The impact of unconventional fuels like shale oil on the global energy system is still an issue of great uncertainty. Not so much because of the size of the tank (the resource base), but due to the large physical effort necessary to obtain a sizeable supply of this type of fossil fuel. For instance, to exploit tight shale oil formations we need large capital expenditures to obtain relatively low flow rates from many horizontally drilled wells.
The developments of all things shale oil were discussed at a seminar organized by Allen & Overy and their Future Energy Strategies Group in London on 16 October, of which a summary and key take-away points can be found below the fold. With many thanks to both Allen & Overy and the speakers at this event for sharing their knowledge on these important developments in a public setting.
Key take-away points from speakers at Allen & Overy meeting:
Presentation (1) Justin Jacobs, Journalist or the Petroleum Economist
The first presentation about the big picture on shale oil was given by Justin Jacobs, journalist at the Petroleum Economist. He highlighted the importance of the US Eagle Ford & Bakken plays (approx. 27% and 63% of total shale oil supply), and emphasized large production expectations in the short term, with the EIA forecasting 1.5 million b/d shale oil production in 2013.
Figure 1 – Monthly dry shale gas production from January 2010 to June 2012 in the US.
The Petroleum Economist recently made a first map of oil & gas unconventional resources across the world, to be found here, which Jacobs used to demonstrate the large number of unconventional resource plays in the world. He picked two of the most important shale oil plays to keep an eye on for the future:
At present development has been slowed by the nationalisation of Repsol YPF by the Argentinian government who took a majority share. Because the investment required is at minimum several billions YPF is trying to find big players who are willing to invest, including Chinese firms and Chevron.
The key issue according to Jacobs is whether the large existing resources can be developed economically at sufficient scale. The development requires thousands of wells due to the steep decline rate, which necessitates the on-going development of a new services sector in the majority of countries with plays. Similar to calculations by Rune Likvern as well as Arthur Berman and Lynn Pittinger published at the Oil Drum, he cited shale oil development to require high oil prices at 80-90+ USD per barrel.
Another relevant point brought forward was that the abundance of shale gas in the US sent natural gas prices plunging. The effect is unlikely to be replicated in the oil market. The reason is the difference in market structure. The oil market is fungible in its imports and exports and requires a high oil price to meet demand. In contrast the US gas market is fairly closed with production being sufficient to meet domestic demand.
Presentation (2) Richard Sarsfield-Hall, Pöyry Management Consulting
The second presentation was given by Richard Sarsfield-Hall from Pöyry Management Consulting, who posed the question "Is shale oil the brave new hydrocarbon frontier?" He reiterated important common points on the US gas market:
The key issue presented by Sarsfield-Hall was about internal dynamics in the US market, as he sees a drilling competition occurring between the developments of dry shale gas reservoirs (Haynesville, Fayetteville) as opposed to shale oil reservoirs with associated natural gas (Eagle Ford) and shale gas reservoirs with associated liquids (Utica). This occurs because of more favourable economics for one versus the other in today’s market conditions (high oil price, low natural gas price in US). This is also possible because exactly the same type of rig is used for shale gas well drilling and shale oil well drilling. According to Sarsfield-Hall we already see this happening in today’s market, a point quantitatively further emphasised by the third speaker Tim Guiness, Founder Guinness Asset Management. He showed that well drilling has been overtly dropping in dry shale gas plays, while it has been constant or increasing in shale oil and shale oil with associated gas plays.
Figure 2 – Weekly US natural gas rig count and average spot Henry Hub price.
Figure 3 – Weekly US oil rig count and average spot price of WTI crude oil.
Figure 4 - Production of natural gas from various shale plays in the US from 2007 to 2012.
The implications of this competition are primarily affecting the expectations of institutes and market players, as the US may not produce as much natural gas as currently anticipated in the future, because the industry will be more motivated to drill for shale oil than shale gas. As Sarsfield-Hall puts it “There is a definite move of drilling from dry shale gas into shale oil with associated gas, the rush to shale oil potentially means insufficient shale gas delivered, which may result in higher gas prices and/or insufficient volumes to feed potential US LNG exports”. In addition Sarsfield-Hall showed EIA estimates which are primarily dry gas based increases, with little increase in associated gas from the expansion in shale oil. In terms of shale oil we are talking about a 10%-25% production share of total oil production in the coming decades according to EIA projections.
