http://www.princeton.edu/pei/energy/publications/texts/LarsonYang-China-DME-cooking-ESD-2004.pdf

http://www.aboutdme.org/ DME is the furl of the future for transportation...

World Coal Association Coal to Liquids Emissions Reductions from Synthetic Fuels (Europe) Source: Alliance for Synthetic Fuels in Europe Converting coal to a liquid fuel (CTL) – a process referred to as coal liquefaction – allows coal to be utilised as an alternative to oil. There are two different methods for converting coal into liquid fuels: Direct liquefaction works by dissolving the coal in a solvent at high temperature and pressure. This process is highly efficient, but the liquid products require further refining to achieve high grade fuel characteristics. Indirect liquefaction gasifies the coal to form a ‘syngas’ (a mixture of hydrogen and carbon monoxide). The syngas is then condensed over a catalyst – the ‘Fischer-Tropsch’ process – to produce high quality, ultra-clean products. An array of products can be made via these processes – ultra-clean petroleum and diesel, as well as synthetic waxes, lubricants, chemical feedstocks and alternative liquid fuels such as methanol and dimethyl ether (DME). Where is it Used? South Africa has been producing coal-derived fuels since 1955 and has the only commercial coal to liquids industry in operation today. Not only are CTL fuels used in cars and other vehicles, South African energy company Sasol’s CTL fuels also have approval to be utilised in commercial jets. Currently around 30% of the country’s gasoline and diesel needs are produced from indigenous coal. The total capacity of the South African CTL operations now stands in excess of 160,000bbl/d. CTL is particularly suited to countries that rely heavily on oil imports and that have large domestic reserves of coal. There are a number of CTL projects around the world at various stages of development. Liquid fuels from coal can be delivered from an existing pump at a filling station via existing distribution infrastructure and used, without modification, in the current vehicle fleet. CTL Outside of Transportation Fuels produced from coal also have potential outside the transportation sector. In many developing countries, health impacts and local air quality concerns have driven calls for the use of clean cooking fuels. Replacing traditional biomass or solid fuels with liquefied petroleum gas (LPG) has been the focus of international aid programmes. LPG however, is an oil derivative – and is thus affected by the expense and price volatility of crude oil. Coal-derived dimethyl ether (DME) is receiving particular attention today as it is a product that holds out great promise as a domestic fuel. DME is non-carcinogenic and non-toxic to handle and generates less carbon monoxide and hydrocarbon air pollution than LPG. DME can also be used as an alternative to diesel for transport, as well as for on and off-grid power applications. Benefits of CTL Coal to liquids has a number of benefits: Coal is affordable and available worldwide enabling countries to access domestic coal reserves – and a well-supplied international market - and decrease reliance on oil imports, improving energy security. Coal liquids can be used for transport, cooking, stationary power generation, and in the chemicals industry. Coal-derived fuels are sulphur-free, low in particulates, and low in nitrogen oxides. Liquid fuels from coal provide ultra-clean cooking fuels, alleviating health risks from indoor air pollution Increasing energy demand and rises in vehicle ownership means that it is important for countries to review the balance of their energy supply mix. 96% of all energy used in transport comes from petroleum; it therefore dominates the transport sector. CTL – along with gas-to-liquids (GTL) and biomass-to-liquids (BTL) - allows countries the option of diversifying the liquid fuel supplies. Interest in constructing CTL plants tends to increase when the oil price is high and countries are concerned about the cost of their oil imports. When the oil price drops, the economics of coal to liquids plants are less favourable. GHG Emissions The conversion of any feedstock to liquid fuels is an energy intensive one. Emissions across the entire process have to be considered. While the coal to liquids process is more CO2 intensive than conventional oil refining, there are options for preventing or mitigating emissions. For coal to liquids plants, carbon capture and storage can be a low cost method of addressing CO2 concerns. Where co-processing of coal and biomass is undertaken, and combined with CCS, greenhouse gas emissions over the full fuel cycle may be as low as one-fifth of those from fuels provided by conventional oil. See Also IEA Clean Coal Centre – CTL Report ©2011 World Coal Association

Big Oil says to clean up shale gas business Thu, Dec 8 2011 * Big Oil says to lift shale game standards * Green groups say they heard it before * Companies see room to reduce costs By Tom Bergin DOHA, Dec 8 (Reuters) - Big oil and gas companies say their increasing dominance of shale gas exploration will bring improved drilling practices and should end the safety lapses that have led to environmental opposition to the fast-growing, multi-billion dollar industry. Cases of water contamination and the leakage of flammable methane gas into homes are due to occasionally shoddy activities by some of the small players, who developed the industry over the past decade, rather than fundamental problems with shale gas drilling, some industry executives said. Oil majors such as Exxon Mobil, BP and Royal Dutch Shell Plc have begun to buy up the first movers in the industry. At the World Petroleum Congress (WPC) in Doha this week, big company bosses said they would help the shale industry improve its game. "I think Shell, or for that matter Exxon, coming in a big way into this shale gas operation will actually drive the standards up," Shell Chief Executive Peter Voser told a joint press conference with Exxon CEO Rex Tillerson. Environmentalists said, however, the desire to avoid legislation was likely behind Big Oil's claims of future better practices. "We do not believe this. The large companies violate the law regularly," said Amy Mall, senior policy analyst with the Natural Resources Defense Council in Washington, D.C. The oil and gas industry fears that public opposition will drive increased regulation and restrictions on where it can drill. "Nature has given mankind the gift of natural gas. But our hope now is, 'Please don't let government mess it up'," Jim Mulva, chief executive of ConocoPhillips told the Congress. The industry leaders say their massive research efforts can help ensure the safety of the 'fracking' technique, which involves blasting water, sand and chemicals into deep underground reservoirs to release the gas trapped inside. "I think companies like Exxon, we always put a high priority on technology, so whether that's shale gas or any other resource development, technology is a key part of it for us," Rich Kruger, president of Exxon's production unit, told Reuters. Jack Gerard, president of the American Petroleum Institute, the U.S. oil and gas industry's main trade association, said tough financial constraints on some of the companies that led the shale gas revolution may have contributed to some of the problems associated with drilling. "There's a lot of competitors in the business, and as people are driving those opportunities and looking for opportunities ... it tends to move rapidly, and sometimes they're not thinking of the total consequences," he said. But Erika Staaf, clean water advocate with Philadelphia-based PennEnvironment, said the claim that bad practices would be phased out as so-called "rogue" operators are taken over was not new. "That is a refrain that we've heard again and again," she said. One thing the arrival of the big players to the market is unlikely to bring is additional money. As the business expands, companies are seeking to reduce the amount of spending on drilling. Shell has established a "well manufacturing" joint venture in China, which it hopes will provide more cost-effective means of drilling shale gas wells that can be applied worldwide. Speaking at the WPC, Andrew Gould, chairman of Schlumberger , the world's largest provider of services to the oil industry, said companies had significant opportunities to cut costs. "Current methods are wasteful and expensive," he said.

Shale game by Claire Poole | Published December 9, 2011 at 12:00 PM 121211 YEenergy.jpg Scott Richardson, a co-founding principal of RBC Richardson Barr, has seen a lot in a 25-year career as an energy investment banker. But he's never seen a market like this, with dealmaking veering from busy to quiet to busy again and capital markets swinging open to closed to open. "It's been a schizophrenic market," he told an industry luncheon. What hasn't changed has been the excitement over shale, the sedimentary rock that holds pockets of natural gas and oil that can be extracted through hydraulic fracturing, or fracking. It's led to some pretty big deals with some pretty big prices, most notably BHP Billiton Ltd.'s purchase of Petrohawk Energy Corp. for $15 billion -- a 65% premium. The majors are bolstering their positions. Exxon Mobil Corp. purchased Marcellus Shale explorers TWP Inc. and affiliate Phillips Resources Inc. for $1.7 billion; ConocoPhillips Co. bought 46,000 net acres of leasehold in the Niobrara Shale from Lario Oil & Gas Co. for an undisclosed sum; and Chevron Corp. bought properties in the Marcellus from Enerplus Corp., Chief Oil & Gas LLC and Tug Hill Inc. for $1.8 billion on top of its $4.3 billion purchase of Atlas Energy Inc. In the third quarter, shale plays represented almost half the total oil and gas deal value as companies sought to gain "technology know-how and diversify service offerings," says Rick Roberge, a principal in PricewaterhouseCoopers LLP's energy M&A practice. Following the Chinese, the Japanese are piling in. Itochu Corp. is participating in the $7.2 billion buyout of Samson Investment Co. with Kohlberg Kravis Roberts & Co. LP, Natural Gas Partners and Crestview Partners, while Inpex Corp. and JGC Corp. are buying 40% of Nexen Inc.'s shale properties in British Columbia for $700 million. And Mitsui & Co. Ltd., which was burned in the BP plc oil spill in the Gulf of Mexico, is thought to be Chesapeake Energy Corp.'s $3.4 billion sugar daddy in Ohio's Utica Shale after buying stakes in properties in South Texas' Eagle Ford Shale from SM Energy Co. in June for $750 million and in the Pennsylvania portion of the Marcellus Shale from Anadarko Petroleum Corp. last year for $1.4 billion. The U.S. is producing so much oil and gas that it should become a net petroleum product exporter this year -- the first time in 60 years. Shale gas, which made up 27% of U.S. natural gas production last year, is now at 34% and expected to reach 43% by 2015 and 60% by 2035, according to IHS Inc. And while it remains the early days of pulling oil out of shale, estimates suggest there might be as much as 20 billion barrels of recoverable tight oil just in the U.S. "That is like adding 1-1/2 brand-new Alaska North Slopes, without having to go to work in the Arctic north and without having to build a huge new pipeline," Daniel Yergin writes in his new book, "The Quest: Energy, Security, and the Remaking of the Modern World." "Such reserves could potentially be reaching two million barrels per day of additional production in the U.S. by 2020 that was not even anticipated even half a decade ago." The advent of shale is creating a boom, from the equipment and technology needed to get oil and gas out of the ground to ancillary services -- water, chemicals, housing and people -- to storage, processing and transportation. That drove Superior Energy Services Inc.'s $2.7 billion deal for Complete Production Services Inc., Kinder Morgan Inc.'s $37.8 billion acquisition of El Paso Corp. and Crestview-backed Select Energy Services' rollup of water companies. While private equity has become entrenched in shale, some firms are instead investing in conventional natural gas, such as TPG Capital's $1 billion commitment to Maverick American Natural Gas LLC. Denham Capital Management LLP, whose Ursa Resources Group LLC sold its properties in the Bakken Shale, is now backing Ursa management's forays into conventional oil and natural gas. Maybe their investments have reached the end of their life cycle. Maybe they fear stronger regulation after cries from environmentalists. Or maybe they're just getting out while the getting's good. Read more: Shale game - The Deal Pipeline (SAMPLE CONTENT: NEED AN ID?) http://www.thedeal.com/magazine/ID/043314/features/shale-game.php#ixzz1g9EMHWd9

