R&D-program with various projects was initiated by DVGW (Fig. 5). In the first part, available data for biogas production, biogas purification and injection to the gas grid were analysed and recommendation for biogas projects were designed. To complete these data more detailed investigations were undertaken in the second part. For example an extensive monitoring program was accomplished. In this monitoring program the most relevant biogas purification and upgrading technologies are considered to evaluate important operating parameters (e.g. product gas quality, energy demand, methane slippage). Furthermore, sustainability aspects were included in another study. Scope of the ongoing activities will be the optimization of the total biogas process chain from the biomass supply (e.g sustainable cultivation of

various energy plants, usage of biomass residuals) to the injection of the upgraded biogas. Beside technical and ecological aspects economical questions are considered as well. In the following results from three R&D projects are presented briefly.

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Sustainability of biogas

PurposeEvaluation of long-term

impacts of biogas generation and feeding to soil-, air- and water-

quality

Transport of raw biogas

PurposePurposeDefinition of minimum

quality requirements for transport of raw biogas

Conditioning of Biogas I

PurposeQuantification of

LPG/air-adding to biogas against natural

gas quality

Biogas treatment

PurposeTechnical and

economical evaluation of biogas treatment

technology

Biogas monitoring program

PurposeAnalysis of main and trace components of

raw and purified biogas

CO2-limits in residential

applications

PurposeDetection of CO2-limits for the safe operation

of domestic burner systems

Conditioning of Biogas II

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for LPG-adding to biogas

Projected:Material testing

Purpose

Behaviour of various components which are

in contact with raw biogas

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PurposeEvaluation of long-term

impacts of biogas generation and feeding to soil-, air- and water-

quality










gas quality




gas quality

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technology

Biogas treatment



technology

Biogas monitoring program

PurposeAnalysis of main and trace components of

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in contact with raw biogas

Fig. 5 DVGW R&D-program “Biogas”

4.1 Evaluation of biogas upgrading technologies

The prevailing purification tasks for the biogas cleaning are - desulfurization - CO2-removal - drying

The simplest way to remove H2S from biogas is the direct conversion to S, H2SO4 and H2O by microorganisms within the digester. The H2S content can be reduced to 100 - 200 ppm but air has to be introduced in the digester, as Microorganisms like Thiobazillus and Sulfolobus need O2 for the conversion of H2S. Remaining O2 and N2 is undesirable in the upgraded gas. To reach H2S contents of a few ppm the desulfurization is split normally in a primary step for removing the bulk of the H2S in or directly downstream the digester and a second step for removing remaining traces. For the primary desulfurization ferrous salts could be used: a) chelated iron 2 Fe3+L + H2S 2 Fe2+L + S + 2 H+ b) ferrous hydroxide 2 Fe(OH)3 + 3 H2S 2 FeS + S + 6 H2O c) ferrous oxide 2 FeO3 + 3 H2S 2 FeS + S + 3 H2O d) ferrous chloride Fe2+ S2- FeS These four salts can be admixed directly to the substrate in the digester. The H2S content of the raw biogas can be reduced down to 50 ppm. Another possibility to remove H2S from the raw biogas is a double-staged scrubber. In the first scrubber H2S is washed out with a NaOH-solution (s. chemical reaction e) below). The sulphur loaded solution is fed to a second scrubber. There, the NaOH-solution is regenerated under oxygen by microorganisms according to the chemical reactions f) to h). e) H2S + NaOH NaHS + H2O f) NaHS + 0,5 O2 NaOH + S

g) 2 NaHS + 4 O2 2 NaHSO4 h) 2 NaHS + 4 O2 Na2SO4 + H2SO4

With this process the H2S content of the raw biogas can be reduced to 50 to 100 ppm. The final

desulfurization can be undertaken by adsorption with K2CO3, KJ and KMnO4 on activated carbon as sorption material. For producing elementary sulphur oxygen and temperatures of approx. 60 °C are needed.

