1. INTRODUCTION

Unconventional gas is natural gas derived from reservoirs not exploitable by conventional recovery techniques that includes coalbed methane, tight formation gas, gas hydrates (clathrates), and aquifer (geopressured) gas. Tight formation gas is natural gas trapped in low-permeability reservoirs and the importance of these hydrocarbon systems as global energy assets continues to grow with growing world energy demand. In addition to the complex geology, petrophysics, and reservoir heterogeneities, tight reservoirs provide unique challenges related to hydrocarbon storage and flow in complex rock systems, thus requiring an improved fundamental understanding for effective production. Over the coming years, effective exploitation of tight reservoirs will depend on new technologies and on improving the fundamental understanding of tight reservoirs over the life cycle of the field. The purpose of this paper is to provide a summary overview of tight gas reservoirs and their associated challenges from a number of perspectives. In particular, this paper defines tight gas and its worldwide distribution, highlights its petrophysical and lithological properties, stresses the importance of natural fractures, and describes what challenges are encountered during drilling, completion, and development of tight reservoirs. Then we discuss the related geomechanics and how it adds value for the development of tight gas reservoirs.

2.
DEFINITIONS

Tight formation gas is natural gas trapped in low-permeability reservoirs with in situ permeability of less than 0.1 millidarcy (mD), regardless of the type of the reservoir rock [1]. In recent years, the petroleum industry around the world has given tight gas reservoirs focused attention as evidenced by the significant increase of gas produced from such reservoirs. However, exploring for and developing from these reservoirs is met with a number of costly technical challenges due to the low to extremely low matrix porosity (typically <5%) and permeability's (generally in the mD to μD range) and appreciable heterogeneities in reservoir quality. An added complication is the increased effective stress due to depletion, as increased stress will reduce the low permeability further, Fig. 1a. The permeability in Fig.1a is based on direct flow measurements versus pressure drop in the field, and the minimum horizontal stress is based on leak off test data. It can be seen that the permeability has log-linear relation with the minimum stress magnitude. Similar trends can be found for other lithologies. It is also clear that the lower the initial permeability the more stress sensitive the formation becomes and this is illustrated in Fig.1b which shows the variation of fracture conductivity versus confining stress. It is clearly seen from Fig.1b that the lowest initial fracture conductivity (i.e., fluvial) is the most stress sensitive of the three samples. Thus, tight gas reservoirs cannot produce economic volumes of natural gas unless they are stimulated by massive hydraulic fracture treatments to improve permeability. An advanced technique to develop tight gas formations is horizontal drilling or multi-lateral wells often used in combination with massive hydraulic fracturing. These stimulation methods can achieve gas flow rates two to three times those of conventional vertical wells.

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