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Collaborating Authors
Results
Summary Nuclear-magnetic-resonance (NMR) logging is a well-established technology for estimating porosity, pore-size distribution, and permeability in conventional reservoirs. However, the uncertainty associated with these estimates can be significant in complex heterogeneous-carbonate reservoirs, such as those with variable pore size and pore-network connectivity. In such cases, distinguishing isolated-pore space is often impossible by use of well-log measurements and conventional well-log-interpretation methods, which makes permeability evaluation unreliable. This paper proposes a new application of the NMR log-inject-log method to improve assessment of permeability and to distinguish isolated pores from connected pores. We propose injecting manganese-bearing solution in the rock samples and simultaneously analyze NMR measurements before and after injection of the contrast solution. Injection of contrast agents enables eliminating the effect of isolated-pore space from the NMR T2 (spin-spin relaxation time) distribution, which is then used to improve permeability assessment. To confirm the feasibility of the proposed method for field applications, we conduct NMR laboratory measurements in two carbonate-rock types. We inject manganese-bearing solution into rock samples by use of a coreflood experimental procedure and measure NMR T2 distributions before and after injection. We then estimate isolated porosity and interconnected porosity by taking into account the difference between the NMR T2 distributions acquired before and after the injection of the contrast solution. We introduce a method to calculate the geometric mean of the T2 distribution for interconnected pores, and also to obtain effective free-fluid volume and bound-fluid volume. Finally, we use the T2 distribution corrected for the effect of isolated pores in conventional NMR-based permeability models to improve permeability assessment. We cross validate the NMR-based permeability estimates against Klinkenberg permeability measured by an unsteady-state gas permeameter. The results confirm that the proposed method enables quantifying the isolated and connected pore volume (PV), and finally improves NMR-based permeability assessment. The new method provides estimates of permeability with up to 10% average error in eight carbonate-rock samples, which was a significant improvement compared with the average errors of up to 500% when T2 distribution is not corrected for the effect of isolated pores.
- North America > United States > Texas (1.00)
- Asia (0.68)
- Overview > Innovation (0.54)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
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.
- Asia (0.93)
- North America > United States > Texas (0.70)
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.79)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.59)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
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