There were some numbers displayed. One key projection was for dry shale gas production, from a firm called ARC Financial, which showed decline expectation of 0.6 bcf/d up to 2013 from a current level of 23 bcf/d for dry shale gas production. Also some US associated gas production numbers were presented as per table 1, which is gas produced from oil fields (either free gas or dissolved in oil as a solution).
Table 1 – Expected US Associated gas production from oil wells shown by Sarsfield-Hall.
In the last part of his presentation he highlighted work POYPRY has been conducting for Cuadrilla, one of the major players in the EU which is trying to get shale gas production off the ground in multiple countries. The study was conducted to calculate the impact of shale gas development in Lancashire in the United Kingdom, the results of which will be published in a couple of weeks. The Lancashire shale basin is interesting according to Sarsfield-Hall because geological studies indicate the reservoir to be more than a 1000 feet thick, as opposed to US based shale plays which are in exceptional cases up to a hundred feet in thickness. This would in theory make UK shale gas in Lancashire much cheaper to develop. The information provided is preliminary, with full details about to be released by the British Geological Survey (BGS) in a report on UK shale gas resources and reserves.
In using Cuadrilla’s scenario for production POYPRY found that UK natural gas imports could be reduced by 21% by 2020-2025 through shale gas developments. Their conclusions were that this could drive natural gas prices in the UK 4-6% lower which would save consumers 810 million pounds per annum. It would not in his view impact the UK achieving its 2020 renewable targets and alter its power generation at the volumes discussed.
Presentation (3) Tim Guinness, Founder Guinness Asset Management.
The last presentation was from an investors' perspective, with Tim Guinness, chairman and founder of Guiness Asset management, and lead manager of their Global Energy Fund, presenting his views. He began by reiterating the reasons why the US has been able to develop their shale plays as:
He confirmed the switch from dry gas to shale oil/liquid rich shales with associated gas that is occurring, displaying rig figures per type of shale basin (predominantly shale oil, shale gas, and liquid rich with oil + associated gas). In addition he noted that the growth in gas supply has stopped in the US and is on a plateau, whereas oil production is growing substantially due to shale oil. He cited an onshore production estimate for December 2012 at 4.8 million barrels per day, which has been growing since 2008 after 38 years of decline since the peak in the 1970s, of which about 1.2 million b/d is from shale oil.
Figure 5 – US crude oil production to 2012 and forecasts from the EIA.
In his synthesis he compared three different estimates for shale oil production:
Table 2 – US oil production forecast for 2015 from Simmons & Co. Expectation based on 85 USD per barrel of oil and 3.50 USD per McF of natural gas.
Figure 6 - US oil production forecast from 2015 from Simmons & Co, with low, medium and high range scenario's varying due to oil price levels (75, 85, and 100 USD) and service industry drilling rate expectations.
Figure 7 - US oil import forecast up to 2015 from Simmons & Co as per the low, medium, and high range scenarios.
Figure 8 - US oil production forecast from shale oil from EIA.
The final point Tim Guinness discussed was marginal cost, which according to Tudor Pickering for the majority of shale oil plays requires 60 USD, with the highest costing ones amounting to 85-90 USD (see figure 9 for details). He also cited Bernstein Energy research which shows cumulative resources of 30 billion barrels of US shale oil to be available at a cost below 150 USD per barrel. Some of the plays have a very low cost range, such as the Eagle Ford, where a figure of 40 USD per barrel was cited (Tudor Pickering shows this play around 60 USD).
Figure 9 – marginal cost in oily shale plays and other oil basins in the world per comparison from Tudor Pickering.
Figure 10 – marginal cost for shale gas plays according to Tudor Pickering.
Finally in his conclusion, as per recent Bernstein Energy research, Tim Guinness stated that shale oil is not a game changer for these specific reasons:
In Tim Guinness' words: “It is akin to something like the discovery of the North Sea, Alaska or GOM. A useful addition but not a game changer, as the world needs 5 new North Seas every 20 years to provide enough oil to meet growing demand.”
Previous articles on Shale Oil and Shale Gas at The Oil Drum