http://blogs.ft.com/beyond-brics/2011/12/09/chart-of-the-week-the-scale-of-shale/#axzz1g9DUd5hA High quality global journalism requires investment. Please share this article with others using the link below, do not cut & paste the article. See our Ts&Cs and Copyright Policy for more detail. Email ftsales.support@ft.com to buy additional rights. http://blogs.ft.com/beyond-brics/2011/12/09/chart-of-the-week-the-scale-of-shale/#ixzz1g9E0OKwC This week PetroChina discovered shale gas in China’s Sichuan province. How significant is this find for China’s energy supply and how does it compare to shale and natural gas reserves in other countries? Chart of the week takes a look behind the figures to get a better idea. Let’s leave aside the costs of extraction. Not all gas reserves are created equal. And we will also avoid the debate on fracking – which is controversial to say the least, and may be banned in several countries. Purely on a reserves basis, how big a deal is shale gas in China? Well, it’s the country with the largest technically recoverable shale gas reserves in the world and, of course, is the country with the largest energy consumption (in absolute terms, that is – in per capita terms China is still way behind the US). (* UPDATE: this paragraph has been changed. See below for correction details). So shale could be a big source of energy for China. But how does it compare to natural gas reserves? The chart below shows the countries with the largest shale gas resources, compared to their natural gas reserves, with the top four natural gas producers included for comparison. Russia has the most natural gas in the world – nearly a quarter of the world’s reserves, in fact. But China’s shale gas would put it between Russia and Iran, the country with the second-highest reserves. Shale could be very big. In fact, shale could be big for lots of countries – the shale reserves of the US, Argentina, Mexico, South Africa, Australia, Canada and Libya are all potentially bigger than the fourth-biggest country for natural gas, Saudi Arabia. Shale is also a big deal for these countries compared to natural gas. For countries with shale gas resources, only the Netherlands and Venezuela have bigger natural gas reserves than shale. Venezuela has the world’s largest oil reserves according to some estimates, so shale is a distant third to oil and natural gas anyway. But for many emerging markets – China, Argentina, Mexico and South Africa especially – the scale of the shale reserves is, potentially, a game changer. If you can extract it. Reserves vs Resources Sources: EIA, CIA World Factbook * The original version of this post said that the shale gas reserves were proven – this was incorrect, it should have said technically recoverable, as per the EIA website. For a full explanation, see the paragraph “Technically Recoverable Resource” on the EIA website. The chart was also changed to reflect this. Related reading: PetroChina finds shale gas reserves, FT Malaysia: Petronas strikes $1.1bn shale gas deal in Canada, beyondbrics Shale reserves: Gas seen as bridge between old and new forms of power, FT

Anyone involved in long-term grid planning should prepare for lots of natural gas generation. And perhaps for less renewables than expected. Coal has long been the leading fuel for generating electricity, but that will change by 2025, according to forecasts from Exxon Mobil as reported in the Wall Street Journal. The study forecasts that coal will continue to grow (primarily in China and India) but that natural gas will grow even faster. Smart grid, smart grid renewables, electric utilities, natural gas, energy resources, Exxon Mobil The discovery of major reserves and the drop in natural gas prices is also affecting thoughts about renewable energy. Natural gas is cleaner that other fossil fuels and, these days, it is quite inexpensive, making it harder for renewables to compete on cost. Natural gas is more "grid-friendly" than renewables, which require a smarter grid to deal with their constant fluctuations. Right on cue, New Jersey Governor Chris Christie approved an "energy master plan" for the state that reduces the use of solar and wind in favor of natural gas (and nuclear). A 2008 plan called for 30% renewables by 2020. The new plan scales that back to 22.4%. 1 Jesse Berst is the founder and chief analyst of Smart Grid News.com. He consults to smart grid companies seeking market entry advice and M&A advisory. A frequent keynoter at industry events in the US and abroad, he also serves on the Advisory Council of Pacific Northwest National Laboratory's Energy & Environment directorate.

A California real estate services company is joining a coal-to-gasoline project in West Virginia's southern coalfields. Los Angeles-based CB Richard Ellis will help the developer, TransGas Development Systems, negotiate contracts and raise money for the $3 billion project. TransGas President Adam Victor announced CB Richard Ellis' participation in the project today at the fifth annual Governor's Energy Summit at Stonewall Resort. Victor says he expects financing for the project to be raised within 270 days. TransGas announced the project in 2008. The plant would convert 7,500 tons of coal per day into gasolin

Natural gas liquid production in USA to increase over 40% by 2016 (17-11-2011) US gas plant natural gas liquids (NGL) production is expected to increase more than 40% over the next five years, as per a joint market study from BENTEK Energy and Turner, Mason & Company (TM&C). The increase will total approximately 950,000 b/d, with volumes reaching at least 3.1 MMb/d by 2016. At the same time, crude production from the U.S. and Canada will grow by more than 2.8 MMb/d, further impacting NGL supplies as crude quality changes and new refinery upgrading capacity comes online. Current levels of NGL infrastructure are inadequate to handle the surge in NGL production and significant new investment is needed to relieve bottlenecks. The study finds that as a result of excess NGL supply, transportation constraints and demand limitations, the North American NGL and crude oil markets will experience wide and volatile regional price differentials during the next few years. “The shale revolution is having a dramatic effect on the NGL market in North America, and that in turn is driving changes in all aspects of the market, ranging from production, processing, fractionation and transportation to the petrochemical industry,” noted BENTEK Vice President E. Russell (Rusty) Braziel. “At the same time NGL production from gas processing is surging, the U.S. refining industry is in the middle of a significant capital program to accommodate a changing crude slate, which will present still more challenges and opportunities to the NGL market,” added TM&C Senior Vice President John Auers. “Traditional supply/demand relationships for each NGL product are being transformed by these developments.” The rise in NGL supply has the potential to wreak havoc on the NGL market, the study reports. Surplus ethane volumes from the anticipated increases will outpace demand from the U.S. petrochemical industry until new ethylene units are completed. Propane supply is increasing while demand in the home heating sector is down, putting a premium on marine dock space for shipment of incremental supply to offshore markets. Butanes will see wider summer-winter swings in supply, demand and prices. Additionally, natural gasoline will increasingly flow into the diluent market for Canadian heavy crude and could experience a dramatic decline in motor gasoline blending if certain Environmental Protection Agency (EPA) vapor pressure and octane regulations are implemented.

marketwire Sign In Register Français Channel M Blog Contact Marketwire Communication Solutions News Room Knowledge Sharing For Journalists and Bloggers News Room twitter facebook linkedin digg stumbleupon Email Print Friendly Share SOURCE: Carbon Sciences Inc. November 09, 2011 03:01 ET Carbon Sciences Announces Complete Gas to Liquids Solution Company Will Now Offer a Complete, End-to-End Gas to Liquids (GTL) Plant Technology License and Support Services to the Natural Gas Industry SANTA BARBARA, CA--(Marketwire - Nov 9, 2011) - Carbon Sciences Inc. (OTCBB: CABN), the developer of a breakthrough technology to make liquid transportation fuels from natural gas and carbon dioxide, today announced that the company will now offer a complete, end-to-end GTL plant technology license and support services to the natural gas industry. The commercial viability of GTL technology has been proven by some of the largest oil & gas companies in the world. After investing $19 billion in a world scale GTL plant in the State of Qatar and creating more than 52,000 jobs, Royal Dutch Shell announced the first commercial shipment of GTL fuel products on June 13, 2011. Named Pearl GTL, the plant is capable of producing 260,000 barrels per day of oil equivalent products using only natural gas instead of crude oil. According to Shell, Pearl GTL will produce enough liquid fuels to fill over 160,000 cars a day and enough synthetic base oil each year to make lubricants for more than 225 million cars. More recently in September 2011, Sasol, the South African energy and chemical giant, announced plans to build the first United States GTL plant in Louisiana to produce GTL transportation fuels and other products. The Sasol project is expected to cost $10 billion and will create over 5,000 new high-paying direct and indirect jobs. Byron Elton, CEO of Carbon Sciences, commented, "The days of cheap, easy oil have passed, and the era of natural gas is upon us. We recently attended the annual GTL conference in London to meet with industry colleagues and congratulate Shell on its history making GTL success. The consensus at the conference was that oil prices will remain strong and natural gas prices are expected to remain low, leading to a lucrative future for gas to liquids technology. Forecasts show that total recoverable global natural gas resources will last over 250 years. Shell, Sasol and others in our industry have proven the economics of GTL technology that will free us from crude oil by tapping into the vast reserves of natural gas to power the needs of the world." Mr. Elton continued, "At the scale that Shell operates, it must focus on very large fields, which account for only a small number of gas fields in the world. Its particular GTL technology does not scale down economically for small and medium sized gas fields. This is the market opportunity that we are addressing with our end-to-end GTL solution." A typical GTL plant consists of three core components: 1) syngas generation, which converts natural gas into syngas, 2) Fischer-Tropsch processing, which converts syngas into hydrocarbons, and 3) liquid fuels upgrading, which converts hydrocarbons to liquid fuels such as gasoline, diesel, and jet fuel. It is generally accepted in the industry that the syngas portion of a GTL plant is the most expensive. Carbon Sciences' proprietary catalyst technology is aimed at reducing the cost of syngas production by eliminating the expensive requirements for oxygen and steam. Instead, the company's syngas technology uses freely available carbon dioxide to react with natural gas. To provide a complete GTL technology solution, Carbon Sciences will integrate its proprietary syngas technology with Fischer-Tropsch technology and liquid fuels upgrading technology licensed from other companies to deliver an end-to-end GTL plant design. This complete solution will be available for licensing to the natural gas industry for use in small to medium size GTL plants. Carbon Sciences will begin the commercial process by offering pre-feasibility and feasibility study services. "We are very excited about our expanded business plan and we look forward to delivering value directly to the owners of natural gas resources," concluded Mr. Elton. "While we believe our unique syngas technology will ultimately benefit world scale GTL plants, such as Shell's Pearl GTL, our initial target market is small to medium size gas fields. This focus will allow us to address a market ignored by the big players with billion dollar budgets." About Carbon Sciences Inc. Carbon Sciences has developed a breakthrough technology to make liquid transportation fuels from natural gas. We believe our technology will enable the world to reduce its dependence on petroleum by cost effectively using natural gas to produce cleaner and greener liquid fuels for immediate use in the existing transportation infrastructure. Although found in abundant supply at affordable prices in the U.S. and throughout the world, natural gas cannot be used directly in cars, trucks, trains and planes without a massive overhaul of the existing transportation infrastructure. Innovating at the forefront of chemical engineering, Carbon Sciences offers a highly scalable, clean-tech gas-to-liquids (GTL) process to transform natural gas into transportation fuels such as gasoline, diesel and jet fuel. The key to this cost-effective process is a breakthrough methane dry reforming catalyst that consumes carbon dioxide. Our proprietary catalyst is now undergoing rigorous commercial testing to meet the needs of the natural gas industry and will be available for use in pre-feasibility studies of new GTL plants. To learn more about Carbon Sciences' breakthrough technology, please visit www.carbonsciences.com and follow us Facebook at http://www.facebook.com/carbonsciences. Safe Harbor Statement Matters discussed in this press release contain statements that look forward within the meaning of the Private Securities Litigation Reform Act of 1995. When used in this press release, the words "anticipate," "believe," "estimate," "may," "intend," "expect" and similar expressions identify such statements that look forward. Actual results, performance or achievements could differ materially from those contemplated, expressed or implied by the statements that look forward contained herein, and while expected, there is no guarantee that we will attain the aforementioned anticipated developmental milestones. These statements that look forward are based largely on the expectations of the Company and are subject to a number of risks and uncertainties. These include, but are not limited to, risks and uncertainties associated with: the impact of economic, competitive and other factors affecting the Company and its operations, markets, product, and distributor performance, the impact on the national and local economies resulting from terrorist actions, and U.S. actions subsequently; and other factors detailed in reports filed by the Company. Contact Information Press Contact: Jerry Schranz Beckerman One University Plaza, Suite 507 Hackensack, New Jersey 07601 Email Contact Office: (201) 465-8020 twitter facebook linkedin digg stumbleupon Email Print Friendly Share News Room View Related News About this company Carbon Sciences Inc. From this industry Automotive Energy and Utilities Environment Government Manufacturing and Production Transportation and Logistics From this sub-industry Cars Trucks Alternative Energy Oil and Gas Air Pollution Control Regulations and Law State Mining and Metals Public Transportation Trucking See all RSS Newsfeeds marketwire About Marketwire Site Map Privacy US: 1.800.774.9473 Canada: 1.888.299.0338 UK: +44.20.7220.4500 Follow Marketwire twitter facebook youtube rss linkedin © 2011 Marketwire, Incorporated. All rights reserved.

