Friday, June 8, 2012

International Energy Agency IEA sets out the “Golden Rules” needed to usher in a Golden Age of Gas

Exploiting the world’s vast resources of unconventional natural gas holds the key to a golden age of gas, but for that to happen governments, industry and other stakeholders must work together to address legitimate public concerns about the associated environmental and social impacts. A special World Energy Outlook report on unconventional gas, Golden Rules for a Golden Age of Gas, released today in London by the International Energy Agency, presents a set of “Golden Rules” to meet those concerns.

“The technology and the know-how already exist for unconventional gas to be produced in an environmentally acceptable way,” said IEA Executive Director Maria van der Hoeven. “But if the social and environmental impacts are not addressed properly, there is a very real possibility that public opposition to drilling for shale gas and other types of unconventional gas will halt the unconventional gas revolution in its tracks. The industry must win public confidence by demonstrating exemplary performance; governments must ensure that appropriate policies and regulatory regimes are in place.”

“If this new industry is to prosper, it needs to earn and maintain its social license to operate,” said IEA Chief Economist Fatih Birol, the report’s chief author. “This comes with a financial cost, but in our estimation the additional costs are likely to be limited.” Applying the Golden Rules could increase the cost of a typical shale-gas well by around 7%, but, for a larger development project with multiple wells, investment in measures to reduce environmental impacts may in many cases be offset by lower operating costs.
The report argues that there is a critical link between the way governments and industry respond to these social and environmental challenges and the prospects for unconventional gas production. Accordingly, the report sets out two possible future trajectories for unconventional gas:

In a Golden Rules Case, the application of these rules helps to underpin a brisk expansion of unconventional gas supply, which has far-reaching consequences:
  • World production of unconventional gas, primarily shale gas, more than triples between 2010 and 2035 to 1.6 trillion cubic metres.
  • The United States becomes a significant player in international gas markets, and China emerges as a major producer.
  • New sources of supply help to keep prices down, stimulate investment and job creation in unconventional resource-rich countries, and generate faster growth in global gas demand, which rises by more than 50% between 2010 and 2035.
By contrast, in a Low Unconventional Case where no Golden Rules are in place, a lack of public acceptance means that unconventional gas production rises only slightly above current levels by 2035. Among the results:
  • The competitive position of gas in the global fuel mix deteriorates amidst lower availability and higher prices, and the share of gas in energy use barely increases.
  • Energy-related CO2 emissions are higher by 1.3% compared with the Golden Rules Case but, in both cases, emissions are well above the trajectory required to reach the globally agreed goal of limiting the temperature rise to 2°C.

The Golden Rules underline the importance of full transparency, measuring and monitoring of environmental impacts and engagement with local communities; careful choice of drilling sites and measures to prevent any leaks from wells into nearby aquifers; rigorous assessment and monitoring of water requirements and of waste water; measures to target zero venting and minimal flaring of gas; and improved project planning and regulatory control.

At their recent Camp David summit, G8 leaders welcomed and agreed to review this IEA work on potential best practices for natural gas development. “To build on the Golden Rules, we are establishing a high-level platform so that governments can share insights on the policy and regulatory action that can accompany an expansion in unconventional gas production, shale gas in particular,” said Maria van der Hoeven. “This platform will be open to IEA members and non-members alike”.
Global investment in unconventional production constitutes 40% of the $6.9 trillion (in year-2010 dollars) required for cumulative upstream gas investment in the Golden Rules Case.

[In late 2011 the Australian Government decided] to establish an expert Scientific Committee, funded with AUD 150 million ($150 million) over four years, to oversee regional assessments and research on water-related impacts in areas where coalbed methane developments are proposed. 
A typical onshore shale gas well in the Barnett shale in Texas may currently cost $4 million to construct, while a similar well in the Haynesville shale costs twice as much, because of the depth and pressure. A similar well in Poland might cost $10 million to $12 million, because the current size of the market means that the drilling and service industry is much less developed in Poland than in the United States.
The cost of multi-stage hydraulic fracturing can add anything between $1 million and $4 million to the construction costs of a well in the United States, depending on location, depth and the number of stages. In a shale reservoir, when drilling a well with a long lateral section, roughly 40% of the total cost goes toward the drilling and associated hardware and the remaining 60% to well completion, of which multi-stage hydraulic fracturing is the largest component. In a conventional well, the completion cost would be only about 15% of the overall well cost.

Break-even costs of shale-gas production in the United States have fallen sharply in recent years, thanks to an increase in the proportion of horizontal wells, the length of horizontal sections and the number of hydraulic fracturing stages per well, as well as the benefits of ever-better knowledge and experience of the various resource plays. The share of horizontal wells in the total number of shale-gas wells drilled increased from less than 10% in 2 000 to well over 80% today. Over the same period, the average length of the lateral sections has increased from around 800 metres to well over 1 200 metres and the typical number of hydraulic fracturing stages has risen from single figures to around 20.

