Technology development and the uptake of geothermal energy in Australia and around the world

 

(see the important notes at the end)

Friday, 9 December 2011

Central Australia Clean Energy Precinct Proposal

Petratherm unveiled a proposal earlier this week to deliver up to 600 MW to mining developments in NW South Australia like BHP's Olympic Dam. The Precinct is to initially comprise Gas and Wind and later, Solar power generation facilities, and subsequently to incorporate Geothermal power connections.

Overall, I think this is a great initiative and I hope it will gain traction

In terms of the basic components spelled out by Petratherm, I do not think we need to be convinced about solar thermal potential although careful evaluation of the costs (especially with storage) will have to be carried out.

The wind potential obviously will need more support than the area being called "Moolawatana" or a "Windy Place" in one of the local aboriginal dialects.

In terms of geothermal, the existence of abundant subterranean heat has already been demonstrated by Paralana 2 well (see an earlier blog if interested). As I pointed out in my AGEC presentation in Melbourne and in my previous blogs, there is a need for technology improvements to bring this heat to the surface at a cost competitive with the other sources proposed for the precinct. There are advanced projects in place, here (e.g. Geodynamics Innamincka project) and in other countries (the Newberry Project in USA) and R&D projects at various levels of maturity (e.g. a spate of projects funded in the latest US DoE round, which were referred to in one of my previous blogs). Some of the readers of this blog will know that there is a group of universities The fate of geothermal electricity will depend on success in these areas.

One of the crucial enabling technology in solar thermal, geothermal and combined cycle gas turbine is air-cooled condenser technology. There is no access to vast quantities of water to suck the waste heat from 600-MWe of electrical generation in those areas. We may see a series of natural draft dry (or possibly hybrid) cooling towers changing the landscape -- in addition to the wind turbines if Moolawatama lives up to its name.

Finally, while on the topic of the Petratherm press release, I have been trying to find some material on what "Heliotherm" is. In a biology context, it is a more exact term for cold-blooded animals, i.e. animals that require solar heat to keep their body temperatures up, for example a lizard is a heliotherm. Petratherm refers to it as a technology for combining solar with geothermal. In the context of heat engineering, the only references I can find are two brand names, an Austrian heat pump manufacturer Heliotherm/Helioplus and a German ground source heat pump manufacturer. I will keep searching.

Thursday, 24 November 2011

QGECE AGEC2011 presentations

The Australian Geothermal Energy Conference last week in Melbourne was well attended. The QGECE staff and students made nine presentations. The titles are listed below:

1. Large scale integration of geothermal energy into the Australian transmission network by Mehdi Eghbal and Tapan Kumar Saha
2. QGECE Research on Heat Exchangers by K. Hooman and Z. Guan
3. The QGECE Power Conversion Group by P.A. Jacobs, A. Rowlands, H. Gurgenci, E. Sauret, P. Petrie-Repar, A. Atrens, C. Ventura, R. Singh, J. Czapla, H. Russell, B. Twomey, J. Zhang
4. Zircon chronochemistry of high heat-producing granites in Queensland and Europe V. Marshall, K. Knesel and S.E. Bryan
5. Synchysite from the Soultz high-heat producing monzogranite, Soultz-sous-Forêts, France: Implications for titanite destabilisation and differential REE and Th mobility in hydrothermal systems Alexander W. Middleton, I. Tonguc Uysal, H.-J. Förster and Suzanne D. Golding
6. Geological Study – Seasonal Storage of Air-Cooled Water for Arid Zone Geothermal Power Plants by Hugh Russell
7. A new database compilation of whole-rock chemical and geochronological data of igneous rocks in Queensland: A new resource for HDR geothermal resource exploration. C.Siegel, S. Bryan, D. Purdy, D. Gust, C.Allen, T.Uysal, and D. Champion
8. QGECE research on delineation of Australian geothermal resources by I.Tonguç Uysal, Massimo Gasparon, and Scott E. Bryan
9. What will make EGS geothermal energy a viable Australian renewable energy option? by Hal Gurgenci (Extended Abstract and Presentation)

My presentation was on the last day of the conference. I addressed the issue of the commercial viability of power generration from an EGS geothermal resource and identified research areas that will increase this viability.

I presented an estimate for what the cost of geothermal electricity could be in Australia for a high-temperature EGS resource using the state-of-the-art EGS technology and what improvements are required to make it commercially viable. To represent the state-of-the-art, the Geothermal Electricity Technology Evaluation Model (GETEM) will be used. This is an economics/performance spreadsheet model developed by the US Department of Energy Geothermal Technologies Program to assess power generation costs and the potential for technology improvements to impact those generation costs. The GETEM Version 2009-A15 was used. This was the most recent GETEM model before the beta version of a new version was released at the GTP Review in Maryland in June 2011.

The cost of geothermal electricity was calculated for a hypothetical geothermal resource and plant defined with the following parameters.

Brine temperature	250 oC
Well depth	4500 m
Power plant	State-of-the-art binary plant with air-cooled condensers
Plant size	20 MWe

All papers are posted on the conference web site. If you would like to see the QGECE presentations, please e-mail the authors using the links I provided above.

Wednesday, 14 September 2011

Options to connect geothermal electricity to the market

We all know that the best known geothermal resources in Australia are away from the power grid. Therefore, transmission lines up to a thousand kilometers are needed to bring geothermal electricity to the grid. These lines are feasible to build only at a minimum capacity of several hundreds of megawatts. This has two implications. The first one is obvious, no one will make this investment in a transmission line unless the potential resource is large enough and we are confident that it can be exploited as planned. The second implication is more subtle but probably as important from the point of view of the utility planners. A 1000-MWe transmission line cannot be connected to any point in a power network. There are technical issues such as voltage and small signal stability as well as the reliability of supply. These depend on the characteristic of the network and the local parameters around the node(s) the transmission line is connected to.

 

The QGECE transmission program has a been investigating these issues for some time. Tapan Saha and Mehdi Eghbal will present a paper at the AGEC 2011 Conference this November in Melbourne about their progress. Yesterday, a QGECE PhD student supervised by Tapan and Mehdi presented at the QGECE weekly seminar about the progress in his PhD and a preview of a paper he will present in the IEEE Power and Energy Society Innovative Smart Grid Technologies (ISGT) Asia Conference 2011 in Perth later this year. Kazi has been developing analytical tools to examine the stability and reliability and congestion issues as a part of his PhD thesis. In the seminar yesterday, he presented his results as applied to a IEEE benchmark network shown in the above image. In his analysis, Kazi examined different transmission topologies. Every generator of a remote generation cluster can be connected to the grid on their own, which will create the so called ‘spaghetti network’. Alternatively, a high-capacity line can connect the generation zone to load centers and successive generators can connect to the high-capacity line. This is referred to as the scale efficient network extension (SENE). The cost allocation in this approach is of course the most debatable issue. Kazi's work indicates that hub SENE approach appears to be the most economic option considering capital investment. Moreover, proper selection of the hub location could be useful to make this approach more attractive. This work so far has been limited to a benchmark network which has a size comparable to the Queensland grid but is not its representative. Kazi and the rest of the transmission team are applying these tools now to the Queensland grid using the power network models provided to the QGECE by Power Link.

