Square-root-Square-root Formula for Steam Temperature

MORE EFFICIENT CONVERSION OF BIOMASS IN COGENERATION OR FUEL PRODUCTION

SELECTED PATHWAYS FOR A MORE EFFICIENT CONVERSION OF BIOMASS IN COGENERATION OR FUEL PRODUCTION

Daniel Favrat[1], François Marechal, Jan van Herle, Stefan Heyne, Martin Gassner

Industrial Energy Systems Lab., Ecole Polytechnique Fédérale de Lausanne (EPFL), Switzerland 

ABSTRACT

Among renewable energy sources biomass plays a major role. Several paths for improving the conversion of biomass with minimum burden on the environment are being pursued worldwide. This paper reviews some of the most recent results from research at the Swiss Federal Institute of Technology of Lausanne.

On the theoretical and experimental sides it covers the improvement of biogas combustion engines using combustion prechambers both with spark ignition or autoignition in order to reduce the emissions while keeping a high efficiency level, the integration of ORC heat recovery cycles on biogas cogeneration engines and tests with real biogas in Solid Oxide planar Fuel Cells.

On the process modelling side the paper reviews the environomic (environment, economic and energetic) optimisation of the design of biofuel production by means of gasification and fuel reforming. Thermo-economic process modelling and integration techniques are coupled with a multi-objective optimisation algorithm to target the best process technology and operating conditions for the trigeneration of fuels, heat and power.

Keywords: biomass conversion, process optimisation, Organic Rankine Cycles, biogas engine, Solid Oxide Fuel Cell.

1.     INTRODUCTION

Among renewable energy sources biomass always played a major role and this role is bound to be maintained or even increased in the future in light of the closed CO₂ cycle which is made possible. Among renewables, biomass or at least solid biomass has the major advantage of being easily storable. While biomass has been for centuries primarily used for low exergy services like heating and cooking from direct combustion the future will likely be characterised by more advanced conversion paths to higher exergy value products like electricity, combined heat and power or fuels [1].

Several paths for improving the conversion of biomass with minimum burden on the environment are being pursued worldwide. This paper reviews some of the pathways and most recent results from research at the Swiss Federal Institute of Technology of Lausanne.

2. BIOGAS ENGINES CLEAN COMBUSTION

One of the most convenient form of biomass is biogas extracted from sewage water treatment plants. This biogas consists primarily of methane and CO₂, which in many areas is converted in-situ into electricity and heat by a cogeneration internal combustion engine. However, emissions from gas engines can be relatively high and contaminants present in the biogas often prevent the use of catalytic post treatments. Therefore, in countries with tough environmental legislation like Switzerland, one common way has been to lower the compression ratio of the engine in order to keep primarily NOx and CO within acceptable limits. As the mechanical efficiency of internal combustion engines is a function of the compression ratio this implies a net exergy loss.

One way to circumvent the above drawback is to improve the combustion. For lean burn engines this can be achieved by displacing the spark plug to the bottom of an unscavenged ignition prechamber as shown in figure 1.

Figure 1: 150 kW biogas engine with unscavenged ignition prechamber [2,3]

Figure 2: For a 150kW engine, comparison between (a) prechamber ignition and direct ignition of natural gas and (b) prechamber ignition with natural gas and biogas [2,3]

As shown in Figure 2a related to tests with natural gas, prechamber ignition allows a reduction of CO emissions of 40% compared to direct ignition and this for the same range of NOx emissions. Results published in [2] show that even larger reductions (55%) are achieved for the unburned hydrocarbons. Note that in Figure 2, the red rectangle corresponds to the Swiss regulation for stationary gas engines.

Figure 2b shows that, for the same conditions, a further reduction of the CO emissions can be achieved when going from natural gas to biogas, leaving a margin for an increase of the compression ration with biogas.

Figure 3: For a 150 kW engine, comparison of shaft efficiency between natural gas and biogas (ST-8CA indicates that tests have been made at the same spark timing relative to the crank angle)

Figure 3 shows that for the same conditions of compression ratio, prechamber ignition and spark timing, biogas efficiency results are only slightly lower than with natural gas. The level of efficiency with biogas, which is higher than 36% while still meeting the Swiss norms, is significantly higher than the efficiency of direct ignition biogas engines presently operated in Switzerland.

At a time of growing environmental concerns particularly in large cities worldwide the above technical improvements allowing a better use of the biomass resource with low emissions are promising.

