Permeability Characterization and Prediction a Tight Oil Reservoir, Edson Feld, Alberta & Basic knowledge of NMR

Today, I read the thesis ‘Permeability Characterization and Prediction a Tight Oil Reservoir, Edson Feld, Alberta’ Chapter 1 (1.2 1.3 1.4) and learn about NMR online.

Summary

Core-based Permeability Prediction

These equations are accurate in relatively clean, consolidated sandstone with medium porosity (15%-25%).

In tight Cardium Formation, the unique and clean lithofacies is uncommon and shale plays an important role, which impairs the accuracy of these relationships.

1.3 In tight formations, it is difficult to directly measure the grain size distribution.

1.4 It is impossible to find an accurate general constant for all situations.

1.5 Recommend the c=250 and 79 for oil and gas, respectively.

1.6 empirical formula from laboratory tests

Conventional Log Permeability Prediction

1.7 Applicable only in homogeneous sandstones without significant amount of shale.

1.8 The key and difficult point of this model was the determination of the parameter w.

1.9 Applicable in tight formations.

1.10 An experimental estimator for permeability with Sw and resistivity.

1.11 A multiple regression model.

1.12 The model gave a weak correlation with core results.

These models were mainly suitable for high permeability or specific areas. Only the geological conditions from 1.9 are similar to Cardium tight foromation.

NMR-based Permeability Prediction

Two Empirical Models

A model based on 1.5: transverse relaxation time cutoff (T2 cutoff) selection, usually 33 ms for the T2 cutoff in sandstone, overestimation in tight formation compared to the core measured Swi, underestimate k.

SDR model: porosity from the NMR is usually underestimated, compared to core porosity in tight formations.

Thick-weighted permeability calculation model: There are not clean sand zones. So this method will overestimate the sand weights and k. Another weakness of this method is ignoring the shale k, which is unrealistic in tight formations.

For the NMR well log, the dominant T2 time is directly proportional to the pore size, ignoring fluid effects.

The mercury intrusion porosimetry (MIP) method has found pore size to be lognormal distribution.

Method in the thesis

Lithofacies and core analysis:

Pore throat aperture

Permeability distribution

Permeability heterogeneity

Clay minerals

Conventional logs-permeability calibration:

Factorial design

Check and connect well logs, probe permeability and core data

NMR prediction for permeability:

T2 spectrum can be obtained

T2 is proportional to pore size, log pore size has a Gaussian distribution

In core image analysis, specific facies (shale) volume proportions can be calculated according to color differences

Calibrate the model

Decrease uncertainty by Monte Carlo

Basic knowledge of NMR

NMR logging, a subcategory of electromagnetic logging, measures the induced magnet moment of hydrogen nuclei (protons) contained within the fluid-filled pore space of porous media (reservoir rocks). Unlike conventional logging measurements (e.g., acoustic, density, neutron, and resistivity), which respond to both the rock matrix and fluid properties and are strongly dependent on mineralogy, NMR-logging measurements respond to the presence of hydrogen protons. Because these protons primarily occur in pore fluids, NMR effectively responds to the volume, composition, viscosity, and distribution of these fluids.

NMR logs provide information about the quantities of fluids present, the properties of these fluids, and the sizes of the pores containing these fluids.

The volume (porosity) and distribution (permeability) of the rock pore space

Rock composition

Type and quantity of fluid hydrocarbons

Hydrocarbon producibility

NMR porosity is independent of matrix minerals, and the total response is very sensitive to fluid properties. Differences in relaxation times and/or fluid diffusivity allow NMR data to be used to differentiate clay-bound water, capillary-bound water, movable water, gas, light oil, and viscous oils. NMR-log data also provide information concerning pore size, permeability, hydrocarbon properties, vugs, fractures, and grain size.

Whether used as a standalone service or in combination with other logs and core data, NMR logs can provide an improved understanding of reservoir petrophysics and producibility. However, NMR logs are the most complex logging service introduced to date and require extensive prejob planning to ensure optimal acquisition of the appropriate data needed to achieve the desired objectives.