 

Monday, 12 September 2011

The DoE awarding $38m to Geothermal Technology Development

Last week, on 8 September, the U.S. Energy Secretary Steven Chu announced $38m to thirty-two projects as part of the Geothermal Technology Program support. I list below some of the project titles that I interested me. Not much is given away inthe DoE announcement. It would be good to know a bit more about the objectives of some of these projects.

Hattenburg Dilley & Linnell, LLC (Anchorage, AK) received $330k for a project that will evaluate the chemical, thermal and permeability characteristics of a geothermal reservoir using chemical signatures that are trapped inside minerals to increase exploration drilling success rates. Hattenburg Dilley & Linnell is an engineering consulting form operating out of Alaska. They are developing a new method, Fluid Inclusion Stratigraphy (FIS), based on measuring the gas concentrations trapped within minerals for evaluating the hydrological regime in geothermal reservoirs. Rock chips are collected during the drilling of geothermal wells and from these rock chips the trapped fluids and gases are released and analyzed using a quadrupole mass spectrometer. I may be mistaken but this sounds similar to some pf the QGECE PhD projects. For example, Alex Middleton's work on European and Queensland granite samples indicates that there may be a connection between the geochemistry of the rock and the secondary permeability of the reservoir at that horizon. Alex present his progress in the AGEC2011 Conference in November.

Los Alamos National Laboratory (Los Alamos, NM) received up to $1.6m with an objective "to reduce the cost of geothermal energy by developing an innovative method that combines high pressure impulses and thermal gradients to drill through hard rock". I have no idea what this means but sounds interesting. Los Alamos of course had the track record in advanced drilling technologies, including high-temperature downhole motors. I am not sure how this is related. There a number of projects working on temporary sealing: Sandia ($400,000) and Brookhaven ($300,000) in two separate projects to develop sealers to prevent fluid loss during drilling. Clean Tech Innovations, LLC (Bartlesville, OK) ($500K) to modify a gel to isolate lost circulation zones. On a more intriguing note, Impact Technologies ($1m) will "examine the feasibility of employing intense radiation technology to drill and seal off the walls of geothermal wells." Brookhaven National Laboratory received another $300k "to develop a multi-functional cement to protect geothermal wellbores against common geothermal failure risks such as thermal cycling, thermal expansion, and corrosion". Two big chunks of money (probably matched by contributions from the companies themselves) go to Atlas Copco and Baker Hughes in two separate grants. Atlas Copcy Secoroc received up to $3.4m for high temperature drilling technologies. Baker Hughes received up to $5m to develop high-temperature real-time downhole logging systems. Potter Drilling, Inc. (Redwood City, CA) received up tp $1.5 million to continue work on their thermal drilling project. It is good that support for Potter Drilling continues. It would be good to get an update on the progress. I checked the Potter Drilling web site but the newest posting was almost a year old. Geothermal Expandables received up to $1.5m improve upon existing casing designs by increasing the effective diameter of production wells -- presumably by reducing the casing wall thickness.

***

On a completely different matter, I read on the UQ Newsletter just now that The University of Queensland has again been ranked as one of the world's top 50 universities for the eighth year in a row in the QS World University Rankings released today. The QS academic survey is based on survey responses, with 34000 academics surveyed in 2011. Apparently, the university achieved a score of 94.4 for its academic reputation, giving it a world rank of 45, a further improvement from its 54th ranking last year.

 

Monday, 5 September 2011

Treasury modelling favours geothermal energy as the future baseload alternative

A syndicated article by Malcolm Maiden (click to see it on Sydney Morning Herald or The Age web sites) prompted this blog entry. The article refers to a Treasury report that predicts that the Gillard government's proposed carbon pricing regime will be most beneficial to the geothermal sector. According to those predictions, the now-fledgling Australian geothermal industry will have the chance to become "a crucial source of baseload electricity" in a future carbon pricing regime. This is about the Treasury report released a month ago. Providing a commentary on it has been on my "to-do" list since then. Better late than never. My purpose in the following is to evaluate the assumptions behind the cost assumptions that caused the Treasury modellers to be so optimistic about the prospects of geothermal energy. I will summarise my views at the end.

Introduction of a carbon price obviously causes significant changes in the mix of power generation technologies. Gas and renewable technologies become more competitive relative to coal, leading to a progressive transition away from conventional coal-fired generation. The extent of this change and the relative positioning of the gas and the individual renewable generation alternatives depend on the price of carbon. The Treasury Report considers two scenarios:

• Core policy scenario — Assumes a world with a 550 ppm stabilisation target and an Australian emission target of a 5 per cent cut on 2000 levels by 2020 and an 80 per cent cut by 2050. Assumes a nominal domestic starting price of A$20/t CO2-e in 2012-13, rising 5 per cent per year, plus inflation, before moving to a flexible world price in 2015-16, projected to be around A$29/t CO2-e.
• High price scenario — Assumes a world with a more ambitious 450 ppm stabilisation target and an Australian emission target of a 25 per cent cut on 2000 levels by 2020 and an 80 per cent cut by 2050. Assumes a nominal domestic starting price of A$30/t CO2-e in 2012-13, rising 5 per cent per year, plus inflation, before moving to a flexible world price in 2015-16, projected to be around A$61/t CO2-e.

As expected, the high price scenario drives a far quicker transformation of the electricity generation sector, with gas and renewables together contributing over 75 per cent of the generation mix by 2050. This is shown in the following figure. The two columns correspond to two sets of results produced by Sinclair Knight Merz MMA and ROAM Consulting. The Treasury asked these two groups to prepare to independent detailed bottom-up models as a hedge against modelling uncertainties.

As seen in the following charts, the trend is the same in both SKM MMA and ROAM models. Both predict that by 2050, the fraction of the zero-emission generation in the total mix will rise to about 70% in the core policy scenario and about 80% in the high price scenario. The mix of the 2050 zero-emission portfolio is slightly different between the two models. The SKM MMA is more optimistic about the take-up of renewables and ROAM Consulting on the prospects of Clean Coal.

 

Figure 1. The electricity generation sources in 2050 for two carbon pricing scenarios; independently modelled by SKM MMA and ROAM Consulting.	Figure 2. The make-up of the renewable power sector in the 2050 electricity generation portfolio for two carbon pricing scenarios; independently modelled by SKM MMA and ROAM Consulting.

The early increase in renewables is largely driven by increased wind generation. However, over time, other renewables become increasingly competitive. By 2050, geothermal is a major source of renewable generation, accounting for between 13 per cent (ROAM) and 23 per cent (SKM MMA) of total generation in 2050, as seen in Figure 2 above.

The uptake of a particular renewable energy technology is very sensitive to the price of the technology of course. The capital costs in the ROAM models are based on Electric Power Research Institute (EPRI) estimates as reviewed by ACIL Tasman (2010). I had a copy of the ACIL Tasman Report and therefore can provide a copy of the capital cost estimates below:

An EGS geothermal capital cost of about $7000/kW installed looks realistic to me. In my cost estimations using the US DoE GETEM spreadsheets, I concluded in an earlier blog that this can be achieved provided we have the following:

• Doubling the production flow rates to about 60 kg/s
• Drilling costs according to the DOE's WellCostLite-Medium cost curves (about $12.5m for one well excluding the cost of reservoir stimulation)

The following gives the estimated costs for a doublet producing 5.4 MWe with these assumptions:

When combined with improvements in the power conversion efficiencies by 20-50% to be delivered by some of technologies we at the QGECE are pursuing, the above costs should come down even further.