A next step currently under investigation is the potential replacement of the spark plug ignition by auto ignition in temperature controlled prechambers. This would potentially eliminate one key maintenance concern and allow a reduction of the volume of the prechamber as a result of the faster generation of hot jets from the prechamber nozzles. The proof of concept is being investigated for natural gas both with a theoretical approach (new reaction mechanism and coupling between the new reaction mechanism [4] and Navier-Stokes calculations) and with tests in a single cylinder engine [5, 6].

Figure 4a shows a schematic view of the hot jets from the prechambers, which are to ignite the mixture of the main chamber. Note that the cylinder head is conical in this particular case. Autoignition has been demonstrated but with instabilities which need further analyses. Calculations on the right (Figure 4b) show that, in certain conditions, parasitic auto ignition could take place inside the main chamber, which is one the problems which are being faced in the on-going investigations.

Figure 4: Prechamber autoignition system, (a) representation of the hot gas jets ignition in the main chamber [5], (b) heated autoignition prechamber with Navier-Stokes calculation on the right [6].

3. BIOGAS COGENERATION UNITS WITH ORC

Figure 5 shows the efficiency of natural gas engines resulting from an extensive data base of installed cogeneration units in Europe. It has been shown above that efficiency improvements at the engine and combustion level can be made and the red mark shows the level which can be achieved with unscavenged prechambers. However, in many of the applications, recovering the heat from the jacket cooling or from the exhaust gases is only partial and often seasonal. Therefore there is a reasonable potential for electric efficiency improvements by converting the waste heat using Organic Rankine Cycles (ORC). This, of course, applies to biogas engines as well.

The green zone in figure 5 illustrates the gain of efficiency which can be expected. One of the obstacle to the use of ORCs in these applications has been the unavailability of reliable expander-generator at small scale (5 to 20 kWel). Therefore one research effort at EPFL has been the demonstration of the feasibility of small hermetic expander-generators, so far mainly derived from existing scroll compressors. Published demonstration results include the heat conversion in a hybrid solar thermal power plant coupled with a biofuel Diesel engine [5] and the initial tests of an ORC unit as an add-on to biogas engines installed near Geneva [6]. In the latter case biogas is produced in fermenters using greens collected separately from city wastes. For conservative reasons only the heat from jacket cooling is converted so far in this plant and with a net efficiency of 6% (4.8 kWe) and an exergy efficiency of 38%. Significantly better efficiencies could be expected in the case of ORC units directly assembled with the engine cogeneration units, which would limit the parasitic losses linked to long pipe connections imposed in the retrofit case.

The present work with ORC equipped with scroll expander generators is being marketed by a startup company from EPFL (LENI) and new concepts of scroll expanders are being studied jointly.

Figure 5 Gas engines with ORC unit: overall expected efficiency (left) and measured ORC efficiency in a retrofit case [6].

4. BIOGAS FED SOLID OXIDE FUEL CELLS (SOFC)

Figure 5 shows that the electrical efficiency of present cogenerator units falls in the small power range. On the other hand new technologies and in particular SOFC, which are quite tolerant to a variety of fuels are emerging. SOFC technology is one of them and can be considered as a serious candidate in particular for the small cogeneration market (1 to 200 kW). For this market planar SOFC concepts are considered because of their compactness and potentially low specific price.

Present work at EPFL(LENI) includes [9,10,11]:

-          Experimental and theoretical investigations of various planar anode supported SOFC cells and stacks in collaboration with an industrial company. The experimental investigation includes feeding a cell or a stack with hydrogen or methane or simulated biogas. Investigation also include segmented electrode tests. In addition small sample material tests in particular for cathodes and anodes are done in collaboration with other universities and European research centers.

-          The assistance to field tests of SOFC units with farm biogas [12,13].

-          System studies for the best integration of SOFC fuel cells in complete systems including hybrid fuel cell – gas turbine cycles.

