Chemistry & Life Sciences

Effect of Global Shale on the GCC

Assessment of Regional Shale Development

15.12.2013 -

Hydrocarbon Building Blocks - Exploitation of shale deposits in the U.S. has risen quickly and will continue to intensify in the coming years as technology and expertise improve and extraction costs decline. Gulf Cooperation Council (GCC) countries must build on their hydrocarbon background to extend their coverage of the chemical value chain until they may be able to tap into their own shale plays.

Before discussing any implications of the shale boom on GCC countries, it is reasonable to briefly describe global developments in this field. While the U.S. had negligible production rates of shale gas and shale/tight oil as recently as five to 10 years ago, production rates from shale in 2012-2013 are impressive:

• Methane: 170 million tons/year (≈ 8.5 trillion cubic feet [tcf]/year)
• Natural-gas liquids (NGLs): 18.5-37 million tons/year (≈ 0.5-1 million barrels/day)
• Shale/tight oil: 95 million tons/year (≈ 1.9 million barrels/day)

Among other reasons, significant improvements in drilling, fracking and overall extraction technology have made this boom possible. Learning-curve effects (typical example in Marcellus: decrease of well costs from $8 million to $4 million within a larger project) will lead to further cost reductions and yield increases, which will ensure that the boom will last beyond the period of picking only the lowest-hanging "unconventional fruits."
Because of the massive increase in domestic oil and gas production, the U.S. is forecast to become a net liquefied natural gas (LNG) exporter by 2020 at the latest, and in the same year will satisfy domestic oil demand to a large degree via its own regional sources. Furthermore, polyethylene exports are expected to nearly double in the period from 2013 to 2020.

Other countries pursue exploration activities and production plans for unconventional gas and shale/tight oil to very different degrees. Countries with expected commercial projects for unconventional gas production in the long term include (all figures are estimations for 2020 in tcf/year, with shale gas being a substantial part in most cases) Canada: 3.5 tcf/year, China: 2.8 tcf/year, Australia: 2.1 tcf/year, Europe (all countries): 0.3 tcf/year, Mexico and Argentina: 0.2 tcf/year each. In contrast, shale gas production in the U.S. is expected to exceed 11 tcf/year by 2020 and hence will dominate global production volumes in shale gas.

As the wetness of the basins outside the U.S. is not yet sufficiently known, NGLs and shale/tight oil production projections outside the U.S. remain highly speculative. However, given the time required for exploration and developing the infrastructure to produce, fractionize and transport NGLs from shale and/or tight oil, it is reasonable to state that no region outside the U.S. will reach production rates with a global market effect until 2020 at the earliest.

The U.S. will maintain its competitive advantage in shale gas as a feedstock and energy carrier at least until 2020, in particular when compared with Europe and East Asia. Prices for natural gas in 2013 are (average January-June) $4 per million British thermal units in the U.S., $12 per million Btu in Europe and $16 per million Btu in Japan. Because of the high costs for liquefaction and transport of LNG, global arbitrage will reduce these interregional price differences only by a few dollars per million Btu.

Availability of large volumes of hydrocarbons at low prices drives investments in power production from gas, ethane crackers and chemical plants producing ethylene derivatives, fertilizers and other products that have the "shale gas advantage." As a consequence, a number of affected production sites, especially in Europe, are already experiencing declining margins and it is expected that older and less efficient crackers and basic chemicals capacities in Europe will be shut down in the medium term.

Opportunities in the Unconventionals Boom

Investments in involved companies, plants and other related projects in North America are an obvious option to participate in the U.S. boom. Qatar Petroleum, for example, has acquired exploration and production assets from Suncor Energy together with its partner Centrica. The problem is that the time for bargains in this market is over, thus any investments require careful evaluation.

Despite this, there are presumably significant unconventionals opportunities in the GCC countries. From both geological analysis and already existing exploration data, it is clear that the likelihood of high concentrations of gas, NGLs and oil in shale formations is highest in areas with abundant conventional resources. Indeed, first estimations of shale resources in the GCC confirm that, with more than 700 tcf of shale gas, including supposedly significant amounts of NGLs and shale/tight oil, the regional resource opportunities are tremendous.

