Deliverable 14: Report on the optimised CHP use in agricultural … · Current standard exhaust gas...

GE Proprietary Information

Project no. 513949

Project acronym: EU-AGRO-BIOGAS

Project title: European Biogas Initiative to improve the yield of agricultural biogas plants Instrument: Specific targeted research or innovation project Thematic Priority: Priority 6, Sustainable Energy Systems

Deliverable 14: Report on the optimised CHP use in agricultural biogas plants

and increased degree of efficiency Due date of deliverable: 2008-11-30 Actual submission date: 2010-01-15 Start date of project: 2007-01-15 Duration: 36 months (2007-2009) Organisation name of lead contractor for this deliverable: Partner N° , GE Jenbacher (GEJ)


D14: Report on the optimised CHP use in agricultural biogas plants and increased degree of efficiency GE Jenbacher Friedhelm Hillen, Günther Wall, Matthias Schulze, Susanne Chvatal

Table of Contents:

1 CHP – Best Practice and Increase of Efficiency in Energy Conversion ___ 4 1.1 GE Jenbacher Gas Engine Competence: 7 2 CHP Heat Utilisation and Limitations _______________________________ 8 2.1 Acid dew point of exhaust gas 8 2.2 Analysis of acid dew point in the exhaust gas 9 2.3 Influence of exhaust treatment technologies 11 2.3.1 Oxidation catalysts: 12 2.3.2 CL.AIR® 13 2.4 EGHE corrosion/clogging – influence on maintenance 14 3 New EGHE Concepts ___________________________________________ 16 3.1 Carbon EGHE 17 3.2 New concepts in EGHE maintenance 19 4 Increase in operational availability ________________________________ 22 4.1 Influence of fuel gas quality on engine operation 22 4.2 Gas drying, ammonia separation 25 5 Reduction of operating costs / life cycle costs ______________________ 26 5.1 Engine oil management in biogas plants, and oil sensors 26 5.2 Quantification of the effect of H2S 30 5.3 Desulphurisation concepts 32 6 Optimisation of energy consumption - parasitic consumers ___________ 35

7 AdOn Technology: ORC _________________________________________ 36

8 Best Practice CHP agricultural biogas plants | Summary _____________ 39

9 Table of Figures _______________________________________________ 43

10 References ____________________________________________________ 44


Document Description Deliverable D14 is the report on Task 5.1, performed by GE Energy Jenbacher gas engines. High conversion efficiency is one key for economical feasible bio energy usage, the second important factor is a high reliability and availability of the used systems, the third factor is the life cycle costs. The report show the interaction between fuel, engine operation, emissions and exhaust heat utilization and give some hints how to approach plant concepts. Further some potentials to reduce operating costs for auxiliaries and lubrication oil are named and first results of a field demonstration of the ORC Technology, an innovative approach for heat recovery, are provided.


1 CHP – Best Practice and Increase of Efficiency in Energy Conversion

In order to optimise the conversion in gas engine plants of the chemical energy held in the biogas into heat and power for public utility networks, the entire biogas - gas engine - exhaust system must be looked at and optimised. If the quantity of energy that can be obtained and utilised over time (electricity, waste heat) is taken into account, then plant availability is of major importance in addition to energy conversion efficiency.

Fig. 1: Biogas utilisation in a CHP [1]

Energy conversion is affected by a number of factors. The fuel gas quality, in other words its energy content (CH4 content) and impurities content are of major importance. While the energy content has a direct effect on engine efficiency, the impurities are harmful to engine operation. Biogas as a fuel contains a number of impurities such as hydrogen sulphide and ammonia as well as methane and carbon dioxide, and as a rule is also saturated with water. Depending on the quantity of impurities and the water content, these substances can adversely effect engine availability and lead to increase maintenance and servicing costs for the following reasons:

• water can condense in the gas path right up to the engine or in the gas pressure control system • H2S leads to acidification of the engine oil and therefore to a shorter oil service life • H2S and condensate can cause corrosion in the gas line • NH3 in conjunction with condensation in the mixture cooler results in corrosion of the mixture cooler.


Engine

FuelTreatment

Lubrication Oil

ExhaustTreatment

Heat Utilization

Fuel

Emissions

Engine

FuelTreatment

Lubrication Oil

ExhaustTreatment

Heat Utilization

Fuel

Emissions

Depending on the biogas quality, the availability and efficiency of engine operation can be improved by the appropriate gas pre-processing (desulphurisation, gas conditioning).

The combustion process in the gas engine must be specifically matched to the thermodynamic characteristics of the fuel gas to achieve the most efficient energy conversion. As well as the optimal engine configuration and control system (valve timing gear), the targeted thermodynamic design of the individual engine parts is a key factor for achieving a matching high efficiency level.

Engine auxiliaries such as pumps and container ventilation also play a part in determining the overall efficiency of the plant, in other words the net energy yield into the public grid. The net electricity yield can be increased still further by optimising the design of these components for the operating point in question. Finally, recovering the waste heat for electricity generation can increase the overall electricity generation efficiency even further. ORC technology was adapted for use with gas engines in CHP plants in order to achieve this.

Fig. 2: Gas Engine plant [2]

Moreover, the engine oil has a considerable influence on engine availability. Trouble-free engine operation requires a specific oil quality for setting up the engine tribological system and for cooling in accordance with the Technical Instructions. The fuel gas quality in particular has a very strong influence on the change of oil quality over time, and therefore on the necessary oil change interval. Lubricating oils manufactured specially for biogas applications can give substantially longer oil change intervals by virtue of their inherent characteristics together with the action of the additives, thus giving higher plant availability.

Finally, the design and operating point of the exhaust gas heat exchanger and the acid dew point of the exhaust gas have a major influence on the recovery of the energy content in the exhaust gases, with the acid dew point depending primarily on the sulphur content of the biogas. The net heat yield can be raised by


improving the way the engine heat is integrated into the local heating network, and by increasing the heat extracted from the exhaust gas. However, the additional cooling resulting from this can lead to problems in the exhaust gas heat exchanger due to deposits and acid corrosion. Different exhaust gas treatment concepts affect on the acid dew point and consequently the amount of heat recoverable, and also the exhaust gas heat exchanger maintenance intervals.

The individual components in the system consisting of fuel gas, gas engine, lubricating oil and exhaust gas utilisation all interact with each other. For example, the exhaust gas dew point and economically recoverable exhaust gas heat are determined by both the fuel gas sulphur content and the type of exhaust gas treatment system installed.

In order to improve the energy feed into the public grid, new concepts for exhaust gas heat extraction and possible ways of extending the maintenance intervals – and thereby improving availability – were examined in the course of the project.

In summary, biogas utilisation and energy conversion in gas engines in CHP plants can both be improved by the following measures, which target both increased efficiency and plant availability.

Increased efficiency and energy yield:

• modifying the gas engine from a natural gas engine to one optimised for biogas applications (components, combustion, engine control). Continuous optimisation of gas engine technology, which is one of the core competences for the development of GE Jenbacher Gas Engines. This is not part of the EU-AGRO-BIOGAS project, but is mentioned for the sake of completeness.

• optimisation of auxiliaries and therefore the energy used in running the engine • utilization of the energy content of the exhaust gas for power generation by means of ORC

technology. • optimising the waste heat recovery by installing an additional exhaust gas heat exchanger or

improving the heat exchanger cleaning and maintenance.

Increasing plant availability:

• improving the fuel gas quality by gas pre-processing and/or desulphurisation to the engine manufacturer's minimum requirements. This achieves stable engine operation with minimal maintenance costs and downtimes, which have a direct effect on the amount of energy produced in a year.

• gas drying and ammonia separation from the fuel gas • use of engine oils specially formulated for operation with biogas • online oil level monitoring to optimise oil changes and the associated costs • removal of hydrogen sulphide from the fuel gas • use of suitable exhaust gas treatment technologies.


