Article:Rystad Energy forecasts U.S. oil production at 9.9 mmbbl/d December 2017
Article:Shale investment and conventional asset sales
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We have recently observed strong empiric evidence for the theory that a positive tendency in initial production rates for shale wells does not always lead to similar improvements in ultimate recovery.
One of the mature U.S. onshore plays, Eagle Ford, was particularly exposed to accelerated decline rates. While activity collapsed dramatically in 2015 from peak levels in 2014, Eagle Ford maintains its leadership across the liquids plays when it comes to the total number of horizontal wells drilled and completed historically. With the shift to more intensive completions, infill drilling and down spacing on older pads, several major Eagle Ford operators have recently been communicating faster reservoir depletion, compared to the decline rates that were observed in the early years of Eagle Ford development.
Figure 1 illustrates the breakdown of quarterly horizontal drilling activity in Eagle Ford by well type. The first horizontal well in each section is classified as a parent well. If there are two or more simultaneous first completions on the pad, they are both classified as parent wells. All subsequent completions are classified as infill wells. Back in 2010, up to 90% of activity corresponded to new pad development. This share declined rapidly over time, falling to 15-20% in 2015-2017. While we still observe new pad development (e.g. by new major entrants like WildHorse Resource Development), a dominant part of the recovery in 2017 was driven by infill development.
Karnes and De Witt counties, one of the core areas of Eagle Ford, accounted for 30-36% of total Eagle Ford activity in 2015-2017. In fact, Karnes County is the only significant county in Eagle Ford where activity has already returned to the peak level of 2014. This area was particularly exposed to the penetration of infill drilling. Hence, it is important to address the changes in the decline rates over time.
Figure 2 shows the evolution of average first-year decline curves from 2011 to 2016, including only the wells that produced for at least 13 months.
We conclude that average production rates in the peak production month (typically month 0 or 1) increased continuously over time in both counties. In De Witt County, the peak production rate increased by 80-90% from 2011-2013 to 2015-2016. In Karnes County, the peak rate has more than doubled from 2011 to 2016. However, when we look at the average production rate in month 12, we don’t see a similar outperformance of recent completions. In fact, in De Witt County, wells from all vintages typically produce 190-260 Bbld in the 12 months after they are turned-in-line, with 2015 being the worst year. In Karnes County, well completions from 2015-2016 also struggle to outperform completions from previous years. Essentially, a typical completion from 2016 delivers only 40 MBbl of additional oil production during the first year when compared to a completion from 2011 and enters the second production year with a similar production rate to the well from 2011. By any means, this cannot be classified as a significant uplift for the well ultimate recovery when considering a 100% increase in the peak production rate.
Some of the changes in average decline curves over time are explained by portfolio effects. The structure of activity in Karnes County and Eagle Ford has been changing continuously with different operators, acreage positions and completion techniques contributing to the total activity with different weights in different years. Therefore, it is important to look at individual leases to examine well productivity in an accurate way. In some cases, this approach reveals an even more drastic difference in well productivity between parent and infill wells.
Figure 3 illustrates one example of such a lease. It is Marathon Oil’s Davila Unit lease in Karnes County. Two parent Eagle Ford wells were completed back in 2012 with lateral lengths around 4,900 feet and moderate frac fluid loadings of 11 barrels per foot. The wells peaked at an average rate of 35.6 MBoe per month in August 2012 on a two-stream basis, and the average production rate fell below 8 MBoe per month by September 2013 (13 months after peak production was reached). Over a five-year period these wells produced 350 and 420 MBoe respectively.
A major completion round was run in late 2016, with eight infill Eagle Ford wells and three Austin Chalk completions coming online in December 2016. These completions were significantly more intensive compared to the parent wells, with 5,800 – 7,200 ft laterals and an average fluid loading of 23 barrels per foot. Nevertheless, only four of these completions were able to outperform parent wells in terms of the peak production rate, while the average rate in a peak month was observed at 32.5 MBoe for Eagle Ford wells and 28.9 MBoe for Austin Chalk completions. Moreover, the average production rate for these recent completions fell below 8 MBoe per month just seven months after the peak month, indicating faster reservoir depletion than for the parent wells. After 10 months on production, cumulative recovery averaged at 150 MBoe, a 17% underperformance when compared to the parent wells.
Finally, it is worth mentioning that Marathon Oil executed another completion round in the Davila Unit in August 2017 with even more intensive completions. Four new Eagle Ford wells and one Austin Chalk completion most likely came online in 3Q 2017, but production results from these infill completions are yet to be seen in the official state filings.