Operational costs, similarly, vary with local conditions: for example, just as for drilling, operating costs in Europe are expected to be 30% to 50% higher than in the United States for a similar shale gas operation. Dry gas requires less processing than wet gas (gas containing a small fraction of liquid hydrocarbons), but also has lower market value, particularly in the current context of very high oil-to-gas price ratios in some markets. 

It is worth noting that two of the key subsurface drivers of well cost – depth and well pressure – are expected to be higher in many of the areas being explored outside North America.
[Several Golden Rule measure can result in significant savings.]

Central purpose-built water-treatment facilities: these facilities, allowing closed-loop recycling of waste water, could be linked by pipeline to each pad location. They would reduce the overall water supply required for operations and minimise the need for offsite disposal, thereby reducing total transportation, water and disposal costs. Based on industry case studies, we estimate savings at $100 000 to $150 000 per well. A long-term monitoring program for the development: this could take different forms but might include performing a 3-D seismic survey over the licensing area before drilling commences to establish a geological baseline for the location of faults and sweet spots, as well as the temporary or permanent installation of micro-seismic monitoring to monitor seismic events and the propagation of fractures, and the installation of equipment to monitor the quality of water in aquifers that are being drilled through. We estimate the additional cost of these three measures at between $100 000 and $150 000 per well.

Systematic learning about the shale: this could involve taking the opportunity provided by each well to learn more about the reservoir by capturing data (typically by using down-hole measuring instruments) that will enable the character and behaviour of the shale to be better understood. This understanding is an important contributory factor in improving the operational performance (and therefore the environmental impact per unit of production) of each well drilled and in eliminating wells and fracture stages that do not contribute significantly to production. We estimate the additional cost at $200 000 per well.
Exploiting economies of scale: pad drilling and the associated ability to carry out simultaneous operations on more than one well has been shown to bring significant cost savings as well as reducing the total surface footprint. Typically the drilling phase of a number of wells on the pad would be finished first, enabling the completion phase to be carried out for multiple wells in parallel. “Simultaneous operations” of this sort can allow for more efficient use of equipment for hydraulic fracturing. The US company, Continental Resources, has reported a 10% drop in average well cost in the Bakken Shale, from $7.2 million to $6.5 million, by using such an approach at eight well pads. Other industry sources report savings of up to 30%, due to a combination of economies of scale and improvements in operational efficiency. On this basis, we have estimated savings of 10% per well.
Optimising the number of fracture stages: this can achieved by acquiring better information about where the sweet spots are likely to be and fracturing only in those zones, rather than simply fracturing every 100 metres, with no science applied. Industry data from different shale plays in the United States show that, on average, between 30% and 40% of fractures do not contribute any production at all. We have assumed conservatively that at least two hydraulic fracturing stages out of twenty could be saved as a result of better reservoir characterisation by systematically learning about the shale. This would represent a cost saving of around $400 000 per well or equivalent gains in production for the same number of stages.
Summing up the effects of the more stringent environmental measures applied to the development and the efficiency savings from better planning yields an overall net cost saving of approximately 5%. Most of these savings come from economies of scale and reduced hydraulic fracturing, which more than offset the additional cost of implementing well-specific measures and monitoring environmental effects.
The break-even costs for gas can vary greatly from one location to the next, or within a single country (Table 2.2). For example in the United States, break-even costs for dry gas wells probably range from $5/MBtu to $7/MBtu; gas containing liquids has a lower (gas) break-even cost, which can be as low as $3/MBtu, as the liquids add considerable value for a small increase in costs (associated gas from wells producing predominantly oil can have an even lower break-even cost). \

Since conventional gas resources are already fairly depleted onshore and most future conventional gas production will therefore come from more expensive offshore locations, the range of break-even costs for conventional and unconventional gas in the United States is fairly similar.

In Europe, the costs of production are expected to be about 50% higher, with a range of break-even costs between $5/MBtu and $10/MBtu. Conventional and unconventional gas are expected to be in the same range, as conventional resources are depleted and new projects are moving to the more expensive Norwegian Arctic. China has a cost structure similar to that of the United States, but shale reservoirs there tend to be deeper and more geologically complex; similarly, coalbed methane reservoirs in China tend to be in remote locations, so we estimate the break-even cost range to be intermediate between that of the United States and that of Europe ‒ from $4/MBtu to $8/MBtu (although there are production subsidies in place that can bring this figure down). This estimate for China applies to both conventional and unconventional gas, as the easy conventional gas is depleting and production is moving to offshore or more remote regions. In countries that have large, relatively easy, remaining conventional gas, such as the Middle East, with break-even costs of less than $2/MBtu, the break-even cost range for unconventional gas is expected to be higher (similar to that for unconventional gas in the United States).

International Energy Agency (IEA)
Press Release dated May 29, 2012

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