Wednesday, April 7, 2010

EOG Update

EOG Resources held and investor conference today and discussed its operations in great detail. EOG has made an effort in the past year to become more “oily” by pursuing wetter gas (with more NG liquids) and oil. As a result, its interest in the Haynesville Shale, with its mostly dry gas, is not as rabid as some other E&P companies.

That said, however, the company says it will run an average of 11 rigs in the play in 2010 and plans to drill 72 gross wells. At the end of 2009, EOG was producing about 60 MMcf/day, and the company expects that number to grow to 175 MMcf/day by the end of 2010. The company has a total net leasehold of 160,134 acres, with 45,789 of that total held by production. EOG estimates that it has potential reserves of 10 Tcf, evenly split between the Haynesville and Mid-Bossier Shales.

EOG is concentrating its drilling efforts on what it deems to be the sweet spots in both Louisiana and Texas. EOG will drill most of its 2010 wells in the Trenton Field in Louisiana and what it calls the South Jeterville Field in San Augustine and Nacogdoches Fields in Texas. On the map below, the darker colors signify the amount of gas in place. As you can see, the sweet spots do not necessarily correspond with the highest levels of gas in place because there are other geologic conditions like pressure and permeability that determine sweet spots.


As the above map indicates, early activity on the Texas side concentrated on the north, but operators were somewhat disappointed by the results, especially compared to the Louisiana side of the play. Where the estimated ultimate recoveries (EUR) on the Louisiana side were in the 6 to 12 Bcf range and bottom hole pressures were around 10,000 psi, EURs on the northeast side of the play averaged 4 to 6 Bcf and pressures were in the range of 8,100 psi. EOG figures that one important determinant of the difference between the two areas is total organic carbon (TOC) of the source rocks, which is around 3.3% in the Louisiana sweet spot and only around 2.3% in the Harrison County area. With more exploration in the southwestern part of the play in Shelby, San Augustine and Nacogdoches Counties, geologists found higher organic carbon (3.6%), higher pressures (11,900 psi) and higher recoveries (6-12 Bcf) that make the southwestern part of the play as good as the Louisiana sweet spot. This is why drilling activity on the Texas side of the play is shifting southward.

On the Louisiana side of the play, EOG will drill 32 2010 wells in the Trenton Field where it is seeing initial production rates in the 15 MMcf/day range. EOG noted that its IP rates could be higher, but the company was an early adapter of the concept of restricting flows to optimize recoveries. On the Texas side of the play, EOG has added acreage in the southwestern part of the play and now has 84,590 total acres in its definition of the Texas sweet spot.


EOG is particularly excited about the Middle Bossier Shale, which the company believes will make up half of its reserves in the combined play. EOG is seeing similar characteristics to the Haynesville Shale and is estimating a 6-12 Bcf EUR for the Mid-Bossier properties. The company announced a new Mid-Bossier completion, its first in Texas. The Hassell Gas Unit in Nacogdoches Co. is generating 21 MMcf/day after one month of production. EOG actually estimates higher reserves from the Mid-Bossier (3.05 Tcf) than the Haynesville (2.55 Tcf) in the south Texas part of the combined play.


EOG is somewhat unique in its approach to drilling in that it is using 128 acre spacing (5 wells per 640 acre section), where most producers are using 80 acre spacing. EOG feels that because of high system permeability it can use fewer wells to drain the same area. Based on this spacing, EOG estimates that it has 1,662 potential wells. By drilling fewer wells, the company saves money, but its well costs are still in the $9.8 million range. EOG has been using 12 to 15 frac stages with laterals averaging 4,400 feet. The company is using higher proppant levels, but it is still able to average around 28 days of drilling time.

Management brought up pressure sinks, an interesting concept that has not been discussed widely in the Haynesville Play. EOG has observed in the Barnett Shale that pressure decreases around horizontal wells after a while. This decreased pressure might reduce the effectiveness of fracturing and decrease ultimate recoveries of adjacent wells. EOG said that the impact of these pressure sinks, which might arise in around six months, can be avoided if the producer drills adjacent wells in a timely manner and suggested that companies that are drilling one well in a section to hold a lease by production with the intent of drilling remaining wells later might have lower recoveries.

EOG management also suggested that it completion and operating techniques have led to flatter (or less steep) decline rates. Reducing decline rates is the holy grail of shale drilling these days, but the proof of this success is a ways off.

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