With biogas several reforming aspects are to be mentioned in comparison with natural gas. One is the absence of non-methane hydrocarbons (except for landfill gas) and the other is the presence of a significant proportion of carbon dioxide. These two features represent an advantage for the fuel processing upstream of the SOFC. Higher hydrocarbons compared to methane are more prone to carbon deposition because of their lower decomposition temperature, while CO₂ can be used as a reforming agent to partly convert methane into syngas. However the amount of CO₂ is far from sufficient to operate in a thermodynamically safe region to avoid carbon deposition above 600°C and another reforming agent (either water vapor or oxygen from air) still has to be added. A sensitivity analysis and a comparison between reforming approaches can be found in [9, 10]

Figure  6 (a) Assembly of a SOFC stack (collaboration with SOFCPower)  and (b) CFD flow calculation in a cell

Figure 6 (a) shows a cocurrent stack being assembled and instrumented. Figure 6(b) shows a CFD result of the predicted fuel concentration along the anode of a planar SOFC fuel cell.

So far prototypes up to 1 kWel with efficiencies above 30% and a power density of the order of 1.5 kW/dm³ have been realised. Research key topics include the improvement of the sealing elements, which are crucial for planar fuel cells, trends towards bigger active area per cell, and improved life time.

5. BIOGAS FROM WOOD

Among the various sources of biomass wood is the one, which is not in direct competition with food and is available in many areas around the world. Although there are many discussions about future networks of hydrogen with tremendous challenges in terms of safety and overall energy efficiency, one path to be seriously considered is the conversion of wood to methane for reinjection in existing natural gas networks. It can then be used in high value applications like decentralized cogeneration or for transportation feeding compressed natural gas (CNG) vehicles, which are known to be less polluting.

The challenges to convert wood to methane are both economical and physical (gasification). Modern methods of process integration including superstructure based multi-objective optimisation are being developed at EPFL (LENI).

Currently different process designs are under investigation. From the atomic composition of wood they all have in common that the gas produced by gasification lacks hydrogen for completely reforming the carbon into methane, which implies a by-production of CO₂. However the thermochemical production processes are exothermic implying that the co-production of electricity is possible. Hence one idea consisting in integrating an electrolyser in the system to increase the methane yield has been conceptually studied and some of the results partly reported here from [14]. This is also favoured by the fact that oxygen from the electrolyser can also be profitable to the gasification process. Alternatively if electricity is imported from renewable sources, the process could represent a way of storing green electricity in the form of synthetic natural gas.

The investigated technological options can be described in a global superstructure flow diagram represented in figure 7. It includes a sub-process of wood drying, followed by the sub-processes of gasification, gas cleanup to prevent methanation catalyst damages, reforming with steam addition, gas post-treatment to finally get the quality required for reinjection in the gas network (Wobbe index between 13.3 and 15.7 kWh/Nm³).

Figure 7 Process superstructure (dashed boxes include competing sub-processes and dotted boxes include optional sub-processes) [14]

Figure 8 shows the two alternatives for the integration of electrolysis to the gasification. Detailed analysis using a multi-objective optimisation shows that indirectly heated system are preferable and figure 9 illustrates the influence in terms of total production costs for this option. Further details can be found in [14]

Figure 8 Pathways from electrolysis through directly or indirectly heated systems [14].

The exergy efficiency of figure 9 is defined as follows:

In which  designates the exergy value per unit of mass while  refers to the overall produced power and  refers to the overall consumed power (nomenclature and definitions are based on [15].

The results of figure 9 are based on a nominal power plant of 20 MWth which is under planning in Switzerland and a 50%wt humidity has been assumed. They indicate a potential increase of the exergy efficiency by 2 to 3 % as a result of the introduction of an electrolyser. For the given economic environment the optimum exergy efficiency could be achieved with an extra cost of about 20%.

Although the specific production cost of SNG tends to increase with the addition of hydrogen by electrolysis, the profit for a given amount of wood might increase as a result of the increased production of additional gas. Future implementation of such technology will be highly influenced by future governmental measures to favor renewable or not.

Figure 9 Exergy efficiency and production costs in the case of indirectly heated gasification [14]

Table 1 Assumptions for the economic analysis

Parameter	Value
Marshall & Swift index (2004)	1197
Dollar exchange rate	1 euro/US$
Interest rate	6%
Expected lifetime	15 years
Plant availability	90%
Operators	4p./shift
Operator salary	60kEuro/year
Maintenance costs	5%/year
Oxygen price	70 Euro/ton
Wood price (at 50%wt humidity)	16.7 Euro/MWh
Electricity price (import)	88.9 Euro/MWh
Electricity price (export)	26.4 Euro/MWh

6. CONCLUSIONS

Improvements for a more efficient energy conversion of biomass into high exergy products either in cogeneration of heat and power or of trigeneration of power, heat  and fuel is important for biomass to play a major role in solving present resource and environmental challenges.