http://www.worldenergysource.com/articles/pdf/economides_we_v8n1.pdf

Gas to liquids Natural gas can be use to produce bulk petrochemicals, including methanol and ammonia, but these are relatively small users of the gas reserves with limited markets. Liquid and other petroleum products are cheaper to transport, market, distribute to large markets. These can be moved in existing pipelines or products tankers and even blended with existing crude oil or product streams. Further, no special contractual arrangements are required for their sale with many suitable domestic and foreign markets. New technology is being developed and applied to convert natural gas to liquids in gas to liquids technology (GTL). The projects are scalable, allowing design optimisation and application to smaller gas deposits. The key influences on their competitiveness are the cost of capital, operating costs of the plant, feedstock costs, scale and ability to achieve high utilisation rates in production. As a generalisation however, GTL is not competitive against conventional oil production unless the gas has a low opportunity value and is not readily transported. GTL not only adds value, but capable of producing products that could be sold or blended into refinery stock as superior products with less pollutants for which there is growing demand. Reflecting its origins as a gas, gas to liquids processes produces diesel fuel with an energy density comparable to conventional diesel, but with a higher cetane number permitting a superior performance engine design.[1] Another “problem” emission associated with diesel fuel is particulate matter, which is composed of unburnt carbon and aromatics, and compounds of sulfur. Fine particulates are associated with respiratory problems, while certain complex aromatics have been found to be carcinogenic. Low sulfur content, leads to significant reductions in particulate matter that is generated during combustion, and the low aromatic content reduces the toxicity of the particulate matter reflecting in a worldwide trend towards the reduction of sulfur and aromatics in fuel. 1.1.1 Technology It is technically feasible to synthesise almost any hydrocarbon from any other; and in the past five decades several processes have been developed to synthesise liquid hydrocarbons from natural gas. There are two broad technologies for gas to liquid (GTL) to produce a synthetic petroleum product, (syncrude): a direct conversion from gas, and an indirect conversion via synthesis gas (syngas)[2]. The direct conversion of methane, (typically 85 to 90 per cent of natural gas), eliminates the cost of producing synthesis gas but involves a high activation energy and is difficult to control. Several direct conversion processes have been developed but none have been commercialised being economically unattractive. Methanex is working with catalyst producer Synetix, an ICI subsidiary, and engineering firm ABB Lummus Global to develop and commercialise a synthesis gas process. Indirect conversion can be carried out via Fischer-Tropsch (F-T) synthesis or via methanol. 1.1.2 Fischer-Tropsch The discovery of F-T chemistry in Germany dates back to the 1920s and its development has been for strategic rather than economic reasons, as in Germany during World War II and in South Africa during the apartheid era. Mobil developed the "M-gasoline" process to make gasoline from methanol implemented in 1985 in a large integrated methanol-to-gasoline plant in New Zealand. The New Zealand plant was a technical success but produced gasoline at costs above $30 per barrel and required large subsidies from the New Zealand government. Syngas The syngas step converts the natural gas to hydrogen and carbon monoxide by partial oxidation, steam reforming or a combination of the two processes. The key variable is the hydrogen to carbon monoxide ratio with a 2:1 ratio recommended for F-T synthesis. Steam reforming is carried out in a fired heater with catalyst-filled tubes that produces a syngas with at least a 5:1 hydrogen to carbon monoxide ratio. To adjust the ratio, hydrogen can be removed by a membrane or pressure swing adsorption system. Helping economics is if the surplus hydrogen is used in a petroleum refinery or for the manufacture of ammonia in an adjoining plant. The partial oxidation route provides the desired 2:1 ratio and is the preferred route in isolation of other needs.[3] There are two routes: one uses oxygen and produces a purer syngas without nitrogen; the other uses air creating a more dilute syngas. However, the oxygen route requires an air separation plant that increases the cost of the investment. 1.1.3 Conversion Conversion of the syngas to liquid hydrocarbon is a chain growth reaction of carbon monoxide and hydrogen on the surface of a heterogeneous catalyst. The catalyst is either iron- or cobalt-based and the reaction is highly exothermic. The temperature, pressure and catalyst determine whether a light or heavy syncrude is produced. For example at 330C mostly gasoline and olefins are produced whereas at 180 to 250C mostly diesel and waxes are produced. There are mainly two types of F-T reactors. The vertical fixed tube type has the catalyst in tubes that are cooled externally by pressurised boiling water. For a large plant, several reactors in parallel may be used presenting energy savings. The other process is uses a slurry reactor in which pre-heated synthesis gas is fed to the bottom of the reactor and distributed into the slurry consisting of liquid wax and catalyst particles. As the gas bubbles upwards through the slurry, it is diffused and converted into more wax by the F-T reaction. The heat generated is removed through the reactor's cooling coils where steam is generated for use in the process. 1.2 Commercial examples 1.2.1 Sasol Sasol is a synfuel technology supplier established to provide petroleum products in coal-rich but oil-poor South Africa. The firm has built a series of Fischer-Tropsch coal-to-oil plants, and is one of the world's most experienced synthetic fuels organisations and now marketing a natural-gas-to-oil technology. It has developed the world's largest synthetic fuel project, the Mossgas complex at Mossel Bay in South Africa that was commissioned in 1993 and produces a small volume of 25 000 barrels per day. To increase the proportion of higher molecular weight hydrocarbons, Sasol has modified its Arge reactor to operate at higher pressures. Sasol has commercialised four reactor types with the slurry phase distillate process being the most recent. Its products are more olefinic than those from the fixed bed reactors and are hydrogenated to straight chain paraffins. Its Slurry Phase Distillate converts natural gas into liquid fuels, most notably superior-quality diesel using technology developed from the conventional Arge tubular fixed-bed reactor technology.[4] The resultant diesel is suitable as a premium blending component for standard diesel grades from conventional crude oil refineries. Blended with lower grade diesels it assists to comply with the increasingly stringent specifications being set for transport fuels in North America and Europe.[5] The other technology uses the Sasol Advanced Synthol (SAS) reactor to produce mainly light olefins and gasoline fractions. Sasol has developed high performance cobalt-based and iron based catalysts for these processes. The company claims a single module or the Sasol Slurry Phase Distillate plant, that converts 100 MMscfd (110 terajoules per day of gas) of natural gas into 10 000 barrels a day of liquid transport fuels, that can be built at a capital cost of about US$250 million. This cost equates to a cost per daily barrel of capacity of about US$25 000 including utilities, off-site facilities and infrastructure units. [6] If priced at US$0.50/MMBtu, the gas amounts to a feedstock cost of US$5 per barrel of product. The fixed and variable operating costs (including labour, maintenance and catalyst) are estimated at a further US$5 per barrel of product, thereby resulting in a direct cash cost of production of about US$10 a barrel (excluding depreciation). These costs should however be compared with independent assessments. In June 1999, Chevron and Sasol agreed to an alliance to create ventures using Sasol's GTL technology. The two companies have conducted a feasibility study to build a GTL plant in Nigeria that would begin operating in 2003. Sasol reportedly also has been in discussions with Norway's Statoil, but no definitive announcements have been made. 1.2.2 Statoil With its large gas reserves, Norway's Statoil has been developing catalysts and process reactors for an F-T process to produce middle distillates from natural gas. The Statoil process employs a three-phase slurry type reactor in which syngas is fed to a suspension of catalyst particles in a hydrocarbon slurry which is a product of the process itself. The process continues to be challenged by catalyst performance and the ability to continuously extract the liquid product. 1.2.3 Shell Shell has carried out R&D since the late 1940s on the conversion of natural gas, leading to the development of the Shell Middle Distillate Synthesis (SMDS) route, a modified F-T process. But unlike other F-T synthesis routes aimed at gasoline as the principal product, SMDS focuses on maximising yields of middle distillates, notably kerosene and gas oil. Shell has built a 12 000 bbl/day plant in 1993 in Bintulu, Malaysia. The process consists of three steps: the production of syngas with a H2:CO ratio of 2:1; syngas conversion to high molecular weight hydrocarbons via F-T using a high performance catalyst; and hydrocracking and hydroisomerisation to maximise the middle distillate yield. The products are highly paraffinic and free of nitrogen and sulfur. Shell is investing US$6 billion in gas to liquids technologies over 10 years with four plants. It announced in October 2000, agreement with the Egyptian government for a 75 000 bbl per day (3.8 million tpa) facility and a similar plant for Trinidad & Tobago. In April 2001, it announced interest for plants in Australia, Argentina and Malaysia at 75 000 bbls/day costing US$1.6 billion. 1.2.4 Exxon Exxon has developed a commercial F-T system from natural gas feedstock. Exxon claims its slurry design reactor and proprietary catalyst systems result in high productivity and selectivity along with significant economy of scale benefits. Exxon employs a three-step process: fluid bed synthesis gas generation by catalytic partial oxidation; slurry phase F-T synthesis; and fixed bed product upgrade by hydroisomerisation. The process can be adjusted to produce a range of products. More recently, Exxon has developed a new chemical method based on the Fischer-Tropsch process, to synthesise diesel fuel from natural gas. Exxon claims better catalysts and improved oxygen-extraction technologies have reduced the capital cost of the process, and is actively marketing the process internationally.[7] 1.2.5 Liquid derivatives Made from gas, the high molecular weight liquid gas-to-liquid products can be hydro-cracked in a simple low-pressure process to produce naphtha, kerosene and diesel that is virtually free of sulfur and aromatics.[8] These derivative fuels are therefore potentially more valuable, notably in the US, Europe and Japan with high environmental standards. 1.2.6 Syntroleum The Syntroleum Corporation of the USA is marketing an alternative natural-gas-to-diesel technology based on the F-T process. It is claimed to be competitive as it has a lower capital cost due to the redesign of the reactor; using an air-based autothermal reforming process instead of oxygen for synthesis gas preparation to eliminate the significant capital expense of an air separation plant; and high yields using their catalyst. It claims to be able to produce synthetic crude at around $20 per bbl. The syncrude can be further subjected to hydro-cracking and fractionation to produce a diesel/naphtha/kerosene range at the user’s discretion. The company indicates its process has a capital cost of around $13 000 per daily barrel of diesel for a 20 000 to 25 000 barrel per day facility and an operating cost of between $3.50 to $5.70 per barrel.[9] The thermal efficiency of the Syntroleum process is reported to be about 60 percent, implying a requirement for about 90 million cubic feet (85 terajoules) per day of dry gas for a $300 to $350 million, 25 000 barrel per day capacity facility. These figures therefore suggests a unit cost of less than $20 per barrel ($3.20 per gigajoule) of diesel fuel. The company claims the required economic scale would be smaller if based on LNG. Syntroleum Corporation now also licenses its proprietary process for converting natural gas into other synthetic crude oils and transportation fuels. In February 2000, Syntroleum Corporation announced its intention to construct a 10 000 barrel per day (requiring 130 terajoules/day or 800 000 tonnes per year of gas) natural gas-to-liquids plant for the state of Western Australia to become the first location in the world to acquire full access to Syntroleum technology. The project plans to produce synthetic specialty hydrocarbons (polyalphaolefins lubricating oils), naphtha, normal paraffins and drilling fluids.[10] It is estimated to cost US$500 million generating sales of around US$200 million per year at constant prices. The process is designed for application in plant sizes ranging from 2 000 barrels per day to more than 100 000 barrels per day. Current licensees include ARCO, Enron, Kerr-McGee, Marathon, Texaco, Repsol-YPF and Australia. The company has advised that it is "working on development plans" for gas-to-liquids specialty chemicals plant and is working with DaimlerChrysler to develop super-clean synthetic transportation fuels. The project is helped by $60 million of Australian government funding.