Preface

An oil and gas reservoir is a formation of rock in which oil and natural gas have accumulated. The oil and gas are collected in small, connected pore spaces of rock and are trapped within the reservoir by adjacent and overlying, impermeable layers of rock. Conventional hydrocarbon reservoirs consist of three main parts: the source rock that contains the kerogen that the oil and gas forms from; the reservoir rock, which is the porous, permeable rock layer or layers that hold the oil and gas; and the cap rock, which seals the top and sides so that the hydrocarbons are trapped in the reservoir, while water often seals the bottom. Reservoirs containing only free gas are termed gas reservoirs. Such a reservoir contains a mixture of hydrocarbons, which exists wholly in the gaseous state. With the ongoing energy needs of the world, the importance of oil and natural gas is increasing tremendously in the global market.

There are different types of crude oils with different properties, such as light crude, heavy crude, and extra heavy crude oils, which are categorized according to the American Petroleum Institute (API) degree of the crude. Normally, the heavier the crude, the higher its asphalt content. In addition, crude oils are also termed sweet or sour based on their sulfur content. In a refinery, crude oil processing mainly involves distillation, cracking, hydrocracking, hydrotreating, and blending. Depending on the type of crude used as feedstock, different processes are involved, with the main purpose being to convert as much of the barrel of crude oil into transportation fuels. Petroleum processing technology is rather mature. Nevertheless, it continues to develop in consideration of all types of sustainability-related challenges.

This book provides comprehensive information on the oil and gas industry, in addition to highlighting technological developments in the field. It is a useful resource for geoscientists, petroleum and reservoir engineers, and chemical engineers.

#### **Ali Ismet Kanlı, Ph.D.**

Professor of Geophysics, Faculty of Engineering, Department of Geophysical Engineering, Istanbul University-Cerrahpasa, Istanbul, Turkey

#### **Tye Ching Thian, Ph.D.**

Associate Professor, School of Chemical Engineering, Universiti Sains Malaysia, Engineering Campus, Pulau Pinang, Malaysia

**1**

most cases.

**Chapter 1**

**Abstract**

distribution

**1. Introduction**

Knudsen diffusion [10–13].

Gas Slippage in Tight Formations

In order to address the gas slippage for flow through tight formation, with a very low porosity (less than 10%) and permeability in micro-Darcy range, a series of single-phase gas flow experiments were conducted. Two different gases (N2 and He) were used to carry out many single-phase experiments at different overburden and pressure drops and were compared with carbon dioxide (CO2) flow types. The pore size distribution measurements showed the existence of a wide range of pore size distribution. Also, the single-phase gas flow experiments through the core plug, mostly at low pressure, showed Knudsen diffusion type, which is an indication of gas

**Keywords:** tight formation, slip effect, Knudsen diffusion, non-Darcy flow, pore size

Due to its high compressibility, gas flow behavior can vary greatly as the porous media size varies. Understanding this behavior and the type of flow is vital for the oil and gas industry, especially with the increase in production from unconventional

The flow behavior in pores can be estimated using many different mathematical models and experiments, the majority of which used the Knudsen number definition [1–3]. Many mathematical models were developed to determine the flow regime in nanopores as a function of adsorption [4, 5], rock permeability [6, 7], and molecular dynamics [8, 9]. All of these models used some form of the Knudsen number definition in their model in order to predict gas flow behavior as a function of different parameters. Many researchers also attempted to model Knudsen diffusion in shale gas reservoirs to determine the recovery potential when the dominant flow regime was

One of the main experimental methods to determine gas flow in nanopores relies on understanding the formation properties of the unconventional reservoir. Research has shown that unconventional tight sand gas reservoirs have three distinct features. These include relatively large pores with mineral deposition in the pores that resulted in a reduction in the overall pore diameter, narrow and flat pores that were generated due to alteration of the primary porosity of the rock, and grains supported by ultrafine micro-matrix particles, usually clays [14–16]. All three of these have a common feature, which is an extremely small average pore diameter, reaching nanoscale in

*Sherif Fakher and Abdelaziz Khlaifat*

molecules' slippage at the wall of the pores.

reservoirs with extremely low permeability.

**Chapter 1**