While internal combustion engines play a dominant role for cogeneration units fed by biogas, less polluting combustion can be achieved by using prechambers. At small scale particularly advanced cogeneration technologies based on SOFC fuel cells are emerging with a large potential both in terms of energy efficiency, pollution and convenience of use. For both of the above technologies the integration of small ORC based on scroll expander-generators will further improve the conversion efficiency. Moreover converting wooden products into fuels, and in particular methane to be reinjected into gas networks when available, is a promising way to favor a better use of these important resources.

Finally process improvements using more advanced design and planning techniques already at the conceptual level are emerging. In particular tools taking advantage of modern information technology approaches like pinch technology and multi-objective optimisation can significantly contribute to a more rational use of energy and financial resources. Information sharing with model and technology exchanges between groups of developing, emerging and developed countries are in the present context to be further developed.

7. REFERENCES

[1]        Maréchal F., Favrat D., Jochem E. Energy in the perspective of sustainable development: The 2000W Society challenge. Resources conservation and Recycling 44(3):245-262, 2005

[2]        Roubaud A., Roethlisberger R.P., Favrat D., Lean-burn cogeneration biogas engine with unscavenged combustion prechambers: comparison with natural gas, Int J. Applied Thermodynamics, Vol.5(No4)pp169-175,Dec 2002

[3]        Roubaud A., Favrat D., Improving performances of a lean burn cogeneration biogas engine equipped with prechambers, Fuel 84(2005) pp2001-2007

[4]        Heyne S., Roubaud A., Ribaucour M., Vanhove G., Minetti R., Favrat D. Development of a natural gas reaction mechanism for engine simulations based on rapid compression machine experiments using a multi-objective optimisation strategy. Submitted to Fuel (2007)

[5]        Meier M. Etude expérimentale de l’auto-inflammation d’une préchambre de moteur monocylindre ; Perfectionnement des diagnostiques et implémentation d’un système de démarrage sans bougie. EPFL Master thesis 2007

[6]        Wunsch D. Numerical flow simulation of a natural gas engine equipped with an unscavanged auto-ignition prechamber. EPFL Master thesis 2006

[7]        Kane M., Larrain D., Favrat D., Allani Y. Small hybrid solar power system. Energy:The International Journal 28/14 pp1427-1443, 2003

[8]        Kane M., Favrat D., Gay B., Andres O. Scroll expander Organic Rankine Cycle (ORC) efficiency boost of biogas engines. Proc. ofECOS 2007, ed Mirandola A, June, Padova, Italy, pp1017-1024

[9]        Van Herle J, Membrez Y, Bucheli O., Biogas as a fuel source for SOFC co-generators. J. of Power Sources 127(2004)300-312

[10]      Van herle J, Marechal F, Leuenberger S, Membrez Y, Bucheli O, Favrat D Process flow model of solid oxide fuel cell system supplied with sewage biogas. J. of Power Sources 131 (1-2): 127-141, 2004

[11]      van Herle J.,Marechal F.,Leuenberger S.,Favrat D. Energy balance model of a SOFC cogenerator operated with biogas, J. Power Sources 118(1-2):375-383, 2003

[12]      Van Herle J., Final Report on Analysis of Biogas for Solid Oxide Fuel Cells for the Swiss Federal Energy Office, May 2003, CH-3003 Bern, Switzerland.

[13]      Jenne M., et al. Sulzer HEXIS SOFC systems for biogas and heating oil, in: U. Bossel (Ed.), Proceedings of the 5th European Solid Oxide Fuel Cell Forum, Lucerne, Switzerland, July 2002, European Forum Secretariat, CH 5452-Oberrohrdorf, Switzerland, pp. 460–466

[14]      Gassner M., Marechal F. Thermoeconomic optimisation of the integration of electrolysis in a wood to methane process. Proc of ECOS2006, ed Frangopoulos C.

[15]      Borel L., Favrat D. Thermodynamique et énergétique. Presses Polytechniques et Universitaires Romandes, EPFL Lausanne, Switzerland 2005 (in the process of being translated in English at EPFL Press)

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[1] Industrial Energy Systems Lab., Ecole Polytechnique Fédérale de Lausanne (EPFL), CH-1015, Switzerland. Tel: +41 21693 2511, Fax: +41 21 693 3502.daniel.favrat@epfl.ch      

Natural Gas Composition and its Effect on Low-Emission Combustors

Changes in Natural Gas Composition and its Effect on Low-Emission Combustors

by Robert Bland, Gas Turbine Efficiency

As traditional global sources of natural gas are exhausted, new nontraditional sources such as coal bed methane and imported liquefied natural gas (LNG) will supply a bigger fraction of the total demand.