1.1 GE Jenbacher Gas Engine Competence:

Jenbacher cogeneration technology enables customers to realize the maximum economic and ecological benefits available from utilizing biogas for power generation. More than 1,150 Jenbacher biogas systems with a total electrical output of about 800 MW have been delivered worldwide. These plants generate about 6.5 million MW-hours of electricity a year – enough to supply about 1.8 million EU homes. Generating this amount of electrical power with biogas could save about 1,600 million cubic meters of natural gas a year. To operate a Jenbacher cogeneration plant with an electrical output of 500 kW, the dung of about 2,500 cows, 15,000 hogs or 300,000 laying hens is required. Additionally, compared to fossil fuels, utilising biogas in the engines avoids any additional greenhouse gas emissions; due to the organic nature of the components of biogas, burning it in a gas engine for power generation emits the same amount of CO2 into the atmosphere as was originally absorbed during the process of photosynthesis in the natural CO2 cycle.

GE Jenbacher's years of experience in biogas applications and engine development have resulted in an optimised engine design and therefore in high efficiencies. The following design features are of decisive importance in this:

• valve timing • adapted components design • design for long term operation

slow burning rate high exhausttemperature self ignitionslow burning rate high exhausttemperature self ignition

Fig. 3: optimized Gas Engine design [3]

Jenbacher biogas engines have been certified as “ecomagination” products by an independent agency as they provide our customers with a cost-effective, high output means of generating power while substantially and measurably reducing emissions from their operations. Ecomagination is a GE commitment (www.ge.com/ecomagination) to use and develop new technologies to help customers around the world meet escalating environmental challenges.


2 CHP Heat Utilisation and Limitations

The maximum recoverable heat from the exhaust gas of a gas-engine CHP plant is determined by the engine operating mode and the resultant exhaust gas quantity and temperature. The heat extraction is further limited, however, by the acid dew point of the exhaust gas and the formation of deposits.

Current standard exhaust gas heat exchangers extract just enough heat from the exhaust to prevent the exit temperature from dropping below 180°C. Any further heat extraction and associated cooling of the exhaust gas would result in condensation in the exhaust gas heat exchanger as the temperature dropped below the acid dew point. This would lead to:

• corrosion in mild steel exhaust gas heat exchangers • formation of deposits in the exhaust gas heat exchanger and consequently worsened heat extraction.

2.1 Acid dew point of exhaust gas

If sulphur is brought into the engine in the fuel gas, generally in the form of hydrogen sulphide (H2S), it is converted in the engine predominantly to SO2 with small quantities of SO3 and emitted in the exhaust gas. While SO2 is relatively inert and is discharged from the system in the exhaust gas, the SO3 formed reacts with the water vapour in the exhaust gas to form sulphurous acid (H2SO3). If the exhaust gases are cooled to below the acid dew point, condensation of sulphurous or sulphuric acid (H2SO4) occurs, followed by corrosion attacks on the heat exchanger material.

Fig. 4: Corrosion attack by sulphuric acid [4]

Fig. 5: Acid dew point [5]

The typical condensation temperature of steam under the prevailing background conditions in biogas operation is about 55°C. However, as shown by the graph, even a small volume fraction of sulphur of a few ppm can result in a significant increase in the exhaust gas dew point.

Acid Dew Point [°C]

Volume fraction H2SO4


2.2 Analysis of acid dew point in the exhaust gas

Optimized heat recovery means cooling down the exhaust gas as far as possible, which leads to low exhaust gas outlet temperatures. To ensure that these do not drop below the dew point, thereby preventing condensate and acid formation, the exhaust gas dew point must be known. If the exhaust gas dew point can be measured, the gas can be cooled almost down to the dew point and the maximum heat extracted.

To do this, a measuring sensor for measuring acid dew point in the exhaust gas with the engine running has been developed and validated. The aim was to show the effect of sulphur in the fuel gas on the exhaust gas dew point.

Fig. 6: Measuring sensor for analyse of acid dew point, field test [6]

The measuring principle is based on the change in conductivity caused by incipient condensation on a cooled glass head at the sensor tip in the exhaust gas flow.

For validation, a series of measurements were carried out under defined conditions on the test stand and with a known fuel gas composition, and one field test was carried out on a biogas engine with continuous fuel gas H2S measurement. A series of tests were carried out specifically to examine the effect of oxidation catalysts on the acid dew point.

Glass head

Measuring probe with cooling connection

Measuring sensor with cooled glass head, field test installation


Without catalystCatalyst conversion rate SO2=30%Catalyst conversion rate SO2=50%Catalyst conversion rate SO2=80%


Concentration of H2S in fuel gas [ppm]

Typicaloperating range







Typicaloperating range


When an oxidation catalyst for the exhaust gas was installed in the plant, the conversion of SO2 into SO3 it encouraged had the effect of raising the dew point. This point is dealt with more fully below.

Fig. 7: Exhaust gas dew point for different oxidation catalysts [7]

The graph shows a series of exhaust gas dew point measurements for different oxidation catalysts recorded with the acid dew point sensor. The increase in the dew point when using a catalyst for exhaust gas treatment compared to operation without a catalyst can be clearly seen.


2.3 Influence of exhaust treatment technologies

The SO2 contained in the exhaust gas downstream of the engine reacts with the oxygen present in the exhaust gas as a function of temperature and thermodynamic equilibrium (combustion with surplus air) to SO3. This conversion is encouraged to different extents in exhaust treatment components.

Fig. 8: thermodynamic equilibrium SO2 – SO3 conversion [8]

In order to arrive at any conclusions about the maximum possible SO2 and SO3 concentrations, the thermodynamic equilibrium of the reaction and the reaction rate must be considered. The equilibrium is heavily influenced by the temperature and at approx. 400°C is almost entirely on the side of the SO3 products. While SO2 is relatively inert and is discharged in the exhaust gas flow, SO3 reacts as described above with the water vapour present in the exhaust gas to form sulphurous acid.

The exhaust gas treatment system therefore plays a decisive role as regards exhaust gas heat recovery. A low SO2 conversion rate is favourable for the acid dew point and corrosion effects.

Fig. 9: Influence of exhaust gas treatment system on exhaust gas heat recovery [9]

Fuel gas Exhaust gasOxidationcatalyst

Exhaust gasheat exchanger


2.3.1 Oxidation catalysts:

The main task of oxidation catalysts in the exhaust gas flow of biogas engines is to convert carbon monoxide into carbon dioxide. This catalytic oxidation takes place on noble metals such as platinum and palladium, applied to a thin layer of aluminium oxide. This so-called "wash coat" is applied to the actual metallic honeycomb structure of the catalyst, which has a very high specific surface area and influences the activity and selectivity of the catalyst by the targeted positioning of metallic oxides.

The oxidation catalyst encourages the oxidation of sulphur dioxide to sulphur trioxide. Since the formation of sulphur trioxide is low without a catalyst due to the low reaction rate, the influence of an oxidation catalyst is significant, as it reduces the activation energy and makes it easier for the reaction to take place.

Fig. 10: SO2- conversion rate for different catalysts [10]

In oxidation catalysts, the conversion of SO2 to SO3 depends on the following functions:

• gas hourly space velocity - catalyst design • catalyst type - platinum group metal loading • temperature < 300°C low flow • SO2 and O2 content in the exhaust gas • sulphur (H2S, mercaptane) content in fuel gas -

results in SO2 in the exhaust gas

Fig. 11: Oxidation catalyst [11]

Typ A

Typ B

Typ C

Typ A

Typ B

Typ C

SO2 conversion rate for different catalysts

Type A Type B Type C

Space velocity [1/h]


2.3.2 CL.AIR®

The CL.AIR® system is an installation for the thermal after treatment of engine exhaust gases. In heating up the exhaust gas in the CL.AIR® system to a temperature of about 800 °C the hydrocarbons (CH4 and NMHC) as well as the CO react with the residual oxygen in the exhaust gas and form H2O and CO2. The nitrogen oxides (NOx) remain unchanged.

Figure 12 shows the technical scheme of the CL.AIR® system:

Fig. 12: technical scheme of the CL.AIR system [12]

The CL.AIR® system is constructed as a regenerative heat exchanger and consists of • two storage media, • a reaction chamber and • a switch mechanism.

In combination with the lean-burn engine concept, the CL.AIR® system is able to achieve pollutant emission values which are clearly below the limits specified by the German “TA-Luft”.

In the course of thermal post-combustion in the CL.Air, a far smaller conversation rate of SO2 to SO3 is achieved than in oxidation catalysts. Typical measured values are in the range of < 10%.