NMR physics

Atomic nuclei spin, and this angular moment produces a magnetic moment (i.e., a weak magnetic field). The NMR technique measures the magnetic signal emitted by spinning protons (hydrogen nuclei are the protons of interest in NMR logging) as they return to their original state following stimulation by an applied magnetic field and pulsed radio frequency (RF) energy. These signals, which are observed (measured) as parallel or perpendicular to the direction of the applied magnetic field, are expressed as time constants that are related to the decay of magnetization of the total system.

Polarization is not instantaneous—it grows with a time constant, which is called the longitudinal relaxation time, denoted as T1. Once full polarization (magnetic equilibrium) has been achieved, the applied static magnetic field, B0, is turned off.

T1 relaxation (polarization) curves indicate the degree of proton alignment, or magnetization, as a function of the time that a proton population is exposed to an external magnetic field.

T1 is the time at which the magnetization reaches 63% of its final value, and three times T1 is the time at which 95% polarization is achieved.

T1 is directly related to pore size and viscosity.

After application of a 90° pulse, the proton population dephases and an FID signal can be detected.

The FID signal measured in the x-y plane is called T2 —the transverse or spin-spin relaxation.

The primary objectives in NMR logging are measuring T1 signal amplitude (as a function of polarization), T2 signal amplitude and decay, and their distributions. The total signal amplitude is proportional to the total hydrogen content and is calibrated to give formation porosity independent of lithology effects. Both relaxation times can be interpreted for pore-size information and pore-fluid properties, especially viscosity.

In general, pulse NMR offers better methods to measure relaxation times and quantify liquid displacement in rock.

However, because the gradients produced by NMR-logging tools are relatively constant, they can be accounted for in T2 interpretation. In fact, the existence of these field gradients has actually proved beneficial in NMR logging.

The fundamental basis of Nuclear Magnetic Resonance (NMR) measurements on fluid-bearing rocks is that the decay or relaxation time of the NMR signals (T2) is directly related to the pore size. The NMR signal detected from a fluid-bearing rock therefore contains T2 components from every different pore size in the measured volume. Using a mathematical process known as inversion, these components can be extracted from the total NMR signal to form a T2 spectrum or T2 distribution, which is effectively a pore size distribution. From this distribution, various petrophysical parameters such as porosity, permeability, and free and bound fluid ratios can be measured or inferred.

Careful calibration of petrophysical interpretation models with core data is essential for obtaining accurate permeability and bound fluid answers from NMR logs, as compared to using default parameters in the petrophysical model.

The so-called ‘T2 cut-off’ in a T2 distribution is the T2 value that divides the small pores that are unlikely to be producible from the larger pores that are likely to contain free fluid. The integral of the distribution above the T2 cut-off is a measure of the free fluid (mobile fluid) in the rock, and is clearly influenced by the position of the T2 cut-off point, as shown in Figure 1. The portion of the curve below the cut-off is known as bound fluid and is made up of the clay bound fluid and the capillary bound fluid.

An accurate determination of the T2 cut-off point is essential for an accurate determination of recoverable reserves (mobile fluid). T2 cut-off can be easily determined in the laboratory by using two NMR measurements; one on a cleaned and re-saturated plug, the other on the same plug after it has been spun in a centrifuge to irreducible water saturation. T2 distributions are plotted for both data sets, along with the cumulative values of the distributions. The T2 cut-off is taken to be the point at which the cumulative value of the saturated distribution (yellow horizontal arrow in Figure 2) equals the final cumulative value of the irreducible distribution (vertical yellow arrow in Figure 2). The data plotting and calculation for this measurement are carried out automatically by the LithoMetrix software supplied as standard with every GeoSpec NMR core analyser.

Necessary apparatus

Tools needed to perform NMR log calibrations as described in this note include: a GeoSpec NMR Core Analyser with LithoMetrix or LithoMetrix Plus software; a centrifuge capable of removing all mobile (free) fluid from the core plug; and equipment to measure permeability. Although not required to perform log calibrations, pulsed field gradients on the GeoSpec instrument and optional GIT Systems software can allow users to perform additional advanced measurements to further enhance interpretation of NMR logs.

Tomorrow, I will read Chapter 4 of the thesis.