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Vol. 13, No. 4 Week of January 27, 2008
Providing coverage of Alaska and northern Canada's oil and gas industry

Appalachia to the rescue

Could Devonian shales deep under the Appalachians supply trillions of cubic feet of much needed natural gas for the U.S.?

Alan Bailey

Petroleum News

In the midst of a national debate about energy independence, the importance of natural gas in the future mix of U.S. energy supplies and escalating fuel prices, could energy salvation lie right underneath the Appalachian region of the eastern United States?

In a report published mid-January two geologists have suggested that a rock unit known as the Marcellus shale that extends from southern New York state through western Pennsylvania into eastern Ohio and West Virginia may contain anywhere from 168 trillion cubic feet to 516 tcf of natural gas. That could translate to a “super giant” gas field with at least 50 tcf of technically recoverable gas, the geologists, Terry Engelder, professor of geosciences at Pennsylvania State University and Gary Lash, professor of geosciences at the State University of New York (Fredonia), have said.

The 50 tcf estimate is based on about 10 percent of the 516 tcf gas-in-place number, Engelder told Petroleum News Jan. 21.

“Believe you me, that 500 tcf … number is conservative,” Engelder said.

In comparison, the U.S. Geological Survey puts known, technically recoverable natural gas reserves in northern Alaska at 35.5 tcf, 24.5 of which are in the Prudhoe Bay field, and total undiscovered, technically recoverable gas onshore and offshore Alaska’s North Slope at more than 200 tcf, for a grand total of 235.5 tcf of conventional natural gas in the northern part of the state.

Deepest Appalachian shale

The Devonian-age Marcellus shale was formed about 365 million years ago and constitutes the deepest and oldest of a number of prospective Devonian shale units within what geologists term the Appalachian basin. Black shales within the rock sequence are of particular interest because these shales contain large quantities of organic material that can, under the appropriate circumstances, convert to petroleum products.

“In the Appalachian basin there are as many as six different Devonian shale layers, all of them potential gas reservoirs,” Engelder said. “… The Devonian is one period in which there are a lot of black shales worldwide, so that whatever happens in the Appalachian basin may well be a model for other plays in the Devonian.”

Laid down in a seaway interior to an ancient continent, organic material in the mud that later formed into shale began generating natural gas as a consequence of subterranean heating, when the shale became buried deep beneath the surface of the Earth.

Some of that gas would typically remain adsorbed within the solid shale, while some would be released as free gas in the pore spaces within the shale.

Engelder and Lash’s resource estimates come in dramatically higher than a USGS 2002 assessment of a mean undiscovered gas volume of 1.9 tcf for the Marcellus shale.

So how come these new large numbers?

Rock volume

Engelder and Lash arrived at their estimates by first calculating the total volume of probable gas-bearing Marcellus shale. In doing this, they estimated a total area of shale that would likely contain adsorbed gas, and a larger area that would likely contain both adsorbed and free gas.

They then derived rock volumes by multiplying those areas by an average rock thickness of 50 feet.

Then the two geologists used the known gas sorption curves for a similar gas shale known as the Rhinestreet shale, from a few hundred feet higher in the Appalachian rock sequence, to estimate the adsorbed and free gas contents of the Marcellus shale, assuming a 3 percent porosity at a burial depth of about 4,000 feet — the Marcellus shale is typically buried to a depth of more than 6,000 feet, resulting in pressures that ought in fact to give rise to a higher gas content, Engelder said.

Multiplying the gas content per unit volume for adsorbed gas and then, for both absorbed and free gas, by the appropriate rock volumes resulted in the 168-516 tcf estimates for total gas in place.

Engelder’s optimism about the resource estimates derives in part from the fact that the average Marcellus shale thickness of 50 feet represents a very conservative estimate — the most attractive interval of the shale is known to be substantially thicker than that in places, he said.

“The Marcellus, particularly in north central Pennsylvania, exceeds 50 feet by a lot,” Engelder said. “… And the northern end of the Appalachian basin at least is overpressured … which even further … adds gas to this.”

Source and reservoir

In a gas shale such as the Marcellus shale, the host rock constitutes both the hydrocarbon source and reservoir, with either natural or man-made fractures needed to induce the gas to flow from the rock. That, then, raises a question regarding the feasibility of producing gas from the Marcellus shale.

Engelder and Lash have presented evidence for fracturing in the shale that could provide a key to successful gas production.

The geologists have observed widespread fractures, known in geologic parlance as joints, in surface rock exposures on both sides of the Appalachian basin. The joints exist in two distinct sets with different orientations and which formed at different times.

The earlier set of joints, referred to as J1, has been rotated by folding of the rock strata of the Appalachian basin during the Permian period. The later joints, referred to as J2, appear to have formed during that Permian folding.