In summary, the projections for geothermal energy in the Treasury models seem appropriate to me and even conservative, if (and only if) we learn how to double production flow rates from an EGS reservoir. I am optimistic that we will achieve this because there are significant projects overseas and projects in the QGECE aiming just at this target and we should expect to see significant progress in the next couple of years.

Wednesday, 24 August 2011

Coal Seam Gas Debate and Geothermal Energy

What is coal seam gas?
CSG in Australia
Water contamination issues?
Hydrofracturing Issues?
Effect on the Local Environment
Greenhouse Emissions

The recent debate on access to agricultural farmland by coal seam gas developers has caused some people thinking about possible implications for future geothermal energy applications. Since both access what is under the surface of the land through drilled wells and possible hydrofracturing of their source reservoirs, the argument has been raised that the issues raised by the coal seam gas protests may be applicable to future geothermal power developments as well.

In the following sections, I will explain that, apart from drilling noise and the local impact during the drilling activities, none of the concerns that have been raised for CSG industry apply to the future Australian geothermal power plants. Specifically,

• Geothermal power plants in Australia will be binary power plants with the geothermal fluid circulated in a closed circuit without being exposed to the environment. The geothermal fluid will be pumped up to the surface and it will be reinjected into the reservoir after its heat is extracted as shown in Figure 6. None of this water is released and there is no issue of contaminating surface or underground aquifers.
• Geothermal reservoir stimulation occurs at depths of 4000 meters or deeper. At such depths, there is no risk of the stimulation fluids leaking into shallow underground aquifers that are providing water for agricultural and other usage.
• Geothermal energy is converted to electricity at the site. There are not going to be pipelines that may have an effect on the local communities and the local flora and the fauna.
• Australian geothermal power plants will have no emissions.

Only the temporary local impact of geothermal drilling, e.g. the drilling noise and the disposal of drilling fluids during drilling, will be similar to CSG drilling but such impact will be minimised because all geothermal production and injection drilling is expected to be done from the same drill pad accessing the entire reservoir through directional drilling underground. Therefore, the surface footprint of geothermal drilling will be smaller than CSG and geothermal drilling will be limited to the area where the geothermal power plant will be built -- and therefore the access to such land will have to be negotiated with the local owners regardless of what the law says about access rights to underground resources. Nevertheless, geothermal power industry will be using drill rigs and therefore they need to monitor the CSG drilling practice in terms of minimising the local impact, even though it will be much less then the CSG drilling impact.

Let us now try to look into these issues in greater detail and hopefully convince the reader that the above is true.

What is coal seam gas?

Coal Seam Gas (CSG) or Coal bed methane(CBM) refer to the same gas: methane. In Australia we call it Coal Seam gas (CSG) and in other countries (e.g. USA, Canada), it is referred to as Coal Bed methane (CBM). All coal seams have some methane (CH4) in them. Copying from the Geosciences Australia web site, its origin could either be biological or thermal.

During the earliest stage of coalification (the process that turns plants into coal) biogenic methane is generated as a by-product of microbial action (similar to the mechanism which generates methane in council landfills). Biogenic methane is generally found in near-surface low rank coals such as lignite.

Thermogenic methane is generally found in deeper higher-rank coals. When temperatures exceed about 50°C due to burial, thermogenic processes begin to generate additional methane, carbon dioxide, nitrogen and water. The maximum generation of methane in bituminous coals occurs at around 150°C. The methane produced is adsorbed onto micropore surfaces and, and as shown in Figure 1 (copied from the web site of Australia Pacific LNG, an Origin - Conoco joint venture), is stored in cleats, fractures and other openings in the coals. The gas is held in place by water pressure and does not require a sealed trap as do conventional gas accumulations. In other words, the coal bed is the reservoir for methane and the water is the seal.

Figure 1. Coal Seam Gas(CSG) is stored in the cleats and fractures in coal	Figure 2. Production of Coal Seam Gas

Since the gas is kept in the matrix by the pressure of water, the initial operation that needs to take place is the extraction of that water. The removal of water reduces the pressure and releases the gas from coal. The water (and then the gas) move through the coal seam by the openings provided by the cleats as seen in Figure 2. As in a geothermal reservoir, the permeability is of critical importance. We will come back to this in a later section when talking about hydrofraccing. We note here that water is co-produced with the gas and the amount of water produced is site- and seam-dependent. Therefore, we need to examine this in the context of the Australian CSG industry.

CSG in Australia

The GA web site states that the CSG exploration in Australia started in 1976 in Queensland's Bowen Basin when Houston Oil and Minerals of Australia Incorporated drilled two unsuccessful wells. In February 1996 the first commercial CMM(Coal Mine Methane) operation commenced at the Moura mine in Queensland methane drainage project (then owned by BHP Mitsui Coal Pty Ltd). In the same year at the Appin and Tower underground mines (then owned by BHP Pty LTD) a CMM operation was used to fuel on-site generator sets (gas fired power stations). The first stand alone commercial production of CSG in Australia commenced in December 1996 at the Dawson Valley project (then owned by Conoco), adjoining the Moura coal mine.

According to Baker and Slater, CSG was supplied to the eastern Australian market at a rate of 419 TJ per day (153 PJ per year) in 2008. Queensland produced 96% of this total. This is a small fraction (about 5% of the Australian conventional natural gas production) of the total Australian primary energy production in 2006-07 as shown in Figure 3 (which incidentally gives 87 PJ as the CSG production instead of 153 PJ of Baker and Slater but it is for 2006-07).

Figure 3. Australian primary energy supply and utilisation (http://www.australianminesatlas.gov.au/mapping/files/australian_energy_flows_2006-07.pdf)

The Australian proven and probable CSG reserves in 2009 were reported as 21180 petajoules (Underschultz et al, AAPG Conference, Calgary, 2010). I use the term "reserves in 2009" because new exploration is adding to the reserves every year. Therefore, it is reasonable to expect that, although it is only a small fraction of the total Australian energy supply today, the share of CSG will grow exponentially in future years. The expectations of such growth probably have been the driver for some of the anxiety expressed in recent months. A summary of some of these concerns can be found on the Queensland Conservation web site. The main environmental issues associated with the CSG industry according to the postings on the Queensland Conservation web site are

• water - contamination of adjacent aquifers and removal of too much water from underground storages
• local environment - the impact on farming and local environment from wells and pipelines
• greenhouse gas emissions - during the extraction and transportation

Let us give a closer examination to these issues.

Water Contamination Issues

We have already seen above that a CSG well produces both water and gas. More water than gas is produced in the initial stages of production as seen in Figure 4.

