Hydrogen production and injection into the the natural gas network

Transcription

1 Hydrogen production and injection into the the natural gas network Årsmøde i Hobro - Partnerskabet for Brint og brændselsceller, 3. april 2014., EUDP EUDP file Aksel Hauge Pedersen, DONG Energy A/S February, 2014

2 Hydrogen in the gassystem - opportunities and limitations - Opportunities Load balancing Energy storage from fluctuating renewable energy sources. Reduce need for new power infra strucure "Cheap" transport for hydrogen New "green" fuel for transport. Limitations Demand for gas qaulity Reduced transport capacity/-"line pack" Demand for quality of pipelines Economy/efficiency

3 Power balance and - storage. *) Fig. Hourly prices Nordpool, power consumption, wind power production. West Denmark 2nd half January *Customers Response to Electricity price variations caused by Intermittent Generation", Risø 2007 *) Fig. Power prices west DK, Nordpool. * Ea Energianalyser, *) Fig. Power consumption (grey), wind production (green) and export/import of power, December * Energinet.dk Periods with low even negative power prices. However infrequent occurence. *) Expect that interconnection and domestic regulating reserve can handle the needed power balance inside at timehorizon of ten years. Followed by commercial power storage from app *) Status and recommendations for RD&D on energy storage technologies in a Danish context, Febr. 2014, EUDP, Forskel, Forsk VR, Elforsk m.v. More windpower will increase periods with export of "cheap" wind power.

4 Reduce the need for new power infra- structure, - cheap transport of hydrogen new fuel for transport Use-/conversion of power at the place for power production reduce the need for power transport and and by that the loss through transportation. Existing network for gas. Huge capacity for storage. The natural gas system will be the cheapest way for hydrogen transportation. Separation technologies need to be commercial (membrames, PSA, cryogenics) When/if hydrogen for vehicles becomes commercial pipeline transportation of the hydrogen/natural gas mix might the cheapest solution for distribution of hydrogen.

5 Summary / How much Hydrogen? How much hydrogen is recommended to inject into the existing natural gas network? Max 2 % - if connected to CNG filling station Max 5 % - if not connected to CNG filling station, gas turbines and most gas engines Max 10% - if not connected to filling stations, gas turbines and all gas engines. Injection of hydrogen should be carefully controlled to avoid sudden increases of the hydrogen concentration in the natural gas system

6 Summary / the power balancing effect? Future (in years) assumed continuous flow of natural gas 4 billion m 3 Natural gas/year (equal to app ½ million m 3 /h - with the possibility to inject m 3 hydrogen/h (max 2%)). This requires 10x3/0,6 = 50 MW Power capacity (3 kwh/m 3 H2 and electrolyser efficiency of 60%). Gas flow (and consumption) is not steady - therefore the hydrogen injection (and power out-take) will vary maybe between 0 and 100 MW, however continious storing of 50 MW power capacity is only possible with separate hydrogen storage. Future - real need - for the very few hours per year with extrem "excess power production" (for a windy night in a weekend of the summer of 2020 excess power from wind turbines will be around 3000 MW and in the summer of 2035 up to 5000 MW). Storage of hydrogen - and/or methane production might be answer to that challenge. DGC also made some estimates for hydrogen injection possibilities here 10% of hydrogen used as max injection. One conclusion was - energy storage possibility in the order of 1 % of the annual electricity consumption (31TWh). Converted to power capacity over a whole year - this equalizes to a power capacity of app 40MW.

7 Summary / Where should the Hydrogen be injected? It's a question about cost for compression, energy loss through transport of power - and mixing possibilities with natural gas. If optimal mixing possibilities - most suitable place seems to be in Nybro. Avoiding energy loos through transport of power and compression - injection should take place in the medium- or low pressure system. In a minor scale might be used injection spots after M/R stations. Here hydrogen/natural Gas mix only can flow in one direction, but injection will be limited - and always depending of gas consumption downstream the injection point. Preliminary estimates for injection at Nybro (max flow of natural gas up to 1 million m³/h) and max hydrogen content of 2% (20000 m³/h) would require an electrical input of app. 100 MW for the electrolysis reaction. That would be the max possible power storage for the Danish gas-system - but only for periods with max. gas flow.

8 "Methanation" how much CO2/hydrogen might be used? needed power capacity If methane production through "methanation" (combination of H2 and CO2) is developed, the question is - how to generate CO2? The most simple source seems to be the CO2 contained into biogas (app 40%). For the Danish market the biogas production to day is app. 4 PJ and this amount will increase to 10 PJ in 2020 and maybe 20 PJ in 2030 (or 185-, 452-, and 925 mill m 3 biogas/year in 2014, 2020 and 2030). This amount of biogas will produce 74-, 185-, and 370 mill m 3 of CO2 in 2014, 2020 and If 50% of this amount is used for "methanation" - this will result into app. 185 mill m 3 CH4 in or 5-10% of the assumed total Danish consumption of Natural Gas in However 1 mol CO2 needs 4 mole H2 to create 1 mole CH4. Needed H2 production - 4x185 = 740 mill m 3 hydrogen/year (app m 3 hydrogen/hour) - or a mean power capacity of app 400 MW for the electrolyzer.

9 Pipeline consideration PE systems: DGC found strong indications for polyethylene gas pipes PE80 and PE100 being usable for transportation of hydrogen - without any adverse long-term effects on polymer structure or the mechanical performance of the polymer pipes. Same indications found for both new and old pipes used in the Danish natural gas distribution network for more than 20 years. Steel pipes: The dynamic testing equivalent of 80 years with two times the maximal pressure variations found in the danish gas transmissionssystem showed no growth of defects in weldings. Overall conclusion Overall conclusion from the tests (100% hydrogen) clearly indicates no safety problems. The conclusion only applies to the tested types of pipe material, and not to other components and connections in the natural gas network.