For the CO2- removal the pressure swing adsorption (PSA) and the water scrubber (WS) are the processes which are most widely used for biogas upgrading. Furthermore, physical scrubbing (PS) with Genosorb (polyethylene glycol dialkyl ethers) as scrubbing liquid is used. Also chemical scrubbing processes with diethanolamine (DEA) are commercially available. These CO2-removal systems which are commercially available produce an off gas consisting of CO2, optionally H2S and CH4 which have to be burned to avoid the emission of the greenhouse gas CH4 and - optionally - H2S. In Tab. 2 important operating data are summarized. Furthermore, other gas treatment technologies are under development e. g. monoethanolamin (MEA) and piperazin scrubbers, membranes and cryogen processes.

Tab. 2 Operating data of commercially available CO2-removal systems [7-15]

DEA PS WS PSA

removable components - CO2, H2S CO2, NH3, H2S, H2O

CO2, NH3, H2S CO2, H2O

pre desulfurization required - no no no yes

poperation bar > 1 > 7 > 7 > 5

Toperation °C < 55 < 40 < 25 < 10

Tregeneration °C < 160 < 80 < 20 - specific electrical

consumption kWh/m3 0.06 - 0.2 0.19 - 0.51 0.24 - 0.4 0.25 - 0.33

specific thermal consumption

kWh/m3 0.44 - 0.8 0.15 - 0.4 - -

Because of the possibility to remove CO2 solely or in combination with H2S, the purification steps can

be arranged with two process chains (see Fig. 6. and Fig. 7). For primary desulfurization FeCl2 will be admixed directly to the digester. The pre-dryer to follow is a condensation dryer enabling a dew point of the gas of 5 - 10 °C. Fig. 6 shows a proposed solution with H2S being removed prior to CO2. The pre-dried gas is desulfurized by iodized activated carbon. This process chain has the advantage that all the discussed CO2 removal processes can be used and no further treatment of the off gas is necessary. Also, H2S fluctuations in the raw biogas are buffered in the final desulfurization unit and no H2S will affect the CO2 removal process. If CO2 is removed in a PSA, a final dryer will be unnecessary because the PSA will produce a biogas with a dew point below -40 °C.

Fig. 6 Principle of a process chain with the desulfurization upstream the CO2 removal

The alternative sequence (s. fig. 7) foresees a scrubbing system for both CO2 and H2S. The sulphur in the off gas has to be removed to avoid emissions to the environment. If the CO2 is removed in a genosorb-scrubber,

a final dryer can be unnecessary because the genosorb-scrubber will produce a biogas with a dew point below -20 °C.

Fig. 7 Principle of a process chain with combined CO2 and H2S removal using a scrubbing system For the injection into high pressure grids and underground storage, respectively, the allowed oxygen

content is 10 ppm. The presented processes for CO2-removal are not suitable to remove O2 and N2. There are two suitable processes to remove O2. The first solution is chemical adsorption with Cr and Cu as sorbent. It must be pointed out that the chemisorption runs at temperatures above 150 °C. For the regeneration hydrogen is required to reduce CuO. Because of these reasons this process is not an economical reasonable solution for O2-removal from biogas. The other possibility is the selective catalytic combustion with hydrogen on a platinum-palladium-catalyst. As the typical hydrogen content in biogas is not sufficient hydrogen has to be added.

4.2 Sustainability aspects

The discussion of ecological aspects has started within the last years. Several questions have to be answered concerning energy efficiency, greenhouse gas emission, cultivation and supply of substrates and the output and use of digestates. Especially for the protection of water and soil the two last mentioned topics are of interest. First of all the energy efficiency of biogas injection with subsequent combined heat and power generation has to be compared to the direct use in CHPs near to the biogas production. Obviously, the second alternative is favourable if an adequate heat sink is available near to the power generation. Unfortunately, in rural areas the potential for heat demand is limited and excepting from digester heating most often the waste heat can not be used reasonably. In Fig. 8 the overall energy efficiency for biogas injection is compared to the direct power generation for different upgrading technologies. For the decentralized CHP a total efficiency of 85 % was assumed (hel = 40 %, hth = 45 %). Two different injection pressures were considered (16 bar and the particular operating pressure of the upgrading technology). The total efficiency lies between 59.3 and 66.5 %. Thus the injection is a reasonable alternative if no heat sink is available near to the biogas plant.

