Fluid-Rock Characterization for NMR Well Logging and Special Core Analysis

for Project NMR well logging provides a record of formation porosity, permeability, irreducible water saturation, oil saturation and viscosity. In the absence of formation material, the NMR logs are interpreted using default assumptions. Special core analysis on core samples of formation material provides a calibration between the log response and the desired rock and/or fluid property. The project proposes to develop interpretations for reservoirs that do not satisfy the usual assumptions inherent in the interpretation. Also, NMR will be used in special core analysis to investigate the mechanism of oil recovery by wettability alteration and the relative permeability of non-water-wet systems. Some common assumptions and the reality of exceptional reservoirs are listed in the following and will be addressed in this project. (1) Assumption: in situ live crude oil and OBM have a relaxation time proportional to temperature/viscosity as correlated from stock tank oils. Reality: methane and ethane relax by a different mechanism than for dead oil and GOR is a parameter; carbon dioxide does not respond to proton NMR but influences oil and gas viscosity and relaxation rates. (2) Assumption: the in situ hydrocarbons have a relaxation time equal to that of the bulk fluid, i.e. there is no surface relaxation as if the formation is water-wet. Reality: Most oil reservoirs are naturally mixed-wet and drilling with oil-based mud (OBM) sometimes alters wettability. If the formation is not water-wet, surface relaxation of the hydrocarbon will result. (3) Assumption: OBM filtrate has the properties of the base oil. Reality: OBM filtrate often has some level of the oil-wetting additives and in some cases has paramagnetic particles. It may also have dissolved gas. (4) Assumption: the magnetic field gradient is equal to that of the logging tool. Reality: paramagnetic minerals may result in internal magnetic field gradient much greater than that of the logging tool. (5) Assumption: pores of different size relax independently. Reality: clay lined pores can have significant diffusional coupling between microporosity and macroporosity. Abstract for 2nd-Annual Report Progress is reported on Tasks: (1.1) Properties of live reservoir fluids, (2.1) Extend the diffusion editing technique and interpretation, (2.4) Interpretation of systems with diffusional coupling between pores, (2.5) Quantify the mechanisms responsible for the deviation of surface relaxivity from the mean value for sandstones and carbonates. and (3) Characterization of pore structure and wettability.for 2nd-Annual Report Progress is reported on Tasks: (1.1) Properties of live reservoir fluids, (2.1) Extend the diffusion editing technique and interpretation, (2.4) Interpretation of systems with diffusional coupling between pores, (2.5) Quantify the mechanisms responsible for the deviation of surface relaxivity from the mean value for sandstones and carbonates. and (3) Characterization of pore structure and wettability.