10 Pipeline transportation of Hydrogen

11 Other pipeline transportation issues Due to the Joule-Thomson effect, reducing the pressure of natural gas causes its temperature to decrease with 0.5 deg C/bar, whereas the temperature rise with deg C/bar when the pressure of 100% hydrogen is reduced. Throttling hydrogen from 80 bar to 15 bar would result in a temperature rise of 2 deg C. A pressure reduction of a hydrogen/natural gas mix therefore will not cause any problems, that is not already foreseen with natural gas. The volumetric loss of hydrogen by leakage are always larger than for natural gas (due to size of molecule), but the energetic loss smaller. From literature calculations examples shows yearly loss of hydrogen by leakage amounts to approximately % % of the totally transported volume.

12 Reduced wobbe index and methane number when hydrogen is injected Figure: HHV as function of Wobbe index for different gases with or without 10 % hydrogen. Figure: Methane number as a function of Wobbe index for different gases - with or without 10% Hydrogen

13 Influence upon gas engines Gas engines: Increase in flame speed and reactivity caused by hydrogen addition to natural gas typically increases in-cylinder peak pressures. Addition of hydrogen to a natural gas system decrease the methane number This can result in: increased combustion- and exhaust gas temperature, which might lead to enhanced sensitivity for engine knock and increased NOx emissions; improved engine efficiency, but with increased engine wear and increased NOx emissions; reduced power output or tripping, for engines with knock control; an adverse effect on lambda sensors which can cause an inaccurate (low) measurement of oxygen in the exhaust gas. Conclusion: Recommendations are that 2-5 % hydrogen addition should be the aimed interval for engines.

14 Influence CNG tanks CNG tanks: According to UNECE3 Regulation 110 for CNG vehicles, the H2 content in CNG is limited to 2 vol %, if the tank cylinder is manufactured from steel. This limit stems from the risk of hydrogen embrittlement. Car manufacturers are held responsible for the suitability of car components, including CNG tanks. This means that CNG vehicles will only be fuelled with natural gases containing more than 2% hydrogen when substantial tests have proved that it's safe. Further concerns focus upon leak tightness of seals, both metallic and polymer. All gas carrying components inside the vehicle are currently designed and tested for a maximum 2 % H 2. As a result, all such components are potentially critical and their ability to cope with higher H 2 fractions remains to be tested. Conclusion: Max 2% Hydrogen for CNG purpose.

15 Influence on gas turbines gas turbines: Current fuel specifications for many gas turbines place a 5% limit on hydrogen. However exceptions are that dedicated (syngas) gas turbines that can accept very high hydrogen content(> 50 %) and some specific gas turbines which are capable of burning natural gas containing 10 % hydrogen and even more. Conclusion: According literature the fuel composition variation can have an adverse impact on gas turbine operation, despite being within the range allowed in the grid and manufacturers specifications. For installed gas turbines without having knowledge about performance through adding of hydrogen - 1 % hydrogen must be considered as the general limit for hydrogen admixture to natural gas in a first step.

16 The domestic sector Domestic burners: Hydrogen has a direct and indirect effect on the flame speed in burners used in domestic appliances: it increases the flame speed, it increases the air ratio if rich premix burners are considered (unless there is a systems that controls it) Many appliances are tested with test gas G222, which is a mixture of 23 % H 2 /77 % CH 4, and this gives a strong indication that such a high H 2 content in natural gas is acceptable, at least in the short-term. Conclusion: The conclusion amongst experts are that injection of 10 % of H 2 in natural gas grids (H gas) seems to be a reasonable future prospect for the domestic and commercial appliances considered.

17 Safety problems underground storage of Hydrogen Long experience with salt caverns for hydrogen storage. No remarkable problems. For aquifair storage potential risk for bacterial growth. The associated issues are principally loss of gas volume and disappearance of injected hydrogen, whether partial or total. Also potential for damage to the cavity itself, and production of H2S. This raise a special danish issue related to the presence of both salt cavern storage and aquifair storage in the Danish natural gas system. How to hinder H2 in the aqufair storage?

18 16 German Plants for Green Hydrogen and Power2Gas Falkenhagen first mover ITM/Thüga Group first major PEM electrolyzer Fig : ITM kw PEM electrolyzer (60 m 3 Hydrogen/hour) Fig.: E.ON Falkenhagen, 2 MW alcaline electrolyzer plant. The power capacity of the electrolyser is 315 kw. It produce about 60 m 3 /hydrogen/hour ( = 57%, LHV). If max. allowed pipeline concentration is 2% hydrogen, then in one hour can be injected 3,000 m 3 hydrogen-enriched natural gas into the natural gas system First hydrogen test delivery dec This unit, which has a power capacity of 2 MW, produce 360 m 3 hydrogen per hour ( = 54%, LHV). In operation since August 2013

19 Audi with upgrading to methane Grapzow (E.ON) combining hydrogen injection with local storage and power production Fig. 6 MW alacaline electrolyzer. Inclusive methanisation Overall the plant will reuse up to 2800 tons of CO2 /year. The plant will produce app Nm 3 hydrogen/h ( = 65%, LHV) and 300 m 3 SNG/h. Fig. Grapzow, Germany. 1 MW electrolyzing system (Hydrogenics, alcaline) - Taking power from 140 MW wind farm. established Sept MW Power-to-Gas system. The unit produces 210 m 3 H 2 per hour (h = 63%, LHV). The system includes: a) hydrogen storage system with capacity of 27 MWh, b) gasengine for hydrogen based power production or c) hydrogen injection into the natural gas system.