American Oil and Gas Reporter - January 2016 - 65

for DeWitt and Lavaca counties.
After petrophysical property modeling
of porosity and water saturation, pore
volume and hydrocarbon pore volume
were computed and normalized by acre
for each drilling unit. Maturity, PVT data,
and fluid type produced in each unit were
also taken into account for these calculations. The distribution of OOIP by drilling
unit normalized by acre is roughly log
normal as expected, and truncated on the
low end due to lack of leases in uneconomical areas. OOIP volumes per drilling
unit normalized by acre are a key driver
for asset development planning, recovery
factor analyses, EUR estimates, and reserves. In addition, OOIP volumes provide
a basis for evaluation of drilling and
completion efficiencies.
While OOIP is a key parameter in determining the potential of the well, reservoir quality controls the recovery factor
and efficiency. The placement of the
lateral, the nature of the fracture treatment,
and near-wellbore rock quality determine
the ability to recover reserves from the
reservoir. Using the model, we can visualize the reservoir properties along the
wellbore, as shown in Figure 5. This
allows us to further consider geologic
variables in predicting well performance.
Building a model forces the rigorous
understanding of geologic inputs and
their internal interactions. It also creates
the basis for understanding specific units
relative to one another and predicting
performance predrill and post-drill, given
the actual steering and completion. We
have been able to rank drillable units and
link economic choices to geology. Building
the models also has forced us to more
precisely recognize the similarities and
differences of the model areas and modify
our interpretations accordingly. However,
it is important to remember that all models
can only be as good as the geologic
inputs and the collective understandings
that shape them.
Future models will likely need to cover
both Lavaca and DeWitt counties in order
to accurately characterize lateral facies
transitions. Depositional environment
maps will be developed to guide the selection of representative log training sets
and appropriately group wells for facies
propagation and variogram analysis. Seismic attributes will be added to help propagate facies and reservoir properties in
areas of limited well data. The model
then will be better able to predict facies,
reservoir quality, well performance, improve reservoir simulation, and aid completion design.
❒
Editor's Note: The authors acknowl-

FIGURE 5
Wellbore Superimposed onto Cross-Sectional Slice
Showing Reservoir Quality Variability

edge Devon Energy's Chris Mullen, Sean
Bingham, Gregg Jacob, Mike Kendrick,
Ken Silver, Kim Sowder, Doug Schultz,
Bruce Escovedo, Rich Hand, and John
Spaid for their contributions and support

DAVID HULL is a geologist at Devon
Energy in Oklahoma City. Before joining
the company in 2013, he served as a
geologist at Chesapeake Energy Corporation. Hull holds an M.S. in geological and earth sciences from the University of Texas at Austin, and an M.A.
in economics and international relations
from the University of St. Andrews.
PHILIP CHAPMAN is a staff geologist

at Devon Energy, working in the Eagle
Ford Shale. Before joining Devon in
2013, Chapman served for six years as
a district geologist at Chesapeake Energy. He holds a B.S. in geology from
Indiana University-Purdue University
Indianapolis and an M.S. in geology
from the University of Alabama.
DAVE MILLER is a reservoir modeler
at Devon Energy. He previously served
for eight years as a senior staff geophysicist at EP Energy and its predecessor,
El Paso E&P. Prior to that, Miller was a
senior geoscientist at Transworld E&P,
senior project geophysicist at Western
Atlas E&P, and a geophysicist and data
center manager at Western Geophysical.
He holds a B.S. in geology from the University of Pittsburgh-Johnstown, and a
G.A. in economic geology from Colorado
State University.

of the Eagle Ford modeling project. They
also thank Core Lab, Halliburton and the
Mudrock System Research Lab at the
Bureau of Economic Geology for their
assistance.

DAVID INGRAHAM is a senior petrophysicist at Devon Energy working primarily Eagle Ford and Powder River
Basin assets. He previously worked for
17 years as a petrophysicist and 14
years as a wireline engineer at Schlumberger. He holds a B.S. in engineering
from Oklahoma State University.
NICOLE FRITZ is a geologist at Devon Energy. Before joining Devon in
2013, she served for seven years as a
district geologist at Chesapeake Energy
working in the Bossier, Haynesville,
and Granite Wash plays. Fritz began
her career as a geologist at the Oklahoma Water Resources Board. She holds
a B.S. in geology and an M.S. in environmental science from the University
of Oklahoma.
NICHOLAS KERNAN is a geologist
at Devon Energy. He joined the company
in 2015 after receiving an M.S. in petroleum geology from Colorado School
of Mines. He previously worked an
intern geologist at both Devon and Petroleum Development Corporation, and
as a geoscience technician at ExxonMobil. Kernan holds a B.S. in geosciences from Hamilton College.

JANUARY 2016 65

American Oil and Gas Reporter - January 2016

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