Consequently, the variety and variability of compositions of natural gas in pipelines will increase and differ by region. These changes in composition might result in increased concentrations of higher hydrocarbons, producing changes to heating value and hydrocarbon dew point over relatively short time scales. The variations in fuel compositions, if large enough, can have a significant impact on the performance and operability of gas turbines, particularly for those with Dry Low NOX (DLN) combustion systems.

Gas interchangeability traditionally has been based on the gas Wobbe number, which is a measure of the volumetric energy density. Thus, if the gas is pure methane or a mixture of methane, inerts and heavier hydrocarbons, as long as the Wobbe number is the same, then the gases are considered interchangeable. Gas turbine manufacturers typically set other limitations on the levels of the heavier hydrocarbons, keeping the delivered gas within a relatively narrow range of compositions, which ensures that the systems meet performance and operability requirements. This approach historically has succeeded in maintaining a workable level of gas consistency, but that might change soon as these new nontraditional sources impact pipeline gas composition.

New gas sources, such as LNG, often have higher levels of the heavier hydrocarbons, ethane and above than classically have been allowed in the pipeline. The LNG supplier wants to maximize the energy content of the gas and has no local use for the higher hydrocarbons, such as chemical plants, at the liquefaction facility. Conventional diffusion combustion systems on gas turbines are relatively insensitive to these changes in fuel composition and probably will be largely unaffected by this change in fuel supply. The lower NOX premixed combustors, specifically DLN combustors, are considerably more sensitive to these factors.

DLN combustors by nature are not robust devices. To meet the low-emissions levels required, the systems operate close to the lean flame extinction limit because NOX output from a DLN combustor is primarily determined by the maximum flame temperature. For example, the required emissions output of a simple-cycle turbine with a turbine entry temperature in the range of 2,600-2,700 F, significantly above the melting point of metals, is essentially the same as for a domestic gas water heater, which runs at a significantly lower temperature. Historically, any improvements in robustness have been sacrificed to attain ever-lower emissions levels.

As a consequence of operating close to the physical flammability limit, DLN combustors are sensitive to wide parameters. Figure 1 shows the effect of fuel composition on the speed at which the flame propagates. Flame speed affects where the flame can exist in the combustor and how it ignites the fresh fuel air mixture continually entering the combustor. The impact of composition changes on this, and other fundamental characteristics of the combustion process can impact many performance characteristics of the gas turbine combustion system, some of which are:

• NO_X and CO emissions,
• Combustion dynamics, which can impact the durability of combustion systems components,
• Turndown and stability of the combustion system, which can lead to blowouts and machine trips, and
• Auto-ignition or flashback of flame into premixers, which can lead to catastrophic damage to combustor and hot section components.

Constant Wobbe Index

Figure 2 shows such an incident on an ABB combustor where fuel composition changes produced a significant impact on system performance. The heating value of the fuel suddenly drops, and the emissions and dynamics respond adversely to the change.

With many DLN combustors, such as the GE 7FA+e DLN2.6, the fuel distribution can be modified spatially by the use of a series of independently controllable fuel circuits. This allows the system to be tuned for a specific set of circumstances, e.g., ambient conditions or fuel composition. If the combustor encounters fuel compositions outside the narrow range for which it was tuned, emissions or combustor dynamics can be affected adversely. If the variations are large enough, it might not be possible to tune the systems to meet performance and regulatory requirements.

There are two ways to address the issue. The first is for the original equipment manufacturers (OEMs) or third parties to design combustors that are more robust to fuel quality. Siemens has achieved this with its SGT6-5000F 9 ppm combustion system (ULN or Ultra Low NOX). Figure 3 shows the NOX output of the ULN compared with that of older 15/25 ppm NOX DLN combustion systems, as the fuel Wobbe number (energy density) is increased. The ULN system is insensitive to Wobbe number variation as a result of a more robust premixing technology.