2.4 EGHE corrosion/clogging – influence on maintenance

Deposits are formed from particles in the exhaust gas originating from lubricating oil combustion residues, oil additive compounds and fuel gas impurities such as sulphur compounds accumulating on the surfaces in the exhaust gas heat exchanger in contact with the exhaust gas.

Deposits on the exhaust-side surfaces of the exhaust gas heat exchanger have an insulating effect that adversely affects the heat transfer and increases the exhaust gas backpressure downstream of the gas engine. The deteriorated heat transfer results in an increased exhaust gas exit temperature and consequently in reduced thermal output. A higher exhaust gas backpressure can result in reduced engine output.

Fig. 13: Sulphuric deposits by undercutting the acid dew point [13]

The nature of the deposits depends greatly on the nature of the exhaust gas temperature:

• exhaust gas temperature < 120°C: condensation of unburned and partially burned hydrocarbons, formation of an oily layer.

• exhaust gas temperature > 120°C: dry, ash-like deposits. The following analysis report on deposits from the exhaust gas heat exchanger in a biogas plant illustrates the problems. The deposits consist largely of sulphates, by chemical composition. Combustion in the cylinder of "ash-forming additives" in the lubricating oil results in fine metal oxide, phosphate and sulphate particles. The sulphur deposits, which may be considerable, are caused by a reaction of the SO3 or SO4 with calcium (from the lubricating oil combustion residues) to form calcium sulphate (CaSO4 - plaster of Paris), which is precipitated mainly in the exhaust gas outlet chamber.


Parameter Methode UnitAluminiumoxid DIN EN ISO 11885 Gew.% 0,4Calciumoxid DIN EN ISO 11885 Gew.% 0,2Chromoxid DIN EN ISO 11885 Gew.% 5,6Eisen(III)oxid DIN EN ISO 11885 Gew.% 16Kaliumoxid DIN EN ISO 11885 Gew.% <0,1Kupfer(II)oxid DIN EN ISO 11885 Gew.% 0,1Magnesiumoxid DIN EN ISO 11885 Gew.% <0,1Mangan(II)oxid DIN EN ISO 11885 Gew.% 0,4Natriumoxid DIN EN ISO 11885 Gew.% <0,1Nickeloxid DIN EN ISO 11885 Gew.% 2,6Phosphorpentoxid DIN EN ISO 11885 Gew.% 0,2Siliciumdioxid DIN EN ISO 11885 Gew.% 1,8Titandioxid DIN EN ISO 11885 Gew.% 0,1Zinkoxid DIN EN ISO 11885 Gew.% 0,1Chlorid ionenchromatografisch Gew.% <0,001Karbonat (CO2) gravimetrisch Gew.% ?

Sulfat (SO3) ionenchromatografisch Gew.% 39,5TOC DIN EN 13137 Gew.% 3,5

Analysis of the deposits: Sample from the exhaust gas heat exchanger in a biogas plant

Main components: sulphate, chromium oxide, iron oxide and nickel oxide

Fig. 14: phase analysis of the deposits [14]

The phase analysis of the deposits revealed a mixture of:

• Iron-Cr-Ni-oxonium sulphate hydrate – (H3O)Fe(SO4)2.x(H2O)Ti(SO4)2 • Iron sulphate hydroxide – Fe4(OH)10SO4 • Ammonium chromium sulphate hydrate NH4Cr(SO4)2.12H2O


3 New EGHE Concepts

One possibility for increasing the recoverable amount of heat is the installation of an additional special exhaust gas heat exchanger downstream of the standard heat exchanger. This can then cool the exhaust gas still further and extract further heat from it. The precondition for this is countering the above-mentioned problems of the acid dew point and corrosion, and deposits.

Exit temperature: appr. 75°C

Exhaust temperature: appr. 490°C

Biogas engine

Standard EHE

Design temperature: 180°C

Available in standard applications for heat recovery

Additional EHE

Additional source for heat recovery

Wat

er in

let:

80°C

Wat

er in

let:

65°C

Exit temperature: appr. 75°C


Biogas engine

Standard EHE



Additional EHE


Wat

er in

let:

80°C

Wat

er in

let:

65°C


Biogas engine

Standard EHE



Additional EHE


Wat

er in

let:

80°C

Wat

er in

let:

65°C

Fig. 15: New EGHE concept [15]

To ensure optimum operation and to counter these problems, a number of factors must be considered:

• The design and installation of the heat exchanger must ensure that condensate can drain from its chamber.

• An acid-resistant, corrosion-proof material must be used for the heat exchanger due to the increased tendency for condensation to form.

• The exhaust gas final temperature will depend on the return temperature in the public district heating system and therefore on the heat exchanger water inlet temperature. The lower the return temperature, the greater the amount of thermal energy that can be transferred from the exhaust gas to the heating system.

The material of any additional heat exchanger should also be selected to meet the following characteristics:

• its thermal conductivity should be as high as possible to facilitate the heat transfer; • its chemical resistance should be as high as possible; • its thermal resistance must comply with the pertaining operating conditions in the exhaust gas heat

exchanger. Acid-resistant stainless steel (e.g. 1.4571) has been tested so far for condensation heat exchangers and tried out in field installations.


3.1 Carbon EGHE

In the course of a field test, carbon was experimented with as a material for recovering heat from exhaust gas. A trial heat exchanger for this was installed at the Wallsee biogas plant.

Fig. 16: Vertical carbon heat exchanger, layout and integration in power plant [16]

The hydraulic integration into the district heating plant is shown in the illustration below. The operating data given show one operating point for the plant, with a return temperature from the system of about 75°C.

Fig. 17: hydraulic integration of the new EGHE [17]

Carbon exhaust gas heat exchanger

BHKWBHKW


The following table shows the waste heat recovery data for the Wallsee plant. As the data shows, use of an additional carbon heat exchanger allows a substantial additional amount of waste heat to be recovered amounting to 44.5% compared to the standard EGHE waste heat.

The heat recovery can be further improved by the following measures:

• operating the heat exchanger with a reverse flow; • passing the medium through from the top of the heat exchanger to the bottom to assist condensate

drainage.

Exhaust gas Standard EGHE

Exhaust gas Carbon EGHE

Inlet 493°C/ 489kWh 225°C/ 202 kWh

Outlet 225°C/ 202kWh 100°C/ 74 kWh

Difference 268 K 125 K

Output 287 kWh 128 kWh


EGHE outlet temperature

80

100

120

140

160

180

200

0 1000 2000 3000 4000 5000 6000 7000 8000

Operating Hours

Tem

pera

ture

°C

EGHE Outlet Temperature

3.2 New concepts in EGHE maintenance

The recoverable waste energy from an exhaust gas heat exchanger over a review period depends not only on the engine operation and the specified transfer capacity of the heat exchanger, but is also heavily influenced by the following factors.

• The actual transfer performance in operation: dirt contamination of the heat exchanger surfaces results in deteriorated heat transfer;

• heat transfer availability: if the heat exchanger is heavily contaminated with dirt, it must be cleaned, in which case the gas engine must be shut down while this maintenance operation is carried out. The maintenance interval depends on the tendency for dirt contamination to occur; the need for cleaning is indicated by an increase in the measured exhaust gas exit temperature and an increase in the pressure loss across the exhaust gas heat exchanger.

Fig. 18: EGHE outlet temperature [18]

The graph shows the exhaust gas outlet temperature (red line) from the exhaust gas heat exchanger as a function of operating hours. The exhaust gas outlet temperature increases with increased dirt contamination, and the improvement in waste heat recovery after cleaning the exhaust gas heat exchanger is shown by the downwards jump in the exhaust gas outlet temperature. The use of technologies for continuous cleaning of exhaust gas heat exchangers, such as Water Direct Injection (WDI) can greatly reduce the effect of dirt contamination.

Increase in exhaust gas exit temperature = decrease of efficiency

Maintenance, cleaning of EGHE

Influence of continuous EGHE cleaning technologies


The tendency for dirt contamination to occur in exhaust gas heat exchangers depends on a number of factors:

• design of the heat exchanger: e.g. minimum tube diameter of the exhaust gas tubes • fuel gas quality and H2S content and consequently the amount of sulphur entering the exhaust

system • exhaust gas treatment system and resulting additional conversion of SO2 to SO3

The tube bundles in the exhaust gas heat exchangers are cleaned as standard using the following procedures:

• brushes / boring: mechanical cleaning • high-pressure water cleaning: using water with detergent and mechanical pulses at a pressure of up

to 200 bar using a lance • flooding / flushing: flooding the tubes with water with added detergent.

