The Middle Devonian Marcellus Shale has become one doozy of a gas play. In fact, it’s one of the premier shale gas plays of North America in terms of total gas resource, extent, production rates and economic potential, according to AAPG member Bill Zagorski, vice president of geology for the Southpointe, Pa., Marcellus shale division at Range Resources, which pioneered the play.
The Middle Devonian Marcellus Shale has become one doozy of a gas play.
In fact, it’s one of the premier shale gas plays of North America in terms of total gas resource, extent, production rates and economic potential, according to AAPG member Bill Zagorski, vice president of geology for the Southpointe, Pa., Marcellus shale division at Range Resources, which pioneered the play.
It all began in 2003 in Pennsylvania’s Washington County, where Range was drilling the Renz #1 well. It encountered significant gas shows in the Marcellus while on the way to test deeper horizons, which didn’t pan out.
In 2004, Zagorski had an “Aha!” moment and recommended a Barnett Shale-type frack treatment on the well, resulting in what was tagged as the first decent commercial discovery in the Marcellus.
The play soon began to pop.
Zagorski’s key role was acknowledged with fanfare in 2009, when he was officially given the title “Father of the Marcellus” by the Pittsburgh Association of Petroleum Geologists.
Zagorski and principal co-author Martin Emery prepared a paper “An Overview of Some Key Factors Controlling Well Productivity in Core Areas of the Appalachian Basin Marcellus Shale Play,” that was presented at the recent AAPG Annual Convention and Exhibition in Houston.
A family illness kept Zagorski home for the meeting, so Emery, vice president of geology for Range’s Williamsport Marcellus shale division, had the honors of presenting.
The paper’s other co-authors were Doug Bowman, senior geologist at Range’s Southpoointe, Pa., Marcellus shale division, and Greg Wrightstone, director of geology at Texas Keystone Inc. All are AAPG members.
“The organic rich shale of the Marcellus was deposited in a foreland basin setting that allowed for accumulation and preservation of the organic material,” Zagorski said.
“High organic content and the associated porosity and greater overpressure are some of the key Marcellus gas productivity factors.”
Controlling Factors
Zagorski and Emery note two major core areas have developed in the 500-mile-long, southwest-northeast trending Marcellus Shale play fairway.
“One is the southwest Pennsylvania region, which was the original discovery area for Range,” Zagorski said. “The other is the northeast core area in the northeastern part of the state.”
Marcellus shale thickness ranges from about 100 feet average gross in southwestern Pennsylvania to more than 250 feet average gross thickness in north-central Pennsylvania.
“The productivity and geographic extent of the core areas are huge compared to other shale plays, and we’re focusing on the best of the best right now,” Zagorski noted. “But even non-core areas have great productivity.
“The two core areas display unique combinations of controlling geologic factors,” Emery added.
To be simplistic, you can basically call the core areas a northeast dry gas play and a southwest combination NGL and dry gas play, Zagorski and Emergy emphasized.
“There’s one set of rules that describes the core area in the northeast,” their paper states. “It has a different set of fairways, has different pressure gradients, formation thicknesses are quite different and have different fracturing characteristics.
“In the southwest,” they note, “the play tends to be over-pressured and liquids rich, and in the northeast it tends to be more over-pressured but almost all dry gas for the most part.”
Zagorski and Emery suggested there were differences in sedimentation rate in the two areas, so one is thicker but has less concentrated organics, and the other is thinner but more concentrated in terms of organics.
That makes a difference in porosity and permeability distributions of the two plays – and especially how it relates to the NGL plays.
Big Differences, Big Implications
In addition to other basinal faulting associated with the Rome Trough, there also are northwest-southeast trending basement faults that influence or disrupt all of the thermal maturity and depositional patterns that appear to have bearing on exploration approaches in each of the areas, according to Zagorski.
A type log of the southwest area where the shale is about 150 to 200 feet shows the Marcellus there tends to have very high gamma ray counts, high resistivities, high density, high porosity, Emery and Zagorski note:
“If we compare this with the same type log in the northeast we find the Marcellus is about 260 feet thick,” they said, “and the intervals between the overlying Tully limestone and the base of the Marcellus are very great there but relatively small in the southwest.”
They note that this has big implications in terms of fracture containment and fracture height growth, so these things must be considered when comparing the two areas.
“The southwest region tends to have a higher concentration of organics on a per foot basis,” Zagorski said, “so it tends to have better preserved porosity and permeability, because most of the porosity and permeability are directly related to the presence or absence of total organic carbon (TOC).”
Intra-organic porosity is present throughout the whole Marcellus shale play, but there are differences in the type and distribution of it between the southwest and northeast core areas.
According to the two, the Marcellus is one of the strongest intra-organic particulate type plays compared to other shale plays.
“This is due to the concentration of TOC,” they said. “The higher organic content facies of the Marcellus is the key reservoir rock in terms of hydrocarbon storage.
“In the northeast, while the section is thicker, it has lower volume TOCs compared to the southwest,” Zagorski said. “But it has higher volume clay content and seems to have higher salt water saturation and lower porosities; but it’s thicker and higher pressure gradient and is somewhat deeper.
“Surprisingly, the gas-in-place (GIP) numbers and productivity are similar in both core areas, Zagorski and Emery noted, “with the northeast showing the highest GIP values.”