Resources are only real opportunities if they become reserves (economically extractable), and this is the critical issue. Why should a region historically blessed with one of the world's largest concentrations of inexpensively accessible conventional oil and gas deposits be interested in extracting more-costly unconventionals?

There are four main reasons:
• Deposits of cheaply extractable oil and gas are declining, especially outside Qatar.
• Production rate of associated gas is limited by oil production rate.
• Demand for gas in the region is high and increasing.
• Access to Qatar's gas surplus is in competition with global demand.

These reasons explain why there is a gas shortage among GCC countries (except Qatar), both for methane as an energy carrier and for ethane as a feedstock for regional ethane crackers. Regions with shale gas and shale/tight oil deposits have already been identified, mostly in Saudi Arabia, Oman, Kuwait and United Arab Emirates (fig. 1). Development of unconventionals in the GCC is in its infancy. Only a few exploratory measures and test wells have been performed so far. Promising indications of available resources and manageable costs are expected to drive further exploration and yield more detailed data on the unconventionals potential in the GCC.

Assuming that abundant resources lie below the Arabian Peninsula, the main success factors for large-scale production of unconventionals are supportive politics and regulations, as well as competitive production costs. Due to the long history of the hydrocarbon business, high dependence on energy and downstream feedstock, and the lack of strong public opposition (unlike, for example, in Europe), GCC governments have a supportive mindset and will presumably handle regulations pragmatically to enable large-scale projects. The cost issue is more challenging and certainly deserves a quick analysis of the influencing factors.

Costs for shale gas production are driven by the geology (especially depth of shale formation), topography, water availability, technology and infrastructure. A significant part of the deposits in the GCC (for example, in the empty quarter) is located in unfavorable desert environments, which is a serious obstacle for profitable well development. Moreover, 5 million to 20 million liters of water per well are currently required, and water is scarce.

Despite the challenges, there is room for optimism. Because of their large conventional oil and gas sector, GCC countries have oil and gas infrastructure, services and staff that facilitate building up an unconventionals business. In addition, sufficient unconventionals areas are accessible and new concepts are being developed to reduce water requirements through recycling or fracking without water ("dry-fracking"). According to our analysis and experiences from other regions, shale gas extraction costs might initially be around $15 per million Btu, slightly above the costs in the early U.S. shale boom days. These costs are expected to decrease in the short term to $10 per million Btu in favorable locations and might further decrease with progress on the regional and local learning curve.

Commercial Production

Experts frequently give 2020 to 2030 as the time frame in which unconventionals will be broadly produced commercially in GCC countries. It is important to keep in mind that, while local unconventional gas will not be cost-competitive compared with regional conventional gas in the foreseeable future, it can be cost-competitive compared with imported LNG and hence fill the gas gap in concerned countries like Kuwait, Saudi Arabia and United Arab Emirates (figure 2). Using oil as a substitute for gas, e.g., for energy production in countries with abundant oil, is not reasonable because of the much higher price per million Btu for oil.

If shale resources in GCC countries are wet, as experts assume, the incentive to explore and extract NGLs in addition to methane becomes even more attractive. Firstly, NGLs are priced well above methane, and byproduct credits could reduce break-even costs by up to $5 per million Btu. Secondly, ethane would be available as cracker feed. This is very important for cracker operators in Saudi Arabia, who have had difficulties with allocation of sufficient ethane for full-capacity utilization in previous years. The current approach to base new cracker projects on more-expensive mixed feedstock could in the long run be replaced by a trend to use ethane as a predominant feedstock again. Ethane from shale may cost up to $700 per ton (≈ $15 per million Btu) to yield ethylene at similar cost to ethylene from regional naphtha crackers. The quick cost assessment above indicates that if prospective wet basins are found in GCC countries, ethane production costs below $700 per ton are realistically possible (fig.3).

According to recent forecasts, the gas shortage will become more severe in the GCC (except Qatar) in the coming years. This will presumably drive exploration for unconventionals and - if first findings are promising - lead to large-scale commercial projects across GCC closer to 2020 than 2030. Oman even has ambitions to go commercial in the production of unconventionals already in 2017.


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