Shale gas has been called a game changer in the US but Europe will have a tough job emulating the US’ success, writes Tim Probert. This article first appeared in the December issue of The Energy Industry Times.
There is no question that shale gas has been a ‘game-changer’ in the United States. From virtually nothing ten years ago, shale gas now accounts for one-third of domestic natural gas production.
US energy policy has been turned completely upside down by shale gas. Having built a number of LNG terminals in recent years to cope with anticipated demand for natural gas, the US is set to be an exporter. LNG cargoes destined for the US have been redirected to Europe, while LNG terminal operators are considering converting regasification terminals into liquefaction terminals.
With enough shale gas to meet domestic needs for up to 90 years, gas-fired power plants have become the obvious choice to replace aging coal plants, which have been beset by a host of environmental issues. Furthermore, a plunge in the price of natural gas has made coal power even less attractive.
According to the US Energy Industry Administration (EIA), Europe has a shale gas resource of 2587 trillion cubic feet (tcf), enough to meet current consumption for 140 years. Will the same happen in Europe? Well, the short answer is possibly, but it will take some time for the industry to get up to speed. Here’s why. In contrast to ‘conventional’ gas extracted from porous rock, shale is relatively impermeable, meaning gas cannot easily move through the shale in which the well is drilled.
In order to release the methane, drillers use a method called hydraulic fracturing, also known as fracking, essentially pumping a large amount of water, sand and chemicals at high pressure. Shale gas developers use a technique called ‘pad drilling’, with up to ten drill wells radiating horizontally for distances of up to six miles from a single site, or ‘pad’.
This technique has been used for decades, but the improved ability to steer drillbits using off-the-shelf technology has made horizontal fracking cost-effective. The facility to perform surface data acquisition to locate gas in the rock, rather than drill right through the shale as previously, has also brought down costs.
However, fracking is not without problems. To some, the US shale gas industry has been reminiscent of the Wild West, a free-for-all where developers frack first and ask questions later. This is partly due to slack regulation – fracking is exempted from federal Clean Water and Safe Drinking Water Acts – and there is growing evidence that rivers and other water sources have been polluted.
As the fracking process takes place several thousand feet below the layers of aquifers, it is highly unlikely they will be polluted. However, the USA’s Environment Protection Agency has found that there is a serious risk of groundwater pollution from improperly constructed wells, i.e. where boreholes have not been cased with a steel pipe cemented in place. In Europe, stricter regulations should ensure boreholes are tripled-cased between the drill shaft and the acquifer, while the site will be protected by an impermeable membrane to guard against surface spills.
However, shale gas requires approximately 5 million gallons of water per frack and approximately one-third of this water is returned to the surface. This ‘flowback’ water typically contains the released gases from fracking; naturally occurring radioactive substances; metals; and volatile organic compounds like benzene, which easily vaporise into the air.
According to Veolia Water’s Karim Essimiani, the costs of treating the flowback water in the US ranges from up to $6/bbl for reuse or up to $24/bbl for discharge. This would translate to a water treatment cost of up to $3 million per frack, but Essimiani warns that due to deeper European wells up to three times more water may be required.
Tessa Davis, a London-based senior energy attorney at Linklaters LLP, says, “Regulation may affect the ability to economically recover shale gas. Water costs for shale gas fracking in Europe could be ten times higher than in the US, due to greater volumes and higher input costs.”
How much is really down there?
In September Cuadrilla Resources, a UK joint venture between Australian drilling firm AJ Lucas and American private equity firm Riverstone, announced the Bowland sedimentary rock basin in Northwest England, for which it holds shale gas exploration licenses, holds a total potential resource of 200 tcf, or more than ten times existing UK natural gas reserves.
It must be stressed that the estimate by Cuadrilla, which is not a listed company and therefore not subject to usual Stock Exchange reporting criteria, is for ‘gas in place’ and not proven reserves. It is very much a ‘guesstimate’, more than 40 times the official estimate for the whole of the UK, calculated by multiplying the area of shale rock by an average figure of how much gas may be extractable from this particular type of shale.
