(see the important notes at the end)

Wednesday, 9 December

QGECE signs agreement with US manufacturer to develop next generation power conversion equipment for cheaper geothermal electricity

Readers of this blog will be aware of my belief that much higher geothermal power generation efficiencies are possible and and if they are achieved they will substantially increase the commercial attractiveness of geothermal electricity.

The current industry focus is mainly on minimization of risk and maximization of flow rate. Power generation is seen as mature technology where only marginal improvements are possible. We have been challenging this view. This is an important topic because the proven performance of the mature technology may not be sufficient to ensure EGS project viability, unless high flow rates are achieved, e.g. 100 kg/s from a single well. Almost the entire focus of the geothermal community at the moment is on ways of enhancing the reservoir so as to achieve such higher flow rates.

The question that needs to be asked is if this is the only direction towards commercial viability or if it is more prudent to spread the risk. Achievement of sufficiently high flow rates is certainly of critical importance to the success of an EGS project. But what is "sufficiently high"? A flow rate would be sufficiently high only when it allows the project to deliver electricity at an acceptable cost. For example, it is accepted as common wisdom that high temperatures may compensate for lower flow rates because a higher temperature means higher power conversion efficiency, more power generation, and lower unit cost. The same argument must apply to higher power generation ability.

For example, if 100 kg/s is needed to generate 8 MWe of electricity to make it a commercially viable project with the present power conversion technology, then 75 kg/s would be a "sufficiently high" flow rate if a new generation of power generation equipment can produce the same 8 MW or higher from this lower flow rate.

Is this a realistic aim? Undoubtedly so. There is a theoretical limit that defines what fraction of a heat source can be converted to electricity and this limit is set by the second law of thermodynamics. This theoretical limit is different for different power generation technologies because the temperatures are different. However, one would expect the realised fraction of the theoretical limit to be the same for different technologies.

Less than 40% of the theoretical limit is realised in actual geothermal practice and the ratio is as low as 30% for low reservoir or high ambient temperatures (for air-cooled condensers). In contrast, any other modern power technology is able to enjoy around 70% of its theoretical limit. Clearly, the geothermal energy practice has room to improve.

An agreement signed last week between the University of Queensland and the US-based power plant and turbine manufacturer Verdicorp will help bring the geothermal power conversion efficiencies closer to what are achieved in more mature industries.

With this agreement, QGECE and Verdicorp start a collaborative project to develop not only supercritical turbines and supercritical cycle equipment including supercritical turbines but also heat exchangers and air-cooled condensers for geothermal, solar thermal and waste heat power generation applications and new cycle fluids and fluid mixtures suitable for supercritical cycles. The target technologies have the potential to increase the geothermal productivity by 50%.

A successful conclusion of this project will make geothermal electricity cheaper than the present cost of gas-fired electricity and is expected to make geothermal power cost-competitive even without the motivation of a carbon price. At the first instance, a high-pressure supercritical turbine and cycle testing facility will be built next year on the Pinjarra Hills campus of the University of Queensland. The facility will include a portable test plant for testing and demonstrating the benefits of the new power plant technologies at remote geothermal sites. Watch this space for exciting developments in this area.

Tuesday, 16 November

AGEC2010 starts tomorrow

Australian Geothermal Energy Conference starts tomorrow. I am flying to Adelaide tonight. Based on the Conference Program, it looks like it is going to be an exciting Conference.

The Queensland Geothermal Energy Centre of Excellence is represented by nine presentations. I list them in the order they appear in the Conference Program:

1. Evidence of impact shock metamorphism in basement granitoids,Cooper Basin, South Australia, Andrew Glikson and Tonguç Uysal
2. Geochemistry of silica rocks in the Drummond Basin as a record of geothermal potential, Tonguç Uysal, Alexander W. Middleton, Robert Bolhar, and Massimo Gasparon
3. Hydrothermal alteration aspects of high heat producing granites in Australia & Europe, Alexander W. Middleton, I. Tonguç Uysal, Massimo Gasparon, and Scott Bryan
4. Geothermal Prospection Using Existing Groundwater Geochemical and Thermal Datasets: Identifying Regions of Interest in Queensland from Government Well and Bore Data,Craig McClarren, Massimo Gasparon, and Tonguç Uysal
5. Comparative petrology & geochemistry of high heat-producing granites in Australia & Europe, V Marshall, J Van Zyl, SE Bryan, T Uysal, M Gasparon
6. Progress in CO2-based EGS, Aleks D. Atrens, Hal Gurgenci, Victor Rudolph
7. QGECE Mobile Geothermal Test Plant & ORC Cycle Challenges, Andrew S. Rowlands and Jason Czapla
8. New Design Concepts for Natural Draft Dry Cooling Towers , Hal Gurgenci and Zhiqiang Guan
9. QGECE Research on Heat Exchangers and Air-Cooled Condensers, Kamel Hooman

The above list shows the range of research conducted at the Queensland Geothermal Energy Research Centre and each one of them will have a very interesting story to tell. It will be a good Conference. If you have not registered yet, it is still not too late to do so using the on-line registration facility.

See you at the Conference.

Friday, 12 November

AGEC 2010 Paper on New Options for Dry Cooling Towers

The QGECE colleagues Drs Guan and Hooman will present two papers at the Australian Geothermal Energy Conference in Adelaide next week on what improvements can be expected in dry cooling area. This is a topic of crucial importance to the Australian geothermal industry and one of the four research programs in our Centre. I will try to explain why it is important in today's blog.  Please note that I am not going to tell you about the contents about the papers.  You have to come to the Conference for that.  The following is just some background information.

A thermal power plant is basically a heat engine operating between a high temperature supply of heat and a low temperature sink. The heat engine converts some of the high temperature heat to work and the remaining heat needs to be dumped. No heat engine can produce work if it is connected to only a hot source. It always needs to have a cold sink to dump its waste heat. The relationship between the heat supply, heat dump and the power is provided by thermal efficiency:

The second law requires that the power cannot be equal to the heat input and there should always be an amount of heat dumped to a low-temperature heat sink. If the cycle is efficient, a higher amount of the geothermal heat is converted to electricity and the waste heat, the amount of heat that needs to be disposed, is relatively small. More heat needs to be disposed of for less efficient cycles. This is shown in the following graph.

The above chart illustrates the point that as the efficiency is lowered, the amount of heat that need to be disposed of for every unit of generated power increases very rapidly. For example, a representative efficiency for coal-fired power plants built in the last century is about 33%. These plants would dump 2 MW of heat for every MW of electricity they generate. A geothermal binary plant at half that efficiency would dump heat at the rate of 5 MWthermal for each MW of electricity generated or two-and-a-half times higher; and it would get increasingly worse at lower geothermal cycle efficiencies as shown in the chart.

