Plank Road fever and the Barnett Shale. Thousands of miles of toll roads, surfaced with wooden planks, were built in the United States in the late 1840s. Plank roads were superior in every way to the dirt roads they replaced for access to canal and rail shipping points. The new roads provided more reliable, all-weather service, allowed faster transport and heavier loads, and caused fewer mechanical breakdowns than dirt roads caused. Demand was so great that the explosion of new road construction was called “plank road fever.” The economic premise for plank roads was that the roads would last for about eight years before they had to be resurfaced, according to civil engineers of that time. When it became clear that the planking wore out after only three or four years, plank road fever ended as quickly as it had begun and became a part of transportation history by the mid-1850s.
The Barnett Shale is a gas play in the Fort Worth basin whose appeal is that it is paradoxically both low risk and high reward. Risk is low because there is no doubt that gas exists in great volumes in the Mississippian Shale source rock, as much as 150 Bcf per square mile, at depths generally less than 7,500 ft. Reward is great because fracture stimulation technologies and, recently, horizontal drilling, have already yielded more than 2 Tcf of gas from the Barnett Shale.
About 1,800 vertical wells were drilled in the Barnett Shale before horizontal drilling began in 2003. More than 3,300 wells have been drilled since then, including over 600 horizontal wells with 3,000-ft laterals in the Barnett interval.
Mitchell Energy Corp. was a leader in Barnett Shale drilling in the early to mid-1980s when the company deepened several wells to the Barnett Shale that were producing from shallower formations. The shale was stimulated using gel and, later, “slick water” fracture techniques. Mitchell’s success led other companies to enter the play using similar economic, drilling and completion models. The economic premise of Barnett Shale development was that high, initial production-decline rates would flatten after two to three years, and result in long-lived, high-volume wells.
To evaluate the Barnett play, percent annual decline was calculated for the first five years of gas production for 1,800 vertical wells completed before 2003, and for 600 horizontal wells completed since 2003. This method was chosen to evaluate profitability, while more conventional rate-decline approaches emphasize production history matching and point-forward cash flow.
Percent annual decline was determined by dividing total gas production for a given year by total production for the previous year, subtracting that ratio from 1.0 and multiplying by 100%.
Percent annual decline values were statistically grouped to determine a representative average for each of the four years following the first 12 months of cumulative production for both well sets. Year-over-year values were almost identical for vertical and horizontal wells. Important differences included initial production rates twice as high for horizontal wells as for vertical wells, and corresponding horizontal drilling and completion costs 2½ times more than for vertical wells.
A simple economic model was developed to predict five-year total production from first-year cumulative volumes, since this information is generally available for most of the more recently completed horizontal wells. An average well cost of $3.5 million was used for horizontal wells, and $1.5 million for vertical wells. Modeled results predict first-year production of 200 MMcfg as the minimum required payout for vertical wells over 5 years, Table 1. First-year production of 575 MMcfg is needed to pay out horizontal wells over the same period of time.
The analysis suggests that 13% of horizontal wells will pay out using $6.25/MMBTU gas price, the average Henry Hub spot price for 2006. About one-third of vertical wells should pay out at that price due to lower drilling and completion costs. Using an $8.00/MMBTU gas price, 22% of horizontal and 53% of vertical wells will pay out (spot gas prices were only above $8.00 during the first 2 weeks of 2006, following the Katrina-Rita hurricane season in the Gulf of Mexico).
This analysis shows that, while many wells are profitable and some operators are significantly more successful than others, most Barnett Shale wells will lose money. The model is generous, because lease and operating costs were not included due to the great variance of these factors among operators, depending on entry date into the play, and the relative difficulty in accurately determining those investment costs.
The Barnett Shale is called a “resource play,” implying that the only real risk is overcoming engineering challenges to convert capital expenditures into a profitable project. Whatever terms are used to describe this or any other oil or gas play, one thing is clear: risk is inherent in all E&P ventures, and the Barnett Shale is no exception. Less than one-third of wells are likely to be economic under current gas pricing scenarios. This is a typical success rate for many exploration plays, but a terrible success rate for what amounts to field development drilling in the Barnett Shale. The overall resource size for the play is great, but economic reserves are relatively small.
Structural mapping suggests that many profitable Barnett wells, including Mitchell Energy’s early wells, are located on anticlinal features, Fig. 1. Perhaps early models did not recognize the structural component of Mitchell’s success.
The rush to lease and drill thousands of Barnett Shale wells before understanding if initial economic assumptions were valid is hauntingly parallel to the plank road fever phenomenon of an earlier time. Limited horizontal well production histories offer some possibility that the model presented here is overly pessimistic. At the same time, the likelihood that gas prices could fall below current levels would offset any uplift from somewhat higher production volumes. In the end, even resource plays must obey the fundamentals of petroleum geology. The ability to define reservoir, source, trap and seal involve risk. If the idea of a low-risk, high-reward E&P play sounds too good to be true, perhaps it is.
Arthur Berman is a geological consultant specializing in petroleum geology, seismic interpretation and database design and management. He has over 20 years working for major oil companies and was editor of the Houston Geological Society Bulletin. He earned an MS in geology from the Colorado School of Mines.
- Machine learning-assisted induced seismicity characterization of the Ellenburger formation, Midland basin (August 2023)
- Executive viewpoint (July 2023)
- Utilizing electronic data captured at the bit improves PDC design and drilling performance (July 2023)
- Regional Report- Gulf of Mexico (April 2023)
- What's new in exploration (March 2023)
- ShaleTech: Marcellus-Utica Shales (February 2023)