Figure 4. Typical gas and water production profile for a CSG well. From Helmuth(2008). CH4 P/L Arrow Energy is the original source.	Figure 5. Gas production scenarios for period 2008 – 2020 (A); and corresponding estimates of CSG water produced (B) based on possible production figures of 10, 28 and 40.8 Mt/y and production for domestic consumption only

According to Helmuth(2008), the amount of water to be produced from CSG wells in Queensland could be between 100 and 450 gigalitres per year. The reason for the wide range is the uncertainty for the CSG sector growth and the gas and water relationships across the target Basins. Figure 5 plots the CSG production scenarios up to 2020 based on three possible gas production figures of 10, 20, and 40.8 MT per annum. The yellow line in Figure 5 represents a scenario in which CSG is produced only to meet domestic consumption. The vertical bars indicate the range in sensitivity of water production estimates for 2020. The water coming out of the CSG well is not potable water and the concern raised by the CSG opponents is on an environmentally safe of disposing such water.

IMPORTANT : The issue of water contamination is irrelevant to geothermal energy. Geothermal power plants in Australia will be binary power plants with the geothermal fluid circulated in a closed circuit without being exposed to the environment. The geothermal fluid will be pumped up to the surface and it will be reinjected into the reservoir after its heat is extracted as shown in Figure 6. None of this water is released and there is no issue of contaminating surface or shallow underground aquifers.

Figure 6. In a binary-cycle geothermal power plant, the reservoir fluid is circulated in a closed piping circuit and returned to the reservoir after its heat is transferred to the power plant working fluid (http://www1.eere.energy.gov/geothermal/powerplants.html)	Figure 7. A typical geothermal well design (Paralana 1 by Petratherm). The well is cased using a steel liner through the entire depth of the well. It is uncased (or partially cased) in the reservoir 4 kilometers below the surface so that it can collect hot water from the reservoir.

Geothermal wells are cased with steel liners that are cemented into the well as shown in Figure 7. The casing prevents the geothermal fluid getting in contact with the aquifers that may be present at shallower depths. In the unlikely event of a casing failure, the situation would be noticed by the operating company and the well can be plugged without any significant leakage. Since production pumping will stop immediately, the leakage from the casing breach will be minimal during the time it takes to plug or repair the well.

CSG Hydrofracturing

In addition to the concern about the native coal seam water coming to the surface, concenrs also have been raised against the CSG industry about the environmental effects of the fluids used furing the hydrofracturing operation. This is needed in some CSG sites to increase the gas production. The higher the permeability, the greater the flow from a CSG reservoir. If the permeability is too low, the gas does not come out. What is too low? Most commercial CBM plays in USA have permeabilities in the range 3 to 30 mD (1 MD or millidarcy is roughly equal to 1 μm²). But there are many seams at lower permeabilities. Different reservoir engineering techniques are applied depending on the permeability of the seam as summarised in Figure 3 (Palmer, 2010).

Figure 8 - Completion methods based on permeability (SIS=Surface to In-Seam horizontal well). Palmer(2010)	Figure 9. Depths and lengths of horizontal wells drilled for CSG harvesting in Australia (Palmer, 2010)

There are many Australian CSG reservoirs with permeabilities in the range 20 - 100 Md. The use of horizontal wells is therefore reported to be standard practice in Australia and, from these horizontal wells, the coal seam is hydraulically fractured to increase the flow rate. This is done by pumping large volumes of water at high pressure down the well into the coal seam which causes it to fracture for distances of up to 400m from the well. Sand particles (called proppants) are included in the water and they move into the fractures created and keep them open once the pressure is removed. Palmer(2010) reports that Australian CSG practice commonly uses proppants of 16/30 size (where the numbers refer to the mesh sizes). As reported in the same paper, gels and similar fluids can also be used to initiate the fractures.

As seen in Figure 9, the hydrofracturing of coal seams may be used at depths 200-700 meters. Concerns have been raised about the possibility of the hydrofracturing fluids bursting our of the coal seam reservoir and invading nearby aquifers providing water for agricultural usage.

IMPORTANT: There is no possibility of geothermal reservoir stimulation fluids contaminating aquifers providing water for agricultural or other usage. A typical hot fractured rock (EGS) reservoir in Australia is below 4 kilometers. Hot Sedimentary Aquifers are shallower but even they are at least 3-km deep or deeper. There is no risk to shallower aquifers.

Effect on the Local Environment

Concerns have been raised about the effect of drill rigs and the gas transporting pipelines on the local flora and fauna.

The temporary local impact of geothermal drilling, e.g. the drilling noise and the disposal of drilling fluids during drilling, will be similar to CSG drilling but such impact will be minimised because all geothermal production and injection drilling is expected to be done from the same drill pad accessing the entire reservoir through directional drilling underground. Therefore, the surface footprint of geothermal drilling will be smaller than CSG and geothermal drilling will be limited to the area where the geothermal power plant will be built -- and therefore the access to such land will have to be negotiated with the local owners regardless of what the law says about access rights to underground resources. Nevertheless, geothermal power industry will be using drill rigs and therefore they need to monitor the CSG drilling practice in terms of minimising the local impact, even though it will be much less then the CSG drilling impact.

The issue of pipelines does not apply to geothermal power because the energy is transmitted as electricity.

Greenhouse Emissions

Since methane is a potent greenhouse gas, the issue of gas leakage during CSG production and gas transportation has been raised as a Greenhouse Gas impact that somewhat mitigates the relatively low (compared to coal) greenhouse impact of burning gas to produce electricity.

In contrast, there are no greenhouse emissions from a geothermal binary power plant. In such plants, the fluid is restricted to within a closed circuit as shown in Figure 6. There are a few places in the world, e.g. some Turkish and some Tuscan fields, where the geothermal fluid contains substantial amounts of noncondensable gases like CO₂, which may be cheaper to vent. These usually apply to geothermal reservoirs heated by a volcanic heat source. This is not applicable in Australia where the heat source is radiogenic granites and therefore future Australian geothermal power plants will have no emissions, greenhouse gas or otherwise.

Conclusion

Except for drilling noise and the local impact during the drilling activities, none of the concerns that have been raised for CSG industry apply to the future Australian geothermal power plants. Specifically,

• Geothermal power plants in Australia will be binary power plants with the geothermal fluid circulated in a closed circuit without being exposed to the environment. The geothermal fluid will be pumped up to the surface and it will be reinjected into the reservoir after its heat is extracted as shown in Figure 6. None of this water is released and there is no issue of contaminating surface or shallow underground aquifers.
• Geothermal reservoir stimulation occurs at depths of 4000 meters or deeper. At such depths, there is no risk of the stimulation fluids leaking into shallow underground aquifers that are providing water for agricultural and other usage.
• Geothermal energy is converted to electricity at the site. There are not going to be pipelines that may have an effect on the local communities and the local flora and the fauna.
• Australian geothermal power plants will have no emissions.

REFERENCES

Baker, G, and Slater, S. The increasing significance of coal seam gas in eastern Australia. PESA Eastern Australasian Basins Symposium III, Sydney, 14-17 September 2008.

Helmuth, M. Scoping Study: Groundwater Impacts of Coal Seam Gas Development – Assessment and Monitoring, report prepared by the Centre for Water in the Minerals Industry, The University of Queensland, for Queensland Government Department of Infrastructure and Planning (December 2008)

Palmer, I, Coalbed methane completions: A world view. International Journal of Coal Geology, 82:184-195 (2010).

