Drilling Deeper Reloaded – 2016 Tight Oil Reality Check
It has been over two years since Drilling Deeper, a report written by earth science and energy expert David Hughes on the ultimate potential of US tight oil and shale gas. The report offered an alternative analysis to numbers and estimates published by the EIA of the US Department of Energy in its annual industry benchmark setting publication called the Annual Energy Outlook (AEO2014 was the publication for that year). In Drilling Deeper, Hughes challenged the estimates put out by the EIA report as being very optimistic and cautioned any business decisions and, more importantly, national energy policies based on such optimistic estimates.
For those not familiar, David Hughes’ career in energy resources has spanned over four decades in which he researched, published and lectured on global energy and sustainability issues in North America and internationally. In one of his prior reports, he similarly challenged the EIA’s estimates of technically recoverable tight oil in the Monterey Shale which the administration hailed as the next mind bogglingly huge oil find, a claim which it subsequently had to write down by 96% in an embarrassing about-face.
In 2016 Tight Oil Reality Check, Hughes continues where he left off in Drilling Deeper. Two years had passed since that last report and two more Annual Energy Outlooks (AEO2015 and AEO2016) had since been released by the EIA. This latest report overlays the estimates put out by the three EIA reports as well as his own estimates from Drilling Deeper.
His assessments or the ‘state of the union’ of the US tight oil plays and challenges to the EIA’s numbers are based on detailed and in-depth drilling and production data to date in most if not all plays. The report is worth a read in its entirely for those who want to know more about the subject beyond the superficial level.
Here are some backgrounders to set the context.
- Both Drilling Deeper and AEO2014 were written in 2014, before the oil price collapse.
- The vast majority of the US tight oil is concentrated in three plays: the Bakken, the Eagle Ford and the Permian Basin. The Bakken and Eagle Ford constitute 49% of tight oil production. The Permian Basin is broken up into the Spraberry, Wolfcamp and Bone Spring in the AEO reports.
- The Eagle Ford and Bakken productions are down 31% and 18% from their respective peaks. Five of the major plays collectively peaked in March 2015, and were down 24% as of June 2016.
- Since the March 2015 peak, total tight oil production was down 19% as of November 2016.
Production Forecasts Comparison
The diagram below overlays the latest EIA 2016 production estimates against their own estimates published in 2015 and 2014 as well as the likely estimates provided by Drilling Deeper in 2014.
Overall, the EIA has revised their total production estimates upwards in its successive reports. The 2016 report projects that production will continue to increase, peak and maintain a permanent plateau through to 2040. In other words, there is no shortage of abundance when it comes to tight oil supply.
Based on play-by-play analyses, the report assigns an optimism bias rating to the EIA estimates on each play. Except for only two of the eight plays which receive ‘moderate bias’, the optimism biases for the rest vary from high to extremely high.
These bias ratings were assigned based on the following rationale.
- The EIA’s net increase in cumulative production between 2015 and 2016 is based on its extremely optimistic revision of the Bakken. Compared to his own estimate in Drilling Deeper, the AEO2014 projection overstated 2014-2040 production by 42%, and the AEO2015 projection by 92%, the AEO2016 projection is overstated by 115%. There is no apparent basis for the Bakken increase, other than the assumption that vast undrilled areas of the Three Forks will become highly productive.
- Future production of tight oil plays is a function of well quality, drilling rates, decline rates and the number of available drilling locations. These are dependent on geology and technology.
- With regard to geology: Tight oil plays have a restricted areal extent, and all have higher productivity “core” areas or “sweet spots”, which typically cover 15-20% of a play’s area.
- High decline rates are a fact of life with tight oil plays, and new technology has not changed that.
