a comparison of biogas usage options - chp, turbines … · gas turbines gas turbines typically...

20th European Biosolids & Organic Resources Conference & Exhibition

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A COMPARISON OF BIOGAS USAGE OPTIONS - CHP, TURBINES OR GAS

TO GRID

Jolly M.1,Knight G.,1 and Polo C1. 1Black & Veatch,

Corresponding Author Tel. 07771 848605 Email [email protected]

Abstract

The conversion of biosolids using anaerobic digestion generates biogas which is a mainly a mixture of methane and carbon dioxide with small quantities of other gasses. The methane can be burned to generate electricity in an internal combustion engine or a gas turbine or it can be cleaned up and injected into the natural gas grid. UK government incentives currently allow biogas generated from CHP to receive 0.5 times the renewable obligation certificates (ROC) value which will come to an end in March 2017. However biogas clean up and injection into the national gas network receives an incentive under the heading “biomethane”. The value and timescale for these payments is constantly under review.

Assessment of the biogas usage options requires consideration of the following parameters:

1. Heat to the process

2. Gas conditioning

3. Emissions to atmosphere,

4. Incentive payments,

5. TOTEX (Whole life cost).

This paper gives a technical and economic appraisal of the technologies for biogas usage.

Keywords

Biogas, biomethane to grid, combined heat and power, gas turbine, methane.

Introduction

Anaerobic digestion generates biogas which can be used in various ways. Traditionally mesophilic anaerobic digestion on its own has fitted well with the use of internal combustion engines as combined heat and power (CHP) plant. However for projects considering thermal hydrolysis (TH), the process heating requirements shift from the relatively low grade heat required for conventional mesophilic digestion (i.e. hot water) to the higher grade heat needed to heat and pressurize Thermal Hydrolysis reactors (i.e. steam 190oC). The need for high grade heat in the form of steam means that where turbine technology may not have compared favourably to internal combustion engines in the past for conventional applications, its use requires more careful evaluation for TH facilities. In addition the option to clean up the biogas to produce a gas with 98-99% methane has been incentivised by the UK government and this has led to a number of UK Water Companies installing biomethane to grid plants.

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Comparison of Technologies Combined Heat and Power (CHP) plant The options considered in this paper for CHP include internal combustion engines as well as three different types of gas turbines. Figure 1 provides an overview of typical size ranges for application of Internal Combustion (IC) engines alongside that for microturbines, small gas turbines and mid-sized gas turbines. Also shown in Figure 1 is a typical range of energy availability for medium to large wastewater treatment facilities from 100 000 to 1 000 000 population. As can be seen from Figure 1, IC Engines typically provide a good size fit for the average medium to large sewage treatment facility where biogas is available. Conventional mid-sized gas turbines tend to only be a consideration for the very largest facilities, however more recently a number of smaller gas turbines have come onto the market which provide a better size fit for wastewater applications.

Figure 1 – Typical size ranges for IC Engines and various classes of Gas Turbines

Figure 2 –Jenbacher Type 6 Internal Combustion Engine (Courtesy of Jenbacher)





Gas Turbines Gas turbines typically have a lower electrical efficiency than internal combustion engines however virtually all of the waste heat available is high grade in the form of high temperature exhaust gas from the turbine. An electrical efficiency of around 25% would be typical for a conventional gas turbine. The electrical efficiency of gas turbines can be improved by adding a recuperator. This is a gas to gas heat exchanger which is used to recover energy from the exhaust gas for pre-heating the inlet combustion air. This recovery of energy reduces the work done in heating / expanding the gas in the turbine and improves the electrical efficiency of the unit. The downside of using a turbine with a recuperator is that the recovery of heat from the exhaust means that less heat is available to raise steam and this can lead to a requirement to burn biogas for direct fired steam production, reducing the overall system electrical efficiency. Figure 3 shows a section of Solar’s 4.5MW Mercury 50 gas turbine with a recuperator alongside a simplified representation of the function of the heat exchanger.

