American Oil and Gas Reporter - July 2015 - 65

SpecialReport: Horizontal Well Operations

Seismic Data Key For Flow Simulation

The final step is flow simulation,
where the effective stimulated rock volume
can be estimated/calibrated with geologic
matrix-fracture models, microseismic
data, hydraulic fracture conductivities,
and well performance.

Matrix Characterization
An adequate and consistent facies definition is essential for the workflow's
success, not only because facies indicate
whether a rock will fracture under hydraulic stress (brittleness), but also because
they control the porosity and permeability
distribution across the model as well as
the variability and intensity of existing
natural fractures relative to faults.
Production drivers should be considered
while defining facies that will also be
carried through flow simulation. For this
reason, geological facies derived from
core descriptions alone may not necessarily
be adequate to build geological models
that end in flow simulation. Another disadvantage of core-based geologic facies
is that they may not separate well in

FIGURE 1
Facies Definition using Neutron-Density Cross-Plot
1.8

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an

2.0

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Porous Limestone

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ite

Li

es

Do

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2.2

2.4

2.6

Porous Dolomite

2.8

3.0
-0.05

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Brittle Rock

An

HOUSTON-Designing horizontal
wells and hydraulic fracture stimulation
in unconventional reservoir requires a
detailed understanding of the variations
in matrix and fracture properties. Matrix
properties control not only the volume
of hydrocarbons and the ability of the
rock to fracture under hydraulic stress,
but also determine how effectively the
hydrocarbons can flow from the matrix
to the fracture network.
Natural fracture properties are responsible for the effectiveness and penetration
into the formation of the hydraulically
connected network of new or reactivated
fractures that result from stimulation.
Understanding local stress field variations
also is an essential part of the equation
for the success of hydraulic stimulation
projects.
However, no matter how good earth
scientists and engineers think their understanding of the static components of
the system is, static models of unconventional reservoirs should be calibrated,
validated and constrained with dynamic
reservoir data before reliable production
forecasts can be made.
For this reason, flow simulation is a
critical component in characterizing unconventional reservoirs because it helps
to ensure consistency between static and
dynamic data, and because flow simulation
is the only way to take into account all
the complex interactions between geologic
properties and fluid behavior that determine the nature of the production decline
and well interference.
Flow simulation models require information about the reservoir variables
that can affect both storage and deliverability. Seismic-derived information can
help constrain critical parameters in flow
simulation models such as the porosity
and permeability of matrix and fractures
in unconventional reservoirs. However,
for seismic-derived information to be
useful for flow simulation models, it must
be "translated" into variables that directly
affect the two main parameters of storage
and deliverability.
A workflow has been developed to
use seismic to generate of both matrix

and natural fracture models that describe
storage and deliverability in unconventional reservoirs, and constrain flow simulation models. The process starts by
careful facies definition based on production drivers. The facies are carried
throughout the entire workflow, ending
with facies modeling constrained by seismic derived-facies probabilities.
The workflow consists of three steps:
matrix characterization, fracture characterization, and flow simulation. Matrix
characterization begins with facies definition, where the critical production drivers
(porosity, brittleness, natural fractures,
etc.) are related to rock types at log-scale
and rock physics diagnostics are made.
Seismic calibration and mapping are then
performed for facies and fracture properties, where seismic data are trained at
well locations and the results are applied
to the entire area. Matrix and fracture
properties are integrated consistently with
geological, petrophysical and engineering
data to generate static matrix and fracture
models.

Density

By Reinaldo J. Michelena,
Kevin S. Godbey,
Hai-Zui (Hai-Ray) Meng
and James R. Gilman

0.05

0.15

0.25
NPHI

0.35

0.45

JULY 2015 65
American Oil and Gas Reporter - July 2015

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