Seawater cooling

For a power plants located on the shore, the preferred option is to use the sea as the heat dump. The cold water is pumped from the sea, passed through the condenser, and the warm water is returned back to the sea. This is also referred to as direct cooling or once-through cooling. Such systems usually target a temperature difference of 5-15^oC between the ambient seawater temperature and the temperature of the returned water. This results in a water suction rate of about 25-50 kg/s per MW of electricity generation. All of the water is returned back to the sea (or the lake as the case may be). Unless the plant is in a sensitive area, open cycle seawater cooling is an environmentally acceptable practice although environmental monitoring needs to be in place to minimise risk. Depending on the size of the power plant, lakes or even rivers can be used as the heat sink using this method. Historically once-through cooling was the preferred method of cooling for a significant number of Australian power stations.

Wet Cooling Towers

If the dissipative capacity of the water reservoir is limited, then the atmosphere can be used as the heat sink. The condenser heat is dumped into a cooling water loop running in a closed cycle as shown in the following figure. The warm water from the condenser is sprayed into a cooling tower. The water droplets trickle down over a packing medium and during this process some of the water evaporates into the air stream through the packing. This evaporation cools the remaining water stream down to the wet bulb temperature of the incoming air stream. The cooled water collects at the bottom of the cooling water and is pumped back to the condenser.

Initially, these towers were built as tall concrete structures with the air flow being powered by natural draft. Recent designs use lower heights with fans pushing the air through the packing and out to the air. The following is a photograph of the wet cooling towers at the Germencik geothermal power plant in Western Turkey.

Since most of the cooling occurs through evaporative cooling, the thermal pollution of the water reservoir is reduced compared to the open cycle cooling as in the previous section. On the other hand, the relatively high water consumption rate can be prohibitive in areas where fresh water is scarce. The water consumption in a wet cooling tower can be estimated by using the latent heat of evaporation:

At a temperature of T=30^oC, the latent heat of evaporation is about h_fg=2400 kJ/kg. Based on this number, the evaporation rate for a 1-MW of electricity generation at 33% efficiency would be about 0.8 kg/s or almost 3 tonnes per hour. In a wet cooling tower, there are additional losses grouped under the general term of leakage, generally limited to below 8% of the evaporative losses.

In general, it is better to represent the cooling tower water requirements in terms of the heat dump rather than the power generated. This makes it easier to calculate the water requirements for thermal power plants at different cycle efficiencies. On that basis, the water consumption is 0.4 kg/s per MW of heat being dumped. A 25-MW geothermal power plant running at 15% efficiency will need to dispose of 142 MW of heat. The wet cooling tower water consumption for this plant would be 56.8 kg/s or 1.8 million tonnes per year or 1800 megalitres/year. If the water is not freely available, it would have to be purchased. The current bulk water prices in South-East Queensland are about $1000/ML. At a price of $1000/ML, supply of water to the wet cooling tower would cost the power plant $1.8m per year.

Dry Cooling Towers

If the thermal power plant is not located on the coast or near a large lake and if the water is either unavailable or too expensive to use a wet cooling tower, then the only cooling option is using a dry cooling tower. In a dry cooling tower, the air absorbs the heat from the heat exchanger bundles placed in the path of the air stream. As in the wet cooling towers, the air stream is either driven by fans or by the buoyancy of the air (natural-draft). The fan-driven systems can be built quickly and at relatively low cost but their operating costs are higher due to their higher maintenance requirements and the parasitic losses associated with running the fans. The latter can be as high as 15% of the gross power generation for geothermal plants and higher on hotter days when the efficiency drops.

Natural draft dry cooling towers also suffer similar efficiency reduction on hot days but the net plant output reduction would not be as high because there are no parasitic losses. They have low maintenance requirements and low operating costs but cost more to build.

Exploration of options to increase the viability of natural draft dry cooling towers for Australian geothermal applications is a major research program for the Queensland Geothermal Energy Centre of Excellence. This is being pursued along a number of avenues, including the following:

• Advanced heat exchangers with more favourable pressure drop to heat transfer ratios (very interesting things ar ehappening in this area and they will be adressed in Dr Hooman's presentation at the AGEC 2010 next Friday)
• Optimised coling tower design using new materials and new construction methods
• Hybrid systems including
  • Solar enhancement (this is an interesting concept in the cooling tower context and you will hear about it in Dr Guan's presentation at AGEC 2010)
  • Using the shallow aquifers as additional heat dumps (suggested by Bob Collins in AGEC2009 and the topic for a QGECE Master student)

The Conference starts next Wednesday and be there to learn more on the above and other aspects of geothermal energy utilisation.

Monday, 8 November

Geothermal Power Generates Jobs

A recent report by the US Geothermal Energy Association (GEA) lists the types and numbers of new jobs that are expected to be introduced as more geothermal power plants are built in the States. GEA anticipates that 2011 will be a high-point of geothermal activity in the US under the stimulus legislation. There will be approximately 500 to 700 Megawatts of power projects in the final construction phase in 2011, and these projects will add approximately 3,000 construction jobs, primarily in Nevada and California.

The report states that the development of a geothermal resource is a significant undertaking requiring the input of degreed and technical professionals as well as the work and support of numerous "green"-collar workers. Many of the jobs supported during geothermal resource development play their most prominent roles in specific phases of the resource development timeline as shown in the following chart.

People with different qualifications are required during each phase of the project. During the start-up, the focus would be on obtaining permits from the state governments. Most of the people employed in this phase are expected to be employed by the legal and engineering consultancies.

Once an exploration permit is obtained, the actual exploration work starts. The exploration of a geothermal resource requires the expertise of professionals with both undergraduate and advanced degrees in geology, geophysics, geochemistry, engineering, and geographic information systems (GIS). The work also calls for the technical expertise of green-collar workers to support exploration drilling and the gathering of geophysical data. Consulting and management professionals are also needed to support development efforts. At least one to two consultants from an outside company will usually be contracted by a developer to review and provide a professional assessment of geothermal exploration data. The following table from the GEA report lists the types of jobs involved in geothermal exploration:

Once the exploration phase results in enough evidence indicating the presence of resource, the next phase is accessing the resource through drilling. In Australia, this phase is carried out either by the company itself (e.g. Geodynamics) or a drilling contractor (e.g. Petratherm and Panax). In either case, The drilling of a geothermal well is a complex and multi-faceted process requiring the support of multiple teams of specialized personnel such as engineers, geologists, welders, rig hands, cementing personnel, and drilling fluids personnel as well as site and safety managers as shown in the following table copied from the GEA report:

Additional supporting jobs for drilling are contracted out to vendors, e.g. casing installation (4-5 staff), directional drilling (5-7), well logging(2), and rig and fuel transport (45).