Figure 3 – Solar Mercury 50 Gas Turbine with Recuperator (courtesy of Solar) Of the small sized gas turbines available, a recent product to emerge onto the US market is the Opra 16 radial gas turbine. This unit provides a good size fit for typical wastewater CHP applications and the manufacturers claim it is robust in its ability to deal with poor fuel quality (there are installations which are successfully burning relatively poor quality syngas). As well as the ability to deal with poor quality gas, the manufacturers claim reduced maintenance due to the bearings being in the cold part of the turbine as well as reduced wear and tear on the turbine due to it being designed to avoid the concurrent application of high stress and high temperature (i.e. the parts of the turbine which are hot are under low mechanical stress and vice versa.)





Figure 4 – Opra 16 Radial Gas Turbine (courtesy of Opra) Another CHP turbine option which merits consideration for smaller scale installations is the microturbine. These units (which also have a radial flow configuration) achieve a higher electrical efficiency than the Opra turbines due to the use of a recuperator, at the expense of reduced thermal efficiency.

Figure 5 – Capstone Microturbine (Courtesy of Capstone) A comparison of the energy balance across the four CHP options outlined above is provided in Table 1. Several key differences between these units in terms of the energy balance achieved are worth highlighting.

The IC engines achieve the highest electrical efficiency but have the lowest high grade thermal efficiency.

The turbine options with recuperators achieve a higher electrical efficiency than the radial turbine with no recuperator, at the expense of a reduced high grade thermal efficiency.

The IC engine has low grade heat available (in the form of hot water at around 90oC).





Table 1 – Energy balance for four CHP options (values shown are averages across the operating range of the unit)

ENERGY FLOW IC ENGINES

MID SIZE TURBINE

WITH

RECUPERATOR RADIAL TURBINE

MICROTURBINE

WITH

RECUPERATOR

Input Energy 100% 100% 100% 100%

Electricity 38% 35% 23% 32%

High grade heat* 27% 46% 63% 39%

Low grade heat (hot water at 70 to 90 C) 17% 0% 0% 0%

Balance 18% 19% 14% 29%

*exhaust cooled to 100C, 212F Another difference between these CHP options is the effect of turndown on the electrical efficiency. The impact of turndown on electrical efficiency for the four CHP options is shown in Figure 6 and Figure 7 shows the electrical efficiency as a percentage of the maximum efficiency. Figure 6 shows that the IC engine has the highest electrical efficiency across the range of operation. Figure 7 shows that the electrical efficiency of the microturbine deteriorates less than the other options at part load, followed by the IC engine, with the mid sized and radial turbines exhibiting the most deterioration of efficiency at part load.

Figure 6 – Electrical efficiency as a function of load





Figure 7 – Electrical efficiency as a percentage of maximum efficiency as a function of load Also important for consideration in terms of the net power output of the CHP facility is the parasitic load required by the CHP units. Figure 8 provides typical parasitic power requirements for the CHP options being considered. The IC engines have the lowest parasitic power requirement. Turbines typically require a higher pressure gas feed than IC engines and as a result require more parasitic power. As can be seen in Figure 8, the microturbines have the highest parasitic power demand of the options considered.

Figure 8 – Parasitic load as a function of power generated





Biogas to grid As an alternative to using biogas from the anaerobic digestion process in a combined heat and power plant, the biogas can be cleaned-up and injected into the natural gas grid. Heat energy to heat the process can be sourced from burning biogas in hot water boilers, steam boilers or using biogas or natural gas in CHP engines installed in addition to the biogas clean-up plant. The remaining biogas after clean-up is termed biomethane. Biomethane quality is determined by the UK Gas Safety Management Regulations (GSMR) 1996 which specify parameters including hydrogen sulphide content, oxygen content, calorific value and odour. Table 2 below gives details of the quality requirements for the biomethane. Table 2 – UK Biomethane quality requirements

Parameter Value 1

Hydrogen sulphide content ≤ 5 mg/Sm3

Total sulphur content (Inc. H2S) ≤ 50 mg/Sm3

Hydrogen content ≤ 0.1 % molar

Oxygen content ≤ 1 % molar for biomethane

Impurities The gas shall not contain solid or liquid material

which may interfere with the integrity or

operation of pipes or any gas appliance which a

consumer could reasonably be expected to

operate.

