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	Vol. 229 No. 9
ARTHUR BERMAN, CONTRIBUTING EDITOR, bermanae@gmail.com

The Haynesville Shale sizzles while the Barnett cools

The Haynesville Shale is the hottest play in North America, and Chesapeake Energy Corp. leads in leasing and drilling. Chesapeake believes there are 250 Tcfe of Estimated Ultimately Recoverable (EUR) resources in an area covering 3.5 million acres in northern Louisiana and East Texas. The company’s share may be as much as 44 Tcfe. CEO Aubrey McClendon said in July that the Haynesville play is likely to become the largest gas field in the US, and the fourth largest in the world.

I am skeptical about this resource prediction. It exceeds the proved gas reserves of the US (215 Tcfe) by 16%, and is nearly 10 times the size of the largest gas field in North America (Prudhoe Bay, 26 Tcfg). It is more than nine times the US Geological Survey’s estimate for undiscovered Barnett Shale reserves (26.2 Tcfe).

North American E&P companies apparently do not share my doubts based on the price they are willing to pay for leases. The major leaseholders in the Haynesville Play are Chesapeake (550,000 ac), EnCana jointly with Shell (325,000 ac), Petrohawk Energy (275,000 ac), Anadarko (110,000 + 700,000 HBP ac), Devon Energy (130,000 ac), and Exco Resources (107,000 ac). In July, Plains E&P paid Chesapeake $35,000/ac for 20% of its Haynesville position. Recently, Haynesville lease bonuses averaged more than $13,400/acre.

The Haynesville Shale is an upper Jurassic fine-grained clastic interval that lies between the Cotton Valley and Smackover formations. Core porosities reach 8−9%, and the reservoir is 200-300 ft thick. The lower portion is overpressured (0.7−0.9 psi/ft), and total organic carbon is 0.5−4.0%. Recoverable gas estimates range 24−68 Bcf/sq mi, representing about 18−27% of gas-in-place.

Eleven horizontal wells have been drilled so far. Vertical well depths are 10,500−13,500 ft, and horizontal laterals range from 2,900−4,000 ft. Well costs are between $6.0−7.5 million including multi-stage fracture stimulations. EUR estimates range from 4.5−8.5 Bcfe/well.

Initial Production (IP) rates have been announced for several wells. One of Chesapeake’s eight horizontal wells produced 14.4 MMcfd during a one week flow test and two others tested 8-15 MMcfd. Petrohawk’s Elm Grove Plantation-63 and Hutchinson 9-5 tested 16.8 and 16.7 MMcfd respectively. Penn Virginia’s Fogle 5-H and EnCana’s Adcock 3H wells each reported initial rates of 8 MMcfd. Penn Virginia’s well reportedly averaged 5 MMcfd over a 50-day period.

I compared these IPs to a group of Barnett Shale wells to calibrate the early Haynesville information with longer production histories from an established shale play. I selected 169 horizontally drilled Barnett Shale wells that each had produced at least 1.0 Bcf. I calculated the daily average of the highest 30-day period of production. These ranged from 1.5−10.0 MMcfd with a mean of 3 MMcfd. IPs from this group of Barnett wells are lower than those in the Haynesville, though the method used to determine Barnett IPs is more conservative. I then calculated EURs for the Barnett select group using standard hyperbolic rate vs. time methods. The average EUR was 3.8 Bcf (1.1−7.8 Bcf), roughly half of estimates for the Haynesville.

This calibration may help to explain why operators are optimistic about the Haynesville play. From my calculations, one might predict that Haynesville per-well reserves could be 2−3 times as high as Barnett reserves. Overpressuring, and possibly better reservoir characteristics with thin silty-sandy beds in contact with the source rock, may explain the higher IP rates observed so far.

Conversely, the Barnett sample group represents the best production in the play. The average horizontal well EUR is 1.2 Bcf/well, and 2−3 times that reserve value will not be commercial at the greater depth and higher cost of Haynesville wells. Like the Barnett, Haynesville reservoir quality and reserves vary, and McClendon’s vision of a single super giant field spanning more than 3 million acres seems improbable based on Barnett history.

An unexpected and disturbing realization emerged from this re-evaluation of the Barnett Shale: production is in steep decline. Production fell 20%in the third quarter (Q3) of 2007 through Q2 2008 (300.8 to 239.6 Bcfe)*. The probable cause is a decline in drilling: well completions dropped 44% in Q2 2008 (358 wells) from Q3 2007 (641 wells). The US Geological Survey and industry analysts estimate nearly 30 Tcfe of recoverable reserves from the Barnett Shale. On June 1, 2008 cumulative production was 4.4 Tcfe, and it seems unlikely that the Barnett play will reach 6 Tcfe based on the pattern of decline observed over the last eight months.

While the Haynesville will probably contribute substantially to US gas reserves in coming years, it seems unrealistic to expect that it will rival the world’s largest gas fields.

The industry may have greatly overestimated the commercial potential of the Barnett Shale. A similar mistake is possible in other shale plays. Lease terms for some operators who entered the Haynesville Shale play in recent months will burden each well with an additional $1.0−2.5 million. Wells cost twice as much as in the Barnett. Regardless of the size of the Haynesville resource, the risk is that the rates and reserves that are found will not be enough to recover the high play entry, drilling and completion costs.

*Production and completion information is from the Texas Railroad Commission. There are concerns about possible reporting delays that might affect the reliability of this data.

IHS provided well and production data for the Barnett Shale, and Petra software that was used to evaluate the data. IHS’s ongoing support of this column is greatly appreciated.

References

Driscoll, T. R. and J. W. Robertson, “Shale drilling transforms gas markets,” Lehman Brothers Global Equity Research, 133 p., 2008.
“Welcome to Haynesville, Population: 60 Tcf,” Energy Investment Research Industry Update, Tristone Capital Company, 55 p., 2008.