Once the resource is characterised, a team of 40-50 designers and engineers are employed in plant engineering and design as shown in the following table:

Once the actual construction of the geothermal power plant commences, the number and range of jobs needed to complete construction expands even further. Project overhead staff can number up to 40 people. Additionally, the EPC contractor will hire subcontractors to complete various aspects of geothermal power plant construction. Subcontractors or craftspeople involved in the construction of a 50-MW geothermal power plant can number from 300 to 400 workers during the final phases of plant construction when the amount of labor required to complete the project reaches its peak. There are various employment positions supported in this phase of geothermal project development as seen in the following table.

The plant construction stage may take up to 2 years and the numbers employed at the beginning are limited but reach the peak numbers shown in the table in the final stages of construction.

The above does not include the jobs generated through the manufacturers of equipment. The GEA report quotes one manufacturer of cooling systems for geothermal applications estimating that as many as 300 laborers getting involved in supplying fan stacks, gear boxes, drive shafts. Similar numbers will apply to the expanders and the other parts of the plant. In Australia, it will be a challenge for the local manufacturing industry to source a significant number of these positions domestically.

In conclusion, a geothermal project employs large numbers of professionals and supports a growing green collar industry starting from the early stages of leasing, permitting and exploration, to components of the geothermal supply chain, to later stages of production well drilling and plant construction, and finally, the continued operation and maintenance of a plant.

Welding at Jolokia (from Geodynamic web site)

Thursday, 28 October

QGECE helping the Queensland Coastal Geothermal Energy Initiative

Yesterday, the Queensland Minister for Mines and Energy, Stephen Robertson, told the parliament about the Coastal Drilling Initiative to identify geothermal recourses closer to the populated areas of Queensland. Areas closer to the coast identified as having possible geothermal potential include near Roma, in the Tarong Basin, the Maryborough Basin South, the Duaringa Basin North and the Hillsborough Basin. The government funding of $5m will be spent in drilling 32 holes that are considered to have potential.

The amount of funding dictates that the wells drilled will be shallow wells. Therefore, the results will not be "proof" of the resource but should increase our knowledge of the geothermal potential in those areas. The QGECE researchers and students will be working closely with the Queensland Coastal Geothermal Initiative to maximise the returns from that investment. I should note here for the record that the QGECE input into the project is covered by the QGECE's own funds not the $5m that is expected to be spent mainly in drilling. The QGECE funding is of course part of the $15m grant give to the University of Queensland that led to the establishment of our Centre last year.

More information about this initiative can be found on the Coastal Geothermal Energy Initiative web site.

The QGECE input into the project will be in the geochemical analysis of the waters and the rock samples obtained during the project. This is going to be a good application of the QGECE methodology in using certain geochemical fingerprints in shallow sedimentary rocks as possible diagnostics for a deep granitic heat source. Alteration mineralogy is a widely used feature to explore for potential ore deposits; however, this method has not yet been deployed for identifying and characterising EGS. The QGECE is investigating alteration mineralogy of high heat producing granites, with particular emphasis on trace element and stable isotope geochemistry. If successful, this can offer an additional approach to geothermal exploration and resource characterisation. Those readers who would like to learn more about this topic may want to attend the following four presentations by the QGECE research team at the forthcoming Australian Geothermal Energy Conference in Adelaide:

• Geothermal Prospection Using Existing Groundwater Geochemical and Thermal Datasets: Identifying Regions of Interest in Queensland from Government Well and Bore Data by McClarren, Gasparon and Uysal
• Geochemistry of silica rocks in the Drummond Basin as a record of geothermal potential by Uysal, Middleton, Bolhar and Gasparon
• Hydrothermal alteration aspects of high heat producing granites in Australia & Europe by Middleton, Uysal, Gasparon and Scott Bryan
• Comparative petrology & geochemistry of high heat-producing granites in Australia & Europe by Marshall, Van Zyl, Bryan, Uysal, and Gasparon

Tuesday, 26 October

Russia to work with Iceland for more Geothermal Power in Kamchatka

According to a recently published report from ABS Energy Research of London, 2009 was a poor year for power generation from Geothermal Energy with only 405 MW of new capacity installed: USA (181 MW), Indonesia (137 MW), Turkey (47 MW) and Italy (40 MW).

According to the ABS, the investment has been down due to the high capital costs for geothermal and high financial risks in the development stages. Growth in the USA was boosted by the American Reinvestment and Recovery Act of 2009 which extended producer and investor tax credits to 2016 and funded several development stage projects. However, the sector is expected to grow rapidly in several countries over the next 5 years due to current and proposed incentives. It is expected that the market will grow by 78% from 10,711 MW at the end of 2009 to 19,016 MW in 2015. In terms of new capacity, growth markets will be the three biggest geothermal countries: the USA, the Philippines and Indonesia. Countries generating electricity from geothermal is expected to rise from 24 at the end of 2009 to 36 in 2015.

The Kamchatka peninsula may contribute to that future geothermal investment. The Russian Energy Minister Sergei Shmatko visiting Iceland said on Monday that an agreement may be signed with the Icelandic government to cooperate in the field of geothermal energy. He also said geothermal energy was one of the most promising renewable energy sources, with RusHydro, the country’s largest renewable energy producer, already operating several geothermal power stations. RusHydro currently operates two geothermal power plants on Kamchatka, with an overall capacity of 62 megawatts. Shmatko reiterated the government’s plan to have 4.5 percent of energy produced in Russia by 2020 come from renewable resources.

The above picture shows bathers enjoying the output water of the HS Orka geothermal energy plant in Grindavik, Iceland. Shmatko also said his government was discussing with Iceland the construction of an energy-efficient metallurgical plant on Kamchatka. He didn’t specify when any of the agreements with Iceland might be signed. It is an interesting coincidence that at an earlier meeting last Friday, the Russian President Medvedev was discussing the impact of alternative energy on Russian oil market: "Of course we want our energy resources to sell well and we do not want to see excessively low oil prices, but $140 a barrel is a catastrophe for Russia. [Such a high price] destroys all incentives for development," he said.

Monday, 18 October

New Drilling Technologies to reduce the cost of EGS electricity

Compared to shallower conventional hydrothermal resources, an Engineered Geothermal System (EGS) typically involves drilling town to 4 - 5 kilometers and the last part of this drilling is into the reservoir rock. Drilling one well can cost as high $15 million. In other words, you have to invest a significant part of your initial capital investment before a major uncertainty about the nature of your resource, i.e. the temperature, can be resolved. The second uncertainty, the flow rate, may require drilling a second well and performing a recirculation test.

Therefore, anything improvement in the drilling technologies is bound to attract a lot of attention. There are three papers in the forthcoming Australian Geothermal Energy Conference in Adelaide on three new drilling technologies.