Hydrocarbon dewpoint and water

dewpoint

Shall be at such levels that they do not with

interfere with the integrity or operation of the

pipes or any gas appliance which a consumer

could reasonably be expected to operate.

Wobbe Number (WN) ≥ 47.20 MJ/ Sm3 to ≤ 51.41 MJ/Sm3

Incomplete Combustion Factor

(ICF)

≤ 0.48

Soot Index (SI) ≤ 60

Odour Gas below 7 barg will have a stenching agent

added to give a distinctive odour.

Note:

1 Standard (S) - UK Standard conditions are 15°C and 1,013.25 mbar for both

combustion and metering.

Source:

HSE, 1996.A Guide to Gas Safety (Management) Regulations 1996.

The waste gas stream is treated to remove odourous compounds before release to atmosphere.

The main steps that are required in order to meet grid injection specifications shown above are the removal of water, hydrogen sulphide (H2S), siloxanes, and carbon dioxide (CO2). The removal of CO2 is the primary focus of leading biogas clean-up suppliers. From a technological perspective, processes are well established to perform each of these steps. At present, the prevailing clean-up technologies for biogas applications are: CO2 removal:

High‐selectivity membranes

Pressure Swing Adsorption (PSA) systems

Water scrubbing systems





H2S removal:

Solid scavenging media (i.e. SulfaTreat)

Biofiltration Siloxane removal:

Regenerative

Non‐regenerative adsorbent media (Carbon)

Recently a number of UK Water Companies have installed the water scrubbing technology biogas clean-up equipment in order to convert biogas generated from anaerobic digestion of sewage sludge to biomethane with a quality suitable for injection into the UK national gas grid. These sites are as follows:

Avonmouth, Wessex Water, 2500Nm3/h gas to grid –November 2014,

Minworth, Severn Trent Water, 1500Nm3/h gas to grid – October 2014,

Howdon, Northumbrian Water, 2200Nm3/h gas to grid –November 2014.

A more detailed description of the water scrubbing technology for removal of carbon dioxide is

given below.

History of technology

The first installation of the Greenlane water scrubbing unit was in France in 1993, with 4 other installations before 2004. The installations accelerated after 2006 with 70 in the last 10 years in Germany, Sweden, France, UK, Spain, Finland, Denmark, Netherlands, North America, Japan, Korea & New Zealand. The first installation of the Malmberg COMPACT® gas refinement system was done in 1998. To date over 80 plants have been installed in Sweden, Germany, Austria, Luxemburg, Finland, Denmark, UK & China.

Overview of the water scrubbing technology

Biogas is generated during mesophilic anaerobic digestion. The composition of biogas is typically 65% methane and 35% carbon dioxide (CO2) with traces of hydrogen, oxygen, nitrogen and hydrogen sulphide (H2S). Biogas is compressed and fed into the bottom of a packed column where it meets a counter flow of water. CO2 and H2S are more soluble in water than methane and are stripped out of the gas by the counter flow of water. Biogas exits from the top of the column, is typically 97-98% methane and is saturated with water. The CO2-enriched water from the bottom of the column is brought to a flash tank where the pressure is reduced and most of the CO2 is released. A Biomethane to Grid (BtG) plant monitors the gas quality and ensures the correct biomethane quality is injected into the grid. The BtG plant includes a propane injection plant to enhance the calorific value (CV – Wobbe Number in Table 2) of the biomethane prior to entering the gas grid. The BtG rejects out-of-specification biomethane prior to injection into the grid. The propane plant typically comprises propane storage vessels, injection equipment and a blending vessel. Following propanation, a small amount of odourant is added in order to give the gas its characteristic smell.