Regarding greenhouse gas emissions several potential sources for methane emissions can be determinded:

leckages in fermentation process biogas upgrading (CO2-removal, drying) storage of digestates

In new fermentation and upgrading plants the problem are minimized due to new technologies and legal requirements. Critical are especially smaller and older fermentation plants e.g. with open digestate storage. For new injection projects methane emission limits for upgrading plants have to be observed (s. chapter 4.3).

Another topics in which especially the German water suppliers are interest are the influences of the increasing cultivation of energy crops for biogas production and the output of digestates on the water and soil quality. These questions were scope of two DVGW-research projects [16-18]. One result was a recommendation for the output of digestate with respect to the substrate type and the water protection area [16,17]. Furthermore, the hazard potential of biogas upgrading technologies (e.g. output of contaminated iron salts from desulfurization) on water and soil quality was checked [18].

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Fig. 8 Overall energy efficiency for biogas injection compared to decentralized CHP (winter operation) (WS: Water scrubber, PSA: pressure swing adsorption, CS: chemical scrubber, PS: physical scrubber)

4.3 Monitoring of biogas injection plants In a Germany wide monitoring program 7 biogas injection plants and 8 further biogas production

plants were monitored in 2008/2009 to clarify the following aspects: - quality of upgraded biogas, especially range of variation and trace components - operation behaviour of upgrading process - methane losses due to upgrading

Most of the plants use energy crops as substrates. Additionally, manure and food residues are fed as co-substrates. Three plants with pressure swing adsorption, 3 plants with water scrubber and 1 plant with a Genosorb scrubber were considered. Within the program 30 long term analysis (4 to 14 days) of main components (CH4, CO2, O2, N2, H2, H2S) and approximately 100 control samples of trace components (e.g. siliceous organic components, higher hydrocarbons, halogens) were accomplished. Samples were taken from the raw biogas, from the product gas and from the lean gas of the upgrading plant. An overview of the main results is displayed in Fig. 9.

The CH4 content in the raw biogas ranges between 47 and 56 vol.-% (for the dry gas) which is typical for the used substrates. The methane content fluctuates in a range between 1 and 5 vol.-% during regular operation of biogas plants (Fig. 10, Fig. 11). Relevant concentrations of oxygen and nitrogen were detected, caused by desulfurization with air in the digester and/or air input with the substrate feeding. In all injection plants the bulk desulfurization is undertaken in situ in the digester, thus moderate H2S concentrations of 20 to 400 ppm were measured in the raw biogas. Hydrogen was found in most cases with concentrations between 200 and 400 ppmv. In one plant 3,000 ppmv were analysed during regular operating. As hydrogen cannot be separated from the product gas with the biogas upgrading technology the concentration doubles in the product gas. Up to a hydrogen content of 5 vol.-% in the product gas no technical restrictions are expected. In Germany hydrogen has to be analysed continuously for metering and billing aspects above concentrations of 0.2 vol.-%.

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upgradingraw biogas

PSAWSGSnatural gas L H HCH4 in vol-% 91 - 93 95 - 99 95 - 97CO2 in vol-% 3 - 5 0.2 - 3 1.4 - 2.6N2 in vol-% 2.5 - 4 0.2 - 1 1 - 2O2 in vol-% 0.4 - 0,8 0.2 - 0,8 0.1 - 0,3

H2 in ppmv yH2,product gas ≈ 2 x yH2,raw gas

H2S in ppmv < 1 < 1 < 1

PSAWSGSnatural gas L H HCH4 in vol-% 91 - 93 95 - 99 95 - 97CO2 in vol-% 3 - 5 0.2 - 3 1.4 - 2.6N2 in vol-% 2.5 - 4 0.2 - 1 1 - 2O2 in vol-% 0.4 - 0,8 0.2 - 0,8 0.1 - 0,3