One of them is a paper by Jared Potter. Potter Drilling is a Californian company which has its origins in the Fenton Hill project. The technology drills boreholes using a process called spallation. The process starts by applying a high-intensity fluid stream to a rock surface to expand the crystalline grains within the rock. When the grains expand, micro-fractures occur in the rock and small particles called spalls are ejected. The process is accelerated by several factors including inherent stress in the rock formation

Earlier this month, Potter Drilling announced that it has been chosen by AlwaysOn for the second year in a row as one of the GoingGreen Silicon Valley Top 100 winners. Inclusion in the GoingGreen Silicon Valley 100 signifies leadership amongst its peers and game-changing approaches and technologies that are likely to disrupt existing markets and entrenched players. At the Australian Geothermal Energy Conference next month, Jared Potter will give an update on the progress in the development and demonstration of the technology and, in a joint paper with Geodynamics, will also highlight a possible application of the technology in enhancing the productivity of an existing production hole.

The second drilling paper at AGEC2010 comes from Bratislava of the Slovak Republic. Ivan Kocis and Tomas Kristofic of the Bratislavan company Geothermal Anywhere will present progress in their work towards a new geothermal drilling technology which also is not using a drill bit. The difference from the Potter technology is the way rock is extracted. The Slovak company developed a process in which pulsed electrically generated plasma melts the rock which is then reconstituted by using water jets and bailed up the well. The following three figures from the company web site shows that the technology can be used to drill holes up to 1-m diameter by placing plasma jet nozzles (in the middle)on the face a drilling disk (at the right).

Earlier this year, the company received about two million euros for further development and demonstration of this concept. At the AGEC 2010 in Adelaide next month, Kocis and Kristofic will report on progress in this project.

The third AGEC2010 paper on drilling is from an Australian company, Specialised Drilling Services (SDS) Australia Pty Ltd. The SDS is a well-known name in metalliferous mining industry for having developed an innovative blasthole drilling technology. For the past several years, the company has been working on application of this downhole hammer drilling technology to geothermal drilling. The Genie Impact Drill is the result. Malcolm McInnes will present the results of this work in Adelaide.

All exciting stuff. Come to the Conference to learn more about these three papers and eighty other presentations on other geothermal energy topics. The Conference web site has the technical program as well as link to register on-line.

Wednesday, 6 October

Optimistic about Salamander-1 Well

Earlier this year, Panax had reported problems in achieving the estimated permeability in its Salamander-1 tests. A study conducted by Down Under Geosolutions (DUGEO) estimated the transmissivity in the open hole section of Salamander-1 well to range from 6.7 Dm to 13.5 Dm. The Panax production tests failed to achieve these numbers.

Subsequently, Panax commissioned SKM-New Zealand to conduct a Well Productivity Index (PI) testing program on Salamander-1. Five production/discharge tests and one injection tests were carried out by Panax under the supervision of SKM engineers. All pressure, temperature and flow data (the latter is also known as spinner data and are collectively known as “PTS” data) collected during the tests, were analysed by SKM. The results, as announced by Panax in a ASX press release yesterday, turned out to be similar to earlier Panax measurements. In other words, the SKM-measured well transmissivity was also significantly below the estimated 6.7 - 13 D-m range. However, the SKM advised Panax that the test results may be reflecting the status of the well itself, rather than the quality of the intersected target reservoir rocks. The significance of this point is that, by adopting appropriate well completion techniques/methods, the Salamander-1 well has the potential to be developed into a production well.

Panax suggests that the problems encountered in the Salamander-1 well are not dissimilar to the problems experienced by the coal bed methane (“CBM”) industry in the 1980s and 1990s. Many of the original pioneers in this field used standard petroleum drilling methods, but did not succeed in producing economic flows. These “well completion problems” have since been resolved by adopting new well completion techniques. Panax is now planning to tap into this experience to develop a suitable well completion program for Salamander 1.

The rest of this blog is part of the educational mission of this blog, where we will try to unpack some of the technical concepts in the above paragraphs.

What is a "good" permeability?

The key parameters of a geothermal reservoir are illustrated in the following figure.

I copied this figure (and most of the following analysis) from a paper by Hugh Murphy, Don Brown et al in Geothermics 28 (1999) 491-506. The paper is on EGS but the figure applies to both HSA and EGS. One operational parameter of great interest is the flow impedance, Z, defined as the difference between the injection and production wellhead pressures, divided by the produced flow rate. It is required that Z < 1 MPa s/l if the power required to pump water through the reservoir is not to exceed a substantial fraction of the power produced by the reservoir. The Murphy paper quotes an earlier estimate by Parker that, if economic development of a commercial reservoir is the target, Z would have to be 0.1 MPa s/l or less. In an earlier blog (27 May 2010), I converted the Panax estimate of 6.7 Dm to the metric impedance units. A transmissivity of 6.7 Dm corresponds to about 0.03 MPa-s/l, which three times better than this economic threshold specified by Parker, and the higher end of the DUGEO estimate, 13.5 Dm, correspond to 0.015 MPa-s/l, which is six times better than the Parker limit.

Panax of course has only one well at this stage and the production tests supervised by SKM would reflect the values around the well.

Instrumentation?

Panax reports that pressure, temperature and the flow rate were logged during the tests. The following downhole tool might have been used in these tests. This is a Schlumberger downhole tool that contains pressure, temperature and flow sensors and, according to Schlumberger, was used in geothermal wells with bottom hole temperatures as high as 650 ^oF or 343 ^oC.

The flow rate was measured by using a spinner. This is an impeller-type flow meter as shown above on the right (copied from a Schlumberger presentation to the USGS Geothermal Conference ):

Wednesday, 29 September

Three more GDP grants finalised

Torrens Energy (TEY) and Green Rock Energy (GRK) signed $7 million Geothermal Drilling Program (GDP)Funding agreements with the Commonwealth Government last week. Another recipient company Greenearth Energy had done the same earlier in the month.

The GDP is a Commonwealth competitive grants program announced in 2008 providing $50 million to seven eligible applicants in the form of dollar for dollar grant funding to undertake drilling of geothermal proof-of-concept projects in Australia. In the first round, only two projects were funded: Petratherm - Paralana and Panax - Penola. Torrens, Green Rock and Greenearth projects are funded in the second GDP round. The other two recipients funded in the second round were Geodynamics Bulga Project and GRE Geothermal WA1 in Perth metro area. No announcements have been made yet by these two companies about the progress with their GDP grants. The GDP program announcement stipulates that the projects funded in the second round need to be completed by 31 December 2014.

Managing Director Richard Beresford said that the company is planning to drill two wells at The University of Western Australia’s Crawley Campus to prove that commercial quantities of geothermal energy can be delivered from depths of about 3,000 metres at temperatures high enough to drive an absorption chiller which would supply a significant part of the Campus’ chilled water requirements. The GDP requires matching funds. Green Rock is hoping to bring such fnds from a variety of sources, including WA Government’s Low Emissions Energy Development Fund (not secured yet but an announcement is expected shortly) and a number of potential joint venture partners.

Torrens is expecting to start drilling its first deep well win parachilna, Elendil 1, in 2011. Based on shallow well data and modelling work conducted in 2008, Torrens Energy is expecting temperatures as high as 240ºC at 4,500m. The matching funds for the project will come from the company shareholders according to the company announcement.