12

3

7

4

8

6

5

1 Biogas in

2 Compression

3 Absorption

4 Gas Drying

5 Biomethane out

6 Flash

7 Desorption

8 Off gas

Figure 9 – Schematic of water scrubbing for CO2 removal

Figure 10 Källby Lund wastewater treatment plant, Sweden





Process heating Heat is required for the operation of mesophilic anaerobic digesters (MAD) in order to optimise the biogas production from the conversion of sewage sludge. Thermal hydrolysis (TH) up-stream of the traditional MAD has become common in the UK Water Industry and the heat balance has changed from using low temperature water required to keep the MAD process at 35-39oC to the requirement for medium pressure steam at 192oC. A generic process schematic for a CHP plant on a TH facility is provided in Figure 11. Typically, biogas is produced from the digesters and gas storage is used in order to provide some attenuation of the gas production and allow for stable operation of the CHP plant. As much biogas as possible is provided to the engines or turbines in order to produce electricity. Waste exhaust heat from the engines or turbines is used to generate steam using some form of waste heat steam generator. (i.e. either a heat recovery steam generator or a waste heat boiler). If steam production from waste heat is insufficient to meet the process needs of the TH plant, then supplementary fired steam production is needed in order to make up the deficit. If this is required, it reduces the amount of biogas available to be burned in the engines or turbines to produce electricity, thus reducing the overall system efficiency for electricity production. In this respect, it is vitally important to recognize that it is the overall system electrical efficiency rather than the engine or turbine electrical efficiency which defines the electrical output of the plant.

Figure 11 – A generic process schematic for CHP on a TH facility Internal combustion engines have a high electrical efficiency (around 40% is typical) and are able to generate steam from their exhaust gas via a heat recovery steam generator or combination boiler. On facilities with TH, however, typically this needs to be supplemented by additional firing of biogas in a boiler in order to make up the steam demand for the TH process. Thus the system electrical efficiency is lower than the electrical efficiency of the combustion engines. There is also usually a surfeit of low grade heat (hot water at around 70 to 90 oC) available from the engine jacket cooling system. Some of this heat can be used for pre-heating boiler feed water. On more recent TH facilities, some of this heat has also been used to pre-heat the dilution water which is used to dilute the sludge cake (from pre-dewatering systems) down to the 16 to 18% dry solids required for the TH feed. This has the benefit of reducing the steam demand for the TH plant, thus improving the overall energy balance and increasing the achievable electrical output.





Despite this, it is often difficult to find a use for a large proportion of the available low grade heat and heat dump radiators are used in order to offload any excess heat available. Gas turbines generate all their heat from the exhaust and this is high temperature heat suitable for raising steam. Typically there is sufficient energy available in the exhaust gas in order to raise the full steam requirement for TH without burning any additional biogas in direct fired steam production. For a gas to grid plant, some biogas would be diverted from the gas holders to a boiler plant to raise low temperature heat for a traditional mesophilic anaerobic digestion plant or to raise steam for a thermal hydrolysis plant.

Steam raising for thermal hydrolysis Another consideration for CHP systems on TH facilities is the method of raising steam and how to integrate fired steam production with waste heat steam production. The options available are as follows:

Separate fired steam boiler and heat recovery steam generators

Combined waste heat boiler with fired and waste heat sections

Heat recovery steam generator with duct burner Figure 12 shows a schematic of a combination waste heat / fired boiler. The boiler consists of a steel shell inside which water is held at steam temperature. Waste heat from the CHP is ducted through the waste heat portion of the boiler and energy from the exhaust is transferred to the water. If the waste heat is insufficient to meet steam demand, then additional heat is raised through the fired portion of the boiler. With a sufficiently large water mass (i.e. a large enough boiler shell) this design provides a very robust solution to meeting the potentially variable steam demands associated with TH because the water is capable of generating a certain amount of steam without any heat input (the exact amount depending on the mass of water and the drop in steam pressure which can be tolerated). The combination boiler can be operated using waste heat, using biogas firing, or using a combination of the two.

