Recovery Factors And Reserves In Naturally Fractured Reservoirs
Authors: Aguilera R. 
Published: March 2010

Introduction

Conventional reservoir engineering techniques and naturally fractured reservoirs do not mix well. The use of conventional techniques has led to underestimating or overestimating recoveries and reserves in many naturally fractured reservoirs worldwide.

This paper is a follow-up to a previous article dealing with advances in the study of naturally fractured reservoirs(1). In that article I concentrated on types of fractures, how to intersect them, and on key items associated with data acquisition.

In this paper I provide general information dealing with recovery estimates and reserves in naturally fractured reservoirs. The paper is intended for the general interest reader who is not a specialist in the field.

Recovery

Not all fractured reservoirs are the same. So talking about fractured reservoirs in general is not good enough. My recommendation is to initially classify the reservoir according to (1) geologic, (2) pore system, (3) hydrocarbon storage, and (4) matrix/fracture interaction points of view.

Geologic Classification

From a geologic point of view the fractures can be classified as being tectonic (fold and/or fault related), regional, contractional (diagenetic), and surface related(1–3). Historically most hydrocarbon production has been obtained from tectonic fractures, followed by regional fractures and followed by contractional fractures. In general, surface related fractures are not important from the point of view of hydrocarbon production. When classifying the fractures determine fracture dip and strike.

Pore Classification

It is possible to make preliminary estimates of productive characteristics of common reservoir porosity types following a classification proposed by Coalson et al(9). In this classification porosity classes are defined first by the geometry of the pores, and second by pore size.

Included in. the geometry are the following pore categories: Intergranular, Intercrystalline, vuggy, and fracture. The combination of any of them can give origin to dual and even multiporosity behavior.

Included in the pore size are megaporosity, macroporosity, mesoporosity, and microporosity.

Table 1 shows typical petrophysical parameters for this classification adapted from a combination of Coalson et al. (9), and White(10). Included in this Table are the geometry, pore size, pore throat radius at 35% mercury saturation (Winland R35 values), permeability to air, immobile water saturation and typical capillary pressure curves coded A through D. These capillary pressures are shown on Figure 1.

The aperture of the fractures and vugs deserve further discussion. From laboratory work and experience it has been found that nut shells and plastic materials can stop circulation losses in fractures with apertures as large as 5,000 microns. If in a given naturally fractured reservoir these materials cannot stop circulation losses the conclusion is reached that the apertures are bigger than 5,000 microns. In fact, secondary porosity apertures can actually reach cavern-size in some instances.

Storage Classification

From a storage point of view the fractures can be classified(3) as being of Type A, B or C. Many reservoirs that would otherwise be non-productive are commercial thanks to the presence of natural fractures,(8)

In reservoirs of Type A the bulk of the hydrocarbon storage is in the matrix porosity and a small amount of storage is in the fractures.