Greenearth will use the GDP funding to prove the potential at the hot sedimentary aquifer (HSA) geothermal energy project located in the Wensleydale - Gherang area northwest of Anglesea, Victoria. The company anouncement states that Greenearth Energy is also developing a large-scale geothermal power project near Geelong with Victorian State Government backing.

Monday, 27 September

Ormat receives DoE grant for North Brawley

Ormat Technologies announced last week that it received $108.2 million from the US Government Section 1603 Program for its North Brawley geothermal power plant in California. Section 1603 of the Recovery Act passed by the US Congress in February 2009 enabled qualifying renewable power projects to elect to receive a 30% cash grant in lieu of pre-existing production tax credit(PTC) or investment tax credit(ITC). The wind and geothermal energy sectors were the major beneficiaries of the scheme. Four projects had already received grants as of March 2010 to the total of US$152m for a total installed capacity of 125 MWe (Salt Wells and Stillwater projects by Enel, Blue Mountain by Nevada Geothermal Power, and Thermo 1 by Raser). The North Brawley was also eligible but for the grant but Ormat delayed application until it solved the sand issue. This project which was supposed to start operation a year earlier was delayed due to problems with large quantities of sand contained in the geothermal brine. The plant uses shell-and-tube heat exchangers to evaporate isopentane on the shell side with the heat supplied from geothermal brine flowing trough the tubes.

Apparently, it was the shift from disposable filtration to the high efficiency hydro cyclones that did work in separating the sand. Hydrocyclones are commonly used in minerals processing to eliminate the sand and other contaminants in a water stream. It would have been good to learn more about the type of hydrocyclones Ormat uses in the North Brawley plant but I found no reference to it in the company literature. In any case, the result was a substantial reduction in the the operating expenses and increased power production from 17 MWe in January 2010 to 25 MWe in in September 2010. "The funding we received today will go toward our continued expansion, including the construction of new projects that will be eligible for future funding under the ITC cash grant program," commented Dita Bronicki, Chief Executive Officer of Ormat.

Friday, 24 September

China building a 2000-km line to provide power to Shanghai

We have been quibbling in Australia about the cost of bringing to market the geothermal electricity produced in Cooper Basin. I understand the concern but I think we need to put it behind us now. Every day it gets more likely that thousands of megawatts can be produced in Cooper Basin from the ample geothermal resource we are blessed to have there (for example, see my blog of 8 September for recent evidence on Geodynamics progress). The transmission distance from Cooper Basin to the present Queensland grid is about 1000 kilometers, give or take a few. When the resource risk vanishes, the cost of producing that resource to the market should start becoming manageable.

In this context, it was interesting to read a story in the latest issue of the British magazine Recharge on the Chinese project to bring power to the city of Shanghai from the hydroelectric plant being built in Xiangjiaba in Western Sichuan. A 2000-kilometer transmission line will be built to transmit 6400 megawatts. This will be a UHV (Ultra High Voltage) DC line. The power transmitted on a DC line is Voltage x Current. Doubling the voltage for a given power will halve the current. Since the losses are proportional to the square of the current, the losses will go down by a factor of four. The HVDC had meant about 500-kV. The relatively new UHV means transmission voltages of 800-kV and higher. The Recharge article says that China wants to be a leader in the UHV technology. They are planning to increase the voltage to 1000-kV. The government is planning to spend RMB300bn (A$44bn) in the next two years on UHV power lines. The rationale is simple. China's energy resources are located in western China while the demand for power is in the export-oriented manufacturing plants located close to a seaport along the coastal region. Getting the power from west to east using standard transmission lines is inefficient. Over standard AC transmission lines, losses over a distance of 1000-km amount to about 10% of the transmitted power. Using a HVDC line, this would be reduced to about 2-3%. With UHV technology at 1000-kV,  China should be expecting to reduce it down to 1%. It is worth watching.

Wednesday, 22 September

Was Cooper Basin hit by a large asteroid 300 million years ago?

Today I will report on something quite exciting.

I will give you a summary of a paper the QGECE Reservoir Geology Program Leader Dr Tonguc Uysal and DR Andrew Glikson of ANU will be presenting at the forthcoming Australian Geothermal Energy Conference in Adelaide. Click here to get a full copy of the paper and attend the Conference for a more detailed justification on why Drs Uysal and Glikson think Cooper Basin may have been hit by a major asteroid about 300 million years ago.

The confirmation for the asteroid hit comes from a microscopic examination of the quartz crystals from rocks underlying the Cooper Basin by DR Tonguc Uysal (QGECE) followed by laboratory tests by DR Andrew Glikson of the Australian National University (ANU). Shock features were found in drill holes spaced as far as 80 kilometres across. Other known examples of large impact structures include the Woodleigh impact (Western Australia; 120 km-diameter; ~360 million years ago), Popigai impact (Siberia; 100 km-diameter; 35.7 million years ago) and Chesapeake Bay impact (off-shore Virginia; 85 km-diameter; 35.3 million years ago). Such structures are formed by the impact of asteroids 6 - 8 km-large.

The impact-triggered explosion, circulation of boiling groundwater and mobilization and reconcentration of radiogenic elements, all may have helped the creation of major geothermal anomalies under the Cooper Basin. Drs uysal and Glikson report that the precise age of impact is yet to be determined, possibly through isotopic studies of clay minerals in the altered zone. Further studies of impact shock metamorphic effects on samples from drill holes in the Cooper Basin in South Australia are required in order to define the extent of the impacted aureole.

Tuesday, 21 September

Business strategies in a warming world

Following a disappointed Copenhagen meeting last year, the global effort towards climate change have seemed to take a pause. The situation was not helped with the procedural problems at the IPCC exposed by the InterAcademy Council Review as I noted in my blog entry on 1 September.

The scientific consensus on climate change process however seems to be getting stronger every day in spite of such shenanigans. In recognition of the fact that physical processes follow their own logic independent of the political games we play, some businesses have already started taking steps to mitigate the effect of the climate change on their future viability. A lot of media space has been given last week to Marius Kloppers' speech at the Australian British Chamber of Commerce luncheon in Sydney on 15 September. In that address, BHP CEO acknowledged that the world was moving towards a carbon pricing regime to combat climate change processes. This was process following its own course in spite of what happened in Australia. The effect of this process on Australia would be particularly severe because of our dependence on coal. Mr Kloppers cautioned that Australia's energy supply was particularly carbon intensive.

Over 80% of our national electricity generation comes from coal-fired power stations. Cheap electricity thanks to the abundant availability has been one of the main strengths of Australian economy. Moreover, coal exports have also been the largest foreign currency earner for the country in recent decades. These major strengths may turn into critical weaknesses very quickly if the rest of the world decides to take action on climate change by putting a price on carbon. It would affect the export earnings of the nation and it would affect the competitiveness of the local economy. Mr Kloppers noted that 90 per cent of carbon emissions in Australia coming from the electricity sector originating from coal-fired power stations. "Reducing Australia's carbon emissions footprint will require substantial changes in consumer behaviour," he said.