Figure 12 – Combination waste heat fired boiler (courtesy of Johnston Boiler Co.) Another option for combined production of steam from exhaust waste heat and biogas firing is a heat recovery steam generator (HRSG) with a duct burner as shown in Figure 13. Hot exhaust





gas from the CHP is ducted through the HRSG. On the inlet to the HRSG, a duct burner provides additional heat to the exhaust gas (if required) in order to meet the steam demand. Typically there is sufficient excess oxygen available in the exhaust to support firing of the duct burner. The duct burner / HRSG system can also be designed to allow the duct burner to be fired to produce steam without the CHP being in operation. This requires isolation from the CHP and air fans in order to provide the oxygen for combustion. The HRSG itself is essentially a counter current heat exchanger whereby water passes in one direction and the exhaust gas passes in the other. Water is fed to the economizer where it is heated to just under saturated steam temperature. In the evaporator section, hot water is evaporated to produce steam at constant temperature.

Figure 13 – Heat recovery steam generator (HRSG) with duct burner

Gas conditioning Gas conditioning is required in order to meet the needs of the internal combustion engines, gas turbines or the biomethane to grid plant selected. Gas conditioning may include H2S, moisture and siloxane removal depending on the engine or turbine requirements, gas quality and emissions standards. The microturbine can achieve low emissions standards but require very low levels of siloxanes in the fuel gas compared to other technologies. Siloxanes Table 3 provides an overview of typical siloxane and relative humidity limitations for the options being discussed. It is important to note that these are only typical values and exact specifications should always be discussed with equipment suppliers. Siloxanes vary in their molecular weight and as a result, concentration limits can depend on the relative quantity of the various siloxanes species present. The siloxane limit for IC engines depends on whether exhaust treatment is required. If catalysts are required on the exhaust to meet emissions standards then the biogas needs to be treated to achieve very low levels of siloxanes. In general, for most biogas applications, IC engines, mid sized turbines and biogas clean-up plant require at least a single stage of siloxane removal (i.e. either regenerative temperature swing adsorption or activated carbon adsorbers).





For IC engines with an exhaust catalyst or for microturbines, a robust siloxane removal process is required in order to guarantee very low levels of siloxanes in the feed gas and this requires multi stage treatment (e.g. regenerative temperature swing adsorption followed by activated carbon). Moisture Water droplets and water vapour will damage moving parts or rotating plant and thus needs to be removed to protect mechanical equipment. Biogas from the anaerobic digestion process is saturated and thus leaves the digestion reactor at 100% relative humidity. At the gas cools through the gas pipework and gas storage system water vapour condenses and is trapped in condensate traps or pots. In order to remove further water vapour from the gas the gas needs to be further cooled using a cooling medium either final effluent or a refrigerant. In order then to reduce the relative humidity which is the amount of water vapour in the gas relative to the saturated gas the gas is then re-heated prior to the users. Hydrogen Sulphide removal Hydrogen sulphide is corrosive and needs to be removed to meet specific emission requirements. Techniques for hydroden sulphide removal include dosing a Ferric solution to the digestion process, biological filtration or carbon filtration. Table 3 – Typical siloxanes and relative humidity limitations

Factor Units IC engine Mid sized

gas

turbine

Radial gas

turbine

Micro-

turbine

Bio-

methane

to grid

Siloxanes mg Si/Nm3

CH4

<3.5 <5 <20 Very low 5

Relative

humidity

% 80 Typical 50

Emissions Internal combustion engines tend to be associated with high levels of gaseous exhaust emissions which require cleaning via exhaust catalysts in order to meet more stringent emissions requirements. Turbines are usually associated with lower emissions than IC engines (in the absence of exhaust treatment). Consideration of emissions permitting is a factor in technology selection. Low emissions can be met with all the technologies being considered, however IC engines have higher emissions than the turbine options unless exhaust gas treatment is used. For this reason, if low emissions standards need to be met, increased capital and operating costs need to be included in the evaluation of IC engine solutions. Table 4 provides an overview of typical emissions performance. It is noted that the biomethane to grid does not involve combustion thus the relevant emission to atmosphere will involve residual H2S and odour from the biogas.