This approach might not be a practical or cost-effective solution for some pre-existing DLN combustion systems. In this case, it is necessary to expand the range of fuel compositions over which the system can operate by a combination of fuel conditioning and continuous real-timing tuning of the combustion systems to maintain system performance when faced with variations in fuel compositions. This approach takes advantage of the combustion system’s ability to operate across a moderate range of conditions if correctly tuned for those conditions. In the past, tuning was performed by a specialist coming to site and modifying the control system settings. This was slow and expensive. In response, OEMs such as GE, Siemens and MHI, as well as third parties such as GTE, have introduced local, near real-time monitoring and control systems. These systems control the combustors, either based directly on the real-time emissions/dynamics data—Siemens, MHI and GTE—or on synthetic models—GE—by modulating the combustor fuel flow splits in response to excessive emissions or combustor dynamics. By continually monitoring the system, changes can be made as frequently as necessary and the performance of the system optimized. Figure 3 shows a number of the drivers and parameters affecting optimization.

In addition to real-time tuning, fuel conditioning and heating capabilities might be a requirement to keep systems operating properly as pipeline fuel compositions change. If the fuel contains heavier hydrocarbons greater than C4, then these can condense out in the fuel system. Liquids that are not captured or evaporated prior to entering the combustor can easily auto-ignite when mixed with the more than 700 F air present in an F-class gas turbine. Combustion will occur in areas that were not designed for it, significantly damaging combustor and potentially downstream hot gas path hardware.

To minimize such problems, an effective fuel-conditioning system is necessary. This takes the fuel though the multiple stages of separating the majority of the liquid, coalescing out any airborne droplets and finally heating the fuel to ensure it has an adequate dew point margin, to pass through the fuel delivery system without cooling to a level where condensation of any of the heavier constituents can take place.

Placing the fuel heater under the control of the auto-tuning system can provide another means of controlling the fuel characteristics to address performance impacts arising from variations in fuel composition. A possible addition to the fuel conditioning system is a fuel analyzer that can allow the fuel’s composition and heating value to be measured in real time. This information can either be fed directly into the control system and used to define the combustor fuel splits or recorded in the historian to help understand factors affecting turbine operation.

The variability in fuel composition that will occur with increased use of nonstandard gas supplies can adversely impact the performance of many gas turbines.

In some cases, new combustion hardware might be available to deal with these issues.

In others, available control and fuel-conditioning technologies exist that can mitigate the majority of the effects on turbine performance.

Author

Robert Bland is chief technologist, combustion architectures, at Gas Turbine Efficiency. He obtained a doctorate from the University of Sheffield and has 20 years of computational fluid experience and 25 gas turbine patents.

Source: http://www.elp.com

Heating Value of Fuel

Gross Heating Value (also referred to as higher heating value [HHV]): 

The heating value (Btu) produced by combustion at constant pressure with the following conditions:

(a)    a volume of one cubic foot

(b)   60° Fahrenheit

(c)    reference base pressure

(d)   with air and gas having the same temperature and pressure

(e)   recovered heat from the water vapor formed by combustion

Net Heating Value (also referred to as lower heating value [LHV]): 

The heating value produced under conditions similar to gross heating value conditions excepting the amount of heat potentially recovered from the water vapor produced at combustion. Net heating value is always less than gross heating value.

The Relationship of Gross Heating Value and Net Heating Value

• The hydrocarbons combine with oxygen during combustion and these reactions provide the heat. When the hydrogen combines with oxygen, it forms water in a gaseous or vapor state at the high temperature of the combustion. The resulting formation of water is mostly carried away with the other products of combustion in the exhaust gases from the equipment where the gases are combusted (calorimeter, boiler, furnace, etc.). When the exhaust gases cool, the water will condense out and transform into a liquid state and release heat, known as latent heat, which is wasted in the atmosphere. The heating value of a fuel may be expressed as a gross value or a net value.
• The gross heating value includes all of the heat released from the fuel, including any carried away in the water formed during combustion.
• The net heating value excludes the latent heat of the water formed during combustion.
• The differences between gross and net heating values are typically 10% for natural gases, solid and liquid fuels.
• There are a few fuels that contain little or no hydrogen (for example, blast furnace gas, high-temperature cokes and some petroleum cokes). In these cases there will be negligible differences between gross and net heating values.
• The net calorific value of a process stream gas is the total heat produced by complete stoichiometric combustion, less the heat needed to evaporate the water present in the gas or produced during its combustion.