One day before Mr Kloppers' address, a much smaller company was voting on the issue by its feet. On 16 September, one of the premier wine manufacturers of the nation, Brown Brothers, announced that they have entered into an agreement with Gunns Limited to purchase its Tamar Ridge Estates vineyard and winery interests. Chief executive Ross Brown said the move south was spurred by global warming.“The Brown Brothers Board has been carefully considering how global warming may impact our vineyards through drought and high temperatures and recently adopted a strategy to source grapes from cooler areas. As part of this process, we discovered Gunns Limited in Tasmania - owners of Tamar Ridge Estates (whose brands include; Tamar Ridge, Pirie, Devil’s Corner and Coombend) had decided to sell its vineyard and winery investments,” he said.

“Until recently, we have always thought we were drought proof in north-east Victoria, ” But he said higher temperatures and bushfires encourage the 120-year-old company to source grapes from cooler areas. “We want to position ourselves to combat global warming.” CSIRO climate change models show much of Tasmania to be slightly warmer, but also wetter, in decades to come. The shift puts Brown Brothers slightly ahead of the pack, according to wine writer Huon Hooke. “A lot of people in the industry are thinking about this, but few have actually acted on it,” Mr Hooke said.

Thursday, 16 September

Birdsville Geothermal Power Station

We were visiting Australia's first and, at the present, only geothermal power station yesterday. This is in Birdsville, western Queensland, and it is currently providing approximately one quarter of the town's energy supply. It is owned and operated by Ergon Energy. The people in the following picture are Hal Gurgenci, Peter Jacobs and Andrew Rowlands. Another QGECE researcher, Zhiqiang Guan was also with us and he is the one who took this picture.

The power plant started operation since 1992. You can see the schematics of the plant in the above picture on the sign behind us. Hot water at 98 ^oC from a 1280-m deep hole provides the heat source to a binary power plant.. The plant was originally designed for R114 but a switch was made to isopentane as part of the global phasing out of the CFCs due to ozone depletion concerns in the atmosphere. Enreco Pyt Ltd, which designed and built the original plant, also undertook the upgrade to isopentane with funding from a QSEIF grant and Ergon Energy and the upgraded plant started operating again in December 2005 using isopentane as the cycle fluid.

Last year, the Queensland Government has committed $4.3 million to Ergon Energy for the new Birdsville Geothermal Power Station. The project will replace existing plant that is reaching the end of its design life with more efficient equipment that will use the existing geothermal resource more efficiently and produce more energy.

Monday, 13 September

Deloitte Energy Excellence Award for the New Zealand Power Plant

The Nga Awa Purua Geothermal Power Station, a NZ$430-million joint venture between Mighty River Power and the Tauhara North No.2 Trust, was named Project of the Year at the inaugural Deloitte Energy Excellence Awards last week. The plant was officially opened by the PM John Key in May.

The geothermal fluid at 300 oC is provided is extracted from a depth of 2500 metres using eight production wells (200-2500 m). The average geothermal production is 65 kg/second/well. The majority of the fluid is reinjected using 5 injection wells (3000 m deep). The company reported that each well took about 40 days to drill. The fluid was transported to the plant in steel pipes of 1200-mm diameter and 30 mm wall thickness.

The plant is a triple flash plant with a single-shaft turbine using three expansion stages. The plant was constructed by Sumitomo of Japan with the turbine and the generator provided by the Fuji Electric Systems. This is reportedly the largest single casing geothermal steam turbine in the world, capable of providing 139MW (gross). A wet cooling tower is used to cool the condensers. Air is driven through the coling tower using 10 fans that are at 10-m in diameter and spin at a speed of 99 rpm. The cooling tower has a footprint of 165m x 20m. The following is a picture taken during the construction of the cooling tower:

The power station will produce enough electricity to meet 3% of New Zealand’s electricity needs. The Mighty River Power chief executive Doug Heffernan says that with the addition of Nga Awa Purua, around 14% of New Zealand’s electricity supply now comes from geothermal energy.

Wednesday, 8 September

Jolokia 1 confirmed as the hottest EGS in the world

Jolokia 1 was drilled to 5000m and plugged almost exactly two years ago. A GDY announcement at that time stated that they were expecting to find Jolokia 10 ^oC hotter than the Habanero wells. Geodynamics re-entered Jolokia-1 two months ago using the Rig 100 pictured below. The picture also shows the 7" completion casing on the rack ready to be run into the well..

Yesterday, Geodynamics provided a very positive update on Jolokia 1 reported on the results of logging using an imaging tool. Reportedly, this is the first time that an imaging tool has been successfully deployed to log a well bore in the high temperature and high pressure conditions prevalent in the Cooper Basin granite. Imaging was done to a depth of 4575 m. Logging results have revealed potential fractures deeper within the granite at higher temperatures which are believed to be comparable to the fractures photographed at 4575 m (see below). The target is to generate a reservoir starting at 4900 m by stimulating and enhancing these existing fracture network.

The logs also confirmed that the temperature at Jolokia is approximately 8 degrees hotter than the company’s Habanero site (at the same depth), making Jolokia 1 the hottest EGS geothermal well in the world at this depth. Temperatures in Jolokia at 4,900 m are around 278 °C. This confirms the 2008 expectations quoted above. The hydraulic fracture stimulation program is now expected to be completed during October -- slightly behind the schedule because of the delays in inserting the liner and the heavy rains in the area but sill just in time for the Australian Geothermal Energy Conference on 10-13 November 2010, where Doone Wyborn of Geodynamics is scheduled to present a paper on Jolokia-1 stimulation.

The good news made an immediate impact on the Geodynamics share price, which lately has gone through some rough times as shown below.

 

Monday, 6 September

Indonesian Geothermal Power Plant Contract to Tata Power and Origin Energy

I reported on 30 March on competition for a geothermal power project proposed for North Sumatra, Indonesia at Sorik Merapi. Tata Power, India’s largest integrated private power company, announced yesterday that the consortium comprising Tata Power (47.50 per cent), Origin Energy (47.50 per cent) and PT Supraco Indonesia (5 per cent) were declared as the successful bidder for the Sorik Marapi geothermal project in Northern Sumatra, Indonesia.

The Sorik Marapi project is estimated to support the development of approximately 240MW of geothermal generation capacity. The project will be developed by PT Sorik Marapi Geothermal Power, a special purpose vehicle formed by the consortium. The consortium would undertake a detailed exploration programme over the next 18 months. The expected commercial operation date for the project is June 2015. In bidding for the project the consortium beat out major foreign competitors, including Chevron and PT Medco Energi International.

