Natural Gas Fracking Boom Turns SourCommodities / Natural Gas Mar 09, 2012 - 09:51 AM GMT
Exxon Mobil's CEO Rex Tillerson, unveiling bad news on Exxon's intense program to develop shale and stranded gas resources, said March 8th that some shale formations in Europe and China are impervious to drilling techniques that opened vast reserves of US natural gas and identified potential shale oil reserves, from Texas and Pennsylvania to North Dakota. He concluded that new methods and techniques will need to be invented to tap many of the shale fields that energy companies and governments across the world, with a few exceptions hope eventually will yield a bonanza of gas and then oil.
Exxon, which by energy output is now 49% gas, failed in its first two efforts to crack gas-rich shale fields in Poland, not located in Poland's renowned USB (Upper Silesian Basin), one of the world's largest coal fields, also rich in coalseam gas. Gas discovered in a pair of Polish wells completed during the final three months of 2011 did not flow, using now conventional US fracking techniques. Forward E&P spending by Exxon, on shale gas and oil outside the US, may be significantly reviewed, but major projects will certainly continue. Exxon agreed last year to explore shale fields in China with China Petrochemical Corp. and also has shale projects under way in Argentina’s Vaca Muerta formation in an E&P program budgeted at $37 billion this year to find and produce oil, gas, chemicals and motor fuels. Annual spending is projected at that pace through 2016.
Shell, which by energy output is now approaching 60% gas, has already backtracked and downsized its shale gas and oil programs. Initially intending to spend about $5 bn on drilling shale field this year, its CEO Marvin Odum now places spending at $3 billion to $5 billion, Odum adding: “We’re at the lower end of that right now because of where natural-gas prices are”.
CHEAP GAS AND FRACKING ARE NOT BEDMATES
Shell's strategy is now moving towards only raising output in liquid-rich shale areas, producing "wet" gas, which can yield synthetic light crude oil or more gas-liquids such as propane. The Hague-based company, which is also active in China and Europe is likely to set a cap on shale gas E&P spending for 2012 unless natural gas prices rise in the US or exploration prospects in "wet" gas formations prove successful. Multiple studies on US "dry" shale gas formations and typical well performance and cost profiles show that US natural gas prices need to be "north of $6 per million BTU" to be long-term feasible - but gas prices for February delivery, last week fell again, to $2.302 per milllion BTU on the New York Mercantile Exchange. This was the lowest settlement price since Feb. 15, 2002.
With prices for gas so low Exxon, Shell, BP, Chesapeake, Conoco and other energy majors focusing gas production in the US need to wrest more value from "dry" gas by using it to produce chemicals, other fuels or by turning it into liquid form for potential export, depending on a mix factors including local oil prices, petrochemicals demand and refinery structures. Shell has in the past heavily invested in GTL (gas to liquids) and holds an estimated 3500 patents on GTL technologies, but has only one major operating plant, at Bintulu, Malaysia. Bintulu, whose airport code is BTU, is currently the largest GTL plant in the world with an output of 14 700 barrels/day, soon to be outdistanced by the Shell JV with Qatar, the Pearl GTL plant, slated to produce 140 000 barrels/day when it starts operating. The Bintulu plant has cost Shell about $1 billion while the Pearl plant is costed at around $19 billion.
Technology choice for GTL is still heavily constrained by physical and industrial parameters to only the Fischer-Tropf process dating from 1923, as also used by South Africa's Sasol for its coal-based GTL plants. At best this process, at Shell's Bintulu plant, can convert about 44% of the input gas energy to liquid oil output, and the Pearl plant is unlikely to far exceed that performance. Over one-half of the input energy is therefore lost (also creating massive CO2 emissions), setting a floor price to the liquids outputs, which are also raised in cost by high capital and operating costs.
Shell therefore targets the highest-value output products, not motor fuels. From a total value chain perspective, GTL outputs such as olefins, waxes, plastic bases are preferred, but Shell and other energy majors are evaluating plans to spend $50 billion or more on GTL plants in the U.S. that could turn gas into refined fuel products like heating oil and kerosene, as well as chemicals or lubricants. To date, no energy major operating in the US will commit to fixed dates, plant sizes or location for GTL plants. It can be gauged on cost for the Pearl plant that $50 bn spending in the US, on GTL plants, could likely develop about 350 000 b/d of liquid fuel and products output - slightly less than 4% of current US motor fuels demand.
CHEAP SHALE GAS AND SHALE OIL ALSO DONT MATCH AND MINGLE
The main thrust of gas-based GTL is for petrochemicals output, strictly due to unit values of products, and the US petrochemicals industry is considering plans for spending as much as $30 billion to build plants that convert natural gas into plastics. Industry interest is cheap gas input and expensive petrochemical products output, but for energy companies, like Exxon now paying as much as $25 000 per acre for shale gas and oil drilling rights, cheap gas is not on the menu.
Simply due to bargain basement gas prices, and Exxon's go-for-gas strategy, its earnings for 2011 are forecast by analysts at about 8% to 10% down on 2010.
Energy majors now see shale oil as the way out of the impasse they created for themselves, in a global context of conventional oil resources being hard to find and expensive to develop. Undeveloped shale oil and deep offshore oil fields will produce a combined additional 1 million barrels/day of oil by 2025, Yves-Louis Darricarrere, E&P president of Paris-based Total said at this week's IHS/CERA energy week in Houston. Using hydraulic fracturing to free natural gas from shale formations should logically lead on to shale oil development, but due to high production costs and technology unknowns, the forecasts of shale oil's output are at the least very modest.
An additional 1 Mbd (1.1% of current world oil demand) over 13 years is a tiny amont of new oil, although this in no way is admitted by shale oil boomers like Daniel Yergin, IHS/CERA chairman. Current production costs for shale oil run at about $70-per-barrel.
Unprecedented amounts of spending would be needed to "unlock" really significant amounts of shale oil: the current forecast of total "unconventional and shale" oil output raising to 2025, given by Total, is costed at more than $10 billion by analysts. On a barrel-day capacity basis, this is high-priced oil !
The shift to shale oil, and a significant rise in shale gas prices, are both likely. The first is due to plain old fashioned peak oil, and the second is due to the current, totally uneconomic extraction of shale gas in the US at a sale price below $2.50 per million BTU. The energy majors, not only due to their lack of access to OPEC state conventional oil resources, but also due to their shale gas and stranded gas E&P strategies, in their corporate shift away from oil to gas, have locked-in high oil prices for the foreseeable future. In turn, their coming focus on shale oil will further lock-in high oil prices, making the energy downstream most likely to move, first. Apart from the always present but never successful Pickens Plan for converting US heavy vehicle fleets to gas fuel, several European major truck building companies, like Volvo are moving ahead with the same concept. Needing first investment in an infrastructure of gas fuelling stations, the cost savings for European fleet operators - paying around $7 per US gallon for diesel fuel - are so large it is increasingly probable the "gas shift"will take place.
By Andrew McKillop
Former chief policy analyst, Division A Policy, DG XVII Energy, European Commission. Andrew McKillop Biographic Highlights
Andrew McKillop has more than 30 years experience in the energy, economic and finance domains. Trained at London UK’s University College, he has had specially long experience of energy policy, project administration and the development and financing of alternate energy. This included his role of in-house Expert on Policy and Programming at the DG XVII-Energy of the European Commission, Director of Information of the OAPEC technology transfer subsidiary, AREC and researcher for UN agencies including the ILO.
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