Possible technologies for extending the cleaning and maintenance intervals are based either on continuous cleaning during operation, or avoidance of SO3 occurring in the exhaust gas. A continuous cleaning system represents an improvement in terms of the dirt contamination problem and cleaning in the exhaust gas heat exchanger, as it enables the heat exchanger surfaces to be cleaned during operation and therefore keeps the formation of deposits within limits.

WDI is such a system for tube heat exchangers. Water is injected in a fine spray through a number of nozzles into the exhaust gas inlet chamber at periodic intervals. The evaporation of the water on the hot tube sheet increases the volumetric flow and therefore the flow rate through the EGHE, which results in the dirt being abraded away.

The sudden change in the exhaust gas temperature causes a thermal shock, which can lead to spalling of the deposits.

The illustrations show a WDI field test. The pressure in the water system is approx. 6 to 8 bar.

EGHE

Water Injection System


This produced the following results:

Continuous cleaning of the heat exchanger surfaces markedly reduced the formation of deposits.

Waste heat recovery was significantly improved by the consistently better heat transfer. An improvement in heat recovery of approx. 11% was achieved, referred to the waste heat.

This additional gain in energy is shown in the graph below. The exit temperature with WDI is clearly lower than without WDI. The area between the curves (yellow area in the graph) corresponds to the additional recoverable energy.

Increase of outlet temperature after EGHE-cleaning operation with water injection

100110120130140150160170180190200210220230240250

50 500 1000 1500 2000 2500 3000 3500 4000

operation hours [h]

EGH

E ou

tlet t

emp.

[°C

]

effect of WDI

normal EGHEheat output

Exhaut gasheat loss

Temp. Outlet EGHE no WDI

Temp. Outlet EGHE with WDI

Fig. 19: Increase of outlet temperature after EGHE-cleaning operation with water injection [19]


4 Increase in operational availability

4.1 Influence of fuel gas quality on engine operation

Biogas as a fuel contains – besides methane and carbon dioxide – a series of impurities such as hydrogen sulphide and ammonium, and as a rule is also saturated with water. The fuel gas quality has a major influence on engine operation. Impurities in the fuel gas can lead to engine operation problems such as corrosion and deposits, which reduce engine availability. Moreover, the quality of the engine oil as an essential auxiliary component can be affected by impurities brought into the engine.

The following fuel gas constituents are of particular importance in this connection: • Water content, relative humidity: if the biogas temperature drops below the dew point, water

condenses in the gas path to the engine and in the gas pressure control system. This results in increased corrosion and reduced gas filter service life. The condensate must be drained off from the gas system through gas-tight piping and disposed off in accordance with the regulations currently in force. Drainage and piping must comply with the state of the art as regards safety engineering and explosion protection regulations.

• Hydrogen sulphide H2S: hydrogen sulphide forms aggressive acids with water, and in conjunction with condensate this results in corrosion in the fuel gas system. The formation of acids in the fuel gas system leads to corrosion of engine components (mixture cooler, connecting rod bearings). Furthermore, the sulphur brought in leads to acidification of the engine oil, which degrades its important corrosion-inhibiting property so that it must therefore be replaced earlier.

• Ammonia NH3: ammonia in conjunction with condensation in the mixture cooler leads to corrosion of the mixture cooler and under certain conditions can result in the formation of deposits in the fuel gas system. The formation of deposits in the fuel gas line and on components results in component wear and reduced filter service life.

• Particles and droplets: result in deposits in the fuel gas line and reduced filter service life or degradation of components. Increased dirt contamination in the mixture cooler affects engine operation and the mixture cooler will need to be cleaned.

• Impurities brought into the engine affect the exhaust gas treatment systems and the exhaust gas emissions. For example, H2S in the fuel gas results in an increased SO2 value, while NH3 increases the NOx emissions. Oxidation catalysts are sensitive to impurities such as silicon or sulphur.

The effects set out here can be summarised as affecting the energy conversion in the engine as follows:

• increased engine downtimes due to maintenance work • shorter maintenance intervals and consequently higher maintenance costs • reduced service life of individual components

In other words, a reduction in energy conversion efficiency and in availability.


Precise limit values for these impurities must therefore be laid down in the Technical Instructions for engine operation. The limit values for sulphur, ammonia and halogen compounds are listed here as an example: Total sulphur < 1,200 mg/10kWh Without catalytic converter, limited warranty

< 700 mg/10kWh Without catalytic converter< 200 mg/10kWh With catalytic converter for CO< 20 mg/10kWh With catalytic converter for formaldehyde

Halogen compounds < 100 mg/10kWh Without catalytic converterTotal Cl + 2 * total F < 400 mg/10kWh Without catalytic converter, limited warranty

< 20 mg/10kWh With catalytic converter

Ammonia < 50 mg/10kWh

Total – oil content < 5 mg/10kWh

Source: GE Jenbacher TI 1000-0300

The following illustrations show striking examples of ammonium bisulphate deposits in the fuel gas line:

Fig. 20: Deposits on the gas fan inlet filter [20]

Fig. 21: Deposits at the turbocharger [21]

The ammonium bisulphate deposit at the biogas fan inlet filter pictured occurred within a relatively short time as a result of bypass operation of a gas scrubber, and led to a substantial increase in the pressure loss and subsequently to a shutdown of the fan and gas engine. With effective gas scrubbing, these deposits were trapped in the scrubber over a period of 40,000 operating hours, thereby avoiding such deteriorations in plant availability.


Quantitative Results Base(1)

Element

Weight %

Weight % Error

Atom %

Atom % Error

Formula

Compnd %

# Cations

Standard Name

C 35.08 +/- 0.22 41.64 +/- 0.26 C 35.08 28.814 N 11.26 +/- 1.33 11.47 +/- 1.35 N 11.26 7.933 O 51.89 +/- 0.92 46.25 +/- 0.82 O 51.89 --- S 0.99 +/- 0.04 0.44 +/- 0.02 S 0.99 0.306 Fe 0.78 +/- 0.15 0.20 +/- 0.04 Fe 0.78 0.138 Total 100.00 100.00 100.00 37.191

Ammonium bicarbonate occurs when CO2 is introduced into an aqueous ammonia solution at temperatures between 35 and 40°C. Ammonium carbonate smelling of ammonia is also formed, which decomposes into odourless bicarbonate after the separation of ammonia NH3. At temperatures above 60°C ammonium bicarbonate starts to decompose into ammonia, carbon dioxide and water. These processes can be summarised in simplified form in the following equation: (Source: Hollemann Wiberg – Lehrbuch der anorganischen Chemie [˜ Textbook of Inorganic Chemistry]).

2 NH3 CO2 H2O (NH4)2CO3

NH4HCO3NH3 CO2 H2O

+ +

+ +

NH3NH4HCO3 +

NH3 CO2 H2O+ +

35-40°C

60°C35-40°C

The following analysis report for the deposits described above clearly identifies the deposits as: ammonium hydrogen carbonate: teschemacherite, (NH4)(HCO3)

Fig. 22: Analysis report of deposits [22]


4.2 Gas drying, ammonia separation

Various methods can be used to reduce the water content (gas-moisture content) in the fuel gas. Although cyclone separators and demisters can be used primarily to remove entrained droplets and condensate that has already formed, the gas must be dried to prevent the formation of further condensation in the fuel gas line. One possible method of doing this is drying by condensation, in which the gas mixture is deliberately cooled to below the dew point and the resulting condensate discharged from the fuel gas system through a gas-tight line.

Ammonia can be separated by absorption, for example. Ammonia is readily soluble in water, so that scrubbing with water will achieve very high separation rates.

These two tasks, gas drying and ammonia removal, can be implemented in combination by scrubbing the gas and cooling the wash water. A test plant using this method has shown very goods results as regards separation rate, gas drying and a positive effect on engine availability.

The plant is constructed as a reverse-flow scrubber in a packed column. It performs the following functions: Gas drying:

• condensation by cooling to below the dew point (10°C) • droplet separator / demister

Gas scrubbing: • absorption of gas components (NH3) • separation of dust and aerosols.

