Oil & Natural Gas Projects
Exploration and Production Technologies
Coupled Geomechanical Deformation, Fluid Flow and Seismic
This project was funded through DOE's Natural Gas and Oil Technology Partnership
Program. The program establishes alliances that combine the resources and experience
of the Nation's petroleum industry with the capabilities of the national laboratories
to expedite research, development, and demonstration of advanced technologies
for improved natural gas and oil recovery.
The ultimate goal of this research is to evaluate the effects of rock density
changes on time-lapse seismic imaging of compactible reservoirs. In particular,
computed changes in porosity, pressure, and saturation are to be used to determine
changes in density and seismic velocities with time. Time-dependent seismic
modeling for coupled flow and mechanics are compared with seismic properties
derived from flow simulations alone. Another goal of this research is to determine
the feasibility and accuracy of two-way staggered-in-time coupling of multiple
Sandia National Laboratories (SNL)
University of Maryland
University of Texas
San Ramon, CA
This project demonstrated that it is possible to loosely couple together two
existing analysis codes and accurately model complex nonlinear phenomena often
observed in the field. Numerical results using the coupled code showed that
coupled flow and deformation calculations, for the Belridge oilfield near Bakersfield,
CA, produced compressional wave velocities that differ markedly from those based
on the flow solution alone. This is an important result when using time-lapse
seismic techniques for accurately imaging production reservoirs.
This work highlights the need for performing coupled flow/geomechanics calculations
for highly compactible reservoirs by the oil and gas industry. Oil industry
reservoir engineers need accurate imaging information in order to improve their
understanding of the oil and gas distribution within the reservoir. Currently,
most time-lapse seismic techniques attribute all time-dependent reservoir differences
to changes in pressure, saturation, and temperature; however, neglecting compaction
when modeling weak-formation reservoirs may introduce serious errors in the
seismic properties. This work showed that this information may be obtained relatively
quickly and inexpensively by coupling together two independent fluid flow and
geomechanics simulators. This work also demonstrated the feasibility and accuracy
of a two-way staggered-in-time coupling scheme.
The motivation for this development is that traditional flow simulations in
compactible reservoirs, such as Ekofisk in the North Sea and Belridge in California,
cannot produce accurate results unless one accounts for mechanical changes in
reservoir geology. Moreover, for this modeling to have a meaningful impact,
the coupled fluid flow/geomechanics simulation must allow for two-way passage
A second motivation for this work is that it will enable researchers to account
for rock density changes in time-lapse seismic imaging. Most 4-D seismic techniques
attribute all time-dependent reservoir differences to changes in pressure, saturation,
and temperature. Neglecting compaction when modeling weak-formation reservoirs
may introduce serious errors in the seismic properties.
Accurate prediction of reservoir production in structurally weak geologic areas
requires both mechanical deformation and fluid flow modeling. Loose staggered-in-time
coupling of two independent flow and mechanics simulators captures much of the
complex physics at a substantially reduced cost.
Two 3-D finite-element simulators-Integrated Parallel Accurate Reservoir Simulator
(IPARS) from the University of Texas for flow and JAS3D from SNL for mechanics-together
model multiphase fluid flow in reservoir rocks undergoing deformation ranging
from linear elasticity to large, nonlinear inelastic compaction. Pore pressures
from flow are used as loads for the geomechanics code in the determination of
stresses, strains, and displacements. The mechanics-derived strain is used to
calculate changes to the reservoir parameters (porosity and permeability) for
the next set of flow time steps. An approximate rock compressibility parameter
is used as a preconditioner to help with convergence of the modified flow equations.
Two numerical experiments illustrate the accuracy of the coupled code. The
first example is a quarter-five-spot waterflood undergoing poroelastic deformation,
which is validated against a fully coupled simulator. Vertical displacements
at the well locations match to within 10%. Moreover, experimentation shows that
13 mechanics time steps (taken over the course of 5 years of simulation time)
were sufficient to achieve this result (a substantial cost savings over full
coupling, in which both the mechanics and flow equations must be solved at each
The second numerical example is based on real data from Belridge field in California,
which illustrates one of the complex plastic constitutive relationships available
in the coupled code. The results mimic behavior that was observed in the field.
The coupled code serves as a prototype for loosely coupling together any two
existing simulators modeling diverse physics. This technique produces a coupled
code relatively quickly and inexpensively and has the advantage of accurately
modeling complex nonlinear phenomena often observed in a real field but difficult
to capture with a fully coupled simulator. Further, the code has produced promising
results when used for seismic time-lapse studies of compactible reservoirs.
Project researchers have:
- Written a high-level driver to couple together two independent simulators
(IPARS and JAS3D).
- Analyzed numerical techniques for improving robustness and speed of the
flow solver when reservoir porosity and permeability change dynamically during
- Implemented a scheme for adaptively controlling time-stepping between the
- Run realistic Belridge Field data experiments-a simple experiment with a
single material layer and a complex experiment with 18 different material
- Performed the first time-lapse seismic analysis using coupled flow/mechanics
simulation (Belridge single layer). Flow/mechanics input produced noticeable
changes in reservoir rock densities for seismic.
Current Status (November 2005)
The project is complete. It received a no-cost extension to the end of March
Simulation domains for the multi-layer Belridge field analysis. Leftmost figure
is the computational domain for the mechanical deformation. The figure on the
right is the computational domain for the reservoir simulation. The calculation
focuses on Layer J, which is labeled in the figure.
Vertical subsidence (in meters) after 7 years of coupled simulation for the
Belridge field analysis.
Minkoff, S.E., Stone, C.M., Bryant, S., and Peszynska, M., Coupled Geomechanics
and Flow Simulation for Time-Lapse Seismic Modeling, Geophysics, V. 69, No.
1, January-February 2004, pp. 200-211.
Minkoff, S.E., Stone, C.M., Bryant, S., Peszynska, M., and Wheeler, M.F., Coupled
Fluid Flow and Geomechanical Deformation Modeling, Journal of Petroleum Science
and Engineering, 38, 2003, pp. 37-56.
Project Start: October, 1999
Project End: March 2004
Anticipated DOE Contribution: $750,000
Performer Contribution: $500,000 (in-kind by oil industry partners; 40%
NETL - Purna Halder (email@example.com or 918-699-2083)
SNL - C. Mike Stone (firstname.lastname@example.org or 505-844-5113)