[11] The small scale of the proposed plant is because the autothermal partial oxidation with air and a once-through reactor design has not yet been proven. The smaller scale also avoids the marketing risk of placing large volumes of speciality chemicals and waxes in the marketplace dominated by large suppliers such as Sasol and Shell. The appeal of the liquid products, which would be straight chain hydrocarbons, is that they would be free from sulfur, aromatics and metals, that can help refiners to meet new guidelines for very low sulfur fuels and general environmental standards. The naphtha however would be low in octane and requires isomerising or reforming if used as a fuel but represents a good petrochemical feedstock. The diesel will have a very high cetane number and be a premium blending product. For reasons of their purity, these synthetic fuels could also be used for fuel cells instead of methanol. As an alternative to fuels, the waxy portion can be converted to lubricants, drilling fluids, waxes and other high value speciality products. 1.2.7 Rentech Rentech of the Colorado USA, has been developing an F-T process using molten wax slurry reactor and precipitated iron catalyst to convert gases and solid carbon-bearing material into straight chain hydrocarbon liquids. In their process, long straight chain hydrocarbons are drawn off as a liquid heavy wax while the shorter chain hydrocarbons are withdrawn as overhead vapours and condensed to soft wax, diesel fuel and naphtha. It is promoted as suitable for remote and associated gas fields as well as sub-pipeline quality gas. During 2000, the company acquired a 75 000 tonne per year methanol plant in Colorado, USA for conversion into a GTL facility producing 800 to 1000 bbl/day of aromatic free diesel, naphtha and petroleum waxes.[12] The facility, the first in the US will cost about $20m to convert. Significantly, it will cost around 50 per cent less than a greenfield site because the methanol plant includes a synthesis gas generation unit. Start-up is scheduled for mid-2001. 1.2.8 Gasoline production There are two methanol-based routes to gasoline. Mobil's methanol-to-gasoline (MTG) process based on the ZSM-5 zeolite catalyst was commercialised in 1985 in a plant now owned by Methanex in New Zealand. Commercial applications of the MTG process are now anticipated to use a fluid bed reactor with their higher efficiency and lower capital cost. 1.2.9 Outlook Use of GTL for chemicals and energy production is forecast to advance rapidly with increasing pressure on the energy industry from governments, environmental organisations and the public to reduce pollution, including the gaseous and particulate emissions traditionally associated with conventional petroleum-fuelled and diesel-fuelled vehicles. In response there are initiatives worldwide to promote the use of unleaded petroleum in conjunction with a catalytic converter or, alternatively, the use of reformulated, cleaner diesel. One well regarded recent study from Business Communications Co., Inc. estimates total production of GTL to reach $120 billion by 2004, growing 5.5 per cent per year from 1999 to 2004. However, it also clear that the commercial success of GTL technology has not yet been fully established, and returns from GTL projects will depend projections of market prices for petroleum products and presumed price premiums for the environmental advantages of GTL-produced fuels. Unit production costs will reflect the cost of the feedstock gas; the capital cost of the plants; marketability of by-products such as heat, water, and other chemicals (e.g., excess hydrogen, nitrogen, or carbon dioxide); the availability of infrastructure; and the quality of the local workforce. 1.2.10 Cost competitiveness Clearly too, the feedstock gas cost will have an influence as it may vary widely depending on alternative applications. Using gas that otherwise would be flared with zero (or even negative costs by avoiding penalties for violations of environmental regulations or increased costs related to compliance with environmental restrictions) would help the production economics. As one indication, based on current efficiencies, a change in the cost of gas feedstock of $0.50 per thousand cubic feet (per one gigajoule) would shift the synthetic crude oil price around $5 per barrel. This is predicated on that in general the processes requires about 10.5 gigajoules of gas to produce 1 bbl or fuel with variations depending on scale, quality of output and variable production costs traded off against capital costs. Shell estimates (2001) that a GTL plant processing 600 000 standard cubic feet (0.7 terajoule) of gas per day would cost 60 per cent more than an LNG plant but the readily used products makes LNG cheaper than LNG. 75 000 bbl/day would cost around US$1.6 billion. Capital costs for GTL projects currently tend to be in a range of double that of refineries, of between $20 000 and $30 000 per daily barrel of capacity (compared with refinery costs of $12 000 to $14 000 per daily barrel), and the cost of GTL-produced fuel could vary by approximately $1.50 per barrel with a shift of $5 000 in capital cost.[13] Estimates of the crude oil prices necessary to allow positive economic returns from a GTL project vary widely, with optimistic estimates ranging as low as $14 to $16 per barrel. More typical estimates indicate that expected oil prices would have to average over $20 per barrel on a sustained basis to lead to commitments for large-scale projects.[14] Presently there are only three GTL facilities have operated to produce synthetic petroleum liquids at more than a demonstration level: the Mossgas Plant (South Africa), with output capacity of 23 000 barrels per day, Shell Bintulu (Malaysia) at 20 000 barrels per day and the subsidised methanol to gasoline project in New Zealand.[15] A joint project in Nigeria of Chevron and Sasol Ltd has been announced with a 30 000 barrel per day plant that would cost $1 billion using the Sasol Slurry Phase Distillate process. It is expected to begin operations in 2003 at costs claimed to be competitive with crude oil prices around $17 per barrel.[16] The Nigeria project will benefit from the infrastructure already in place for nearby oil and gas production and export facilities, although it is unclear whether, or to what extent, subsidies or other considerations helped to lower the estimated costs.[17] Sasol has formed a Fischer-Tropsch technology alliance with Statoil of Norway in 1997 to evaluate the economic conversion of associated gas into synthetic crude oil at the point of production obviating the need to flare or reinject associated gas. It is developing barge-mounted gas-to-oil plants that can be floated into place over small natural gas deposits. Sasol claims that its process can produce middle distillates at a capital cost of $30 000 per daily barrel, with operating costs of $5 per barrel (excluding feedstock costs) and a thermal efficiency of 60 percent. An USA Energy information administration assessment of a hypothetical GTL project estimated the cost of GTL fuel at almost $25 per barrel.[18] It is relevant to note that, one US oil company has estimated a $5 per bbl penalty in extra refining investment to make a fuel meeting the new low (CARB’s) ultra-low-aromatics and low in sulfur. While the U.S. Department of Energy estimates that F-T diesel could fetch as much as an $8 to $10 a barrel premium. 1.2.11 Assessment Under conditions that may be considered reasonable, a GTL project with present technology could be cost competitive with crude oil prices around $25 per barrel but any shifts in the key cost factors could significantly raise the competitive price. This uncertainty about world oil prices, rather than the technology has served to limit GTL investment. GTL fuels used for transport should attract in theory a premium price as they have been shown to reduce vehicle exhaust emissions.[19] The extent of that premium will be dependent on the outlook of environmental legislation in key markets. Given the precedent set with the growing demand for LNG largely for stationary applications, demand for GTL fuels should be anticipated to grow firmly, notably for diesel fuels with the growing emphasis and legislation for low sulfur and aromatic fuels in Europe and the US. Another environmentally motivated advantage of GTL technology relates to the concern in some countries about the disposition of gas produced in combination with crude oil (called associated-dissolved, or AD, gas). Without local use or infrastructure to ship it to markets, AD gas often is flared or vented into the air, releasing greenhouse gases such as methane and carbon monoxide. A GTL project can use gas that would otherwise be vented or flared as a feedstock. In any event, small isolated gas fields would be ideal applications for this technology given the lower capital cost for the establishment of GTL plant and infrastructure An often perceived impediment to GTL technology is that it is considered an alternative competitor to LNG projects. However, for very large gas deposits, the two technologies can be applied on a complementary rather than competitive development basis. Joint development of GTL and LNG projects would allow for shared labour and infrastructure, reducing the costs to both projects and accelerating the development of an LNG projects. Indeed, Syntroleum (see earlier) claims GTL based on LNG feedstock has a lower operating cost, or can be produced at smaller scale to be competitive. However, clearly, its main appeal is the ability to utilise stranded gas or gas otherwise flared. Given the investments around the world in GTL projects and the firming crude oil prices in excess of $20 per barrel, the evidence is that the GTL industry is on the starting blocks. Extensive research and refinements of technology, is pointing to reductions in operating costs. With its synergy to LNG projects, as already evidenced by an intended investment in Western Australia, GTL technology appears to be at the point of viability and most notably for high viscosity lube oil base stocks and for fuels in environmentally sensitive markets. Clearly too, the economics of production are helped by integration not only with an LNG project, but also with other syngas projects notably methanol and ammonia. The co-production of alpha-olefins, another alternative user of syngas, would also assist the economics of its production. Economic rate of return US$/Gj or /mmBTU 22 $0.3 18 $0.5 15 0.8 Source: BP. For a US$20,000/bpd GTL plant with crude at US$21/bbl and syncrude at US$25/bbl Small plant Mid size plant Large plant Capacity (bpd) 5000 30 000 50 000 Gas conversion rate (mcf/bbl)>13 11 <10 Gas required (Tj/d) 70 350 500 Min reserve for 20 years (Tcf) 0.5 3 5 Typical cost (A$) 400m 1700m 2600m Source: BP Statistical Review of World Energy. horizontal rule [1] The Cetane Number indicates how quickly the fuel will auto-ignite, and how evenly it will combust. Most countries require a minimum cetane number of around 45 to 50: A higher cetane number represents a lower flame temperature, providing a reduction in the formation of oxides of nitrogen (NOx) that contributes to urban smog and ground level ozone. Fischer-Tropsch diesel has a cetane number in excess of 70. Naphtha produced is sulfur free and contains a high proportion of paraffinic material suitable as cracker feedstock or the manufacture of solvents. [2] Synthesis gas is produced by reacting methane (or carbon) with steam at elevated temperatures to yield a useful mixture of carbon oxides and hydrogen. It can be produced by a variety of processes and feedstocks. It may require the indicated compositional adjustment and treatment before use in the following major applications: ° Directly used for methanol synthesis. The dried syngas can be used without further adjustment since there is a net conversion of both CO and CO2 to methanol. ° Ammonia synthesis gas, requiring maximum hydrogen production and removal of oxygen-bearing compounds. ° Oxo synthesis gas, requiring composition adjustment and CO2 removal to give a 1:1 H2:CO synthesis gas. ° Industrial gases, as a source of high purity CO, CO2 or H2, ° Reducing gas, a mixture of CO and H2 requiring CO2 removal before being used to reduce oxides in ores to base metals. ° Fuels either as a substitute fuel gas from a liquid or solid feedstock, or as an intermediate for Fischer-Tropsch or zeolite-based alternative liquid fuel technologies. [3] The steam reforming process produces a syngas of H2:CO ratio of about 3:1 with the surplus H2 that can be separated by a hollow fibre membrane process. Evaluations suggest the partial oxidation would be the preferred route when the surplus H2 from the steam reforming process has to be disposed of at fuel value. Under these conditions, the product value of syngas by partial oxidation is lower than steam reforming. The partial oxidation process is also slightly less capital intensive. [4] In the Sasol Slurry Phase reactor, preheated synthesis gas is fed to the bottom of the reactor where it is distributed into the slurry consisting of liquid wax and catalyst particles. As the gas bubbles upward through the slurry, it diffuses into the slurry and is converted into more wax by the Fischer-Tropsch reaction. The heat generated from this reaction is removed through the reactor's cooling coils, which generate steam and the lighter, more volatile fractions leave in a gas stream from the top of the reactor. [5] New US Environmental Protection Agency (EPA) standards for drastically reduced sulphur content in diesel fuel could impact US chemicals production and markets. The EPA is legislating to reduce the sulphur content in highway diesel fuel from the 500 parts/million (ppm) sulphur to 15 (ppm) in current diesel