Fig. 23: required cooling capacity [23]

The graph shows the required cooling capacity [kW] and expected condensate flow [kg/h] with drying by condensation as a function of the biogas inlet temperature, taking a JMS 320 as an example.

0,0

5,0

10,0

15,0

20,0

25,0

30,0

35,0

40,0

45,0

50,0

55,0

60,0

65,0

0 5 10 15 20 25 30 35 40 45 50 55 60

inlet temperature, H2O-saturated [°C]

cool

ing

capa

city

[kW

]

0,0

10,0

20,0

30,0

40,0

50,0

60,0

70,0

80,0

cond

ensa

te [k

g/h]

cooling capacity J 320condensate J 320


5 Reduction of operating costs / life cycle costs

5.1 Engine oil management in biogas plants, and oil sensors

One of the tasks of the engine oil is to ensure appropriate corrosion protection for the engine components. To achieve this, additives are blended with the engine oil that create a certain reserve alkalinity in the oil. Once the alkaline reserve has been used up, the IpH value and TBN drop, acid corrosion can no longer be prevented and the engine oil must be changed. This task of the engine oil is particularly important for biogas applications, since impurities, predominantly sulphur, are brought into the engine in the fuel gas and then result in acidification of the engine oil.

At GE Jenbacher, lubricating oils are tried out in practical tests on different engine types using fuel gases with various sulphur contents. Oil behaviour and long-term effects on engine operation are observed and evaluated in oil approval procedures at the request of the oil manufacturer or customer.

The oil condition is then assessed in series use by the operator as an indicator for the wear characteristics of the engine and brought in fuel gas impurities. The serviceability of the oil will be tested here by chemical analysis of oil samples. The aim of the analysis is to detect changes in the oil characteristics and any increase in the amount of metallic elements.

Engine oils specially adapted to the specific requirements of biogas applications are available on the market. The properties of the selected base oil are modified by a metered amount of additives to meet the requirements of the application. The following table shows a summary and grouping by specification data.

product TBN viscosityat 100ºC

I-pH-Value group TBN

A 10 13,7 9,7 1B 9,6 16 9,37 1C 9,18 14,45 6,81 1D 8,5 14 8,22 2E 8,5 14 9,2 2F 7,4 14,5 8,74 2G 8,2 13 8,3 2H 6,7 13,7 8,23 3I 6 14,2 8,43 3J 6 14,2 8,43 3k 5,6 13,6 9,15 4L 9,4 14,1 8,7 1M 10 14,41 8,54 1N 5,3 13,1 8,4 4

The corrosion-inhibiting potential still available can be assessed using special parameters.

• The TBN (or BN) indicates how much reserve alkalinity is still present in the lubricating oil. • The TAN (or AN) and the ipH value indicate how many acid components are still present.


Limit values for a number of indicator variables are laid down in the Technical Instructions for gas engines, some of which are minima which must be met (TBNm IpH), while others are maxima which must not be exceeded (TAN, metals, trace elements).

If the limit values are exceeded, the properties of the oil are changed to such an extent that the corresponding corrosion inhibition can no longer be maintained. The criteria for assessing an oil are given in the form of limit values for the individual analysis parameters. If a limit value is exceeded, this is a recommendation to change the engine oil.

If the limit values are frequently exceeded in operation, two countermeasures can be employed: • shortening the oil change interval -> means higher operating costs for the oil used • change to a different oil product -> this may allow longer service lives to be achieved, but usually

entails higher oil costs per litre. Oil samples are regularly taken in the field and analysed to monitor the oil quality of engines in service. Conclusions on possible oil service lives and any changes in the fuel gas can only be drawn on the basis of trends, in other words changes in the oil condition over time. This means that samples must be taken from used oil at regular intervals and analysed. Routine trend determination is the only way of reacting in good time to massive sudden changes and preventing severe engine damage.

The analysis interval is generally based on the empirical observations of the plant operator. However, changes in operating conditions and fuel gas quality can also lead to changes in the oil trend, which reduces the forecasting accuracy. In order to reduce the risk for the plant operator, the analysis or oil change interval can be shortened accordingly to prevent the oil from being "overused". Both measures have associated increased operating costs.

Disadvantages of conventional analysis methods in relation to reliability in service: • used oil analysis costs and necessary number of analyses • time gap between taking the oil sample and the report - generally 8 to 14 days, with 3 days being the

optimum • changing the oil early provides good protection for the engine, but results in higher oil costs than

optimum oil service lives until spent Continuous oil condition monitoring brings a marked improvement in this situation. It allows an assessment of the changes in the oil condition to be made, and the oil changes to be managed. Furthermore, the work and costs of regular sampling and analysis are saved.

Sensors available on the market to detect the oil condition, for example, work on the following measurement principles:

• dielectric characteristics: changes in the dielectric characteristics are to be expected due to the introduction of combustion products in the lubricating oil and the resulting continuous ageing.


• electrical conductivity: the introduction of substances in the fuel gas that form acids can be expected to change the conductivity.

Electrical Conductivity

0

10

20

30

40

50

60

29.10.2009

03.11.2009

08.11.2009

13.11.2009

18.11.2009

23.11.2009

28.11.2009

03.12.2009

08.12.2009

13.12.2009C

ondu

ctiv

ity n

S

0

1

2

3

4

5

6

7

8

9

TBN

[mg

KO

H/g

]

Conductivity TBN Limit TBN

Fig. 24: Electrical Conductivity [24]

In a series of laboratory and field tests, various sensors using different measuring principles were examined and tested for suitability in the field. The graph shows the test of a conductivity sensor. It can be clearly seen that conductivity initially decreases sharply after the oil change, which indicates the active effect of the additives, and then increases continuously as the oil ages. A parallel decrease in the TBN compared to the TBN limit value according to the conventional oil monitoring is also plotted.

The graph clearly shows the advantages of the oil sensor: • real-time measurements enable prompt responses to be made and the oil to be replaced when it is

fully spent. This provides plant reliability (reduced risk of engine damage from overusing the oil) and minimal oil costs (oil is fully spent).

• Oil changes can be managed, which allows oil change to be coordinated with impending maintenance work, thereby reducing downtimes.


The following knowledge was gained from the oil type tests:

Changes in the oil condition can be detected from its conductivity using on-line oil condition sensors. Dielectric characteristics do not appear to be a suitable measurement variable in the current state of development.

The technologies available on the market do not yet deliver measurements of the required precision to forecast the oil changes reliably. The technology is not yet ready for introduction on to the market, and requires further development for this application.


5.2 Quantification of the effect of H2S

To quantify and assess the effect of fuel gas quality on motor operation, the following data was recorded in a 6-month data-collection of 30 gas engine plants:

• engine operation • fuel gas quality • oil quality • operational experience

The collected data was compiled in a database and evaluated. The aim was to quantity the effect of the fuel gas quality on changes in the oil condition based on this field data. Since a number of other factors such as oil type, oil quantity and engine behaviour in operation also affect the changes in oil quality, all the data was collected and taken into account in the evaluation.

Fig. 25: Influencing factors on oil lifetime [25]

The evaluation was made more difficult by the following factors: • Fluctuations in the gas quality cause fuzziness in the relationship between the fuel gas quality

(sulphur content) and the deterioration in the oil condition • The relationship is affected by a large number of factors. A precise delineation of the effects is

consequently only possible to a limited extent, due to the quantity of data and its accuracy. The following graph shows the defined correlation of the sulphur input compared to oil volume and time and the theoretically achievable oil lifetime, i.e. the oil operation time according to which the oil change criterion is reached.

BiogasPlant

GasQuality Engine

Operation

OilLifetime

Engine• Engine Type• Number of cylinders• Mean loading

Operating Conditions• Starts / Stops• Operating Hours• Power• Oil Temperature

Oil• Oil type / Product• Oil volume• Oil usage

Fuel Gas Quantity• CH4 content

Fuel Gas Quality• H2S• NH3• Relative Humidity• Temperature

Gas analysis• Measurement Equipment

Oil analysis• Sample taking procedure• Laboratory for oil analysis

Gasconditioning


oil operating time

oil costs

h €/year and kW600 20

1.000 121.500 82.500 5

Correlation of theoretic oil life time to sulfur input

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

0,00 0,20 0,40 0,60 0,80 1,00 1,20 1,40 1,60 1,80

sulfur input per oil volume/ g/h/L

theo

retic

oil

oper

atio

n tim

e (i-

pH)

oil class A (TBN > 9)

oil class B (TBN 7 - 9)

Fig. 26: Correlation of theoretical oil life time to sulphur input [26]

The following conclusions can be drawn, however: The theoretical oil service life is clearly dependent on the quantity of the H2S input. The greater the

sulphur content, the shorter the oil operation time until the oil change. The influence of the sulphur varies with the oil type. Longer service lives can be achieved with engine

oils specially designed for biogas applications. However, no general conclusion can be drawn from the TBN of the oil regarding the possible service life.