Tata Power and Origin Energy are significant stakeholders in Geodynamics. The Sorik Merapi project provides a new vehicle for collaboration between the two companies in geothermal energy area. Sorik Marapi is a conventional geothermal resource similar to established operations in New Zealand, where Origin had experience through its majority-owned subsidiary Contact Energy.

Karen Moses, executive director, finance and strategy, Origin Energy, said, “The joint venture is consistent with Origin’s strategy of pursuing exploration opportunities for energy resources near growing markets. This joint venture is reflective of our belief that geothermal can provide large-scale renewable base load energy.” Tata Power said it has a ‘strong mission’ to achieve at least a quarter of its generation portfolio through renewable sources of energy by 2017, geothermal energy being one of the prime renewable growth engines. ‘The Sorik Marapi exploration is testament to our faith in the untapped potential of geothermal energy,’ said Menon.

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The picture shows a volcanic eruption that occurred at the end of last year on the mountain Berketinggian 2400 meters above the surface. The mountain is in North Sumatra and close to the Sorik Merapi geothermal field. Indonesia, which is within the extremely active seismic region called the Pacific Ring of Fire, is said to have a geothermal power-generating potential of about 27,000 megawatts, but the current installed geothermal capacity is only about 1200 MWe.

Wednesday, 1 September

$2 billion a year from Asian Development Bank to finance clean energy projects in Australia, Turkey and Brasil

Soon there will be a new source of financing for clean energy projects. The Asian Development Bank(ADB) announced on Wednesday that it is planning to issue clean energy bonds. The Bank is targeting Japanese retail investors and it said that it would match the funds raised this way on a dollar-per-dollar basis. The bond will have four tranches, one denominated in Australian dollars, another in Turkish lira and two tranches in Brazilian real. They will mature in four and seven years.

The ADB is targeting $2 billion a year in clean energy investments by 2013 to focus on wind, solar, water, geothermal and biomass(e.g. sugarcane). It has invested more than $5 billion in clean energy since 2005 but this will the first time that an ADB bond program will be targeting clean energy investment. The ADB Press release states that the Clean Energy Bond issue follows the successful sale in April of ADB’s inaugural Water Bond, which is supporting the ADB’s work in the water sector in Asia and the Pacific.

The choice of the currencies in the bond program is interesting. This probably means that the Bank is guessing for most of the investment to occur in these three countries ($500m per year in Australia and Turkey each and $1 billion per year in Brasil). We know all about Australia's increasing demand for electricity of course and how an increasing fraction of that demand will have to be satisfied from clean energy when a carbon pricing regime is put in place in the near future as expected.

I know a bit about Turkey too and I will spend a bit of time to relate what I know as I think this may be of more interest to the readers of this blog instead of trying to read tea leaves to predict what will happen to the Australian renewable energy sector in the immediate future under the new government (whatever form and shape it takes). Turkey has a huge demand for new sources of electricity as indicated by the following graph on the left. I prepared this graph when I was a guest lecturer at the Bogazici University a few years ago. The red crosses are from the web site of the Turkish regulatory authority TEIAS and the blue line is a exponential curve I had fitted to the past data (which are the circles).

The second map on the right is from the web site of the European Geothermal Energy Council - EGEC and shows the relative potential in the European countries. Turkey clearly has a lot of geothermal potential. Most of that potential is volcanically sourced. In spite of this geothermal potential, due also to the availability of cheap and abundant natural gas from its Eastern neighbours, most of the Turkish electricity investment has been in natural gas. The levelised cost of gas-produced electricity in Turkey, I am told, is about 7-8 cents per kWh. This should be compared against the current retail cost of electricity, which is close to 20 cents/kWh (not much different from Australia). Since the electricity demand is increasing exponentially, it is difficult for a natural gas investor to lose money at the current retail prices.

The electricity from cheap gas has worked against wider adoption of geothermal energy in the past. This is inspite of the abundance of easy (relatively speaking) geothermal resources. I say "easy" because I anticipate many Turkish sites which will deliver temperatures exceeding 200 ^oC when drilled to a depth of 3000m. The following is shows well temperatures from existing geothermal wells in Turkey. The x-axis is the depth in meters and the y-axis is the temperature. As one can see, the Turkish geothermal sector has hardly started drilling below 2000 meters yet. The ellipse I added in the upper right corner of the graph is labelled as the "Unknown Territory". I know that a lot of work is needed to prove this potential, possibly by the government first as a precompetitive project. Nevertheless, I think it is fair to expect the unkown territory in this chart to hold huge resources to power the future of the nation. The availability of the ADB Clean Energy Bonds may encourage Turkish investors to start exploring in this territory. Most people I talked in Turkey agreed that the investment in deeper geothermal sources would be commercially feasible at the current electricity prices. The problem so far was that it was not as cheap as gas-fired electricity and therefore geothermal sector was not able to compete against natural gas for the investors' dollars. The ADB bonds may change this.

Wednesday, 1 September

IPCC Management found lacking by the InterAcademy Council

An important report was released yesterday by the InterAcademy Council (IAC). This is multinational organization of science academies from around the world. The current eighteen-member board is composed of presidents of fifteen academies of science and equivalent organizations, including Professor Kurt Lambeck, past president of the Australian Academy of Science.

The United Nations and IPCC asked the InterAcademy Council (IAC) to review the processes and procedures of the IPCC and make recommendations for change. The report released yesterday is a result. The Review was carried out by a 12-member committee representing Academies of Sciences and Universities from USA, South Africa, Brazil, China, Netherlands, India, Mexico, UK, France and Malaysia. Another group of 12 people of similar stature reviewed the report and Australia's John Zillman, a former director of Australian Bureau of Meteorology and a former President of the World Meteorological Organization is amongst them. The Review process was monitored by Kurt Lambeck, a past president of the Australian Academy of Science, and Ralph Cicerone, President of the US National Academy of Sciences.

The Committee examined only the procedures and processes of the IPCC. It did not try to review climate change science or the validity of its representation in the IPCC assessments. The Report is 113 pages long and if you are interested you can download it from the IAC web site. While Report acknowledges many good things about the work of the IPCC, its most critical statement is that, since its inception in 1988, IPCC has failed to adapt to the changing conditions and the increased controversy on the climate change issue across the globe. This has to be seen as an indictment on the current management of the IPCC.

Sources of Data

I was under the impression that only peer-reviewed papers were considered for the IPCC in preparing their assessments. I learn that it started this way but it turned out that a significant amount of useful information was available in non-peer-reviewed sources. An analysis of the 14,000 references cited in the Third Assessment Report found that peer-reviewed journal articles comprised 84 percent of references in Working Group I, but only 59 percent of references in Working Group II and 36 percent of references in Working Group III. The Working Group 1 is the original IPCC brief assessing the physical aspects of the climate system and climate change. The Working Groups 2 and 3 deal with the vulnerability to climate change and policy options for mitigation, respectively. The IAC Report concludes that clearer guidelines and stronger mechanisms for enforcing them are needed in terms of including non-peer-reviewed literature.