Underschultz, J, Connell, L, Jeffery, R, and Sherwood, N. Coal Seam Gas in Australia: Resource Potential and Production Issues. Search and Discovery Article #80129 (2011) - Adapted from oral presentation at AAPG International Conference and Exhibition, Calgary, Alberta, Canada, September 12-15, 2010.

 

 

 

Monday, 25 July 2011

Paralana II Fracture Stimulation Success

Last week, Petratherm and its JV partners Beach Energy and TRUenergy advised that the fracture stimulation undertaken on the Paralana 2 well had been successfully completed. Petratherm and Geodynamics are the two companies leading the field of Enhanced Geothermal Systems (EGS) in Australia but pursuing two different approaches. While Geodynamics is aiming to develop its reservoir in the hot rock mass itself, Petratherm has chosen a slightly different approach and been aiming to develop a geothermal reservoir in the insulating layers. These layers are not producing heat themselves but would have been heated by heat conduction from the underlying granite rock mass. By aiming to develop a reservoir in the insulating layer, Petratherm is pursuing a trade-off between lower temperatures and higher permeability. The insulating layers already have some porosity (albeit small at those depths) and the company believes that they should be easier to fracture due to lower mechanical strength.

The results announced by the company show a 500-m stimulated zone extending about 900 metres in an easterly direction. The fracture events were recorded by microseismic sensors in six surface and six borehole stations located around the well. A total of 3.1 million litres of water was injected over five days at pressures up to 9000 psi (62 MPa) and sustained pumping rates up to 1600 litres/minute.

Pumping 1600 litres/minute at 62 MPa needs about 1800 kW or 2400 hp of pumping power. The Paralana team was prepared for even harder stimulation as evidenced by the presence of 8500-hp pumping equipment shown below.

The first successful stimulation of an EGS well in Australia was Habanero 1, where over 20 million litres of water were injected at maximum flow rates up to 40 litres/sec (2400 litres/minute) with wellhead pressures sustained at values as high as 65 MPa and reaching peak values close to 70 MPa. I am sure Petratherm will publish injection their curves in due time, possibly at the Australian Geothermal Energy Conference (AGEC) in November.

At this stage, it looks like Paralana reservoir is also overpressured at pressures similar to Cooper Basin with the wellhead pressure stabilised at 3940 psi or about 27 MPa. This is not too far below the wellhead pressures observed at the Cooper basin wells by Geodynamics. . The Geodynamics experience with production pumping from overpressured reservoirs should be of value to the Paralana JV.

Based on a superficial comparison between the two stimulation events, the numbers support the original Petratherm hypothesis that insulating layers should be easier to stimulate. Whether the resultant permeability is high enough to produce flow rates sufficiently higher than those in Cooper Basin to compensate for the lower temperatures will be seen after drilling of the Paralana 3 well. The positioning of the well will require a careful analysis of the stimulation results. In the graphs included in the ASX release, the directional nature of the stimulated zone is interesting. The fractures were generated to the east of the well. Based on the following geological cross section provided by Petratherm on their web site, it is tempting to speculate that the fractures were generated towards the vertical fault shown on the east of the well. I am sure we will hear more from Petratherm in the future as they have time to analyse the results.

Finally, one interesting observation is that in spite of the effort that successfully stimulated a zone stretching to 900 metres in the plan view, the largest seismic event recorded on the surface was of magnitude 2.6 on the Richter scale with 98% of the microseismic events detected being below 1.0. According to the USGS, events below 3.0 magnitude are not felt except by a very few under especially favorable conditions. For those people who are unnecessarily worried about the earthquake risks from geothermal development, I should note that the Newcastle earthquake in 1989 measured 5.6 on the Richter scale and Richter scale is a logarithmic scale - which means that the largest event measured during the Paralana stimulation is 3 below (3=5.6-2.6) the Newcastle earthquake on the Richter scale and therefore one thousand (10³)times weaker. Therefore, Paralana stimulation results prove that the EGS stimulation in stable geological settings have no earthquake risk.

 

Thursday, 20 July 2011

Geothermal to grow in Japan

Japan is located on the volcano belt and the tectonic plate boundaries as seen in the map below. . This means higher risk of earthquakes but also a larger geothermal resource. For a country with such a risk and resource profile, one would aspect the electricity sector would be biased towards earthquake-tolerant power generating technologies with a large contribution from geothermal. We know that this is not the case. At the present, renewables (except hydro) constitute only 1% of its energy consumption with only one-fifth of that 1% coming from geothermal. However, it looks like there are moves to increase this fraction. Norio Yanasigawa of the National Institute of Advanced Industrial Science and Technology, Higashi, Japan, in a recent presentation (Geothermal Research Symposium, 23-24 May 2011, Colorado School of Mines), claims that after Fukushima national energy strategies are being re-examined in Japan and as a result of this there is expected to be a lot more attention to be given to geothermal.

 

World map showing tectonic plate boundaries and volcanoes. The red triangles are arc volcanoes (volcanoes placed along the subduction zones) and the yellow triangles are hot spot volcanoes(isolated locations where magma comes near the surface for various reasons)	The above shows estimated rock temperatures at a depth 2000m. No data are available regarding temperatures at deeper levels

While geothermal energy is the most promising baseload electricity alternative, the Yanasigawa presentation mentions a number of obstacles as

• high potential region exists inside of nation park, over 80% of national potential
• several hot spring owners resist building of geothermal power plants
• long lead time (over 10 years) for geothermal power plant due to legal delays and assessment
• high cost due to long lead time and no government incentives for initial development costs

While the problem of access to national parks can be solved by directional drilling, innovative co-generation concepts need to be developed for geothermal power plants co-located with hot spas. The Icelandic experience shows that the power plants and touristic spas are not necessarily in conflict. Yanasigawa presents a concept design where a relatively low-temperature hot spring (70-120^oC) can be used to serve a number purposes including hot baths, water heating for other purposes, and electricity generation.

There are some technical challenges preventing widespread acceptance of such systems such as long-term stability and safety, grid connectivity, scaling and corrosion, lack of reliable designs to enable automated generation, and finally higher costs. There is also raised to be a need for legal changes e.g. the act of electricity, boiler management and environmental protection.

It will be interesting to watch the next few months as Japan takes account of the Fukushima disaster and assesses future electrical power options for the country. It makes sense that geothermal has to be a significant component of this future.

Friday, 15 July 2011

The University of Queensland launches the 1.22-MW solar panel array

Australia's largest rooftop photovoltaic solar energy generating system was launched to day on the University of Queensland St Lucia campus. The 1.22-MWe array cost of $7.75m. The University of Queensland funded the system with a $1.5 million contribution from the Queensland Government. UQ’s technology partners also strongly supported the project. Brisbane solar company Ingenero installed more than 5000 polycrystalline silicon solar panels across four building roofs, and also donated the SolFocus CPV array. Trina Solar, one of the world’s leading manufacturers, made the panels, and Power-One made the inverters. RedFlow, a local company established by two UQ graduates, Chris and Alex Winter, made and installed the battery. And Energex, Brisbane’s network distribution company, provided $90,000 to assist in developing specialised computer software to monitor the quality of the solar power feed and how it interacts with the local grid network

The performance of the array can be monitored from http://uq.edu.au/solarenergy/. Here are examples of instantaneous power generation curves for yesterday (14 July) and today:

 

Thursday, 14 July	Friday, 15 July

Yesterday was a clear sunny day with occasional clouds, which probably are the cause of the dips in the chart. Today we have overcast gray skies expecting rain sometime later during the day. In spite of that, I was pleasantly surprised to see the array generating electricity as shown on the right-hand chart above.

