New Albany Economics:
|From Aurora Oil & Gas Co.|
|Drill a horizontal well at 2,400 ft. depth|
|Recover: 700 MMcf to 1.2 Bcf of gas|
|Wells decline at 5% per year|
|30-year productive life|
Covering portions of Illinois, Indiana, and western Kentucky, the New Albany Shale attracts operators with its wide coverage and shallow depths, but the longtime-producing formation has taken a back seat to more prolific prospects.
According to "Modern Shale Gas Development in the United States: A Primer," prepared for Department of Energy agencies by the Ground Water Protection Council and ALL Consulting, the New Albany Shale covers approximately 43,500 sq miles, second only to the 93,000 sq miles in the Marcellus among major US shale plays.
The New Albany is the shallowest major shale at depths from 500 to 2,000 ft. It is 50 to 100 ft thick, with the thickest segment near the point where Indiana, Illinois, and Kentucky meet.
Total organic content ranges from 1% to 25%, with 25% placing highest on the shale list for organic content. Similarly, it ranks highest among the shales with a porosity of 10% to 14%.
Its 40 to 80 cf/ton gas content puts it at the bottom of the list of major shales.
Operators have developed the Devonian-Mississippian shale on 80-acre spacing.
The study ranked the New Albany fourth among major shales with 160 Tcf of original gas in place, falling behind the Marcellus, Haynesville, and Barnett, but ahead of the Fayetteville, Antrim, and Woodford. New Albany’s 19.2 Tcf in technically recoverable gas put it in sixth place among those shales, leading only the Woodford.
Technically recoverable gas estimates vary widely, according to "Availability, Economics, and Production Potential of North American Unconventional Natural Gas Supplies," prepared for the INGAA Foundation by ICF International.
US Geological Survey (USGS) reports from 2002 to 2008 put the technically recoverable number at 3.79 Tcf of gas, while a 2007 Energy Information Administration estimate found only 2.04 Tcf of gas. A 2003 National Petroleum Council study revealed only 1.76 Tcf of gas in technically recoverable resource.
A 2009 ICF assessment put recoverable resources at 3.2 Tcf of gas, while a 2008 Clear Skies study showed a 3.8 Tcf of gas mean and a 19.2 Tcf of gas maximum.
First production from the New Albany in Indiana started in 1885, but Kentucky claimed prior production in 1858. Today, nearly all New Albany production comes from Indiana and Kentucky.
In a 2007 presentation, Steve Drake of Marsh Operating Co. said the Indiana Department of Natural Resources listed 575 New Albany completions in the state by March 2007, with an average production of 25 to 75 Mcf/d of gas. Most of those wells were vertical completions.
By that time, some operators had started drilling horizontal wells with a vertical segment of 2,500 ft and a 3,000-ft lateral. The wells were completed with an open horizontal hole and no fracture treatments at rates as high as 2 MMcf/d of gas, Drake said. The natural vertical fracturing in the formations gave horizontal wells an advantage over earlier vertical wells.
A 2003 USGS report said more than 140.4 Bbbl of oil had been generated by the New Albany Shale, but 86.3 Bbbl of oil were lost to erosion. The remaining 54.15 Bbbl of oil represented 21% of total oil generated in the Illinois Basin. The report also said more than 4 Bbbl of oil had been produced from the New Albany petroleum system, which included Pennsylvanian, Mississippian, Devonian, and Silurian zones.
A 2006 report on gas shales by Oil and Gas Investor magazine offered New Albany economics from Aurora Oil & Gas Corp., which later was acquired by Cadence Resource.
Aurora expected peak production of 200 to 300 MMcf/d of gas, with peak production in six to 12 months.
At a natural gas price of $5/MMBtu, the company expected a 45% internal rate of return.
Production depends on the operator's ability to pump off water from the formation. For example, an operator would drill a horizontal well below the producing interval at greater than a 90-degree angle with casing set to the kickoff point for the lateral; the lateral would be left as an open hole with no frac treatment. Water would drain back to the bottom of the casing where an electric submersible pump would move it to the surface for disposal.
Kentucky Natural Gas Corp. said the New Albany produces from at least 40 fields in Kentucky, 19 in Indiana, and one in Illinois. The formation has not been developed, the company said, because of poor pipeline infrastructure and public policy that allows operators to keep production levels tight.
A 2009 presentation by Kent E. Perry of the Gas Technology Institute (GTI) described an analysis of the New Albany Shale by GTI and the Research Partnership to Secure Energy for America (RPSEA) that was designed to help operators produce the formation.
At that time, the formation produced only 300 MMcf of gas a year.
The report said horizontal wells cost between $1 million and $1.8 million and operators drilled to intercept the east-west fractures.
If an operator drilled one horizontal well per 80 acres, recovered 20% of the gas in place, and sold it for $5/MMBtu, a Webster County, Ky., well would pay back $3 million.
More-recent wells still use laterals of more than 90 degrees to drain water, but they include a single fracture treatment to reach the Clegg Creek, Camp Run/Morgan Trail, and Selmer shale members of the New Albany.
Nitrogen fracture treatments were used almost exclusively in the formation at that time, the study said, but better completion techniques might be necessary before production rates would make Wall Street investors take notice.
According to the study, wells typically reach peak production within 30 days, showing a sharp decline in the first year and a shallow decline thereafter. In an illustration, the study showed a well with an initial potential of 275 Mcf/d of gas that dropped to about 150 Mcf/d by the end of the first year, to 125 Mcf/d after 24 months, to 100 Mcf/d after four years, and declined slowly to about 50 MMcf/d after 40 years.
The GTI-RPSEA report said the key to profitability in the New Albany is finding sweet spots with a cost-effective formula, determining optimum well geometry, deciding whether to fracture or not fracture the well, predicting cumulative production from initial potential, controlling well costs, and understanding and mitigating environmental issues such as water management.
Among operators in the play, Atlas Energy Inc. holds leases in southwestern Indiana. In June 2010, the company had access to 130,000 net acres with more than 450 potential drilling locations.
It entered the play in July 2008 and drilled 42 horizontal wells during 2009, all funded through its investment partnerships. By the end of the year, 21 wells were online and the rest were scheduled to come onstream during the first half of 2010.
Penn Virginia Corp. has moved toward liquids-rich plays such as the Granite Wash, Eagle Ford, and Cotton Valley. The latest report on its New Albany activity showed that it drilled one well in 2007.
BreitBurn Energy Partners LP claimed 582 boe/d and 1.2 MMboe from 227 producing wells from its New Albany properties in Indiana and Kentucky. The company also had 21 miles of high-pressure gas pipeline. It spent $1 million in the area in 2009.
Baseline Oil & Gas Corp., the former College Oak Investments, holds 171,000 gross, 34,200 net, acres in the play in southern Indiana, giving it room for 500 wells.
The play has not been completely overshadowed by the Marcellus and other shale plays, however. A March 2010 article in the Evansville Courier & Press said Eagle Resources sent a team of people to Edwards County, Ill., offering mineral rights owners $6/year per acre and a one-eighth royalty for five-year leases on property prospective for the New Albany Shale.
The company planned four horizontal wells in the area, including three core-sample wells in the first half of 2011.
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