CARBONATE RESERVOIR CHARACTAERIZATION
1. As against primary porosity - either inter-granular or intra-particle porosity (which mostly remain insensitive to stresses and thereby not actively participating in dictating the resultant preferred orientation),
(a) if the spatial distribution and alignment of primary fractures and secondary fractures (micro-cracks) in a given direction could contribute to the anisotropic behavior of carbonate reservoirs – as a function of regional stress distribution; and
(b) if the presence of secondary pores such as vuggy/fenestral/moldic/inter-crystalline porosity could contribute the stiffness (leading to a significant difference between acoustic log porosity and neutron-density log porosity) and strength to the carbonate reservoirs; then,
to what extent, are we successful in characterizing the quality (and elasticity) of a carbonate reservoir by measuring the various in-situ secondary pore-types?
And, how easy/difficult would it remain, if the secondary porosity keeps varying as a function of (varying) effective stress?
Can we still manage to characterize the above system with the data from neutron-porosity and sonic-logs (albeit, their inability to directly measure the rock’s pore-types)
or
an averaging between HSW/Reuss lower bound and Voiget upper bound would sound better for a carbonate reservoir?
2. In the presence of a formation damage, will we be able to qualify fracture porosity when VDL remains negative;
or,
Formation/Electrical micro-imagers would remain better (or a micro-CT)?
3. Leaving aside the micro-cracks associated with the fracture-porosity, which one of the following three:
(a) clay-related pores;
(b) inter-grain and inter-crystal pores; and
(c) stiff pores;
would predominantly aid
in migrating the mobility of oil
from low-permeable rock-matrix to high-permeable fractures?
Dr. Govindarajan, greetings. If you are trying to characterize a reservoir with permeability anisotropy related to natural fractures, your biggest challenge is the inadequacy of borehole data to describe the fracture system. Several tasks must be undertaken to provide the context to extrapolate borehole data to the drainage area that would be sampled by dynamic well production data for history matching. The first task is to understand the relation of the reservoir-scale geologic structure to the regional stress field. Second, find suitable outcrop analogues to your reservoir based on what you know from the first task. Third, some attempt to develop a probabilistic geostatistical understanding of the fracture geometry and intensity at the reservoir scale from the outcrop analogue would help understand the range of uncertainty to apply to your wellbore data. The amount of uncertainty inherent in using just the wellbore data without a context to extrapolate it makes successful prediction difficult. John Lorenz has published data comparing vertical and horizontal cores that sampled fractured reservoirs. His work on the Multi-Well Experiment in Colorado would be a starting point.
- Badges
- Science topic
- Similar topics
- Engineering
- Petroleum Engineering
- Oil