The aim of better utilisation of the engine oil and of achieving higher plant availability as a result can be achieved by estimating the theoretical oil service life. Since the oil quality decreases with increasing sulphur content in the fuel gas, the oil service life can again be improved by desulphurising the fuel gas. This gives longer oil service lives and therefore reduced oil costs.

Whether and as from when desulphurisation is actually worthwhile depends on a number of factors: • fuel gas quality and sulphur content, behaviour of the sulphur

content over time • oil type, oil costs per litre, engine oil requirements • planned desulphurisation technology.

The following tables gives an approximate summary of how the specific oil costs decrease if the oil operating hours can be increased accordingly.


5.3 Desulphurisation concepts

A number of different technologies from various manufacturers are available on the market for reducing the hydrogen sulphide content of the fuel gas. These are summarised in the table below:

Sulphide

precipitation internal Potassium Potassium Iron (III) Iron (III)

in the fermenter trickling biofilter bioscrubber iodide carbonate hydroxide oxideApplication Biogas Biogas Biogas Biogas, sludge gas

Separation process Chemical binding Biological conversionMethod / technology Admixing of iron salts Wetted surface Packed column Packed column

Chemical binding the substrate in the

fermenter

Creation of aerobic zones in the fermenter

gas space

Column with packing for growing thiobacilli

(aerobic)

2-stage process:Scrubber (absorption)bioreactor (biological separation, aerobic)

Adsorption on activated carbon with

catalytic oxidation

Adsorption on activated carbon with

oxidation to potassium sulphate

Chemisorption on iron (III) oxide with

formation of elemental sulphur

Chemisorption on iron (III) oxide with

formation of elemental sulphur

Internal / external fermenter internal internal external external external external external external

Separable substances H2S, NH3 H2S H2S, NH3 H2S, NH3 H2S H2S H2S H2S

coarse coarse coarse coarse / fine fine fine coarse / fine coarse / fine

Operating conditionsContent in raw untreated gas [ppm] 500 to 30,000 30 to 30,000 up to 15,000 up to 30,000

Achievable content in clean gas

[ppm] 100 to 150 ppm 200 - 500 ppm 50 to 100 ppm 5 to 50 ppm 1 to 100 ppm 1 ppm

Temperature [°C] >20℃ 25 to 37 ℃ 25 to 37 ℃ 25 to 70℃ >50℃ 25 ℃ 25 to 50 ℃

Pressure [bar] atmospheric 1 to 13 bar atmospheric

Air / O2 injection No 8 to 12 % by volume of the biogas

volumetric flow

2 to 12 % by volume of the biogas

volumetric flow

Air injection necessary into bioreactor

necessary for regeneration

necessary for regeneration

Materials / reagents Iron salts

Iron (II) sulphate Fe2(SO4)3

Ferrogranul20, 124-165 g/m³ (bei 2300 ppmv -> 20 ppmv)

NPK nutrient solution and trace elements

NPK nutrient solution and trace elements

Activated carbon impregnated with potassium iodide (1/5% Kl/AK by

weight)

Activated carbon impregnated with potassium iodide

(10/20% K2CO3/AK by weight)

Bog iron oreiron (III) hydroxide)

(Fe(OH)3)

Iron (III) oxide (Fe2O3) (steel wool,

woodchips, pellets)

Iron (II) chloride FeCl2, Kronofloc (Messrs.

Kronis), liquid

NaOH lye Content up to 150% by weight

Content up to 25% by weight

Content 20 to 50% by weight

Product FeSin the fermentation

substrate

Elemental sulphur in the fermentation

substrate

Elemental sulphur, sulphate in a nutrient

solution

Elemental sulphur,sulphur sludge

Waste disposal Discharged with fermenter effluent

(max. 5%)

Discharged with fermenter effluent

Purification plant Landfill, recycling

Load change dynamics slight slight, unreliable sluggish

Investment costs + + + + - - - + + + + + + Operating costs - - + - - - - - - - - - -

Desulphurisation / area of application

Costs / efficiency

Impregnated activated carbon

Disposal / landfill

atmospheric

Microorganisms (thiobacillus)

Overview ofDesulphurisation Technologies

Absorption and biological conversionSolid bed

Adsorption

BiogasSludge gas

Biogas, landfill gas,Sludge gas

external

Biological desulphurisation Impregnated activated carbon

Regeneration / landfill

Elemental sulphur, depleted activated carbon

Elemental sulphur, spent cleaning compound

~1-2 % by volume - min. double stoichiometric

Ferrous substances

Ferrous cleaning pellets

5 ppm

up to 10,000 1,000 to 50,000

Sources: Profaktor GmbH: Desulphurisation Concepts Study, Fraunhofer UMSICHT - Study of Analysis and Evaluation of Possible Uses of Biomass, own research based on manufacturers' information


The use of in gas engines of gases containing H2S can have the following damaging effects:

• The lubricating oil becomes acidic, loses its lubrication capability and must be changed frequently

• If the oil is not changed in good time, moving parts of the engine become excessively worn.

• If the H2S content is very high (2,000-4,000 ppm), some engine components suffer direct damage.

• Acid attacks on metal parts in conjunction with condensate (inadequate biogas drying, start-up procedures in the exhaust gas heat exchanger).

• Deposits in the exhaust gas heat exchanger if the temperature drops below the dew point.

Fig. 27: sulphur corrosion [27]

Limit values for the total amount of sulphur in the fuel gas are therefore given by GE Jenbacher in Technical Instruction TI 1000-0300. The following graph shows an overview for determining the sulphur contents referred to 10 kWh. The background for these reference variables is the fact that the decisive factor for the engine is the amount of impurities brought into the engine. With a gas with a low calorific value (methane content) the engine must overall process a higher fuel gas flow than with a gas with the higher calorific value (methane content).

Fig. 28: Limit values for sulphur content in fuel gas [28]

CH

4 in

fuel

gas

[Vol

.%]

Grenzwerte für Schwefelbelastung im Treibgas

< 20

mg

S / 1

0 kW

h

< 20

0 m

g S

/ 10

kWh

< 50

0 mg

S / 1

0 kW

h< 7

00 m

g S / 10 k

Wh

< 1200 mg S / 10 kWh

0

10

20

30

40

50

60

70

80

90

100

0 100 200 300 400 500 600 700 800

H2S im Treibgas in ppm

CH

4 G

ehal

t im

Tre

ibga

s in

Vol

%

Limit values for sulphur content of

H2S in fuel gas [ppm]


The selection of the most suitable or most economic and efficient desulphurisation method is governed by the following criteria:

• H2S content in the raw untreated gas • target H2S content in the treated gas - coarse / fine - desulphurisation • fluctuations in the raw untreated gas quality and quantity (charge in the fermenter, changes in the

substrate) • necessary reliability and availability of the desulphurisation plant (assessment of the consequences

of a desulphurisation failure) • maintenance measures and operational management • investment costs, operating costs

The direct economic consequences for the operator (repair, engine oil and failure costs) serve as a permanent reminder of the need for effective and reasonably-priced biogas desulphurisation.

As can be seen from the example of continuous gas analysis from the following field system, the H2S concentration can vary considerably depending on the biogas process.

