In this blog we are going to look at horizontal well type curve trends in the Barnett Shale for the most active operators based on latest well count and latest production. We are only including horizontal wells in our dataset because in the last several years horizontal drilling has open the industry up to be able to take full advantage of shale plays in a way that vertical wells could not… and vertical wells are old school. We can see in the table below that Devon Energy, Chesapeake, and XTO (ExxonMobil) make up our list of 3 based on the aforementioned criteria.
First we will look at a plot of overall horizontal well type curves for the Barnett Shale for each operator. To help normalize the operators we are only including horizontal wells that came on after 1/1/2004. We chose this date because all operators have horizontal wells that came on in 2004 and forward. Keep in mind that Chesapeake was the late starter in the play with their first horizontal well in Jan 2004 while XTO has horizontal wells that have been producing from the Barnett since Feb 2002 and Devon since Mar 1992. One could argue that Devon has quite a bit more play experience then the other 2 operators but we can see in the graph that that does not necessarily equate to a better type curve.
Other factors such as the quality of the operator held acreage and operator learning curve play big roles in the success of operators. In this blog about type curves we won’t get into evaluating acreage quality but we will take a look at each operator’s vintage type curves as a proxy for play learning curve. We will compare second month volumes because of the strong correlation between peak production and EUR (note: this correlation is currently being questioned as operators are choking back wells in shale plays to see if it will increase EURs but for the purpose of this analysis we will stick with this popular idea. However, we have not heard anything yet of operators employing this practice yet in the Barnett.)
We are going to start with Devon. Devon’s highest series’ peak is 2004 wells with 1665 Mcf/d and we can see that type curve continues to outperform all other series all the way out to the 64th month. Their type curve performance then seems to drop off with a 2005 peak of 1304 Mcf/d and then even further in 2006 wells with 1266 Mcf/d. There was a 127 Mcf/d peak increase from 2006 wells to 2007 wells but their latest curve, 2009 wells, only peaked at 1141 Mcf/d. Ultimately their type curve’s 2nd month performance declined 31% from 2004 to 2009.
Chesapeake had a high peak of 2410 Mcf/d for 2004 wells then dropped in each peak until 2008 where it increase slightly then ended with the 2009 wells at 2135 Mcf/d which is an 11% decrease in performance. Note that the lowest type curve peak for Chesapeake was 1809 Mcf/d which is still higher than Devon’s highest month of 1665 Mcf/d. One might wonder whether part of this change is due to operators drilling acreage that is not as productive as the areas drilled earlier in the play. We have included this type of analysis in the DI-Energy Strategy Partner’s Unconventional Platform Barnett Shale study and the results are quite interesting when you compare operators across similar acreage within the play.
XTO’s lowest type curve peak was 2004 wells with 1534 Mcf/d which is opposite of the other operators considering both Devon and Chesapeake had their highest peaks in 2004. XTO’s highest peak is in the 2009 series with 2216 Mcf/d which accounts for a 45% performance increase.
Lastly we will compare the peak of each operator on one graph to get a better look at how they fare again each other.
To learn more about any of the operators visit the Barnett Shale Operator folder in the Unconventional Updates in DI’s DNA.
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