Review Process

The IAC Committee notes that all IPCC Reports are subject to open review and they are reviewed extensively. For example, the Working Group II report of the Fourth Assessment received over 35000 expert comments and government comments. The sheer size of the commentary sometimes resulted in ignoring some of the reviews. The IAC Report recommends that (a) targeted reviews are sought and a range of views are included in these targets; and (b) a more rigorous review monitoring system is put in place so that all reviews are considered and addressed by the Lead Authors in the final product. The IAC Committee Report provides the IPCC Working Group II warning on the Himalaya Glaciers as an example of ignoring some of the reviewer comments, which would have increased the quality of the quality of the final product if they had been considered. I am not going to copy it here but I recommend you read it in the Report, it is on pp 23-24.

Influence of the Governments

The "Summary for the Policy makers" is probably the best-read part of an IPCC Assessment. These summaries are drafted by the scientists but negotiated with the government representatives into their final form. The negotiations occur in plenary sessions. These sessions last for several days and commonly end with an all-night meeting. Thus, the individuals with the most endurance or the countries that have large delegations can end up having the most influence on the report. The IAC Committee recommends that government inputs are provided as written comments prior to the plenary session.

Treatment of the Uncertainty

IPCC Scientists are asked to make predictions about the future. Different degrees of uncertainty are assigned to such predictions in the IPCC assessment reports. Since the authors of these reports extract these predictions from published research not from their own work, it is difficult for the to formally characterise uncertainty. This becomes especially difficult when you consider that 10000+ references are cited in each Assessment report. The standard IPCC procedure in assessing the uncertainty associated with a particular assertion in a particular reference appears to be assignment of subjective measures of confidence. The following table is included in the IAC Review Report to represent the IPCC procedure:

Terminology	Degree of Confidence in Being Correct
Very high confidence	At least 9 out of 10 chance of being correct
High confidence	About 8 out of 10 chance
Medium confidence	About 5 out of 10 chance
Low confidence	About 2 out of 10 chance
Very low confidence	Less than 1 out of 10 chance

I guess there is nothing wrong with stating subjective opinions, especially when a more rigorous uncertainty analysis is not possible. However, it may be misleading when these subjective opinions are presented as something which they are not. The IAC Review concludes that assigning probabilities to imprecise statements is not an appropriate way to characterize uncertainty. If the confidence scale is used in this way, conclusions will likely be stated so vaguely as to make them impossible to refute, and therefore statements of “very high confidence” will have little substantive value. It should be stated that the domain of the Working Group I is more amenable to statistical analysis and some predictions in their reports are the result of statistical analyses on measured trends.

Six of recommendations are made to improve this process. They are all good recommendations actually for anyone doing a study on future forecasting based on a review of others' work and need to be read and understood, IMHO, for all of us as we all are asked to make predictions about the future in one form or other. I quote the first one directly from the IAC Review Report:

"The IPCC uncertainty guidance provides a good starting point for characterizing uncertainty in the assessment reports. However, the guidance was not consistently followed in the fourth assessment, leading to unnecessary errors. For example, authors reported high confidence in statements for which there is little evidence, such as the widely-quoted statement that agricultural yields in Africa might decline by up to 50 percent by 2020. Moreover, the guidance was often applied to statements that are so vague they cannot be falsified. In these cases the impression was often left, quite incorrectly, that a substantive finding was being presented.

Scientific uncertainty is best communicated by indicating the nature, number, and quality of studies on a particular topic, as well as the level of agreement among studies. The level-of understanding scale is a convenient shorthand way of communicating this information in summary documents.

Recommendation: All Working Groups should use the qualitative level-of-understanding scale in their Summary for Policy Makers and Technical Summary, as suggested in IPCC’s uncertainty guidance for the Fourth Assessment Report. This scale may be supplemented by a quantitative probability scale, if appropriate" (IAC Report, p 48).

Management and Governance

The IAC Review is particularly critical about the way IPCC has been managed so far. Part of the problem, as they see it, is that the Panel has grown too quickly beyond its original terms of reference and the initial arrangements may not provide adequate support at the level of complexity and controversy facing the Panel. A permanent Executive Committee and a strengthened Secretariat is amongst the recommendations.

I was particularly interested in the comments on the Conflict of Interest. I quote directly from the Report since they express it in a much more elegant manner that I can do in trying to summarise it:

"A key governance feature of institutions that deal with broad public policy interests is the consideration of conflict of interest (NRC, 2002). The term “conflict of interest” refers to any financial or other interest that compromises the service of an individual by significantly impairing the individual’s objectivity or creating an unfair competitive advantage for any person or organization. Conflict of interest means something more than a strong view or bias—there must be an interest, ordinarily financial, that could be directly affected by the individual’s participation (NAS, 2003).

Many governmental and nongovernmental institutions that carry out scientific assessments or provide scientific advice have adopted conflict of interest and disclosure policies in order to assure the integrity of, and public confidence in, their results.....

The lack of a conflict of interest and disclosure policy for IPCC leaders and Lead Authors was a concern raised by a number of individuals who were interviewed by the Committee or provided written input. Questions about potential conflicts of interest, for example, have been raised about the IPCC Chair’s service as an advisor to, and board member of, for-profit energy companies (Booker and North, 2009; Pielke, 2010b), and about the practice of scientists responsible for writing IPCC assessments reviewing their own work. The Committee did not investigate the basis of these claims, which is beyond the mandate of this review. However, the Committee believes that the nature of the IPCC’s task (i.e., in presenting a series of expert judgments on issues of great societal relevance) demands that the IPCC pay special attention to issues of independence and bias to maintain the integrity of, and public confidence in, its results.

Recommendation: The IPCC should develop and adopt a rigorous conflict of interest policy that applies to all individuals directly involved in the preparation of IPCC reports, including senior IPCC leadership (IPCC Chair and Vice Chairs), authors with responsibilities for report content (i.e., Working Group Co-chairs, Coordinating Lead Authors, and Lead Authors), Review Editors, and technical staff directly involved in report preparation (e.g., staff of Technical Support Units and the IPCC Secretariat)." (IAC Report pp 45-46)

The rest of the Review Report is on implementing a more transparent communications policy for the IPCC and future issues such as the participation of developing nations and private sector in the IPCC deliberations; and the IPCC access to confidential data, e.g. commercial databases.

My Conclusions

I think this is a very strong report. When it was reported in the media, it was seen as an invitation for the IPCC Chair to resign

I welcome the introduction of more rigour and accountability in to the IPCC. The climate change is probably the biggest challenge facing the humanity. The IPCC is the leading agency in formulating responses to this challenge. Anything short of full competence and transparency on the part of the IPCC has the danger of producing doubt on the nature and the size of the climate change challenge. This IAC Review is a step in the right direction and it is a credit to the Review Panel. I guess we will wait and see what will follow.

 

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