Photo courtesy of Newfield Exploration
Don Warlick, Warlick International, Houston
After several momentous years of natural gas development across North America, and specifically in the US, it's time to take stock of what segments of natural gas supply will drive the business in the years ahead. It has become evident that gas shales are at the forefront of development, especially five leading shales that account for significant production and drilling.
These five gas shales — Marcellus, Haynesville, Fayetteville, Woodford, and Barnett — accounted for more than 10% of US natural gas production in 2008. There's a good chance they could account for more than 19% by 2012. Likewise in drilling, about 12% of US wells drilled in 2008 occurred in these five gas shales. That could increase to as much as 20% by 2012.
Last year weak natural gas prices slowed all gas development with average Henry Hub gas prices falling from $8.86/MCF in 2008 to just $3.96 in 2009. The good news for 2010 is that forecasters anticipate gas prices to be in a range of $5 to $5.50, perhaps higher. Some of the leading players in gas shales, especially those operating in the Top Five, will have advantages this year and in future years as well. The reason? They are managing their operations in very efficient ways for the long term in order to accommodate lower gas prices.
The Top Five gas shales are populated with select E&P leaders with several common characteristics, including lower F&D costs (thanks to control over extensive holdings), early entry, JV deals of consequence, continued emphasis on drilling improvements, and enhanced reservoir knowledge as time goes forward. Their development programs will include more downspacing for higher-density drilling, extending horizontal laterals, manufacturing approaches to drilling, etc.
What takes place in these five important shales will have a lot to do with drilling and development trends in the US natural gas space. Prolific wells can call for even more drilling, but keep in mind the gas supply issues that impacted 2009. In any case the Top Five will have a significant impact on drilling, completion, and overall direction of US natural gas in the future.
A brief summary of the Top Five gas shales follows to update the reader in understanding what's taking place in each.
Along with the Haynesville Shale, the Marcellus is becoming one of the most active gas plays in the US with hyperactive leasing in the past three years and now ramped-up drilling. The central part of the Marcellus play encompasses about 28,000 square miles with the northeast and southwest corners of Pennsylvania being the most active in drilling and development.
This is a middle Devonian, black and organic-rich shale that is one of several known/potential producing horizons in the shales of the Appalachian basin. Its geology is well suited to gas shale development given its high organic content and fracture geometry. As a result, it lends itself to smart applications of horizontal completions, engineered fracs, etc. It also helps that the Marcellus is near major gas-consuming markets on the Eastern Seaboard.
Range Resources and Chesapeake/Statoil are leading the charge in the Marcellus, but others are joining in. A quick listing of notable basin players includes:
- Chesapeake — the busiest driller in the basin, aided by its earlier joint venture with Statoil with ready funds put to use in drilling and development.
- Range Resources — was the early developer of the Marcellus after drilling its first commercial well in 2004. An aggressive user of technology, experiencing good returns.
- Cabot — becoming busier in drilling, leasing also; giving attention to reducing drilling time and costs.
- Others — it's a busy play with involvement of companies like Chief, Atlas, Anadarko, EQT, Talisman/Fortuna, XTO, Exco, Ultra, etc.
The fractured nature of this shale is a big plus, given the completion techniques that are being employed here. It has great potential as a huge gas resource as development extends across the complete play where economics warrant. It is somewhat shallow from 4,500 — 8,000 feet and has shale thickness from 100 to 400 feet. Horizontal wells will cost $3 to $4 million with IP around 4 MMCFD and higher; Range and Chesapeake are experiencing EURs of 4.2-4.4 BCF.
Just two years after the first drilling in 2008, Haynesville is recognized as fabulous shale that is extremely attractive to many operators. It can become one of the most profitable gas shale developments in the industry given the course of ongoing development in DeSoto and Caddo parishes in northwestern Louisiana. With these and other Louisiana parishes being most active, the play is now going into East Texas in San Augustine, Nacogdoches, and Shelby counties. The play's prospective acreage could exceed 3.4 million acres to its fullest extent.
This shale is an upper Jurassic fine-grained plastic interval deposited between the Cotton Valley and Smackover formations in parts of North Louisiana, East Texas, and Southern Arkansas. Besides those two formations of opportunity there are others like the Cotton Valley Sand and Cotton Valley Lime, a plus for drillers considering opportunities beyond the Haynesville.
A number of big gas portfolio Haynesville players are in developments that are uptrending quickly, including companies like:
- Chesapeake — the largest leaseholder in the Haynesville involved in an 80/20 joint venture with Plains Petroleum in a deal that has funded more than half of Chesapeake's drilling.
- Petrohawk — a very aggressive driller with fast-growth plans and significant acreage.
- Exco/BG Group — a 50/50 JV totaling $1.3 billion announced in June 2009.
- XTO — as announced in late 2009, being acquired by ExxonMobil.
- Others — EnCana, Goodrich, Forest, EOG, Noble.
Haynesville horizontal wells have extremely high productivity, and due to their highly overpressured nature, conditions can allow lower operating costs, at least in their initial development. A typical horizontal completion today could cost $7.5 million, drilling to depths of 10,500 to 14,000 feet, but the payoff can be an IP up to 14 MMCFD in the core area of the Haynesville. Estimated ultimate recovery (EUR) rates for these wells will most often be at least 6.5 BCF.
This is a great development story that began prior to 2004 when Southwestern Energy drilled just 13 Fayetteville wells. Early geological analysis and smart leasing allowed Southwestern to get the jump on all others in a strategic leasing-drilling-development-production campaign.