Use Wobbe Index to Manage Fuel Quality to Gas Burner

Gas turbine generator or gas turbine driven compressor is common used in refinery, LNG and gas plant. These turbine basically will burn gas fuel from the plant itself and hot flue gas is passed through the gas turbine. Gas turbine is then rotate and drive motor or compressor to generate power and head.

Gas fuel burnt in gas burner which typically has fixed orifice nozzles. Heat output from the fixed orifice burner is proportional to flow (Q) and heating value (HV) of the gas fuel. As fuel composition change, flow and heating value will have to be changed to maintain a correct heat output. However, the magnitud of flow and heating value changes may not change linearly or there is not fix relation between flow and heating value. How to relate these two parameters ?

Continuous Changes in Fuel Heating Value (HV)
Gas fuel from refinery, LNG or gas plant is normally a mixtures of gas from several sources i.e. waste gas with low, medium and high heating value. A typical example is fuel gas system in LNG plant. Fuel source can be 

• End Flash Gas which contains very high inerts (as high as 50%-55% Nitrogen level) and low heating value
• Flash gas from Amine regeneration unit which contains high level of CO2 and H2S, Hydrocarbon component varies from ethane to Decane including BTEX
• Demethaniser overhead which contain high Methane level
• Boil-off gas (BOD) which contains very high level of methane and low level of nitrogen
• Flash gas from Ethane, Propone, and LPG storage
• Make-up which composition varies from Methane to Decane

These gases will have large differences in composition, high heating value(HHV), low heating value(LHV) , specific gravity (SG), etc. As the flow for each sources may change due to dynamic of the plant and above value will change dynamically from time to time. How to manage the dynamic changes ?

How to manage a the flow and heating value which may vary in different magnitude and continuous variation in source heating value whilst maintaining a constant heat input into the gas turbine ? What are the parameter to be maintained or limited ?

Wobbe Index is the parameter. Mr. Wobbe found that

• Flow is proportion to gas specific gravity (SG) and;
• Heating Value is also proportion to gas specific gravity (SG)

Wobbe Index (WI) is define as

WI = HHV / Sqrt (SG)

where
Sqrt = Square root of
HHV = High Heating Value (Btu/Scf)*
SG = Specific Gravity (MWgas / 28.96)

* Some may use Lower Heating Value to define WI

This is the parameter that gives a relative measure of the mix/heating value. 
Wobbe Index is used to compare the combustion energy output of different composition fuel gases. Two fuels with identical Wobbe Index at given pressure and valve setting (orifice size) the energy output will be identical. The variation in WI is typically upto 5% (but maximum could be 10% for some manufacturer).

Thus, plant fuel gas designer shall design the fuel gas system such that the fuel gas mixture feeding into the gas turbine meeting the WI limitation. In the event of any upset or interference of any fuel supply source, the control system shall be able to maintain the WI within the limitation.

Calculations of Specific Gravity, Calorific Value & Wobbe Index Table Excerpted From The Institute of Gas Technology, bulletin No. 32

• Wobbe Index is a measure of the amount of energy delivered to a burner via an injector (orifice). The energy input is a linear function of Wobbe index.
• Two gases differing in composition but having the same Wobbe Index will deliver the same amount of energy for any given injector/orifice under the same injector pressure. 
• In natural gas appliances, the gas flow is restricted by passing it through an orifice (hole). The Wobbe Index is useful because for any fixed orifice size and gas pressure, any gas compositions that have the same Wobbe number will deliver the same amount of heat energy or expressed as interchangeability of varying gas compositions.

Interchangeability; Wobbe Index

According to ISO-13686, gas interchangeability indicates the degree of substitutability between the combustion characteristics of different gas types.

Gas with one particular composition is interchangeable with another having a different composition, only if the quality of combustion remains within the specified range.

The Mexican NOM uses the Wobbe Index to deal with gas interchangeability. This index shows the relationship between heat value and the specific gravity of gas, as a flow of energy at constant pressure.

Gas with different compositions but the same Wobbe Index provides the same amount of energy at the same pressure (Fig. 3).

This relationship is represented by a flow equation at the flow point, as follows: W=HHV/ (squareroot of)sg ; where W= Wobbe Index; HHV=high heat value; and sg=specific gravity.

Sources: 

http://www.ogj.com/articles/print/volume-102/issue-25/transportation/mexicos-cre-issues-new-gas-quality-specs.html

http://www.analyticexpert.com/category/gas-analysis/