Table 4 – Typical emissions performance

Emissions Units IC engine Mid sized

gas

turbine

(with

recuperato

r)

Radial gas

turbine

Micro-

turbines

Bio-

methane

to grid

NOx mg/Nm3 500 <25 <25 10 N/A

CO mg/Nm3 1400 <50 <50 190 N/A

SOx ppm Dependent on H2S in biogas N/A

H2S ppm 350 No

nuisance

Odour N/A No

nuisance

Table 5 provides a summary of how the technology options compare in terms of some key considerations which have been discussed above. Table 5 – Summary comparison of options

Factor IC engine Mid sized

gas turbine

(with

recuperator)

Radial gas

turbine

Microturbine

(with

recuperator)

Biomethane

to grid

Electrical

efficiency

-

High grade

exhaust heat

-

Low grade

waste heat

- - - -

Emissions -

Fuel clean up

Parasitic load

O&M costs

best worst Case Studies

1. Blue plains Washington DC (US) – Gas turbines

The plant consists of a thermal hydrolysis plant upstream of a mesophilic anaerobic digestion

plant. The biogas is used in 3No 4.6 MW Gas Turbines (Solar Mercury 50) and the heat from the

turbines is used to raise steam using heat recovery steam generators with duct burners.

Gas is conditioned by the following stages

Wet scrubber for particulate removal.

Moisture removal by chilling and reheating.

Two stage siloxane removal – regenerative plant followed by carbon filters





Boosting to turbine inlet pressure of 14 bar.

2. Davyhulme, UK –Internal combustion engines

Similar to the Blue Plains plant in the US, United Utilities have installed a thermal hydrolysis plant

upstream of a mesophilic anaerobic digestion plant. The biogas is used in internal combustion

engines (5 x 2.4MW) to generate electricity and the heat is used in combination boilers to raise

steam at 12 bar to be used in the thermal hydrolysis plant. The biogas stream passes through

gas boosters which provide heating to reduce the relative humidity of the gas stream. After

boosting there is a cooler installed which operates automatically using final effluent to ensure that

the temperature on entry to the siloxane removal plant remains below 45oC. The siloxane

removal is by regenerative absorption media. The gas passes through each side of the plant for

24 hours and then the media is taken off line and cleaned by blowing air through the media and

burning the resultant gas in a vent air burner.

3. Minworth UK – Biomethane to grid

The biomethane to grid clean-up plant has an operating flowrate range 600 – 1400m3/h

Gas is boosted from the digester outlet at 20mbar to the chiller inlet at 150mbar.

Moisure removal by chilling and re-heating.

Carbon scrubber for siloxanes removal down to 5mg/Nm3 .

After clean-up, facilities are available for propane injection, odourant injection and boosting from 4 bar to 15 bar for injection into a high pressure gas main. If there is any problem with the gas quality as measured at the monitoring unit (measurements made every 5 minutes) then gas is diverted to a flare rated at 1500m3/h.

Incentive payments Table 6 below show a summary of incentive payments as set out by the UK government relevant as of September 2015. These incentive payments regularly change with changing government policy and uptake of the incentives. All payments once received increase annually in line with the retail price index (RPI). The Contracts for Difference (CfD) payments are current and will replace the ROC payments on 1st April 2017. Applications for new schemes up to March 2017 can apply for either the Renewable Obligation Certificates (ROC) or the CfD. Table 6 – Incentive payments

Description End Date Period of

incentive

(years)

Value

(£/MWh)

Renewable Obligation Certificates (ROC) March 2017 20 46

Contracts for Difference (CfD)2 15 24

Renewable Heat Incentive (RHI) – Biomethane. 20 73

Note 1 – Digestion of sewage gas receives on 0.5 ROC Note 2 – there is a bidding process where the maximum value is the difference between the reference price (2015/2016 – £51.06/MWh) and the bid price up to a maximum of £75/MWh. The bid price is the value received by the applicant irrespective of the reference price. It can be seen from Table 6 that the income from Renewable Heat Incentives is 3 times the value for electricity generation. In addition the conversion from biogas to electricity is around 40%





whereas the biogas conversion to biomethane is 98%. However for the biomethane option some biogas is diverted for the process heating requirement.