0

10

20

30

40

50

60

70

30.09.2005 19.11.2005 08.01.2006 27.02.2006 18.04.2006 07.06.2006 27.07.2006

CH

4, C

o2, O

2

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

H2S

CH4 [vol.-%] O2 [vol.-%]CO2 [vol.-%] H2S [ppm]

Fig. 29: Variation of H2S-content in biogas [29]

In order to achieve reliable desulphurisation, it may therefore be necessary due to the extent of the sulphur content fluctuations to employ an overdimensioned desulphurisation plant compared to its average loading.


consumer load kW reduction potentialcycle pumps 3,3 design acc. actual operating conditionsair coolers 8,4 frequency control acc. process requirementscontainer ventilation 11 frequency control acc. actual room temperaturgas blower 4,6 -

6 Optimisation of energy consumption - parasitic consumers

The energy consumption of the engine auxiliaries for engine operation, such as room/container ventilation, water pumps, table coolers, etc., represents a certain energy requirement, necessary for energy conversion in the gas engine CHP plant, but which must be deducted from the net energy yield fed into the public grid.

As part of a data survey, operating data for the main electrical consumers was collected at a field system using existing and additionally-installed measuring instruments.

The following areas were investigated:

• warm-water circuit • emergency cooling circuit • mixture cooling circuit • container ventilation • gas compressor.

The following packages of measures were considered:

• components designed exactly to the operating point • optimised control (frequency control).

The focus here was on design and control aspects. The following potential areas for optimisation were demonstrated:

• parts / components designed for the operating point e.g.: pumps, table coolers

• improvements in control systems, e.g.: speed control

Fig. 30: Gas Engine auxiliaries [30]

The amount of energy was estimated in the following example, based on the data from the test plant:

The total energy electrical energy requirement for the auxiliaries amounts to: 121,000 kWh annually. Achievable savings, using all potential areas, amount to: 19%

The identified possible savings are either already standard at GE Jenbacher, or will be transferred into series production with the project.


Heat Source

Heat Sink

WHR System

Qin

Qout

Power

7 AdOn Technology: ORC

ORC technology represents a significant capability for gaining additional electrical energy from the available exhaust gas heat. The advantages and motivation are obvious:

Benefits: • CO2-free additional power • Increased plant / process efficiency • Fuel savings

Driving forces • Fuel prices • CO2 or emissions constraints • Grid independence

The decisive factor is ultimately the required investment per kW of usable energy

In the ORC process, a working fluid is passed through a circulatory system similar to a steam process. Instead of water, an organic fluid is used as the working fluid. This means that, in principle, standard components can be used for the ORC process. Commercial ORC plants for woodchip or geothermal plants, for example, have already been operating successfully for several years. The following illustration shows the outlines of the process:

BOILER

CONDENSER

Heat Source

Near-saturatedvapour

30°C

Fan Power:

Pump Power:

ORCPressurised liquid

Shaft Work

BOILER

CONDENSER

Heat Source

Near-saturatedvapour

30°C

Fan Power:

Pump Power:

ORCPressurised liquid

Shaft Work

Fig. 31: ORC- process [31]


•Thermodynamics

•EHS

Esthers,ketones

Aromatics

Silicon oils CFCs

Hydro-carbons

Refrigerants

Verdampfer

Wärme-quelle

Pumpe

ORC withrecuperator

Kondensator Rekuperator

Working fluid Application

0,0 0,5 1,0 1,5 2,0 2,5 3,0-50

-0

50

100

150

200

250

300

350

400

s [kJ/kg-K]

T [°

C]

2600 kPa

920 kPa

220 kPa

30 kPa 0 ,2 0,4 0,6 0,8

Cyclohexane

heat source

heat sink

0,0 0,5 1,0 1,5 2,0 2,5 3,0-50

-0

50

100

150

200

250

300

350

400

s [kJ/kg-K]

T [°

C]

2600 kPa

920 kPa

220 kPa

30 kPa 0 ,2 0,4 0,6 0,8

Cyclohexane

0,0 0,5 1,0 1,5 2,0 2,5 3,0-50

-0

50

100

150

200

250

300

350

400

s [kJ/kg-K]

T [°

C]

2600 kPa

920 kPa

220 kPa

30 kPa 0 ,2 0,4 0,6 0,8

Cyclohexane

0,0 0,5 1,0 1,5 2,0 2,5 3,0-50

-0

50

100

150

200

250

300

350

400

s [kJ/kg-K]

T [°

C]

2600 kPa

920 kPa

220 kPa

30 kPa 0 ,2 0,4 0,6 0,8

Cyclohexane

heat source

heat sink

• Thermodynamics• Safety• Cost, …

• simple ORC• recuperated ORC• …

• Temperature range• Heat load• CHP, …

•Cost

Unlike the steam process, the OCR is also very suitable for use with smaller heat sources with low energy levels, such as the exhaust gas from a gas engine co-generation plant. An examination of the potential of ORC plants was carried out at the Wasmerslage demonstration plant.

• Design: Frauenhofer UMSICHT • Operator: Agri Capital • Design: Fraunhofer-Umsicht • 2 GEJ gas engines with each 500kW • ORC Output: ~ 50 – 60 kWel • Actual Oh: ~17.000

The planned electrical output was initially calculated as being slightly higher, but over a long period of operation the plant showed itself to have very good operating characteristics.

Notable field problems were mainly sulphur deposits in the exhaust gas heat exchanger. Overall, the demonstration plant produced a very positive result which will help to increase acceptance of the technique. Technical background: A number of factors need to be taken into account for the optimal use of ORC technology in gas engine CHPs. As well as the choice of a suitable working medium to meet the process requirements, an optimal operating point to match the waste heat potential needs to be set. The basic design and construction must also be matched to the existing given factors.


As the following summary shows, various design layouts are possible when combining a gas engine with suitable ORC technology:

Fig. 32: Concepts of ORC – integration [32]

The difference is the way the available heat sources at different temperatures, such as engine exhaust gas (approx. 450°C) or engine cooling water (approx. 90°C), are incorporated. The incorporation method determines both the efficiency of the energy recovery and the ORC module costs.

A concept developed by GE Jenbacher uses both heat sources (exhaust gas heat and engine cooling water) in a cascaded system with two selected working fluids, the objective being to obtain a higher electrical output at the lowest possible specific costs.

Fig. 33: ORC- concept by GE Jenbacher [33]

The advantage of a high electrical output is offset by the disadvantage of a significantly more complicated system.

Cond.

Evap.

„Dual“ concept

Cond.

Evap.

Cond.

Evap.

„Dual“ concept

Cond.

Evap.

Cond.

Evap.

„Exhaust“ concept

Radiator

Cond.

Evap.

„Exhaust“ concept

Radiator

Cond.

Evap.

„All-in-one“ concept

Cond.

Evap.

Cond.

Evap.

„All-in-one“ concept

cond. / evap.

Evap.

condenser

Thermo oil loop

perheater

LT ORC

HT ORC

cond. / evap.

Evap.

condenser

Thermo oil loop

perheater

LT ORC

HT ORC


8 Best Practice CHP agricultural biogas plants | Summary

The results of the investigations and field tests carried out can be summarised as follows: Increased efficiency and energy yield:

The tests carried out with an additional carbon exhaust gas heat exchanger produced the following results: The exhaust gas can be cooled down to 75°C with the additional exhaust gas heat exchanger. The

heat energy additionally recoverable means that the following improvement in the CHP heat recovery can be achieved: (calculation basis: GE Jenbacher gas engine JGS 312GS C25)

o increase in waste heat recovery of some 44% compared to the waste heat recovery of the standard EGHE and 31% compared to the total waste heat

o increase in the overall waste heat recovery of the CHP plant of some 15% The carbon heat exchanger did not show any corrosion attacks, deposits or reduction in power output

due to dirt contamination over the duration of the test operation in excess of 4,000 operating hours. The lower the cooling water inlet temperature, the higher the additional recoverable heat from the

exhaust gas. The system is therefore especially suitable for district and local heating systems with return temperatures from 50 to 60°C.

The effect of sulphur and acid corrosion on the waste heat recovery can be countered by the following measures:

full desulphurisation of the fuel gas (H2S, mercaptane, etc.), but the desulphurisation solution adopted must have a very high availability.

Suitable materials for the exhaust gas heat exchanger (carbon, stainless steel). Use of a suitable technology for exhaust gas treatment to keep the conversion of SO2 to SO3 in the

exhaust gas as low as possible. A continuous cleaning system represents an improvement in terms of the contamination problem (deposits) and cleaning in the exhaust gas heat exchanger, as it enables the heat exchanger surfaces to be cleaned during operation and therefore keeps the formation of deposits within limits.

Continuous cleaning of the heat exchanger surfaces markedly reduced the formation of deposits. Waste heat recovery was significantly improved by the consistently-better heat transfer.

