Abstract

An examination of the core and log analysis of carbonate reservoirs has confirmed that identified shortcomings are rooted in disparate pore character. Many of the interpretation methodologies were developed for clastic rocks, which typically show an intergranular porosity, sometimes augmented by fracture porosity. In carbonate reservoirs, the primary pore system comprises interparticle porosity that co-exists with a highly variable secondary system of dissolution voids and/or fractures. As a consequence, carbonate reservoirs are markedly heterogeneous from pore to reservoir scales, and this variability poses significant challenges to data acquisition, petrophysical evaluation, and reservoir description. For example, the ranges of carbonate facies and their pore character often control the distributions of net pay, porosity and hydrocarbon saturation.

Putting these matters together, conventional petrophysical practices that exclusively use reservoir zonation based on lithology/mineralogy have limited application in carbonates. Instead, recourse is made to a zonal discrimination that draws upon the distribution of microporosity and its connectivity with macroporosity and fractures. The discrimination scheme utilizes downhole technologies such as high-resolution imaging and magnetic resonance logs, supported by advanced core analysis. On this basis, a value-adding workflow is proposed to increase confidence in those petrophysical deliverables that are used in static volumetric estimates of petroleum Resources.

Introduction

Petroleum Resource estimation underpins the basis for field appraisal, development and management. At least in the earlier stages of field life, static volumetric methods form the basis for estimates of hydrocarbons in place and thence ultimate recovery. Petrophysics sits firmly on this critical path through the evaluation of reservoir size, net-to-gross pay, porosity and hydrocarbon saturation. Yet, although the uncertainties associated with these technical building blocks can be usefully quantified for clastic reservoirs, they are much less predictable in carbonates.

The reasons lie in the fundamental differences between clastic and carbonate reservoirs. Clastic reservoir rocks are predominantly sandstones that comprise quartz and other mineral components. These are transported from elsewhere and modified through weathering, lithification and diagenetic processes to form a clastic reservoir system. Sandstones can show a wide range of reservoir quality through variations in mineralogy, grain-size distribution and sorting, texture and degree of induration. On the other hand, carbonate rocks are mostly formed in situ through the growth of calcitic organisms and precipitation, with subsequent evolution being governed by compaction, cementation, dolomitization, dissolution and other diagenetic processes. Carbonates can show a very wide range of reservoir quality through pore-size distribution, pore connectivity, brittleness and thence fracturing, and the degree of dolomitization. In essence, therefore, sandstone reservoir quality is governed by mineralogy and texture whereas carbonate reservoir quality is governed by pore character.

Traditionally, most petrophysical practices utilize mineralogical criteria, so they are notionally tuned to sandstones. Therefore, their application to carbonate pore characterization is not straightforward and, because of this, it is more uncertain.

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