All of the major, publicly-traded companies drilling into the Marcellus Shale have reported their second-quarter earnings. Thanks to SeekingAlpha, transcripts from those calls are publicly available and easily searchable.
Here are some of the major takeaways in the reports:
- Spudded seven new operated wells and drilled and completed 6 gross (2.7 net) operated wells during the second quarter 2011 in the Marcellus shale. The IP [initial production] rates of these wells ranged from 2 Mmcf per day to over 5 Mmcf per day from lateral lengths between 3,200 feet and 5,000 feet. In all of EXCO’s operating areas, (the company) discloses IP as the peak 24-hour production rate during the first few days of flowback. However, in Appalachia, we have wells that realize peak production rates approximately one to two months after initial production, as the wells unload water, flowback is managed and tubing is installed. In certain areas, we have realized an average rate increase of 50-75% between the first seven days of production and the peak production rate.
- In the northeast portion of the play, we brought online our first 5 horizontal wells in the first quarter. The average estimated ultimate recovery for these 5 wells is 6 Bcf. The average lateral length of the wells is 2,573 feet with a 9-stage frac. For our first 5 wells, that's very encouraging. Again, like the southwest, we're running our own analysis of various lateral lengths and frac stages, and we'll also look at the results of other operators.
- In the Upper Devonian, we'll be spudding our third well and its formation beginning in early 2011. This well will target the wet gas portion of the play and will be drilled into the area, with what we expect to be the highest gas and liquids content in place. In terms of liquids content, we expect the Upper Devonian will be like the Marcellus Shale, where the Marcellus is wet, the Upper Devonian should be wet. Where the Marcellus is dry, the Upper Devonian should be dry.
- Currently, we have over 45,000 net acres in this play, which equates to over 900 potential well locations. If we keep drilling with roughly 2,000 foot laterals, we believe that it will take 12 wells per section to develop the reserves, that equates to a little over 50-acre spacing. Assuming that the average recovery of 485,000 barrels of oil holds, that's a recovery factor of 4% to 9% of the oil in place.
- Seeing that we've only drilled and completed a little over 200 horizontal wells, according to this math, we may have -- or we have 96% of our wells left to drill. As good as our rates of returns are now, we may be able to improve that going forward.
- The Upper Devonian section relative to the -- and really where it's -- we feel it's -- the highest prospectivity is in the southwest, although there's a couple of good Upper Devonian wells, even in the central part of the State, so it has potential in a lot of areas. When you look at the thickest part of the Upper Devonian, in general, say, in the southwest -- it's actually on our website, you can look at it, there's a type log.
- ... But the exciting part (of the Upper Devonian play) is we'll have an infrastructure in there. We have a team there, and you're going to have roads and well pads and gathering and takeaways, so there's really an exciting upside to it.
Stay tuned. I'll continue to add to this as I scan through the other reports, which will include Rex Energy and Anadarko Petroleum. Order a reprint