(John Kemp is a Reuters market analyst. The views expressed are his own)
By John Kemp
LONDON, June 4 (Reuters) - Britain’s politicians and petroleum explorers are promoting increasingly optimistic visions about the country’s shale gas future. But the only way to gauge the potential properly is to start drilling and fracturing wells.
So far, only a handful of wells has been drilled specifically to explore shale formations, and only one well has been fractured.
Estimates for shale gas are therefore based on models which take into account the thickness and extent of shale formations, their organic content, thermal maturity and porosity, and draw analogies with similar shale formations in the United States.
“The UK shale gas industry is in its infancy, and ahead of more drilling, fracture stimulation and testing there are no reliable indicators of potential productivity,” the British Geological Survey warned readers of its 2010 estimate of “The Unconventional Hydrocarbon Resources of Britain’s Onshore Basins.”
“Resource estimates can only be made by analogy with producing shale gas plays in America,” BGS explained. “Ahead of drilling, hydraulic fracturing and flow testing these analogies may ultimately prove to be invalid.”
Formations vary enormously in their productivity, depending on the amount of pore space, organic content, how much organic material has been converted into oil and gas, and how much clay is present and therefore how easy it is to prop open the fractures once the formation has been fracked.
Even within the same formation, different areas and different wells can yield vastly different amounts of oil and gas.
Like Texas and North Dakota, Britain will need to drill and fracture hundreds of wells before the country’s shale gas production potential can be predicted with any confidence.
In 2010, BGS conservatively estimated Britain’s potential shale reserves could be as high as 150 billion cubic metres (5.3 trillion cubic feet), enough to supply the country’s needs for about 20 months.
BGS is currently updating its estimates, which are expected to show large upward revisions when they are published region by region, starting with the North of England.
But exploration and production companies have already begun to publish their own estimates showing far larger resources.
On Monday, IGas Energy captured the headlines and stoked the country’s shale fever by saying there were likely to be 102 trillion cubic feet, and possibly up to 170 trillion cubic feet, of shale gas under 300 square miles of Northwest England where it has exploration and production licences.
“Our estimates for our area alone could mean that the UK would not have to import gas for a period of 10 to 15 years” IGas Chief Executive Andrew Austin told the BBC.
Britain’s Institute of Directors (IOD) said last month shale gas development could create tens of thousands of jobs, reduce imports, generate significant tax revenue and support British manufacturing.
The problem is that all these estimates have been constructed on a very slender base of evidence.
“IGas has constructed a geological model utilising 320 kilometres of reprocessed seismic lines, subsurface data ... from about 20 offset wells and geological data from IGas’s well at Ince Marshes,” the company explained.
“This data has been analysed to give estimates of the reservoir characteristics of the shale formations and the thickness of the shale. Based on this model, IGas has estimated the volume of gas initially in place (GIIP).”
In other words, the company has drilled, but not fractured, one well itself, and acquired data from 20 others in the region, none of which has flowed shale gas on a sustained basis, and coupled that with seismic and other data, to produce an estimate for the total amount of gas that might be contained in shale formations over an area of 300 square miles.
No wonder its estimate for the GIIP ranges from practically nothing (15.1 trillion cubic feet) to an enormous amount (172 trillion cubic feet), with a most likely estimate somewhere in the middle (102 trillion cubic feet).
Based on IGas’ model, the region could contain shale gas equivalent to anywhere between 5 years and 54 years worth of Britain’s consumption, though in practice, much less will be technically and economically recoverable.
The original aim of the well at Ince Marshes was to explore the coal seams in the area for coal-bed methane potential. But when the seams were encountered at shallower depths than expected, the company carried on drilling into the underlying shale, where the hydrocarbon potential “surpassed our expectations”.
“Clearly further wells and analysis are required to fully appraise the shale and critically flow tests need to be performed, however our results combined with those of operators in neighbouring licences in the Bowland shale are extremely encouraging,” IGas wrote candidly in its 2011/12 annual report to shareholders.
IGas is “one of the leading producers of onshore hydrocarbons in the UK,” according to the company. Its total output amounted to 2,700 barrels of oil equivalent per day at the end of March 2012.
Substantially all of that came from acquiring Star Energy Group in December 2011, including Star’s inventory of 247 oil and gas wells, some 85 of which are still operating.
This is all from conventional oil and gas wells - including eight fields in the Weald Basin in Hampshire and Sussex, one of which nestles, virtually unknown, in the fields at Stockbridge, near my home town of Winchester.
In the year to March 2012, IGas drilled just three new wells, including the one at Ince Marshes, according to its annual report.
Like its better-known rival, Cuadrilla Resources, IGas is essentially a promoter and pioneer of the shale concept. Publication of optimistic estimates is intended to build interest among investors to help finance the enormous capital cost of drilling more exploration and production wells.
In the United States, thousands of shale wells have been fractured, allowing companies to identify the most attractive plays and the sweet spots in each one.
The prolific gas-bearing Barnett shale in Texas is not a good analogue for the potential of Britain’s own shales, BGS wrote in its 2010 report.
Instead, the best analogies are probably to Michigan’s Antrim shale and the little-developed Conasauga shale in Alabama. Far less is known about their productivity.
The only way to test Britain’s shale potential is to start drilling and fracturing wells to test how much gas they flow, and experiment with different techniques and configurations for the wells and the fracturing operations to see which work best.
IGas plans to start a drilling programme in the fourth quarter of 2013, and has already ordered long lead-time items such as wellheads and casings.
The drilling programme will allow the company to “further refine these estimates and advance our understanding of this shale basin” in the Northwest.
For the industry as a whole, drilling and fracturing dozens or hundreds of wells will be expensive and highly risky.
Investors must be convinced that the potential rewards are worth the costs and the risk. Optimistic estimates about how much shale gas is potentially recoverable are part of the process of building a case for investing.
The resource estimates published by BGS, IGas and Cuadrilla are best thought of as Bayesian first guesses that will be substantially updated in the light of experience from actual drilling.
With only one well fractured so far, it would be premature to start relying on a shale gas boom transforming Britain’s economy. The potential is there, but it can only be proved by wheeling up the heavy equipment and getting down to fracking.
Editing by Keiron Henderson