« Bad Actors Hurt Eagle Ford Shale Well Performance February 8, 2015Posted in The Petroleum Truth Report on February 8, 2015
February 8, 2015
Recent well performance in the Eagle Ford Shale play has declined among key operators. This is due in part to especially poor well performance by a few operators. Excluding those operators, well performance for 2013 and 2014 was still poorer than in 2012 but improved in 2014 compared with 2013.
When I wrote that Eagle Ford well performance was declining in a recent post, some readers were indignant as if a shale play somehow deserves a pass on the laws of physics and eternally gets better instead of eventually declining as all plays do.
“Never confuse production with reserves” is one of Halloran’s Immutable Principles of Energy. Wells may produce at relatively high rates but never reach commercial reserve levels because of cost or declining well performance over time despite high initial rates. Published analysis of shale plays too often stresses success based on production volumes but not reserves, production rates but not the cost, the benefits of technology but not its price, and claims of profit that exclude important expenses.
Below is an example of well interference and rate acceleration in the Eagle Ford Shale play where an operator has over-drilled an area with bottom-hole locations approximately 300 feet apart. EUR values are shown for each well. None will be commercial because the wells are cannibalizing production from each other. Approximately $150 million in capital cost was spent on the non-commercial wells shown on this map.
Example of well interference and rate acceleration in Eagle Ford Shale play in Dimmit County, Texas. Closely spaced wells are shown with EUR values. Source: Labyrinth Consulting Services, Inc. Data from Drilling Info.
(Click to Enlarge)
The Eagle Ford Shale play is perhaps the most successful of the tight oil plays in the U.S. Below are maps showing the commercial core areas in green for $70 and $45 per barrel WTI oil prices.
Despite assurances by operators and fawning analysts that break-even price is whatever the new low price of oil is today, it is clear that there is almost nothing commercial in the play at $45 oil prices, and the $70 commercial area is fairly small.
This study, however, is not about break-even prices. My focus is on evaluating trends in reserves or EUR (estimated ultimate recovery). This involves decline-curve analysis that I won’t go into here except to say that it is the industry standard and I had the details reviewed by technical experts.
I evaluated well performance by the leading operators in the play–those companies with the largest number of wells shown in the table below.
I limited my study to wells with single-well production reporting. In Texas, oil wells may be reported by lease and this means that many wells are reported as one. Those wells are impossible to evaluate based on publicly available data.
I evaluated wells in vintaged groups by operator meaning that I separately forecasted EUR by year of first production by individual operator to account for changes in technology and differing completion practices among operators. The results are shown in the table below.
Overall, 2012 was the best year for well performance for the group with an average well EUR of 310,175 BOE (gas was converted to barrels of oil equivalent–BOE–using a value basis of 16:1 based on $50 oil and $3 gas prices). Results for 2013 and 2014 were substantially lower than for 2012 with EUR of 223,311 and 233,748 BOE, respectively. The average EUR for all years and operators was 258,211 BOE which is commercial at $95 but not at $70 WTI oil price.
Looking at the individual operators, it is clear that Anadarko (APC) and BHP Billiton (BHP) significantly under-performed the rest of the group. Anadarko had the most wells used in this study (upper table) so their results significantly skewed the group weighted average well performance. The table below shows the results when APC and BHP were excluded from the group.
In this case, well performance for the group was lower in 2013 (290,986 BOE) and 2014 (326,659 BOE) compared with 2012 (359,702 BOE) but not as low as in the previous table and with much stronger performance in 2014. Chesapeake and EOG had their strongest years for EUR in 2014. It is important to note that approximately 75% of EOG’s wells are reported on a multi-well lease basis and therefore could not evaluated in this study. It is probable that EOG’s performance is better than my results suggest. Similarly, Marathon and Chesapeake have significant multi-well lease reporting.
There are 4 core areas for the Eagle Ford Shale play shown on the map below.
The following table shows the percent of wells by key operators in those core areas. Anadarko and BHP have the lowest percentage of their total wells in the core areas. It is clear that well performance is tied to location within core areas of the play. Other companies not evaluated in this study that are represented within core areas include Devon Energy, Encana Corporation, Rosetta Resources, Murphy Oil Corp., SM Energy, Carrizo Oil & Gas, Fasken, Lewis Petro, EP Energy, SN Operating, 1776 and Matador.
The key observations that come from this study include:
- EUR is the best way to evaluate well performance.
- Production rate and volume analysis may be deceptive because cost is not a factor.
- Performance varies by operator and is mostly a function of location in core areas.
- Even within core areas, well performance varies.
- Operators have not cracked the code on shale plays and still drill poor wells despite the best science, location and completion methods.
- All plays mature and decline and shale plays are no exception.
- Companies should be held accountable for poor well performance and not evaluated solely on production growth.