Optimisation of auxiliaries operation to reduce the plant's own electrical energy requirements shows:

that the achievable savings in a selected example, exploiting all the potential savings, is about 19%; the implementation of various measures must be decided in individual cases according to economic criteria.


Recovery of the energy content of the exhaust gas with ORC for power generation represents a major improvement potential.

The technology study and the field test in Wasmerslage have shown that stable and low-maintenance long-term operation of an ORC plant for gas engine applications is possible.

An additional electricity yield of 6% was shown, and estimates of the potential show that values in excess of 8% are possible.

Increasing plant availability:

Gas pre-processing for biogas engine systems should adapt the gas to meet the engine requirements exactly. To this end, the following tasks should be performed:

• Gas drying: reduction in the biogas water content • Removal of impurities: ammonia, hydrogen sulphide • Removal of dust particles • Achieving the operating parameters necessary for engine operation such as gas pressure,

temperature, relative humidity The following diagram shows the design of a gas drying plant in simplified form. In the case of biogas plants with renewable raw materials as a substrate and no ammonia content or other impurities to speak of, this standard gas drying solution can be employed.

Fig. 34: Design of a gas drying plant [34]

Chiller

Blower

CondensateDrain

PreaheatingCondenserSeparator

Demister

Gas QualityControl

CH4 / O2


Chiller

Blower

CondensateDrain

PreheatingSeparator

Gas QualityControl

CH4 / O2

Absorber

In the case of biogases with higher ammonia and impurities contents, for example substrates made of chicken or pig manure, gas pre-processing based on scrubbing is advised.

Fig. 35: gas drying plant with absorber scrubber [35]

Using this kind of method can increase the availability of gas engine plants considerably. Extrapolations from individual experiments show that without suitable gas pre-processing, additional downtimes of up to 75 hrs per annum can be expected for maintenance activities.

If the hydrogen sulphide content is outside the TI specifications, a desulphurisation plant should be provided anyway. A suitable process should be selected depending on the sulphur content, fluctuations in the gas quality and the requirements on the clean gas.

In summary, the following conclusions can be drawn: Gas conditioning provides stable engine operation with minimum maintenance costs and downtimes,

which has a direct effect on the amount of energy produced in a year. The tasks of drying the fuel gas and removing ammonia from it lend themselves to be combined in a

single plant. Increase in operational availability for a typical biogas application (rule of thumb):

Earnings due to increased availability ~10 €/kWel-installed@100 Oh -> (Assumed Power Price 0.1 €/kWhel)


Active oil management brings the following advantages: The use of engine oils specifically constituted for biogas operation can substantially lengthen the oil

service life. On-line oil condition monitoring enables the oil to be managed and therefore oil changes and the

associated costs to be optimised. However, oil sensors currently on the market are not yet sufficiently developed.


9 Table of Figures

Fig. 1: Biogas utilisation in a CHP [1] .................................................................................................................. 4 Fig. 2: Gas Engine plant [2] ................................................................................................................................. 5 Fig. 3: optimized Gas Engine design [3] ............................................................................................................. 7 Fig. 4: Corrosion attack by sulphuric acid [4] ...................................................................................................... 8 Fig. 5: Acid dew point [5] ..................................................................................................................................... 8 Fig. 6: Measuring sensor for analyse of acid dew point, field test [6] ................................................................. 9 Fig. 7: Exhaust gas dew point for different oxidation catalysts [7] .................................................................... 10 Fig. 8: thermodynamic equilibrium SO2 – SO3 conversion [8] ........................................................................... 11 Fig. 9: Influence of exhaust gas treatment system on exhaust gas heat recovery [9] ...................................... 11 Fig. 10: SO2- conversion rate for different catalysts [10] .................................................................................. 12 Fig. 11: Oxidation catalyst [11] .......................................................................................................................... 12 Fig. 12: technical scheme of the CL.AIR system [12] ....................................................................................... 13 Fig. 13: Sulphuric deposits by undercutting the acid dew point [13] ................................................................. 14 Fig. 14: phase analysis of the deposits [14] ...................................................................................................... 15 Fig. 15: New EGHE concept [15] ...................................................................................................................... 16 Fig. 16: Vertical carbon heat exchanger, layout and integration in power plant [16] ........................................ 17 Fig. 17: hydraulic integration of the new EGHE [17] ......................................................................................... 17 Fig. 18: EGHE outlet temperature [18] .............................................................................................................. 19 Fig. 19: Increase of outlet temperature after EGHE-cleaning operation with water injection [19] ................... 21 Fig. 20: Deposits on the gas fan inlet filter [20] ................................................................................................. 23 Fig. 21: Deposits at the turbocharger [21] ......................................................................................................... 23 Fig. 22: Analysis report of deposits [22] ............................................................................................................ 24 Fig. 23: required cooling capacity [23] .............................................................................................................. 25 Fig. 24: Electrical Conductivity [24] ................................................................................................................... 28 Fig. 25: Influencing factors on oil lifetime [25] ................................................................................................... 30 Fig. 26: Correlation of theoretical oil life time to sulphur input [26] ................................................................... 31 Fig. 27: sulphur corrosion [27] ........................................................................................................................... 33 Fig. 28: Limit values for sulphur content in fuel gas [28] ................................................................................... 33 Fig. 29: Variation of H2S-content in biogas [29] ................................................................................................ 34 Fig. 30: Gas Engine auxiliaries [30] .................................................................................................................. 35 Fig. 31: ORC- process [31] ................................................................................................................................ 36 Fig. 32: Concepts of ORC – integration [32] ..................................................................................................... 38 Fig. 33: ORC- concept by GE Jenbacher [33] ................................................................................................... 38 Fig. 34: Design of a gas drying plant [34] .......................................................................................................... 40 Fig. 35: gas drying plant with absorber scrubber [35] ....................................................................................... 41


10 References

[1] GE Jenbacher, Biogas Application, Product Information, 2009 [2] GE Jenbacher, internal report: Biogas utilization [3] GE Jenbacher, internal report: Biogas utilization [4] GE Jenbacher, field report [5] GE Jenbacher, internal report: SO2/SO3 conversion on catalyst, 2008 [6] GE Jenbacher, internal report: SO2/SO3 conversion on catalyst, 2008 [7] GE Jenbacher, internal report: SO2/SO3 conversion on catalyst, 2008 [8] GE Jenbacher, internal report: SO2/SO3 conversion on catalyst, 2008 [9] GE Jenbacher, internal report: SO2/SO3 conversion on catalyst, 2008 [10] GE Jenbacher, internal report: SO2/SO3 conversion on catalyst, 2008 [11] GE Jenbacher, field report [12] GE Jenbacher CL.AIR® Product Information, 2009 [13] GE Jenbacher, field report [14] GE Jenbacher, field report [15] GE Jenbacher, internal report: Waste Heat Utilization, 2009 [16] GE Jenbacher, internal report: Waste Heat Utilization, 2009 [17] GE Jenbacher, internal report: Waste Heat Utilization, 2009 [18] GE Jenbacher, internal report: Waste Heat Utilization, 2009 [19] GE Jenbacher, internal report: Waste Heat Utilization, 2009 [20] GE Jenbacher, field report [21] GE Jenbacher, field report [22] GE Jenbacher, field report [23] GE Jenbacher, internal report: Biogas utilization [24] GE Jenbacher, internal report: Impact of fuel gas quality on lube oil properties, 2008 [25] GE Jenbacher, internal report: Impact of fuel gas quality on lube oil properties, 2008 [26] GE Jenbacher, internal report: Impact of fuel gas quality on lube oil properties, 2008 [27] GE Jenbacher, field report [28] GE Jenbacher, internal report: Desulphurization Technologies, 2009 [29] GE Jenbacher, internal report: Desulphurization Technologies, 2009 [30] GE Jenbacher, internal report: Parasitic losses, 2009 [31] GE Jenbacher, ORC Product Information, 2009 [32] GE Jenbacher, ORC Product Information, 2009 [33] GE Jenbacher, ORC Product Information, 2009 [34] GE Jenbacher, internal report: Biogas utilization [35] GE Jenbacher, internal report: Biogas utilization

Deliverable 14: Report on the optimised CHP use in agricultural … · Current standard exhaust gas...

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