fuels. [6] Sasol lower costs can be achieved with larger capacity with two or more modules in parallel. [7] "Gas to Oil: A Gusher for the Millennium," Business Week (May 19, 1997). This article suggests that the cost of synthetic diesel fuel would be on the order of $20 per barrel and "perhaps as low as $15 per barrel." [8] Some cetane is sacrificed by light isomerisation to improve low temperature behaviour of the products. [9] M.A. Agee, "Convert Natural Gas into Clean Transportation Fuels," Hart's Fuel Technology & Management (March 1997), pp. 69-72. [10] It will be owned by a subsidiary called Syntroleum Sweetwater in which Enron Corporation and Methanex Corporation are equity participants to be located approximately 4 kilometres from the North West Shelf Joint Venture LNG Plant in the north west of the state. Since then Methanex expressed interest in a proposed methanol project for the Northern Territory in Australia. [11] The Western Australian State Government will provide $20 million in a general infrastructure package including roadways and a desalinisation plant (to provide the cooling water). The Commonwealth Government has acquired a license for $15 million plus lending the company A$25 million 25 year loan to support R&D in Australia. Under the terms, Syntroleum has agreed to work with approved Australian Universities and research institutions towards advancing GTL technologies. This arrangement provides a reduced royalty structure for this technology and is therefore a sophisticated form of assistance tied to success. [12] It can also produce hydrogen for stationary fuel cell applications and generate 100-150MW of surplus power. [13] Capital costs are from Howard, Weil, Labouisse, and Friedrichs, Inc., Fischer-Tropsch Technology (Houston, TX, December 18, 1998), p. 44. Cost impacts were estimated by EIA’s Office of Oil and Gas, based on analysis in Cambridge Energy Research Associates, New Developments in Gas-to-Liquids Technology: Fundamental Change or Just a Niche Role? (Cambridge, MA, August 1997). [14] Cambridge Energy Research Associates, “Gas-to-Liquids” Two Years Later—Still Just a Niche Opportunity? (Cambridge, MA, October 1999). [15] Gas-to-Liquids At-a-Glance Reference Guide 1999,” Hart Gas-to-Liquids News, in association with Syntroleum. [16] Assumptions behind this estimated price level include feedstock gas at $0.50 per million Btu (considered the rough equivalent of $5 per barrel of crude oil, or less at strict Btu equivalence), capacity costs of $25,000 per daily barrel, and operating costs of $5 per barrel. Source: “Advanced Technology Puts Sasol in GTL Driver’s Seat,” Gas-to-Liquids News (July 1999), p. 6. [17] A memorandum of understanding between Sasol, Qatar General Petroleum Corporation and Phillips Petroleum Company was signed in 1997 for the proposed construction of a Sasol Slurry Phase Distillate process facility. The envisaged, twin-train Sasol Slurry Phase Distillate plant would be built at Ras Laffan in north-east Qatar to produce 20 000 barrels of liquid transport fuels a day. [18]The US government agency used a capital cost of $10.48 per barrel ($25,000 per daily barrel over 12 years at a 12 per cent discount rate), an operating costs of $5.50 per barrel and feedstock costs equivalent to $8.92 per barrel of crude oil (including conversion losses of 35 percent). [19] In one test in the US ,100-percent synthetic diesel used in place of No. 2 diesel fuel produced lower levels of nitrogen oxides (by 8 percent), particulate matter (by 31 percent), carbon monoxide (by 49 percent), and hydrocarbons (by 35 percent). Chemlink Pty Ltd ABN 71 007 034 022. Tel 61 8 9294 3254 Publications 1997. All contents Copyright © 1997. All rights reserved. Information in this document is subject to change without notice. Products and companies referred to are trademarks or registered trademarks of their respective companies or mark holders. URL: www.chemlink.com.au/

Transcript for Robert Rapier: The Scientific Challenges To Replacing Oil with Renewables Subscribe to this feed Below is the transcript for the podcast with Robert Rapier: The Scientific Challenges To Replacing Oil with Renewables Chris Martenson: So welcome to another ChrisMartinson.com podcast. I am, of course, your host, Chris Martenson and today we are speaking with Robert Rapier the chief technology officer and executive vice president for Merica International, a Hawaii based renewable energy company. Merica’s core focus is on the localized use of biomass to energy for the benefit of local populations. In addition to his work there, Robert speaks about the intersection of energy and the environment. And I have come to know him through a shared participation at ASPO, the Association for the Study of Peak Oil and Gas, where we had the pleasure of co-presenting on a panel this past year. He has deep engineering expertise I respect tremendously, notably on cellulosic ethanol, butanol production, oil refining, natural gas production, gas to liquids. He is also currently planning a book detailing present and future energy options in a resource-constrained world. Robert, hey, pleasure to speak with you today. Robert Rapier: Pleasure to be here, Chris. Chris Martenson: Well, you know while we were at ASPO together you had a very interesting presentation on how to perform due diligence on alternative energy companies that I really enjoyed a lot that I would like to bring to our listeners today. And the reason is that there are many out there who pin their hopes on a disruption free future to the idea that we will transition from oil to something else. Perhaps they have heard of a lab somewhere that has a made biodiesel from algae at twice the output efficiency of past efforts. I get emails from people all the time telling me of some great lab discovery. Or perhaps they have heard that solar or wind has a high net energy return, could easily replace oil if we ever decided to get serious about that. Make the switch. I want to have a discussion with you about how realistic these ideas and hopes are, given your experience in analyzing the actual companies that are behind these claims. With the intent of putting real money to work on real efforts. That is what you will do is you are aligning opportunities and money. So I guess that means higher level of rigor has been applied than exists in your typical PR release or a news article is what we find in your efforts. If we could, let’s begin with a story you told about an energy magazine that recently asked you to rank the 50 best alternative energy companies and we will go from there. Robert Rapier: Right, so the request came in, there is a magazine, online magazine, I won’t say who it is because I don’t know that they want their voters to be know but they asked to rank the top 50 companies in renewable energy and they asked me to vote this year. I had a list of a couple of hundred companies from them and as I started to sort the list once I got past about a top five it became really iffy and I mean by iffy I mean I’m not sure these companies will exist in 10 years. What I am looking for when I am ranking one of these companies is I think that it can actually go head to head and compete with oil at some higher oil price. That means that the embedded oil in the production of biofuel has to be low because if its not it won’t be competitive as oil prices get higher. And it has to be ultimately cost competitive. So maybe it costs $100 a barrel to produce but if it has low oil inputs I think that is a company that could hang around. So many of these companies I think they made so many false claims and some of them I am very sure won’t be in business in 10 years so it got very hard beyond about five, to really rank companies. By the time I’m 10 I’m ranking companies that I’m sure are not going to be around. I mean, some of these companies I am sure will not be around and I don’t think they have a very good business model. It becomes very difficult in the renewable energy sphere to find some of these companies. Maybe, I mean, my focus is biomass and biofuels, mostly so maybe in the wind sector, maybe in the solar sector and I think solar is actually a good example of something that is coming on and doing pretty well. But in the biofuels sector there is not a lot to choose from there that you could say this company is going to be in for the long haul. Chris Martenson: It is the biofuels that I’m most interested in because at present as exciting as wind or solar would be we still do not have even a fraction of a percent of our transportation infrastructure running on electricity. So of the things where we can get liquid fuels, I am glad that is where your expertise is. Let’s begin then, so you are ranking these companies. First you are doing a sort of financial due diligence and you are saying look if they have high embedded oil costs in them and they are not competitive with oil, right now, as oil goes up they will still not be competitive with oil in the future. Just some sort of a receding horizons dynamic at work there. Robert Rapier: Exactly. Chris Martenson: What are some of the reasons that you don’t think some of these companies will be around? Robert Rapier: When you think about what oil is then you understand why these biofuels companies have a tough time of making it work. I mean, oil is accumulation of billions, I mean millions of years of biomass that have accumulated. Then nature has applied the pressure, it’s applied the heat and it has cooked these into very energy dense hydrocarbons. Now, what we are trying to do in real time is speed all this up. Somebody has to plant the biomass, somebody has to grow the biomass where nature did it in the first place. We have to transport it, we have to bring it into a factory, we have to get it in that form, we have to convert it from biomass into some fuel. We are adding energy and labor inputs all along and then finally we get a fuel out of the back end. A lot of the times, a lot of these so called biofuels are very heavily dependent on fossil fuels to begin with. So some of them it is not even clear that they would be viable if you took the fossil fuels out of the process. When you think about all the labor and energy goes into making a biofuel from an annual crop it becomes apparent why oil has been the dominant fuel for the last 150 years. It is much easier to go poke a hole in the ground and get that oil out of the ground than it is to go through all the labor of actually producing the fuel. So companies are competing against that. Now there are some cases, like sugar cane ethanol is a good poster child for something that competes head to head with oil most of the time, but it has got some very special things going for it. It is largely grown in tropical climates, so you got year round sun. The bagasse when you harvest sugar cane ends up at the plant, it is washed, it is dried and it is there piled up in big piles so essentially you have free energy. Sugar cane ethanol historically has been able to compete on the price of gasoline. Right now its a little bit different because there is a bit of a sugar shortage and so the sugar cane ethanol prices are high. That is an example and the biggest reason is the fossil fuel inputs into that process are very low. Most of the guys that I think will fail are because they are making bad assumptions. So looking forward they will assume, and most of the guys that are predicting a dollar biofuel or two-dollar biofuel are making assumptions on the cost of their biomass, which I don’t think will be very good. And often that assumption is we will get tipping fees to tip this biomass. And that assumption comes up frequently very early in the process before they even had a chance to test on that particular feedstock or pilot on that particular feedstock. You call it a business plan and you say if I assume somebody is going to pay me $70 a ton to take this biomass, well suddenly that offsets the cost of your fuel by a great deal. There may be absolutely no merit to the assumption you just made, but that assumption will drive those costs down. Historically there is the example that I gave at the ASPO conference was a company called Changing World Technologies, they were in Discover Magazine in 2003 and they were very, very much hyped. They said they could turn any waste product imaginable into oil, they talked about this being the solution to our energy problems and they predicted that they produced the oil for $8 to $12 a barrel. This was featured in Discover Magazine before they ever even built a demonstration plan. They got very little critical examination. You had Warren Buffet’s son, Howard Buffet, was invested in it so they had that piece of credibility out there. Obviously, he must know what he is doing. The hype was on this company to deliver and once they built a plant they could not deliver. The worst assumption they made is they thought they were going to get paid to take the biomass, and they ended up having to pay for it. So their actual cost of production at the time oil was $40 a barrel, their cost of production was $80 a barrel. They had some other technical problems; they had some odor problems and they ultimately they went bankrupt and this was presented in Discover as the solution. If you follow these companies, that story is very, very common. If you follow these companies, Range Fuels has done the same thing; they came out, they made all of these promises and they shut their doors. That will be the case with most of the biofuel companies out there making promises. They get out there; they will build their pilot plant. They will discover that things don’t work as they thought they would and then they will close down. Chris Martenson: So let’s describe that process because we read about this all the time -- somebody is in a lab. They develop