Totex (Whole Life Cost) An economic comparison of the two most common options used in the UK has been carried out for this paper and is based on prices as of 2015. A comparison is made between internal combustion engine CHP and biomethane to grid. The plant has been sized at 30000tds/annum (1.1million PE) based on a conventional mesophilic anaerobic digestion plant. Assumptions regarding equipment selection for costing are provided in Table 7 below. Table 7 - Assumptions for cost comparison

Costs/Revenues Unit

Gas to grid upgrading plant specific electricity

usage.

kWh/Nm3

biogas

0.24

Electricity cost p/kWh 9.56

Electricity ROC allowance p/kWh 2.25

Gas wholesale price p/kWh 2.6

Propane cost £/l 0.49

Odourisation chemical cost £/kg 6

Renewable heat incentive (RHI) p/kWh 7.5

Methane slip % 1

Gas to grid operational time % 97

Gas to grid maintenance % of capital 2

CHP operational time % 90

CHP maintenance % of capital 2.44

Table 8 below shows the capital cost estimate build up used for the comparison of the two options. Table 8 – Capital costs estimates

Component CHP (£k) Biomethane

to grid (£k)

Biofilter (H2S removal) 280 280

Biogas upgrading plant 2664

CHP Engines 1968

Siloxane removal 82 82

Waste gas treatment (carbon filter) 48

Propane Injection 105

Odour injection 28

BtG (monitor and control) 1050

Telemetry, LV cabling, CCTV, lighting 210 210

Gas injection booster 70

Pipe connections including to Gas network 241

Total 2539 4778





Table 9 shows the estimated running costs and revenues based on the assumed unit values in Table 7 above. Table 9 - Estimated annual operational Costs and Revenues

Costs in 2015 CHP (£k) Biomethane to grid (£k)

Income from biomethane to grid 3844.7

Income from electricity 2403.1

Propane cost -337.3

Electricity cost -33.3 -109.1

Odourant cost -0.2

Maintenance cost -63.0 -23.6

Carbon filter cost - Siloxane removal -3.4 -3.4

Carbon filter cost - waste gas H2S removal -1.9

Annual Income from scheme 2303 3369

Table 10 gives a summary of the comparison showing the net present value using a discount rate of 5.1% over 25 years and shows that although the biomethane to grid option has a greater capital cost the Net Present Value over the period is greater than the CHP option. Table 10 - Estimated annual operational Costs and Revenues

Costs in 2015 CHP

(£million)

Biomethane to grid

(£million)

Capital cost 2.54 4.78

Annual operating income (per annum) 2.30 3.37

Net present value 31.4 44.8

Conclusions

Three main technologies are available for the use of biogas generated from the anaerobic

digestion of sewage sludge.

Internal combustion engines

Gas Turbines

Biogas clean-up and biomethane injection to grid.

Historically internal combustion engines were used to produce electricity and to provide waste

heat for the digestion process as the heat to electricity ratio fitted well with the requirements of

mesophilic anaerobic digestion (MAD) operating at 36oC. However recently commercial gas

turbines for use on biogas have become smaller and offer a different heat balance which is better

matched to a thermal hydrolysis plant up-stream of a mesophilic anaerobic digestion plant.

Thermal hydrolysis requires steam to be generated at 192oC which allow the exhaust heat from a

gas turbine to be used economically.

Each of the technologies requires gas conditioning upstream of the mechanical equipment to

avoid damage, high maintenance costs and reduce down-time. Removal of moisture, siloxanes

and hydrogen sulphide is required to differing degrees.





Emissions of nitrogen oxides and carbon monoxide to atmosphere from the burning of biogas in

the CHP engines produces different levels of emissions from the different technologies and where

biogas is injected to the natural gas grid there are no emissions from burning gas (nitrogen oxides

and carbon monoxide).

UK government incentives have recently favoured injection of biomethane to the grid and this has

been shown to be economically viable by three Water Companies in the UK who have recently

installed biogas clean-up and injection plants at their sites.


a comparison of biogas usage options - chp, turbines … · gas turbines gas turbines typically...

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