Operators Moving Toward Exploitation Phase In Marcellus Shale
(Tech Connections Column, February 2008, American Oil
and Gas Reporter)
 Are operators in the Appalachian Basin Marcellus Shale
approaching the rapid exploitation phase that converts resource to
reserves? On the surface, the answer appears to be a resounding
yes. Range Resources has announced drilling horizontal wells
with initial potentials ranging from 1.4 million to 4.7 million
cubic feet a day, and other companies also report successes.
An early January workshop in Morgantown, W.V., zeroed in
on the Marcellus Shale–just one of the Devonian black shales in
the Appalachian Basin. Terry Engelder of Pennsylvania State
University and Gary Lash with State University of New York
College at Fredonia, presented insights from their decades of
work on Devonian-age shales in the Appalachian Basin, while
focusing more on the geological aspect than on drilling, completion
and fracturing techniques.
Why is interest in the Marcellus so strong? For starters, the
play covers an area at least four times as large as the productive
Barnett Shale, and its attributes compare favorably with other
successful North American shale plays. These favorable attributes
include:
- Continuous reservoir over a large enough area to contain
a potential resource equivalent to a supergiant gas field;
•
Up to 10 percent total organic carbon (TOC);
- Adequate thermal maturity;
•
Significant gas-in-place (20 billion-100 billion cubic feet
a section);
•
Thickness (50-200 feet) at a reasonable depth (4,5008,500
feet);
- Favorable mineralogy (The Marcellus is a lower-density
rock with more porosity, which would be filled with more free
gas.); and
- Overpressured, at least in the northern part.
Some sources estimate 337 trillion-516 trillion cubic feet of
gas in place. A mere 10 percent recovery rate equates to 34 Tcf52
Tcf of gas. This would make the Marcellus a giant field
located close to market with an existing transportation infrastructure.
In a 1911 Cornell University doctoral thesis that focused on
fracturing in Appalachian Basin black shales, Pearl Sheldon
observed a set of maturation-related joints (J1) that were most
dense in the highest TOC portion of the black shale formations.
This joint system stores both free gas, and when accessed, provides
a flow network for desorbed gas.
The J1 joint system, whose orientation is controlled by the Appalachianwide stress field of the late Paleozoic, is generally
oriented east-northeast. Horizontal laterals drilled perpendicular
to the J1 joint system (that is, laterals oriented generally in a
NW-SE direction) would access the most joints and have higher deliverabilities and recoveries. Operators don’t openly broadcast
the orientation of successful horizontal laterals, but multiple
“unofficial” comments indicate that laterals oriented NW-SE are
making the better wells.
Interlayered gray shale formations host large cross-fold
joints (J2). Both J1 and J2 joints in the Devonian shales of the
Appalachian basin are fluid-driven, natural hydraulic fractures.
It is the crosscutting of the J1 and less dense J2 joint sets that
provide an ideal dual-porosity reservoir.
So what is different from the Barnett Shale? Barnett production
is associated with a J2 joint system resulting from the main compression
of the Ouachita (Barnett) and Appalachian (Marcellus)
trends. In the Barnett, the J2 joint system is propped open with
mineralization. The Barnett does not appear to have the J1 maturation-
related joint system. Appalachia’s Marcellus Shale has both J1
and J2 systems, with the J1 system being more dense.
With closer spacing, the J1 system better connects matrix
porosity to production wells. Neither the J1 nor the J2 system is
propped open in the Marcellus. This means the Barnett’s propped
J2 joint system may have higher initial deliverabilities, whereas
the Marcellus may better access matrix porosity, which would
increase estimated ultimate recovery because of the ability to utilize
the dense array of J1 joints.
The characteristics of the Marcellus Shale change from east to
west. The west side has a higher organic content, but is shallower
and thinner. The east side is deeper and thicker, with a higher
quartz content (more brittle), but has less organic content.
Historical production is on the organic-rich west side of the trend.
One question is whether multistage fractures in horizontal well
bores can open the gas potential of the deeper, thicker eastern side.
The northern part of the play is slightly geopressured, while
the southern part is underpressured. Natural fracturing is
accepted in the southern part, but some have questioned its contribution
in the northern part. Sheldon’s J1 observations suggest
that natural fracturing is present in both areas.
PTTC’s January workshop focused on the geological side of
the Marcellus: its basic geologic characteristics and the influence
of natural hydraulic fracturing. Lessons also are being
learned in drilling, completion and fracturing, which creates the
incentive for a future workshop focusing on these aspects,
which are crucial to realizing the Marcellus’ full potential. Put
together, operators will continue to rapidly move the Marcellus
Shale from resource to rapid exploitation.
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