Porosity Distributions in Carbonate Reservoirs Using Low-Field NMR
Authors: Mai A. , Kantzas A. 
Published: March 2010

Alberta contains significant deposits of oil and gas in carbonate formations. Carbonates tend to have fairly tight matrix structures, resulting in low primary porosity and permeability. Laboratory characterization of carbonate properties is a slow and tedious process, however, core data is often collected in order to augment and tune logging tool predictions. In this application, having a good understanding of carbonate pore systems at the core analysis level is key to proper reservoir characterization. Low-field NMR is an emerging technology that shows great promise for rock characterization measurements. In this paper, low-field NMR technology is investigated for determining primary and secondary porosity through the interpretation of NMR spectra. This data was also used to establish the bound and mobile fluid distributions existing in the porous medium.

The data set for this experimental work consists of a large collection of core samples from various fields in Alberta and Saskatchewan. CT data were analyzed to obtain the primary and secondary porosity fractions, which were used to find corresponding NMR cutoff values that separate the NMR spectra into primary and secondary porosity.

A distinct relationship was observed between the primary porosity fraction and the irreducible water saturation, Swi. The fraction of NMR amplitude in the last peak of the NMR spectra can also be correlated to CT secondary porosity. Another important relationship observed is that the geometric mean relaxation time of the last NMR peak correlates well with the cutoff between primary and secondary porosity. The bound and mobile fluid distributions are generally distinguished through the identification of T2cutoff values. A correlation was found to predict T2cutoff for this wide range of samples.

This study shows that information from the fully saturated NMR spectrum can be used to estimate primary and secondary porosity fractions in carbonates, as well as bound and mobile fluid fractions.

Introduction

Porosity of carbonates is a complex problem that has had only limited attention in the literature(1). In general, carbonate porosity is divided into primary and secondary porosity. These different types of porosity are not easily distinguishable unless the primary pores and the diagenesis processes that occurred are studied(1). Despite these difficulties, it is very important to recognize and attempt to quantify the different porosity types and mobile/immobile fluid fractions in carbonates in order to help in developing carbonate reservoirs and to estimate the pore connections and recovery efficiency in these reservoirs.

As various researchers have found, Nuclear Magnetic Resonance (NMR) can capture pore size information of the porous media(2–4). Thus, in theory, it describes both the primary and secondary porosity. However, separating the signal into different porosity components remains a daunting task. Part of this difficulty arises from the fact that there is no clear distinction between primary and secondary pore size distributions, as they overlap with each other.

Chang et al.(3) have previously tried to separate the signal of vugs in NMR response. In carbonates, however, even the definition of vugs can be quite different. Chang et al.(3) used the term vugs to describe cavities that are formed in the matrix by diagenesis, with sizes ranging from about 100 μm to cavern size.