Geomechanics issues are vital in all reservoir processes, but particularly so
in weak, unconsolidated sandstones. Coupled stress-flow simulation is necessary
to analyze and understand effects such as changes in reservoir volume that
arise from heating and pressurization. Also, non-linear plasticity models
incorporating shear dilatancy are needed to simulate the dilation effects that
are observed in thermal extraction processes in unconsolidated sands.
Stress-flow coupling is based on the volume changes that arise with pressure
and temperature changes ( Δp, ΔT). Incorporating shear dilation is based on
computation of effective stresses from ΔT and Δp, then assessing the state of
the rock to see if it is shearing and by how much it must dilate. These
processes are poorly quantified at present, so it is necessary to monitor the
process to calibrate simulation models.
The two monitoring domains of greatest interest to coupled geomechanics
simulation are the deformation field and the seismic attributes field. How
these fields evolve in space and with time are the key factors to tracking
processes, to calibrate geomechanics models and to successfully optimize
complex in situ processes.
A general geomechanics view of how to achieve process monitoring and
optimization goals is presented here. Though recent developments have been
promising, further progress in monitoring, inversion and coupled geomechanics
simulation is needed.
Conventional monitoring in petroleum engineering addresses pressure,
temperature and rate measurements, as well as data collected by wellbore logs
such as temperature or rate surveys (e.g. spinner surveys). Oil, gas and water
production and injection rates are required for regulatory purposes and to help
calculate saturations and recovery factors (RF).
Changes in reservoir response were commonly assessed using classical well tests
and analyses(1, 2). Because classic reservoir simulation in conventional low
viscosity cases deals only with mass and heat transport (Darcy and Fourier
diffusion processes) combined with saturation changes and relative permeability
calculations, these measures were deemed sufficient for reservoir management.
Flow rates (Q), well test data and facilities capability analyses are also used
for production optimization(3).
These measures are considered insufficient for heavy oil (HO) thermal
extraction, HPHT reservoir management, high compaction cases and
gravitationally-dominated production technologies. In such cases, we are more
interested in measures such as the reservoir pore volume change ( ΔV), gas
saturation changes in situ ( ΔSg), swept volume distribution, and so
on. These cannot be measured by conventional p-T-Q methods or geophysical
wellbore logging, nor are they easily amenable to calculation. When shear
dilation, compaction or induced fracturing take place, major changes in rock
mass properties occur; understanding what is happening and where it is taking
place requires different monitoring and simulation methods.
To make monitoring data more useful, flow-stress coupled modelling, also
referred to as coupled geomechanical modelling, is carried out. Changes in p
and T are analyzed in terms of effective stress changes ( Δ σ'ij)
through their effect on rock and pore volumes. The links between ΔV and the
changes Δp, ΔT and Δ σ'ij are established through p-, T-,
σ'-compressibilities of the bulk rock and of the mineral matter comprising the
© 2009. Petroleum Society of Canada (now Society of Petroleum Engineers)
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- Original manuscript received:
4 April 2007
- Meeting paper published:
12 June 2007
- Revised manuscript received:
15 April 2009
- Manuscript approved:
5 June 2009