a process and you see a beaker of this looks like oil. That is what it looks like anyway and they hold it up and they say look, we produced this at the equivalent of I don’t know $10 a barrel or something and we can make this out of waste. I don’t know, chicken guts or something, right? And we read that a lot. Describe for us what happens that has to happen in order to go from beaker to 10,000, 100,000 barrels a day, what are the steps and what are the pitfalls or shortcomings that you often encounter? Robert Rapier: Okay the scale up issue is the most important issue because in my experience, most technologies get wiped out as they go up in scale. So something you may be able to do in a lab, 90% of those lab ideas don’t work and only 10% will go on to make a pilot plan. And for lab experiments there are going to be all kinds of things. Your catalyst didn’t work; your actual process didn’t work. Let’s say your process did work in a lab. In the lab you are doing all kinds of things that are different than what you would do at a larger scale. Your waste products may not be a problem but you may have a small amount of bi product that can be thrown away, lab equipment is smaller and so the heat transfer in that lab equipment is very different than it is as you scale up. The example I give a lot is a turkey, we are coming up on thanksgiving. If you are cooking one turkey and you imagine an oven with the heating elements on the sides that is one thing and not everybody gets that right. The turkey is too dry, it’s overdone, it’s not cooked enough. Now imagine taking that turkey and scaling it up to cook say 1,000 turkeys an hour. You can imagine that the issues there are very, very different than they would be in a smaller oven. You got maybe turkeys in the middle that would be still cold while the turkeys on the outside are burnt to a crisp. So you are trying to get an even heating distribution across this larger oven and it is the same as a reactor. As the reactor goes from lab scale, up to larger scale, as you get heat differences and temperature differences inside that reactor you can make different products, different byproducts, things that you didn’t want to make not as much of the thing that you did want to make. And some companies will skip those steps. As you skip the steps, if you think about it – most technologies get knocked out at each step. So normally a company would go from lab scale to pilot scale to demonstration scale to a commercial scale. If somebody is jumping over steps they are greatly reducing the risk or their chance of success. Chris Martenson: So what would be the chance of success if we jumped straight from the lab to commercial? A big commercial operation? Robert Rapier: It all depends on how many steps there are that are unproven. If you have multiple unproven steps and somebody goes from say they skip the pilot and go straight to demonstration and the size we are talking about let’s say lab experiment is producing a few pounds a day let’s say and only part of the technology. A pilot plant is going to be around a barrel a day so that is 42 gallons maybe a few hundred pounds a day on a pilot plan. But it is going to incorporate more aspects of the technology. A demonstration scale is going to go up to about 10 barrels a day and the biomass based second generation plants are probably going to be around 600 to 3000 barrels a day. An average corn ethanol plant is 4000 barrels a day and an average oil refinery is 125,000 barrels a day, so we are talking about very, very different scales here. The biomass plants are going to be restricted on the basis of the energy density of biomass and the logistical challenges of bringing biomass into a certain area. If you were go from say a lab experiment and were trying to jump to demonstration scale your odds of success are probably 10 – 20%. At that pilot scale you would have learned a lot of things that in fact, a lot of times you would have learned that you don’t want to take this forward. You want to stop that right there. And then, the next step at demonstration scale you also learn that. So now you have compounded that. If you had a 50/50 chance of success at the pilot plant and demonstration, well suddenly you are down to 25% by skipping that step of piloting. The investors, for investors the risk is far lower but the ultimate cost will be higher. If you go through all those steps and you have a commercial process it is going to cost you more to go through all of those steps but your probability of success is much greater and you have got less money at risk throughout that process. Chris Martenson: So this is just generally true of all the companies you look at; somebody has got a process and basically we are taking a fairly diffuse energy source in some form of biomass. Whether it is corn or straw I guess maybe if there is a cellulosic ethanol process or even algae, does this apply to algae as well? I don’t know. The basic process here is you are saying we have something that needs to be cooked in some way, shape or form; modified, transformed chemically, processed, we’ve got inputs, we’ve got waste streams coming out, we’ve have got pieces of technology that need to be proven out. Do you have examples? So the things I’ve read about. One was the ones where they are basically turning anything into oil that is one thing. Another are these gasification plants. I have heard a lot about those as well. How do these actually bare out in practice. I thought some of these were up and functioning and running? Robert Rapier: Some of them are, but not biomass based. So the history of gasification, this is what the Germans used during World War II to make their liquid fuel when they were cut off from oil, they took coal and they do a process where they actually burn, you can do a coal natural gas or biomass and you burn it without enough oxygen to completely combust. So to complete combustion would be coal, plus oxygen makes carbon dioxide and water. Those are not very useful for chemical synthesis. But if you only put half as much oxygen in there as needed to combust you will instead make hydrogen and carbon monoxide. That is synthesis gas. And synthesis gas can make a lot of different things and one of those is through the Fisher Tropsch process to make liquid fuels, can make diesel. And so the Germans used this during World War II, it scaled up. It is a scalable process and they made like 150,000 barrels a day of liquid fuels during World War II for their military. In more modern times, South Africa during Apartheid when they were cut off from liquid fuels they used the same process. And today, that still produces 40% of their liquid fuels from coal. From natural gas, Shell has a plant in Bintulu, Malaysia. I have been there and seen that plant running. It is 15,000 barrels a day and they have just built a very large facility in Qatar to turn natural gas into liquid fuels. Now, the issues there are the costs are quite high. The capital costs of these plants are very high and it is easier to do natural gas than it is to do coal because the transport is much easier and it is easier to do coal than it is to do biomass. Biomass does not perform as well in a gasification and mainly because you have these tars that form. When you cook biomass you get this stick tar that has to be dealt with and the energy density of biomass is much lower. On the same footprint a plant can produce a lot more liquid fuels from coal than it can from biomass. So nobody has quite cracked the nuts on biomass yet. There is companies that are building plants. In fact, I was involved with a plant in Germany the company was called Koran, the man that I work for is a major investor in Koran and that was their model; they were doing gasification of biomass to synthesis gas and then to liquid fuels. The commissioning of that plant went on and on and on and it took a very long time. Ultimately, he decided to pull out of that because he is funding the whole operation out of his pocket and he finally got to a point he said I just can’t do this anymore. We never identified any real knock out factors but there was a lot of different things that you have to get right. And so I would say that gasification holds some promise for the future it is not at $80 a barrel of oil. It is going to be more expensive than that where gasification of biomass could make some impact. Chris Martenson: What sort of a price are you talking about? Robert Rapier: I would guess that at $120 a barrel GTO, gas to liquid and coal to liquid can compete head to head with oil just fine. In fact, Sasaw the company in South Africa, says they can compete at $40 a barrel, but then their sunken costs were at $20 they built those plants when oil was at $20 a barrel. Biomass is going to be out there a little farther just guessing. Maybe $150, $200 a barrel you are going to be building some plants. There are a lot of caveats that go in there. I mean, the amount of biomass available is not nearly as large as people think. The pool of biomass out there, what gets burnt in a gasifier is not all interchangeable. So municipal solid waste is trouble some for a gasifier. A gasifier that is designed to burn wood won’t necessarily burn grass, so there is a lot of caveats. A gasifier that is burning biomass has to be in the middle of biomass. The biomass has to be logistically very close because they further you go out, the more labor you are paying and the more energy you are paying into that central location. And the low-density biomass means that it is just more embedded at cost and they will ship a truckload of biomass into the facility rather than a truckload of coal or to bring natural gas in by pipeline. Chris Martenson: The wonders of a defuse, rather than a concentrated energy source. There is learning there. You know when we were at ASPO, Wess Jackson of the Land Institute, he also spoke and he noted that this great carbon liberation that is happening in the burning of the fossil fuels right now was not the biggest, nor the largest carbon liberation that has happened in human history. In fact, the first one was taking the native soils that existed before agriculture started as a practice from an average 6% organic matter content down to 3%. So we lost about half the organic matter from soils, which is really a way of saying we have liberated a tremendous amount of carbon from the soils. In this story, that you are talking about with biomass something that I think also escapes notice a lot of times. The idea that well, this stuff just grows out of the ground and you just take it and if you want to turn that into sim gas and liquid fuels, have at it. What is missing in that story is that carbon that we are taking off of the land is not being returned to the soil. So it is somewhere in this equation if we are going to do this sustainably we also have to allow for some of the grown crops to be harvested back into the soils if it were to maintain the organic content or we are going to be just strip mining the soil. So there is even other considerations here that really – what did Woody Allen say? You can have great optimism about a problem until you understand it, or something close to that. There are complexities in here. So what I hear you saying is that when we try to operate at scale we have these plants and there is all kinds of things that bite you from proven technologies that need to be worked out. From waste products that might build up that you didn’t expect, from incomplete reaction cycles that are problematic to fix which gives us things we hadn’t quite intended to produce, and which now are things we have to deal with. From relatively defuse energy sources that by necessity we are going to be getting less out of a plant on a footprint basis than we did out of prior plants. All of these things are actually considerations that exist in the real world. Did I miss anything? Robert Rapier: No, that’s all correct. Just looked at the scale you think about replacing all of this oil that you use with biomass. Nobody anywhere is saying that they think we have a biomass plant anywhere close to the size of an oil refinery. So then you get into a situation where you have numerous of these biomass based plants. So we are talking about an enormous scale up of these things that will roll out to displace the oil that we use. The other problem is if we do the math and make some assumptions on biomass availability and conversion and so forth, you would come to a conclusion that we are never going to realistically replace more than maybe 10% of the oil we use with biomass based energy – with biomassed liquid fuels, let’s say. Chris Martenson: So the United States is I guess producing about 5.5 million barrels of liquid oil fuels at this point in time and we are burning maybe 15 in terms of actual oil that goes into the gas tanks. So we are talking 10 million barrels a day that have to come from somewhere if we are to truly be independent from imports and what not, 10 million barrels. Let’s just put that into proper context in the size of these plants you have been talking about. You have been saying if a pretty good-sized ethanol refinery is turning out what 4,000 barrels a day? Robert Rapier: Right. Chris Martenson: 10 million, 4,0000 there is quite a big gap there. Robert Rapier: Yeah, no doubt and these second-generation plants won’t be as big as an ethanol plant. I mean corn is the energy density of corn is quite high and the crops can be grown very high yields all around these plants. I have never seen anybody suggest a second generation biomass plant can be even that large, 4,000 barrels a day. Chris Martenson: Well, when I read about some of these things there is such optimism. One of the graphics that fishes through my inbox every so often; somebody says look, if we just took