H2 in ppmv yH2,product gas ≈ 2 x yH2,raw gas

H2S in ppmv < 1 < 1 < 1

product gas

GS = Genosorb® scrubberWS = water scrubberPSA = pressure swing adsorption

CH4 in vol-% 47 - 56CO2 in vol-% 43 - 52N2 in vol-% 0.4 - 3O2 in vol-% 0 - 0.7H2 in ppmv 0 - 3,000

H2S in ppmv 40 - 200

CH4 in vol-% 47 - 56CO2 in vol-% 43 - 52N2 in vol-% 0.4 - 3O2 in vol-% 0 - 0.7H2 in ppmv 0 - 3,000

H2S in ppmv 40 - 200 GS WS PSAmethane slope in % 2 - 2.6 0.8 - 1.8 1 - 3

CH4 in vol-% 0.4 - 1 0.1 - 0.4 1 - 10CO2 in vol-% 26 - 32 14 - 22 87 - 99N2 in vol-% 51 - 59 62 - 70 0 - 4O2 in vol-% 14 - 17 16 - 19 0 - 1H2 in ppmv ≈ 0 ≈ 0 ≈ 0

H2S in ppmv < 1 20 - 90 < 1.5

GS WS PSAmethane slope in % 2 - 2.6 0.8 - 1.8 1 - 3

CH4 in vol-% 0.4 - 1 0.1 - 0.4 1 - 10CO2 in vol-% 26 - 32 14 - 22 87 - 99N2 in vol-% 51 - 59 62 - 70 0 - 4O2 in vol-% 14 - 17 16 - 19 0 - 1H2 in ppmv ≈ 0 ≈ 0 ≈ 0

H2S in ppmv < 1 20 - 90 < 1.5

lean gas

Fig. 9 Gas quality at biogas injection plants

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Fig.11 Fluctuation raw biogas (wide range) According to the required gas quality 91 to 99 vol.-% methane were detected in the product gas. Due

to fluctuation in the raw gas quality and quantity and process specific aspects methane contents in the product gas vary in a range of 1 - 1.5 vol.-% (Fig. 12, Fig 13). Due to the above mentioned input of air oxygen and nitrogen were found also in the product gas. Furthermore, oxygen can be got into the product gas via the regeneration of scrubber systems that run with air stripping. In Fig. 14 an example for a water scrubber system is displayed. In this case the oxygen flow is increased by 50 % by the air input in the regeneration. H2S is removed nearly completely from biogas. In average the outlet content lies below 1 ppmv. The product gas quality was satisfactory in all cases. One remarkable finding was the presence of siliceous organic components in various raw and product gases. Up to now neither the origin nor the long term quantity are unknown. This aspect should be examined in a continuative monitoring program.

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Fig 14 oxygen input due to regeneration with air The lean gas from CO2-removal contains 1 to 3 % of the total methane related to the raw gas. In

Germany there are limits for the emission of methane from biogas upgrading plants. Since 2009 1.0 % methane loss are permitted, 0.5 %, from the beginning of 2011 respectively. Thus for all considered upgrading technologies a thermal treatment of the lean gas is required. Due to the regeneration of the saturated wash solution with air methane concentrations in the lean reaches low values between 0.1 and 0.5 vol.-%. The consequence is that the methane content is too small for the after treatment with a FLOX-burner or a catalytic burner. The only way to remove methane is a recuperative firing. With this process a heat recovery is hardly possible. The higher methane slope of the PSA allows the use of a FLOX-burner and therewith a heat extraction e.g. for the heating of the digesters. Relevant H2S contents in the lean gas have to be removed also to avoid smell nuisance.

