Summary
Nuclear-magnetic-resonance (NMR) measurements are considered among the most-reliable methods to evaluate porosity and pore-size distribution in fluid-bearing rocks. However, in reservoirs with complex pore geometry, there is still a challenge to interpret accurately NMR relaxometry data to evaluate petrophysical properties of these reservoirs such as interconnected porosity. In this paper, we introduce the application of nanoparticle contrast agents to improve assessment of interconnected porosity with NMR measurements. The comparison of NMR relaxometry data before and after nanoparticle injection enables distinguishing connected and isolated pore volumes (PVs), which might not be possible in the absence of contrast agents. The use of these contrast agents was demonstrated successfully in the magnetic-resonance-imaging (MRI) technique for clinical diagnosis.
We used superparamagnetic iron oxide nanoparticles (SPION) as contrast agents injected into rock samples with a multiple-porosity system (including intra-/intergranular pores and natural fractures) and then quantified their impact on NMR measurements with laboratory experiments and numerical simulations. We injected contrast agents in sandstone and organic-rich mudrock samples, and measured NMR T2 (spin-spin relaxation time) distributions before and after contrast-agent injection. We simulated the NMR responses in sandstone and organic-rich mudrock samples before and after injection of contrast agent with a random-walk algorithm. The simulated NMR T2 distribution was cross validated by experimental results. We also documented the simulation results in a carbonates sample before and after injection of contrast agents, and characterized the pore-network connectivity with the simulation T2 distribution.
The results show that the comparison of NMR relaxometry data before and after SPION injection improves characterization of interconnected porosity and connectivity of natural fractures in rock samples with complex pore geometry such as those from carbonate and organic-rich mudrock formations. We observed that the long-relaxation-time peaks in NMR T2 distribution significantly shift to short relaxation time after SPION injection, indicating that interconnected large pores/fractures are most easily invaded by SPION. However, the original short-relaxation-time peaks remained at the same position with almost the same amplitude and shape, indicating that small pores are not invaded by SPION. The accumulative porosity of the rock remains almost the same before and after SPION injection, indicating that SPION invasion in the rock only results in the downshifting of T2 relaxation time, but does not affect the NMR estimates of total porosity. We conclude from the experimental and numerical-simulation results that interconnected large pores/fractures, isolated large pores, and small pores can be differentiated in NMR T2 distribution with the aid of contrast agents. The outcomes of this paper are promising for the successful application of the introduced technique for pore characterization in heterogeneous multiple-porosity systems containing natural fractures.
A new method for permeability estimation from conventional well logs in glutenite reservoirs