Southwestern's early reviews of the Fayetteville Shale identified great potential. The Fayetteville is a black, fissile, clay shale. Initial assumptions confirmed that this Mississippian-era shale was a geological equivalent to the Barnett. By virtue of its headstart in leasing, Southwestern was enabled to grow its development programs steadily and determine unique methods for drilling and completion.
Today, the Fayetteville is led by Southwestern, Chesapeake, and BP:
- Southwestern — accounts for around half of all Fayetteville drilling and a two-thirds of this play's production. The company's manufacturing approach to horizontal drilling and completion is being continually improved today.
- Chesapeake — the #2 gas producer and second-largest leasehold owner is supported in its development program by the firm's 75/25 joint venture with BP from late 2008. By way of this JV, Chesapeake recovered its entire leasehold investment in the Fayetteville.
- Others — XTO had six rigs drilling in late 2009 with sizable acreage and production. Petrohawk is also present in the Fayetteville.
These wells will average about $2.9 million each and have average horizontal lateral lengths that exceed 4,000 feet. Both Southwestern and Chesapeake have focused principally on efficiencies, allowing them to utilize manufacturing drilling and pad layouts to complete wells in 12 to 14 days. IPs exceed 2 MMCFD and range to 4 MMCFD, with EURs of 2.1 - 3.5 BCF. In 2010 both will concentrate on improvements in completions, optimized well spacing, and economics, important in this era of lower gas prices.
Identified as an attractive development opportunity by Newfield Exploration in 2003, the Woodford has seen reasonable growth since then. Initially it was deemed a vertical play with multiple gas zones, then realized as a horizontal development opportunity. Overall, the Woodford is estimated to extend over one million acres in the Arkoma and Anadarko basins of southern Oklahoma. Most Woodford drilling takes place in four counties: Hughes, Coal, Pittsburgh, and Atoka.
A Devonian-era shale, the Woodford is a dark-gray to black shale widely regarded as an important source rock. It is located in the Arkoma basin in southeastern Oklahoma, the Anadarko basin to the west, and the Permian basin of West Texas and Southeastern New Mexico. Development results prior to 2003 were a bit inconsistent so this area did not start as fast as, say, the Fayetteville.
|Swift Energy employees inspect drilling equipment.|
Photo courtesy of Swift Energy
On average the shale thickness will be 150 to 200 feet with most Woodford drilling in a 6,000 foot to 8,000 foot range. There is some drilling activity in a westward expansion in the Cana Woodford where Devon and Marathon are active.
Leading operators in the Woodford include:
- Newfield — accounts for more than a third of wells drilled and is enhancing its economics via technology with ever-lengthening laterals, now going beyond 5,000 feet.
- BP — entered the Woodford in 2008 by way of two acquisitions from Chesapeake with 90,000 net acres in selected counties and deep drilling rights, paying $1.9 billion.
- Devon — active Woodford driller and, as noted, in the Cana Woodford to the west.
- Others — PetroQuest is emulating Newfield's success with extended laterals. XTO (soon to be part of ExxonMobil) has acreage and several rigs drilling.
Well-engineered horizontal development in the Woodford is very important to economics in this basin. These wells will cost at least $6 million and will have IP of 3 to 5 MMCFD. Typical EUR for these types of completions will be at least 2 BCF and range to 5 BCF. Look for efficiency gains through pad drilling and the ability to complete longer laterals.
This is the largest gas producing field in the US, accounting for more than 7% of total domestic natural gas production in 2008. It's big — extending across 19 counties in north central Texas and may have technically recoverable reserves as high as 44 TCF. As in most US plays, drilling declined significantly in the Barnett from an average of 185 rigs in 2008 to ~ 81 in early 2009.
Geologically, the Barnett is part of the Fort Worth basin, a late Mississippian age shale that covers about 54,000 miles. It evolved into a huge reservoir of gas and gas liquids production owing to the fact that it is organically rich with reservoir thickness from 200 to 800 feet.
There are many operators in the Barnett, especially given its years of evolutionary development. In the beginning, it was Devon Energy that established the technology to bring success to this huge basin, but altogether there is a now a great cast involved in this historic play:
- Devon — decided to reduce drilling significantly during 2009 due to the low price of gas, but still was producing 1.2 BCFD at mid-year. Devon recently said it plans to divest all its Gulf of Mexico and international assets to refocus on North American onshore opportunities.
- Chesapeake — probably the most active Barnett driller in 2009 and continuing a busy Barnett development program. The company announced in January that Total is paying $2.45 billion to acquire a 25% interest in Chesapeake's Barnett holdings.
- XTO — busy in the Barnett Core and Tier 1 with significant production and an attractive platform for ExxonMobil's entry into this huge basin.
- EOG — a long-time player, ranks fourth in Barnett production.
- Quicksilver — took Italy's Eni as partner in a strategic alliance for Barnett development.
- Others — Notables like Range Resources, EnCana, and others are active here as well.
There has been an extraordinary evolution of technology and development techniques in the Barnett over the years, so drilling and completion here is now rather straightforward. Typical horizontals cost around $2.5 million and result in IPs of 2 to 3 MMCFD with an EUR that will range from 2 to 2.5 BCF.
About the author
Don Warlick is president of Warlick International, a Houston-based energy intelligence firm that specializes in the evaluation of global upstream markets. The firm publishes several annual energy reports, including the North American Unconventional Gas Report and the Gas Shales Market Report and Forecast.