- With regard to technology: the fossil fuel industry has responded to the challenge of low oil prices by focusing drilling on “sweet spots”— a practice known as “high grading”—and applying more aggressive technology. This has resulted in average well productivity going up in some plays. Most of this increase is due to high grading, with about a third due to better technology. Technology has certainly improved individual well production, but as each well can now drain more of the reservoir it has reduced the number of locations available to drill. The net effect is that, at a constant drilling rate, better technology will exhaust a play more quickly at a lower cost—but will not substantially increase ultimate recovery.
- The improvement in the number of wells a rig can drill per unit of time has partially offset the effect on production of the steep decline in rig counts since mid-2014, and has improved economics. The service industry’s rate cuts have also had a major impact on the economics of the average well. But there are a limited number of drilling locations in sweet spots, and high grading plus the downturn in oil prices has resulted in their exhaustion at disproportionately high rates, leaving higher-cost oil for later. An analysis of top counties in plays like the Bakken and Eagle Ford shows that average well productivity has begun to decline, meaning that the best locations have been exhausted along with possible well interference (from wells being drilled too close together).
Last but certainly not least and perhaps the most critical criticism leveled against EIA’s reports is the apparent wild fluctuations of data within the span of three reports (most of which adjusted upwards over time) in face of the fact that geological fundamentals of the major tight oil plays are now relatively well known and don’t change wildly from year to year.
One measure of the potential reliability of future production estimates from the EIA is how much successive forecasts change over time. Certainly everyone is entitled to change their mind, but the geological fundamentals of the major tight oil plays are now relatively well known and don’t change wildly from year to year. Although average well productivity has increased somewhat in some plays in the last two years it has declined in others (Figure 4), so large differences in technology cannot account for major differences between projections. Wild swings in projected production rates and cumulative recovery between forecasts, in the absence of significant new information to account for it, indicates a basic lack of robustness in the methodology used for estimation.
Despite the fact that the EIA projections by play examined herein were made only one year apart, they exhibit major differences in future production rates and in estimated oil recovery. Figure18 illustrates the magnitude of production rate differences between AEO2015 and AEO2016 by play in percentage terms. Plays have been revised both upward and downward by amounts exceeding 50 percent in some plays/years, but overall have been revised upward, and 2040 production has been revised upward in all plays.
The EIA offers no explanations for the volatility and optimism of its projections. Geological fundamentals appear to have little to do with it, given that major plays are now quite well understood. Assumptions of vastly improved technology in the future may be a factor, although improvement in average well quality has stagnated or is falling in some of the core area counties of major plays like the Bakken18 and Eagle Ford19 as sweet spots are drilled off. Another factor may be the assumption of much closer downspacing, resulting in far larger numbers of available drilling locations than previously thought, although well interference is already being observed in top counties of the Bakken and Eagle Ford, which discounts this. In the case of the Bakken, vast undrilled areas have been assumed to be prospective from the Three Forks, and production has been added from this source by the EIA, but this remains highly speculative at best. The volatility between successive forecasts and the increase in overall production cannot be attributed to changes in future oil price assumptions either, given that prices for WTI are at or lower in AEO2016 than AEO2015 through 2030 and are $6.56/barrel lower in 2040.
The volatility, optimism, and lack of transparency in EIA tight oil production projections inspire little confidence in their reliability. This is a major concern for future energy policy decisions given the weight that many in government and industry place on them.
In other words, the wild swings from year to year in the absence of changes in fundamentals or quantitative evidence make the reliability of these reports highly suspect.
The report concludes with a stark warning about how important decisions are made by government and industry based on these important official publications whose methodology and conclusions might be wildly off the mark.
The EIA’s projections for oil production are very important, as they are widely used by industry and government policy makers as a definitive estimate of what is likely to happen. The crude oil export ban has been lifted after 40 years on the assumption that tight oil production will be robust for the foreseeable future at relatively low prices. Getting it wrong has very serious implications for energy policy and future energy security, considering that the EIA is the country’s premier source for future production projections. This analysis shows that the EIA has erred on the side of extreme optimism in its tight oil production forecasts, which are highly unlikely to be realized.
Again, the full report can be downloaded here.