While geothermal energy remains as the most promising baseload renewable electricity alternative, it needs to be acknowledged that most of the market penetration in last years has been by solar (both kinds) and wind generators. In a couple of blog entries earlier this month, I mentioned a geothermal renaissance mostly based on the developments in other countries. I think the Australian geothermal industry will need to develop a coherent vision for the future of geothermal energy before similar occurs here.

Thursday, 7 July 2011

Cost of solar thermal power as a baseload supplier

Giles Parkinson reported in Climate Spectator that "last week, Gemasolar, a 19MW solar tower plant located near Seville in southern Spain, delivered electricity continuously over a 24-hour period to the grid." The consortium operating the plant, Torresol Energy, was founded in 2008 as a joint venture between SENER Grupo de Ingeniería of Spain (owner of 60% of the company), and MASDAR, an alternative power company based in Abu Dhabi (owner of 40%).

Torresol Energy is has three plants in Spain : the subject of this blog entry, Gemasolar, a 19.9-MW plant with central tower receiver technology located in Fuentes de Andalucía (Seville); and two 50-MWe plants, Valle 1 and Valle 2, located in Cadiz, using cylindrical-parabolic collectors.

The Gemasol plant uses an array of 2650 heliostats concentrating solar radiation on a receiver placed at the top of a 140-m high central tower. The high level of concentration (a ratio of 1000:1 is quoted at the company web site) generates temperatures over 500^oC at the receiver and makes it possible to use molten salt directly as the heat transfer fluid. The power is generated by the molten salt by providing heat to a steam Rankine cycle. The steam Rankine cycle converts only part of the solar heat to power and the remainder of the heat is stored as the latent and sensible heat in molten salt in a large storage tank. The storage tank is large enough to let the plant keep producing electricity for 15 hours without sun.

Gemasol solar field - 2650 panels spread across 185 hectares (about 460 acres or 1.85 km2)	Molten storage tank during construction (September 2010)

Diego Ramírez, Director of Production at Torresol Energy, explained how it was possible to achieve 24-hour production in record time, after barely a month of commercial operation at the plant: "Gemasolar achieved optimal performance in its systems in the last week of June. The high performance of the installations coincided with several days of excellent solar radiation which made it possible for the hot-salt storage tank to reach full capacity. We're hoping that in the next few days our supply to the network will reach an average of 20 hours a day." The Torresol expectation is for the plant to provide 110 GWh/year in a typical year. This corresponds to a capacity factor of 63%.

The capacity factor is respectable and justifies calling this a baseload power generator technology. What would be the cost of this electricity?

There are slightly different figures quoted for the cost of the plant. Giles Parkinson in his article mentions a figure of $18/W without supplying a reference. The UK Daily Mail reported on 3 June 2011 that the project took two years to construct and cost £260million (A$390m) or $20/W.

If we use the average of these two numbers and assume a plant life of 30 years and running costs as 1% of the capital investment, and using a discount rate of 10%, the cost of Gemasol electricity comes to about 40 cents/kWh. This is about one-third higher than the present cost of EGS-sourced electricity (27 cents/kWh -- see my blog entry on 28 June 2011 to see where this comes from). The 40 cents/kWh Gemasol cost of electricity applies to an area of Spain where the sun shines most of the year. Most places in Australia would have similar conditions so this is a representative cost for future Australian solar thermal plants using the same technology.

I copy the short MATLAB script that I used to calculate the levelised cost.

i=0.10; n=30; CRF=(i*(1+i)^n)/(((1+i)^n)-1); OCC=19000; OM=OCC*0.01; CF=0.63; LCOE=(OCC*CRF+OM)/(8760*CF)*100;

% Interest Rate % Plant life, years % Capital Recovery Factor % Overnight Capital Cost, $/kWe % O&M Costs, $/kW % Capacity Factor % Levelised Cost of Electricity, cents/kWh

Wednesday, 6 July 2011

Kalina Cycle

Following the ASX announcement by Wasabi Energy to join the consortium to develop a new 4.5MWe Kalina plant in Taufkirchen, Germany, I have been meaning to write something about it. A Kalina cycle is of course a mixed fluid cycle where the mixed fluid is ammonia and water. While the Kalina cycle if offered over a wide temperature range, its advantages are more pronounced for lower temperatures.

To see why this Kalina cycle is thermodynamically superior to a regular Rankine cycle, let us remember that the best efficiency that one can achieve in a power cycle is the Carnot efficiency which is given as

where T_C is the condenser temperature and T_H is the turbine inlet temperature. Consider a typical Rankine pure-fluid cycle where the brine heat is used to evaporate a suitable cycle fluid. We are ignoring the superheat. The brine and cycle fluid temperatures along the heat exchanger would then look like this:

Because boiling takes place at constant temperature (at T_X), the turbine inlet temperature (TH) is much lower than what it could have been (T_H') if the cycle fluid were able to increase its temperature while it is receiving heat from the brine. If this were possible than the cycle fluid would reach T_H' by following the dashed line.

It is possible to do this in a supercritical cycle where there is no phase change. It is also possible to do so in a Kalina cycle where the boiling temperature keeps increasing. The boiling point is not constant in a Kalina cycle because as more ammonia is evaporated than water, the concentration of water in the liquid increases and the boiling point increases. This is a so-called gliding cycle and is the basic reason why Kalina cycle is better than Rankine cycle, especially at lower temperatures where heat exchanger irreversibilities have a larger influence on the cycle efficiency and the power generation.

There was a hiatus in the Kalina cycle development and this probably was due to the the IP issues. While the original patent by Alex Kalina was issued in 1982 and must have expired by now, there have been a great many number of patents since then addressing various aspects of the technology and it was not clear what the IP was and who owned it. With the consolidation of the IP with Wasabi Energy, a renewed interest in Kalina cycles was being expected for some time. The decision by the Taufkirchen consortium to favour a Kalina cycle plant for their CHP (Combined Heat & Power) project fulfils this expectation.

Monday, 4 July 2011

Geothermal Energy for China

The new Chinese five-year plan commits the country to carbon reductions and expansion of renewable energy. Geothermal energy is one of the renewable energy options being considered by the Chinese government. Earlier this year, the Ministry of Land and Resources (MLR)announced that China would start a geothermal energy exploration and development project, with a target of meeting 1.7% of the country’s energy consumption by 2015. A large part of that was expected to be in direct use like space heating. The new five-year plan sets the goal of supplying heating to 350 million square meters of building space in the next five years.

This year, China will explore and evaluate shallow-lying geothermal energy in 29 provincial capital cities across the country, including Shijiazhuang, Shenyang and Zhengzhou, according to Wang Xuelong, deputy director of the China Geological Survey. The central government will allocate 164 million yuan ($25.2 million) for the investigation, Wang said. It is interesting to note that one of the industrial powerhouses of China, Chongqing, is also a province with considerable geothermal energy potential. There are already known to be 107 hot-spring sites in Chongqing and industries related to these already provide job opportunities for 60,000 local residents, said Tan Xiwei, vice-mayor of Chongqing.