this much of Arizona and dedicated it to algae production and it is this little tiny postage stamp in the upper corner of Arizona, we could solve all of our liquid fuel needs. What is wrong with that story? Robert Rapier: Yeah, the devil is always in the details. We see this biofuel processes and we project our hopes and dreams and we don’t know enough of the details. And once the details start to come out – well, by then somebody else has come out with something else. I mean do we remember the hydrogen economy and how exciting that was and I mean it is gone and we didn’t even have a funeral for it. These companies, they come, they are flash in the pan, they come out and they are making all of these claims and most people don’t have a technical background to see what is wrong or to ask the right questions. Eventually, these companies fade away because there is a never-ending cycle of these companies, which is why people can be always optimistic because there is 10 companies right now claiming to solve all of our energy problems. Surely, one of those companies will have the answer. And if you follow them you will see them, they go by the wayside but we get excited about something else and move on. Just algae, for instance, algae in the desert. Do you know how much water evaporation occurs in the desert? It’s a lot. I have been to an algae plant before and they tell me two things; I asked them about the viability of producing fuel from algae. He said the problem is my electric bill and my water bill are both very, very high and so there is a detail. So he has got that and that is something he actually has to cope with. He can’t wish that away or hope that well, if I only had wind power here producing the electricity and so on and so forth. He has to deal with real problems and that is when some of these stories start to fall apart when you see actual details. Jatropha is a perfect example. Jatropha came on the scene, Jatropha is a plant that grows in oil feed and it has been used in Africa as a living hedge because animals won’t eat it, the leaves are toxic. It sprung onto the scene a few years ago and it was going to be able to be grown in marginal soil all over the world and all these great yields. And it was going to be the crop that solved all the problems. Well, the truth was it doesn’t thrive, it was advertised as it thrives on drought soils. Well it doesn’t thrive at all in drought soils. It will tolerate drought. I mean not drought soils, drought conditions. It will tolerate drought but loses all its leaves. And then the yields that have been projected run the high side of the yields with fertilized and heavily watered crops they took that and they extrapolated it all over the marginal soils of the world. And then suddenly you start to look at the details and you see this as the real story comes out you see why this isn’t the answer that it was put out there to be. India has invested five billion dollars into Jatropha. There was a story last year that said they are going to lose that investment because it just didn’t produce like they thought it was going to produce and that is all too often the case once you get into the details you find out there are things here that we just didn’t anticipate. Chris Martenson: It is fascinating to see that India has a very intelligent and educated workforce over there and they have given a good hard run at that with a lot of money. What I find most often is that we got these press releases, I remember when one came out a little less than a year ago, but it might have been a year ago where a company said hey, we have engineered this bug and given it a gene and it just excretes oil. It just all it needs is carbon dioxide and sun light says the press release. I thought that was a little odd I have some biology in my background and I thought I remembered most organisms have this stuff called DNA in them and there is things like phosphorus and nitrogen in there. Let’s grant them the idea that there is this bug that can just live on carbon dioxide and no nutrients. And when I started scratching at that story details are really hard to come by and ultimately I did discover that what happens is this little bug does create these little vesicles that fuse with its outer membrane it releases this oil like substance, a long chain hydro carbon, into the water. So what happens is you end up with an oily sheen on top of the water and now you have to separate those things. It turns out the issues of trying to scale to skim this oily sheen off and concentrate it and separate it from the water and then you still have a product that needs further refining and other pieces. It turned out that pretty much rendered this a really, really difficult process to scale beyond anything other than an idea. But that was an example where somebody had a lab with a tiny pilot result and the press that came off of that was staggering. I had that article sent to me probably the most. I probably had twenty copies of that sent to me from various places. So that you have been in the business quite a while, what is the dynamic at work there and why do we keep falling for these things? Robert Rapier: I think that we hope and we believe that our energy predicament can be solved by technology. We have seen technological advancement in so many different fields and we expect this is what we are going to see in the energy field. Also if you look at where computers have come over the last you know, 30 years we expect that to happen with our energy production that the whole society is going to be running off of solar and wind power going forward. I sometimes say there is not always a neat solution to every problem. Imagine we still got the common cold. It is still with us. That has not been cured despite it being around forever. So not all problems can be solved easily. And the energy problem is one that is not going to be solved easily in my opinion. Our society has grown up on something that was rich, abundant, and pretty easy to get to. We are trying to replace that with something that the energy required to get it and process it and produce it is a lot higher than the energy required to process oil. Chris Martenson: Right. So your message here is not that these things cannot be done but when we do them we are going to discover that our energy costs are going to be going up that at what we understand to be current oil prices the various technologies that are currently out there in scalable form are not competitive at current oil prices. Maybe at much higher prices, they are. That is always a possibility and the second piece would be that we are going to discover that there are throughput limitations in terms of the amount of available biomass itself that can actually feed into this process at some point. We might have both a supply constraint and upward price pressure both of those probably combining in some form. Is that the basic message here? Robert Rapier: Yes, that’s pretty much it in a nutshell. These processes that will work at maybe a little bit higher oil price. It is also very important to note what the energy inputs into that process is. I mean one of these processes is like oil shale. It is true that we got maybe a trillion barrels or something of oil shale, something crazy in Utah and Colorado, but the reason that process has never been economical is because of the energy inputs into that process are so high. And so if you follow the story there I talk about a newspaper headline from 1906 that says oil shale development eminent. And 105 years later, it is still eminent we are still talking about it just around the corner. No matter what the oil price is people are always talking about just a little bit higher because it costs so much energy to process this oil shale. So at $40 it was going to take $60 to be economical. At a hundred dollars, it is going to take a hundred and twenty now if we are absolutely certain that oil prices are going up. And we sank those costs in today like the South Africans did with their coal to liquids, we might found out that we can produce oil shale and we can turn it into oil if we are absolutely certain that the oil prices are going up and more importantly, we are not using oil as our input. We are using something else as our input. If you get a big diverges between natural gas and oil like we have got now you will see some things people doing some things that may be not sustainable, but maybe make economic sense. Like you know, turning you might turn natural gas into ethanol, which is kind of what we do today. We use a lot of natural gas and we turn it into ethanol. You say you know even if the energy balance on that was negative net energy. Say you took two BTUs of natural gas to make one BTU of ethanol, you would say well on an energy return basis you would say that is absolutely not sustainable. But on an economic basis you would say you might do something like that for some period of time until the demand on natural gas prices drives that up. There are a lot of complexities here. The biggest ones are what kind of cost competitive with oil and what embodies the energy input into that process and I will give you an idea going forward at higher oil prices a particular process has much of a chance. Chris Martenson: So what is the best process we have right now? Are you saying we would have to have some sort of a grab bag we would have to try all sorts of things? Robert Rapier: I think we are going to have a lot of different options. If we were in a tropical climate we maybe could pull it off with ethanol. We’re not so we have to look for some other solutions. Your point is well taken about the soil and that is one of the things I am very concerned is treating soil, farming as an extractive industry. It doesn’t have to be that way and I have always thought it would be ideal if the breadbasket of the country where the ethanol is produced also used that ethanol to make themselves a lot more self-sufficient. They did it in a way that the corn was a lot more sustainable than it is now. They are actually maintaining the quality of the soil. You don’t want to trade off your soil for some short term fuels because in the future we are going to need to eat. So yeah, for the mid-section of the United States for the Midwest, maybe ethanol is a bigger part of the solution than it is for say, California. Maybe you have a gasification process there you can do some jet fuel and some things like that. In Arizona maybe you have got more solar cars and solar panels in Phoenix and electric cars there because off the high quality solar energy there. There is not going to be one thing that replaces oil. I think there is going to be a lot of different things and more importantly I think it is going to take a lot less oil than we are using now. The good news is we have dropped a million and a half barrels a day over the last five years. The bad news is a lot of that is because of the recession; it shows we do have some capacity to reduce our oil consumption. There is still a lot of low hanging fruit in my view. It is going to be painful as we scale down and some of the alternatives are going to have to meet somewhere. At some level higher than they are today and at some level of oil consumption lower than we are today those will have to meet. Chris Martenson: And that doesn’t necessarily have to be a bad thing unless of course you are expecting, requiring or in some way demanding that the future look just like the present only larger. My main point in all of this is when I say a destruction-free transition. I think some people hold the idea that as we have currently configured our lifestyle, where we live eat, work, play transport ourselves all of those things requiring and relying on a liquid fuel system -- that somehow we will manage to transition to another liquid fuel system. Some form of biofuels in combination with electric cars. We will put together all of those things. In your estimation, so first, what percentage of penetration. Like how much of our transportation infrastructure is running already on what we call alternative fuels. Whether it be an electric vehicle or – I am not going to count hybrids here but just a pure electric vehicle or vehicles running on biofuels themselves and from that percentage to get to something meaningful like 50% how long would that take? Robert Rapier: The electric vehicles are such a small percentage -- that it is, you know -- it is a decimal of a percentage very, very small. I think the goal is to have a million cars on the road by 2015, which I don’t think is close to being reasonable but Jeffrey Styles recently did a calculation that said even if we got to a million and Jeffrey Styles is fellow energy blogger. He did a calculation that showed even if we got to a million cars that is going to displace about 5% of the oil that would have come down the Keystone pipeline. It is a very small amount that we are talking about for a very long time in the future. So electric cars may scale up farther out in the future to make more of a dent but in the near term they are not going to make much of a dent. How much of biofuels contributing today that depends on how you want to figure what is a gallon of ethanol? Is a gallon of ethanol a gallon of biofuel? Or is it a fraction of a gallon of biofuel and some amount of natural gas that has been turned into fuel? So if you consider a gallon of ethanol is fully renewable we got about 10% of our fuel supply by volume is ethanol. But energy content it is about 6 or 7%. But then if you back out and you start to back out the fossil fuels out of that and you say 80 or 90% of the BTUs from that ethanol actually were derived from natural gas in the fertilizer, in the processing. Then the petroleum is moving that around you would say the actual real displacement of oil