FLUID FLOW PROPERTIES FROM ACOUSTICALLY STIMULATED MAGNETIC FIELD GRADIENT NMR

摘要

We analyze a new approach for determining flow permeability using a combined NMR logging measurement in the presence of induced fluid flow. The concept is to measure the local velocity for fluid in the pore space of the formation rock using magnetic field gradient NMR where the local motion of the fluid is created in response to an externally applied time varying pressure. If the borehole fluid is in hydraulic contact with the formation fluid, the pressure could be applied at the surface of the drill well and transmitted by the borehole fluid to the formation of interest. If there is an impermeable barrier between the borehole fluid and the formation fluid, motion of the matrix fluid may still occur in response to a compressional wave that propagates through the formation. The compressional wave can be generated by a down hole vibrating source situated in the borehole fluid or that is in mechanical contact with the borehole wall. In either case, the time varying mechanical stress at the formation boundary generates a fast compressional wave that propagates through the formation, and generates an oscillatory displacement of the formation matrix together with the formation fluid. Biot theory relates the relative fluid flow, which controls the permeability, to the motion of the matrix. The relative local fluid motion in the formation pore space is measured using spin echo magnetic field gradient techniques which are possible using the current generation of NMR logging tools. We describe and present the theory consisting two different approaches for detecting the local fluid motion. One approach is to measure the response of the spin echo relaxation rate while the second is to measure the phase shift of the echo signal in response to the applied pressure wave. We calculate the local pressure in the formation using acoustic theory and predict the local fluid velocity fluctuation as detected by the NMR spin echo in the presence of a magnetic field gradient. Knowing these parameters, the local fluid mobility can be calculated using Darcy's law. The permeability can then be determined after an independent measurement of the fluid viscosity is made, either using NMR relaxation or diffusion measurements or other petrophysical measurements. We use numerical simulations of fluid flow using network model simulations on 3D digital images of rocks created using X-ray microtomography.