Success in developing applications in direct use of the geothermal heat may lead into more geothermal electricity generation projects in the future provided the ongoing exploration efforts identify suitable targets. The electricity generation was mentioned in the MLR announcement but no target was set. As the readers of this blog would know, the only significant geothermal electricity plant in China is the Yangbajain plant in the Tibet autonomous region, which was commissioned in 1977.

Tuesday, 28 June 2011

Geothermal Renaissance (continued from 16 June)

In the previous entry (16 June, the one before the Solar Flagship funding announcement), I mentioned a series of projects mostly in USA aiming step-change improvements in geothermal productivity. These can be added under three headings:

• Projects aiming to increase the production flow rate
• Projects aiming to reduce the cost of drilling geothermal wells
• Projects aiming to increase brine productivity, i.e. more electricity from the same brine stream

The first group of projects is receiving the most attention and the largest share of funding. Rightfully so because the single most important improvement that will make an impact on the commercial feasibility of EGS electricity is increasing the flow rate from an EGS reservoir. At the present, my estimate of the cost of EGS electricity is about 27 cents/kWh. I arrived at this figure using the DoE's GETEM model. This is based on a flow rate of 30 kg/s at a temperature of 250^oC. The values I picked for some of the other critical parameters and the make-up of this cost is shown in the following figure.

Figure 1 - The present cost of EGS electricity using DoE GETEM model

 

If the flow rate is doubled, using the same model and other assumptions remaining the same, this levelised cost of electricity estimate would come down to 15.9 cents/kWh. This would go a considerable way in making the geothermal electricity the cheapest renewable electricity but by itself would not be enough to make it commercially feasible at the current electricity prices. Even if we triple the flow rate to 90 kg/s, using the GETEM model and all other things being the same, the cost of electricity would still be 12.1 cents/kWh. Progress in the other headings, however, will bring it down to the levels where it will be competitive with natural gas.

I believe the following are achievable in the next several years:

• triple the flow rate from one well to 90 kg/s
• reduce the cost of geothermal drilling so that we can use the medium-cost model in GETEM
• develop better plant technology
  • using natural draft dry cooling towers so that we do not lose 10% of our generation to drive fans (accepting an extra $400/kWe of capital cost to build the tower); and
  • using supercritical cycles so that we improve our brine effectiveness (even though this increases the plant capital cost by 30%)

These improvements will bring the cost of geothermal electricity down to 8.5 US cents/kWh, where it will be a viable contender against natural gas as a baseline option.

The effect of different technology advances on the cost of geothermal electricity is shown in Figure 2.

Figure 2 - Effect of new technology on EGS Electricity Cost (using DoE GETEM model; see above for technology definitions)

The numbers in Figure 2 are not stabs in the dark. There are genuine projects aiming to achieve these objectives and more and they have a good chance of success. That is why I am very optimistic about the future of geothermal energy. However, it will be very important for the sector to realise that significant improvements are needed before EGS becomes commercially feasible. These improvements are achievable and there are pathways to achieve them but nevertheless it will take some time and substantive funding to achieve them. Private sector will not be able to generate the funding levels to develop and demonstrate these improvements. You may ask then why I feel still optimistic. I feel optimistic because these facts have been accepted overseas and very strong EGS programs are occurring in USA and soon in Europe. The initial enthusiasm in Australia could not be sustained because too much risk-taking was being expected from the private investors. I think this is being realised now and Australian geothermal energy sector will catch up with the rest of the world.

Monday, 20 June 2011

Solar Flagship Project Funding will also help Geothermal Power Generation

I was planning to continue on the geothermal renaissance theme that I started last week but an announcement by the government over the weekend caused me to reconsider. The federal government has announced three quarters of a billion dollars in funding for two major solar power stations that will go ahead in regional New South Wales and Queensland, one using photovoltaics and one using solar thermal power generation. The Solar Thermal project is based on the compact linear fresnel reflector technology developed by Australia's Dr David Mills, whose company Ausra was bought by Areva early last year. As announced over the weekend, it is the recipient of $464m of Commonwealth money.  The total value of the project is expected to be $1.2b.

The QGECE Heat Exchangers program was part of the solar thermal bid. The Solar Dawn consortium, led by Areva Solar, will now be building a 250 megawatt (MW) solar thermal gas hybrid power plant near Chinchilla. The consortium members are Areva Solar, CS Energy and Wind Prospect CWP. The project will be located near Chinchilla in Queensland, next to CS Energy's coal fired Kogan Creek Power Station and directly adjacent to the the Western Downs electrical substation. The solar plant output will be boosted by gas-fired power to ensure it can provide a “firm” dispatch to the grid when the sun is not shining, an important consideration for utility customers. Under the terms of the flagships criteria, gas will be limited to 15 per cent of its annual capacity, but in practice it could provide significantly more.

The following pictures how the solar radiation is concentrated onto a pipe to produce steam (AREVA web page) in the compact linear fresnel reflector (CLFR)technology..

Whatever collector technology is used to produce steam, a thermal power generator will have condensers and they will need to be cooled. The existing coal-fired Kogan Creek Power Station utilises air cooling. Initially the Solar Dawn Power Station will incorporate wet cooling (using treated water from coal seam methane) but will need to consider a requirement for transition to air or hybrid cooling in future years. To develop and test options for the consortium towards this end, QGECE will design and build a natural draft dry cooling tower test station on site that will be fed by part of the solar collector array. The objective will be to optimise air and hybrid cooling concepts (including natural draft cooling) for the main Solar Dawn Plant.

This is great news for the QGECE. We will be able to develop and demonstrate hybrid cooling techniques on a field-scale natural draft dry cooling tower. It is also great news for the geothermal energy sector since the results of this research will be immediately and directly transferrable to geothermal power generators that will need to use dry cooling but still have some limited to access to water that can be used on very hot days to help air cooling. On my last blog, I referred to the work at NREL, which shows that judicious use of water sprays can increase the power generation by 15% and bring the power generation close to the design-point value even on very hot days.

I will go back to geothermal renaissance theme in future blogs.

Thursday, 16 June 2011

Geothermal Energy Renaissance

At the end of the Queensland Geothermal Workshop last month I expressed the view that the geothermal energy sector could be about to start an upswing after a disappointing year. Since then I have become even more optimistic. Admittedly, there is no solid proof yet but there are many positive signs that lead me to believe that Australian geothermal energy sector will start rejuvenating after our Annus Horribilis.

Some of the reasons for my optimism are based on overseas developments. I was in the Geothermal Technology Program (GTP) review in Bethesda, Maryland, last week. This is a program that has been investing over $500m over the last three years in geothermal technology component development and demonstration projects. This is in addition to the $1660m spent in 1976-2008 as shown in the following graph.

During the review presentations last week, there were quite a few projects showing good progress. Obviously, there were dud ones too as expected in any large program like this. Across the portfolio, I think there is a very good possibility that substantial improvements will be demonstrated on each one of the three major challenges facing the EGS industry today, i.e. the flow rate, the cost of drilling and the power conversion efficiencies.

