Summary

Most existing nuclear magnetic resonance (NMR) permeability correlations for carbonates assume that vugs do not contribute to permeability. The objective of this work is to improve permeability estimation from NMR responses for carbonates by including vug connectivity. Six carbonate samples from a west Texas field were studied. NMR T2 measurement, mercury porosimetry, thin-section imaging [using optical microscopy and a scanning electron microscope (SEM)], computerized tomography (CT) scanning, and electrical measurements were conducted. The permeability of the samples studied is controlled by the channels that connect vugs. Capillary pressure and NMR T2 measurements show multimodal pore-throat and pore-body-size distributions. A modified Chang model, which includes the tortuosity factor, is proposed and proven to yield a better permeability prediction than the original Chang model. It is also shown that for the samples studied, the tortuosity can be estimated from NMR T2 distribution, hence allowing permeability prediction from the NMR T2 distribution alone.

Introduction

More than 50% of the world's hydrocarbon reserves are in carbonate formations.1 However, estimating petrophysical properties from NMR measurements in carbonate rocks has always been a bigger challenge than in sandstone formations. Carbonates are characterized by different types of porosity and complex pore-size distributions. Because of their reactive nature, carbonates undergo a more complicated post-depositional diagenesis compared to siliciclastic sandstones. The diagenesis process includes cementation, dissolution, dolomitization, recrystallization, and evaporite mineralization.2 Carbonates are also sensitive to the microorganism activity in their depositional environment. Depending on whether they are grain- or mud-supported, carbonates can be classified into grainstone (no mud), packstone, wackstone, and mudstone (mud-dominated).2,3

Porosity in carbonate rocks can be categorized into three different types of porosity: intragranular porosity, intergranular porosity, and vugs.2 Intragranular porosity is the porosity inside the grain, and intergranular porosity is the porosity between the grains. A vug is defined as the pore space that is significantly larger than grains or crystals (or that is within grains or crystals).2 In more popular terms, a vug is a pore that is large enough to be visible to the naked eye. Vuggy pore space can be subdivided into separate vugs and touching vugs based on vug interconnections.2,4

A permeability correlation from NMR T2 measurement is given by Chang et al.5:

Equation 1

where f750 is the porosity and T2lm,750 is the logarithmic mean of T2 of the pore space consisting of pores with T2 less than 750 ms. The correlation assumes that vugs do not contribute to the flow and, hence, the contribution of the vugs in the T2 (which is above 750 ms) is not used. This may not always be the case; in some instances, vugs may be connected and may contribute to the permeability.

In this paper, we study six vuggy carbonate samples from a west Texas field using NMR, X-ray CT scanning, and routine core analysis (porosity, air permeability, mercury capillary pressure, thin-section imaging, and formation factor). The paper is organized into four main sections: core-characterization procedure, core-analysis results, permeability correlations from capillary pressure and NMR, and conclusions.

Core-Characterization Procedure
Sample Selection.

Six vuggy carbonate rock samples from a west Texas field were selected. Before the samples were plugged and cleaned, they were scanned by an X-ray CT scanner to identify regions to be plugged. The samples were cleaned with toluene, chloroform/methanol azeotrope, and methanol in a Dean Stark extraction apparatus. The diameters of the plugs were 1 to 1.5 in. The porosity and air permeability for the cleaned plugs were measured.

Mercury Capillary Pressure.

Endpieces of the samples were dried at approximately 100°C. They were evacuated to less than 50 microns vacuum, and mercury was injected over 117 pressure steps ranging from 1.64 to 60,000 psia.

Thin Section.

The thin section was viewed by using an optical microscope. The picture was captured by using a CCD camera, and the video output signal was sent to a PC computer by using a frame-grabber card. The picture was then segmented into pore space and solid by using Crabtree's algorithm.6 Several contiguous images were taken for the same sample and then composed together to form a larger image of approximately 1 to 2 cm coverage. The resolution of each pixel is 10 µm. The endpieces or the stubs of the thin sections were also studied by using SEM in the back-scattered electron (BSE) mode.

NMR T2 Measurement.

The NMR T2 measurement was conducted in a Maran Ultra* low field NMR spectrometer using the Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence. The following parameters were used: number of scans=32, echo spacing=600 µs, and number of echoes=10,240. The samples were saturated with 1 wt% NaCl brine.

3D Porosity Distribution From CT Scanner.

The dry and brine-saturated samples were CT scanned at 2-mm intervals in the z-direction. Then, the porosity distribution was calculated from the CT-number difference between brine-saturated and dry core. The CT scanner used was a Technicare Deltascan** 2060, and the scanner was mounted vertically. The pixel resolution is 254×254 µm in the xy plane and 2 mm in the z -direction. The parameters used were 8-second scanning time, 120 kV, 75 mA, and 12.5 cm scan diameter.

Tracer Experiment.

A 12 wt% NaI in 1 wt% NaCl brine was injected from the bottom into the brine-saturated core. CT scans were taken during brine displacement. The NaI outlet concentration was measured by using an online microconductivity meter.

Swr Experiment.

A 15 wt% iodo-decane in decane solution was injected from the top into the brine-saturated core. CT scans were done only at the end of the experiment. The brine and oil saturations inside the core were calculated from the mass balance.

p. 365-377

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