5 Perspectives

The injection of biogas to the gas grid is a suitable alternative for the use of renewable energy carriers. Compared to other biomass based technologies the energy efficiency and the specific energy production are higher. The widely developed gas grid in Germany allows the decoupling of energy production and consumption and the storage of a renewable energy carrier. Furthermore, injected biogas can be used for various energy efficient appliances e.g. CHP-plants, CNG-cars, gas heat pump. To guarantee a sustainable expansion of the biogas potential the complete process chain from biomass production to the application has to be considered in detailed. Furthermore, new technology should be developed to increase the total energy efficiency and the ecological benefit.

References

[1] http://www.bmu.de/english/renewable_energy/doc/6465.php (2009)

[2] http://www.bmu.de/files/pdfs/allgemein/application/pdf/eeg_verguetungs-regelungen_en.pdf (2009)

[3] http://www.bmwi.de/BMWi/Navigation/Energie/energiestatistiken,did=176654.htm (2009)

[4] http://www.bmwi.de/BMWi/Navigation/Energie/energiestatistiken,did=180888.htm (2009) [5] http://www.biogaspartner.de (2009) [6] Burmeister, F. Senner, J.; Heinen, J.: Biogas injection into the natural gas grid,

fundamental aspects. Proceedings of IGRC 2008, Paris [7] Urban, W., Girod, K., Lohmann, H.; Technologien und Kosten der Biogasaufbereitung

und Einspeisung in das Erdgasnetz. Ergebnisse der Markterhebung 2007 - 2008; BMBF-Forschungsprojekt Förderkennzeichen 01LS05039; April 2008

[8] Schmalschläger, T., Klein, K., Tauto, V., Drexler, C.; „Gasseitige Bündelung von Biogasanlagen und gemeinsame Einspeisung ins Erdgasnetz“; Bayrisches Staatsministerium für Landwirtschaft und Forst, Endbericht; November (2007)

[9] Schulte-Schulze Berndt, A.; „Biogasaufbereitung und -einspeisung - Aktueller Statusreport Deutschland“; BBK GreenGas-Kongress; November (2007)

[10] DGE; "Biogas aus Abfall zur Erzeugung von Strom und Erdgas"; BCM-Verfahren; www.dge-wittenberg.com (2006)

[11] Günther, L.; „Biomethanreinigung mit der drucklosen Wäsche zur Herstellung von Biomethan und Kohlendioxid“; Fachtagung INNOGAS - Herstellung von Biomethan aus Biogas (2006)

[12] Oldhafer, N.; „Großtechnische Biogasanlagen - Konzeption, Energieerzeugung, Gas- und Gärrestaufbereitung“; 20. Kasseler Abfallforum und Bioenergieforum; April (2008)

[13] Franke, S.; „Biogasaufbereitungsverfahren“; Workshop „Einspeisung von Biogas ins Erdgasnetz“; Niederschöne Mai (2007)

[14] Heinen, J., Stichtenoth, J., Erich, E.; „Systemvergleich dezentrale Biogasnutzung versus Biogaseinspeisung“; GWF Gas – Erdgas 149 Nr. 10 (2008)

[15] Vogt R., Gärtner S., Münch J., Reinhardt G. 05.2008: Optimierungen für einen nachhaltigen Ausbau der Biogaserzeugung und -nutzung in Deutschland. BMU (Bundesministerium für Umwelt N. u. R. (Hrsg.): 1.Auflage. Berlin, Heidelberg, Darmstadt, Leipzig ID2739

[16] Kiefer J. 2007: Nachwachsende Rohstoffe/Biogasanlagen und Gewässerschutz - Bewertung aus Sicht der Wasserversorgung. gwf Wasser/Abwasser 148 (2007)

[17] Kiefer J.; Ball T.: Beurteilung der Erzeugung von Biomasse zur energetischen Nut-zung aus Sicht des Gewässerschutzes. energie | wasser-praxis 06/2008, p. 36 - 43.

[18] Kiefer, J; Ball, T.; Karch, U.; Köppel, W.: Bewertung der langfristigen Auswirkungen auf Boden, Pflanze, Luft und Wasser bei der Erzeugung von Biogas und der Einspeisung in das Erdgasverteilnetz, DVGW research projekt GW 1/01/07-A/B (2009)

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