would still be maybe 5 or 6%. But of fossil fuels, if you look at all fossil fuels it is a much smaller percentage. Because what we have done is taken one depleting resource, natural gas and used it to make ethanol and that is not always going to be sustainable. If you only count the fraction of ethanol that you would say and then some people say ethanol is not renewable at all. I would disagree. I think it has got some I think the energy return is above one. Some people argue it is below one. But it is the amount that is above one that is really your renewable fraction. If you said how much of that is there in the fuel system? That is one percent maybe or less than 1% of truly renewable fuel that is in the system. Chris Martenson: Alright, so if you were to go to say 50% leaving aside whether there is enough land to do that. Leaving aside the idea that even the electric cars you started with, the electricity mostly came from fossil fuels itself. It got burned somewhere very far away and got transported through electrical transmission lines so we don’t see it that way. Assuming our electric cars can run on solar panels and that is all well and good. How long would it take to get to a 50% displacement do you think? Robert Rapier: It is hard to say. It depends on if you had a dictator you could force that to happen very quickly, but we have a democracy and in a democracy you have to work with the other party, people have to agree on things, and they don’t agree on anything. And so the next party could come in you could have an agreement now and the next party could come in and turn that over so things in the energy field and this is always a complaint that we don’t have good systems for some of these long-range projects. When you look down the line you say okay to get to 50% if you had complete control of the whole system you could maybe turn that over assuming again, you have the electricity you could turn that over in 10 or 15 years. In a democracy -- and what we have to work with here is going to take a lot longer than that -- it may be 30 or 40 years before you could get to something like that. The way you are going to get there I think, are people not agreeing okay this is what we are going to do. It is going to be oil I think getting so expensive that people are looking for other options. Chris Martenson: Right so my market force is 40 or 50 years. You go to ASPO a bunch, where do you personally think we are in the peak oil story. Robert Rapier: We are right there. I mean whether we are just past or just before I still think that we are right there. And that is the argument that I have always I don’t want to focus I never like to focus too much on a date for the peak but rather what happens when oil peaks and this is something I have been thinking about since 2005. When oil peaks and production declines there is going to be not enough supply for everyone at a certain price. Well, we don’t have to necessarily wait for the peak to happen for that to happen. I mean over the last 10 years demand in developing countries has grown and all the excess capacity in the world practically has been used up. And so 10 years ago where you had all these suppliers that could come online as the price went up you don’t have that anymore. So we have a lot more volatility and a lot higher oil prices than we had before. So effectively, whether you got peak or not, you got effective peak and that is what I have always talked about as peak light and some people misunderstand that to mean I mean peak is going to be a live event. I don’t mean that -- I mean it is like peak, it is a pseudo peak, and it is behaving as a peak even if this year we set a new production record. Next year we can set a new production record, but effectively there is no spare capacity in the system. So prices are going very, very high and we are being squeezed in the west while a country like China who uses two barrels a year of oil per person, the United States uses more than 10 times that so higher oil prices impact us a lot more than it does them. So they will grow if they get their oil consumption even up to four barrels per person per year, ours is going to have to come way down because they are going to drive oil prices much higher than they are now. If that happens, if China goes a little higher, we got a little lower, it will potentially devastate our economy but they may still be able to grow because they are starting from such a low base. Chris Martenson: This was a great point made at ASPO this year, that I heard was that what is the marginal utility of a barrel to somebody. That if I am consuming 20 barrels can I dial that back to 19 easily. If I am a farmer in Brazil and I got a tractor I need to run, it turns out I will pay quite a bit for that oil. Because the amount of utility I get out of that tractor plowing that field instead of doing it by hand is much higher than the marginal utility I personally get up here in the United States by consuming my 20th barrel instead of just my 19. I think that point is well made that in some ways the intrinsic value of the work that the oil can perform has a higher value in a developing nation than in a western nation at that margin barrel. Robert Rapier: That is exactly right and I think that is a mistake that we have made that as oil prices get higher, the developing countries, the poor countries are going to be priced out of that market. It is going to be Europe bidding against the United States, the wealthier countries. But in truth the opposite has happened over the last few years. As oil prices have gotten higher it is the developing countries that have consumed more and more and that is exactly why because they are starting with such a low amount, it is worth so much more to them you know, they are not using oil to run to the store and back for a candy bar. They don’t use it s frivolously as we do and it is worth a lot more to them. It is exactly right, how much would you pay for oil? It all depends on what your other options are. So if our option is okay we don’t drive to the store or I have to bike to work, I have to move closer to work we can do some of those things. We got discretionary oil usage. Them, not so much. I mean you got a lot of people who would love to spend – they would spend a lot more of their income than we are used to spending on their oil. And that is a danger for us whether we are at peak five years ago or this year or five years from now, we are in that paradigm now. Chris Martenson: I think we absolutely are. We look at oil prices right now at $97 for WITC and over $107 for Brenton. It is pretty clear that those are not oil prices that I think anybody would have predicted five years ago or six years ago. If you had said here is the economic growth of the world, here is the current financial difficulties, here is consumption in the west, particularly the United States it is still declining. You put those parameters in front of me five or six years ago I would have not have predicted those current oil prices but here they are, one possible indication of supply tightness is higher prices than you might expect. Robert Rapier: And this was my long recession thesis. The Long Emergency is a book that I read that really made an impact on me on how things could turn out. I paid homage to Jim Kunstler with I would have to say that I called the long recession. The long recession says that historically what happens is oil prices get high, throw us in recession, demand goes down, supply creeps up, and suddenly oil prices are down and then we can recover. But when oil supplies are extremely tight, when peak oil is happening when all of these developing countries want to consume more oil you don’t have that relief because new supplies aren’t coming online at the rate that would allow prices to collapse and the economy to recover. So you get in a situation where we have now (even in a very weak economy) oil at $100. It is unheard of and it may be that is because we are in a new paradigm of potentially never ending recession until we can really dial our oil consumption back faster than say these new guys come online, the new production comes online or these developing countries are using up all this extra capacity. You want to stay out in front of that. And unless we can do that I think we are in a situation where I don’t see an end to the recession. It is hard for me to see how this recession ends if our oil supplies are now permanently tight. Chris Martenson: I agree with you. I wanted to have this part of the discussion around where we are in the peak oil story. Because it is really essential I think to put our hopes and our dreams about what we might be able to do on a technological basis with respect to these alternative fuels up against the reality of where we are in the peak oil story. Because there are actual hard conditions, there are details as you say, there are things that we really have to consider that are involved in going from an idea of how we might live on alternative fuels to the reality of pumping out 10,000, 20,000 maybe 100,000 barrels per day out of a plant. And what is really implied in that and we haven’t really yet fully made that transition in the biomass way with the exception of ethanol we get a bunch out. But really as we ran through the percentages, we see where we are in that story we are very much at the beginning of the story of transition. Your point was, and I agree with this if we wait for market forces to deliver that to us, waiting for the price signals of oil to deliver the correct message so that we make individual and collective decisions as businesses and individuals that will be decades. We don’t have decades before we are going to start facing a long recession, if you follow recession thesis and how it couples to oil. So in recessions it turns out things that were formerly possible are not possible anymore. Big capital investments, when budgets are being trimmed, that is not the time to get creative and aggressive and have what feels like a Manhattan Project times an Apollo Project times ten. Some big national outpouring is not something we have traditionally in the United States, rallied around barring having something external like a war to focus on. We would have to have, I think, in my submission some really, very serious re-orientation of priorities beginning 20 years ago it would be awesome. Even today it would have to be really, really a startling redirection of resources, talent, energy, ideas into really ramping up our domestic alternative energy production for it to have a meaningful impact on our current way of life is how I see it. What do you see? Robert Rapier: That is of course why so many of us are so worried. We have a problem seeing that happening. It is like you say, if we had to have a major effort right now to ramp up say coal to liquids, we got let’s say we don’t have a problem with our coal supplies, hypothetically. You are going to have a lot of resistance from people number one who don’t want to use coal but then where is the money coming from? You are in a very tight economy. These plants take a long time to build. I think some of them will get built anyways but it is hard to imagine that the government is going to roll out a trillion dollar effort to replace a lot of our oil consumption when the economy is so bad and they are trying to find a trillion dollars of savings even now. So this is what concerns everyone and the time frame on these projects is long term. It is hard for politicians to plan long term. So the political situation being what it is it is hard for us to imagine that they are going to be a lot of help with getting the solution out there. Chris Martenson: Exactly. I agree with that as well and we will wait for the liquid fuels emergency to come and then we will respond. I think our solution set will be smaller and less favorable than it would have been say 10 years ago. I see that we are in a shrinking environment so we better get busy quick. I have really enjoyed this conversation. I always enjoy your writing. How can people follow you and read your writing as it comes out? Robert Rapier: My regular blog is R squared energy blog if you google R Squared Energy or if you google Robert Rapier you will find it. I’m on Twitter, I’m on Facebook I am on all those things and I put out usually a couple of new articles a week I have started putting out a video blog at the request of several viewers. They say it would be nice while eating lunch or something I could just listen to you answer a few questions, so I started doing that. But yeah, I’m not too difficult to find. I write for the Oil Drum some and I write for Forbes some and the stuff is out there. But the most regular way to find me is on the blog. That is where all my columns will come out there first before somewhere else. Chris Martenson: And R Squared, that is all spelled out, right? Robert Rapier: Yes. R Squared Energy Blog. Chris Martenson: R Squared Energy Blog, well there it is. Okay, well Robert, this has been a pleasure. I hope we get to do it again sometime. Robert Rapier: Thanks so much, Chris. Chris Martenson: Alright, you’re welcome. Bye-bye. Robert Rapier: Bye-bye. Robert Rapier has been devoted to energy issues and has worked on cellulosic ethanol, butanol production, oil refining, natural gas production, and gas-to-liquids (GTL). He grew up in Oklahoma, and received his Master’s in Chemical Engineering from Texas A&M University. He is presently the Chief Technology Officer for Merica International, a renewable energy company. Merica is involved in a wide variety of projects, with a core focus on the localized use of biomass to energy for the benefit of local populations. Robert is also the proprietor of the blog R-Squared, which fosters open discussions of Energy and the Environment.