By examining the surfaces of the fractures, the geologists have found evidence that the factures propagated through the rocks in a series of steps, driven by methane under pressure, as the gas effervesced from the rock matrix (patterns seen on the joint surfaces are characteristic of the effects of gas rather than water rupturing the shale). Regional stresses within the rocks would have caused the fractures to propagate with their characteristic orientations, Engelder said.

Joints pervasive

And, given this mechanism for joint formation coupled with the fact that the joint systems are observed at the surface on both sides of the basin, the geologists believe that the fractures, driven by methane generation, pervade the shale at depth through much of the basin.

In fact, the joints are not seen in areas where the shales have not reached the thermal maturity needed for methane generation, Engelder said.

The evidence that the J1 and J2 joint sets are of different ages points to formation of methane in two different stages. And with the J2 joints occurring in a grey variety of Marcellus shale, the gas would have flowed into the joints from a black shale source, rather like in the “gas chimneys” that are observed in some petroleum provinces.

“It turns out for the Marcellus play a lot of gas has actually escaped but there’s still a lot of gas in place,” Engelder said.

Engelder and Lash think that the best bet for gas development in the Marcellus shale would be to drill horizontally across multiple J1 joints: the J1 fractures slope steeply, are relatively closely spaced and occur predominantly in the black shale (the J2 joints occur mainly in the less organic-rich grey shale). In addition, the current regional stresses in the shale would tend to cause artificial hydraulic fracturing from either vertical or horizontal wells to propagate parallel to J1. The artificial hydraulic fractures will open up the joints, provided casing perforations sit exactly on joints, Engelder said.

And there are a number of people who think that, with a fracture system in the rock formation, the use of a 10 percent recovery factor from gas in place is conservative, Engelder said.

“We feel that our calculation for recoverable gas is conservative,” Engelder said.

Gas production

There is a precedent for gas production from horizontal wells in the Marcellus shale: Range Resources Corp. has established a drilling program in the shale in Pennsylvania.

According to the company’s report on its third quarter 2007 results, the company planned 15 horizontal test wells in the shale. The company has since reported that two of those wells have gone on line with production rates of 1.4 million and 3.2 million cubic feet equivalent per day; three additional horizontal wells have tested with initial rates of 3.7 million, 4.3 million and 4.7 million cubic feet per day.

But there is a continuing debate regarding whether fracturing is pervasive in the shale at depth. In an April 2007 AAPG Explorer article Jeff Ventura, chief operating officer of Range Resources, said that the northern part of the Marcellus shale lacks natural fracturing, while the southern shale is fractured.

“The Range people, at least initially, felt that they were fracturing into unfractured shale,” Engelder said.

Engelder, however, thinks that the evidence for pervasive fracturing is compelling, and that there must be some other explanation for Range Resources not finding natural fractures — perhaps well stimulation occurred through casing perforations that aligned with intact rock between fractures.

But with the need for expensive horizontal drilling, would gas production from the Marcellus shale prove financially viable?

Engelder thinks yes, especially given the track record of what Range Resources has achieved so far. The total daily production from the five Range Resources wells is in the order of 15 million cubic feet per day, Engelder said.

“The wells complete out, they say, at about $3 million a well,” Engelder said. Multiply the production volume by $8 per 1,000 cubic feet and “you can see in short order the wells are paid for,” he said. “… Those are the wells I think that are driving the huge excitement right now in the Appalachian basin concerning the Marcellus.”

And, of course, the basin is close to the major gas market of the eastern United States.



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USGS more cautious

In a 2002 assessment of petroleum resources in the Marcellus shale of the Appalachian basin, U.S. Geological Survey geologists came up with a mean estimate of 1.9 tcf of technically recoverable natural gas, a substantially lower figure than the 50 tcf estimate of Engelder and Lash.

The USGS assessment used the Greater Big Sand Devonian gas shale as a partial analogue for the Marcellus Shale, Robert Milici, USGS geologist and task leader for the 2002 assessment, told Petroleum News Jan. 23.

“At the time we conducted our assessment of the Marcellus shale in 2002, we had very little production data on which to base the assessment,” Milici said.

To derive an estimate for potential undiscovered resources in the shale, the USGS team added estimates of potential gas recovery from untested quarter-mile-square cells, he said.

“With sufficient new drilling and production data, especially from horizontal wells, we would be able to revise our previous estimate (about 2 tcf) of the technically recoverable gas resources in the area of thick Marcellus in Pennsylvania using the same methodology,” Milici said.

And Milici expressed caution about the Engelder and Lash findings.

“At this time, without a substantial amount of new drilling and production data, we regard the conclusions of the Penn State-Fredonia scientists regarding the potential of the Marcellus to produce 50 trillion cubic feet of gas as speculative, although not impossible,” he said.