How to Double the Flow rate

Under the heading of flow rate, there are two projects that I found particularly interesting. One is the AltaRock Newberry project. This is a $44m project with the aim of achieving a single well mass flow rate of 75 kg/s from the Newberry Volcano EGS site. The project team is hoping to achieve this through multi-zone stimulation and drawing the fluid from three horizons. While there is a large team of participating organisations, the crucial technology, i.e. the diverter technology, seems to be AltaRock proprietary technology. The second project under the same heading is a more modest one. It is a project by Sandia Laboratories and involves constructing a gas generator at the reservoir level to create detonation waves as a new method of reservoir stimulation. This should be particularly useful in creating near-hole permeability.

How to reduce the Cost of Drilling by 20%

At the GTP Review meeting, under the heading of drilling, the most noteworthy project was the Potter Drilling project. Readers of this blog will remember the Potter Drilling project and should be pleased to know that it is progressing well. There are other projects on drilling as well. But even incremental improvements in drilling should be able to achieve the 20% cost reduction target.

How to increase the Power Conversion Efficiencies by 20%

The readers of this blog will know of the QGECE project to develop a supercritical turbine over the next three years with the purpose of achieving up to 50% increase in power production from a typical Cooper basin EGS resource, compared with the existing alternative. It was very encouraging that there were three more projects presented in the GTP Review last week with similar aims, i.e. aiming to develop supercritical power cycles and supercritical power turbines. There are two companies (General Electric and UTC) and one national lab (ORNL) with research projects to develop supercritical cycles and turbines based on optimised fluids and fluid mixtures. The following chart is for example from the GE presentation:

GE examined an array of fluids and the two charts above compare the performance of the best fluid at any temperature against the baseline cycle performance (R245fa and n-Butane).

Under the power conversion heading, another exciting development last week (although not in the GTP review) was the announcement by Wasabi that there is going to be a combined heat & power plant in Taufkirchen in he next couple of years producing 4.5MWe of electricity using the Kalina Cycle technology. This is good news because there has been a hiatus in Kalina Cycle deployment since 2009 when the 3.4-MWe Unterhaching project and the much smaller Bruchsal projects were built by Siemens. The new Taufkirchen project will put Kalina back into the competition and the geothermal industry desperately needs competition in this area to achieve the targeted efficiency increases.

It is good news that the QGECE and its partner Verdicorp is finally facing good competition in developing new Power Conversion technologies that fit the EGS paradigm.

When we speak of power conversion, we need to talk about air-cooled condensers as well since very few of the Australian geothermal power plants will have the luxury of water cooling. There were two presentations last week on new technology development in this area. One was from UTC on their work with microchannel heat exchangers to replace the finned tube bundles. The QGECE research agrees with the UTC that microchannel heat exchangers would be superior alternatives to finned-tube bundles in future air-cooled condensers. However, our research also demonstrates that the metal foam heat exchangers, the flagship QGECE projects in the heat exchangers program, could even be better. The second presentation last week was by Dr Desikan Bharathan of NREL on hybrid cooling. This is about using water sprays on hot days to cool the air on hot days. The QGECE is also working on this problem too. We put in a proposal as part of a large solar flagship bid to try and demonstrate hybrid cooling on a natural draft dry cooling tower. Judicious use of water sprays in hybrid systems may offer considerable benefits. The following chart from DR Bharathan's presentation gives the potential for achieving more power from an air-cooled plant during the hottest part of the day, which incidentally is also the time when the electricity sale price is the highest:

The major geothermal basins in Germany host a network of aquifers containing geothermal fluids at temperatures of up to 140oC at depths of less than 5,000m.. The above is the geological cross-section of the Molasse basin where the new Kalina plant is going to be built.

The chart shows the net power for the steam cycle plants (175°C resource temperature) over the course of an average day in July in Reno, Nevada, using hybrid cooling systems (Bharathan, 2011). The hybrid curves in the chart are obtained by spraying water to cool the inlet air during the hot hours. It looks like one can almost achieve the nighttime performance and possibly double the revenue because the electricity at peak hours can be sold at higher prices. Note that Heller systems (vertical placement of bundles) are slightly better.

***

This is enough on technology. I will continue on the topic of geothermal renaissance in future blogs.

Click here for the rest of the blog

 

Saturday, 11 June

Swiss Plans for Geothermal Power

I was in Bethesda over the last week attending the Geothermal Technology Program review, which is a progress review of the projects funded by the Department of Energy.  Today I am starting the journey to come back home.  It is a long journey and I am not looking forward to it.

However, I am glad to have spent the time to be here during this week.  The GTP is a big budget program including the projects being funded by the $500m geothermal stimulus funding program awarded in 2009. As in any big budget research program there are some very exciting projects and there are some ordinary ones.

Today, I am going to write on another meeting I attended here at the tail end of the review, the IPGT meeting yesterday.

We have known for some time that Switzerland was joining the IPGT but yesterday was the first time that I became aware of the expansion Swiss are planning in the geothermal sector.  Starting from zero at the present. the plan is to be generating 4.4 TWh by 2050.  This is as much geothermal electricity as the current installed geothermal capacity in New Zealand or Iceland.

The Geo-Energie Suisse will develop EGS in Switzerland and the schedule calls for a pilot plant by 2015.  The expected resource temperature is 160oC at depths of about 5000m.  This is lower than the resource temperature we would expect in Australia in such depths but the lower ambient temperatures should help with the cooling of the condensers and compensate to a certain extent for the relatively low brine temperatures.

The most interesting thing about the Swiss plans was the generosity of the feed-in tariff that is out in place to make sure this planned expansion takes place.  All geothermal electricity will have a guaranteed sales price of 48 cents/kWh.  This covers plants up to about 5MWe in size.  Don't we wish we had half of that incentive in the down under power markets?

Wednesday, 1 June

Design of Radial Turbines for Geothermal Applications

In the QGECE Weekly Seminar Series, Carlos Ventura gave a talk on Tuesday on the progress in his PhD Thesis. His Thesis topic is development of computer tools for aerodynamic design and performance optimisation of radial turbines for geothermal power applications. On the side, he is also spending some time on characterising thermoelectric generators for the same purpose with Andrew Rowlands. I should write about the thermoelectric generators on another day.

Flash geothermal plants typically use axial turbines. Radial turbines are the preferred choice for the industry at the moment for binary plants. At the moment, radial turbines are limited in size. The largest radial turbine in use is 15 MWe. By comparison, the largest axial turbine is, as far as I know, the 139-MWe Fuji turbine installed in New Zealand Mighty River Power Nga Awa geothermal power plant.

The unavailability of radial turbines at sizes larger than 15-MW can be a limitation in the future when EGS power becomes more common because EGS plants will use binary plants and they will also use larger power plants by combining the production from several wells. A better understanding of radial turbines may not only push the size boundaries but will also help the QGECE work towards the design of supercritical turbines. Of course, a better understanding of radial turbines may also make us decide that they are difficult to scale up. This is work in progress.
 

Important Notes

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Past Blogs

January-May 2011

September-December 2010

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January-March 2010

December 2009

November 2009

October 2009 Blog

September 2009 Blog

August 2009 Blog

July 2009 Blog

June 2009 Blog

 

 

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