James Elston, CEO of London-based shale gas developer Palladian Energy, says the most that could be realistically extracted from the Bowland shale is 20 per cent. That would be roughly equivalent to the Troll gas field in the North Sea, which holds 60 per cent of Norway’s gas reserves alone. “But they’ve only drilled two wells,” notes Elston. “Only when they’ve done seven or eight fracks over a wider area will we get a true idea of how much shale gas is down there and how much can be got out.”
The EIA estimates Poland as having an enormous shale gas resource of 187 tcf. Initial frack results, however, have been mixed. 3Legs Resources, which partners oil major ConocoPhillips in developing Polish shale gas, has lost two-thirds of its share price since floating in June 2011 due to disappointing flow rates.
The main problem appears to be a lack of suitable drilling equipment. Shale gas wells decline rapidly; Cuadrilla says the typical decline rate is 40 per cent within two years. To exploit the Bowland basin successfully, Cuadrilla may need to drill six to eight boreholes per square mile and up to 50 wells a year, at a cost of £10.5 million each.
According to Joseph Dutton, an unconventional gas analyst with Douglas-Westwood, the lack of suitable drilling rigs is the most important issue impairing shale gas production in Europe today. The UK-based consultancy forecasts European shale gas production to hit 1.2 tcf a year by 2020. This is based on a figure of 3,500 new wells drilled a year by 2020 from a total well stock of 15,000 wells.
Due to the very high decline rates of shale gas wells, however, the industry will need to spend a $1 billion on drilling to hit this production rate. Money which, says Douglas-Westwood unconventional gas analyst Joseph Dutton, is simply not currently available unless investors are “firmly convinced” of the business case.
“Despite the hype, shale gas financing is on a knife-edge,” he said. “For it to really take off there needs to be a great deal of capex and opex to invest in drilling and drill rig, but a lot of companies are sitting on their hands. There are big bucks to be made from addressing drilling rig issues.
“Deep, multiple-stage fracking ideally requires a drilling rig with at least 2000 brake horsepower (BHP), but we’ve identified only 78 rigs in Western Europe, 49 of those have a rated torque of less than 1,500 BHP, 17 have between 1,500-2,000 BHP and only 12 with greater than 2,000 BHP.”
Palladian Energy’s Elston is optimistic the drilling issues will be overcome. “Unlike pressure pumping which is dominated by Halliburton, Schlumberger and Weatherford, shale gas drilling companies can be formed by anyone as long as they can demonstrate competency. Onshore drilling is not all that different from offshore drilling and Europe has a tremendous human resource base of competent drilling engineers working in the North Sea. There will be no capital restraints, as there will be plenty of US private equity and European public market equity available for the right projects.”
Impact on gas prices
There is fear among environmentalists that shale gas will derail plans to decarbonize the power sector by choking investment in renewables and nuclear. The argument goes that shale gas, and therefore gas-fired power generation, is ‘cheap’, so there is no need to build expensive wind farms, solar panels or nuclear reactors.
European shale gas production costs, however, will remain far above conventional natural gas resources. According to the Oxford Institute for Energy Studies, Polish shale gas production costs in 2020 will be four times more than pipeline natural gas from Algeria and twice that of imported LNG from Qatar.
While in the US shale gas recovery has driven gas prices below their traditional oil-linked levels, the complex nature of European gas markets mean that oil indexation in gas contracts will remain for the foreseeable future. Elston says, “Rabid proponents who say shale gas will lead to lower natural gas prices are being disingenuous. What it does is offer a subsidy-free energy source with security of supply, jobs in depressed areas and government revenue, but it won’t change the need for zero-carbon sources of energy.”
Shale gas is not the environmental catastrophe some NGOs would like us to believe. Equally, shale gas is not quite the “cheap and abundant” source some proponents say. The shale gas ‘revolution’ appears to be not quite so revolutionary. At least, not yet.