**1. Introduction**

Unconventional hydrocarbon reservoirs are different from their conventional counterparts in the sense that they require distinctive operations for recovery that differ from normal practices deployed for conventional reservoirs. The main reason for this is the ultra-low permeability of the rock formation, which hinders the ease of flow of hydrocarbons towards the well, but other factors such as the reservoir fluid properties also impact flow mechanisms. Examples of unconventional reservoirs are gas hydrates, oil shales, gas shales, tight-gas sandstones, tight-gas limestones, heavy oil and tar sandstones, and coalbed methane reservoirs [1–7].

As the term implies, heavy oil and tar reservoirs are those that contain viscous and dense oils. About a third of the total world oil and gas reserves consist of the heaviest range of hydrocarbons, yet they are mostly overlooked due to the perceived high costs and difficulties associated with its production [5]. Although reservoir properties including pressure, permeability and porosity are important measures of its behaviour, the fluid density and viscosity determine the approach used for production [5]. Heavy oils and tars are generally high in density and viscosity. Density is a measure of how much mass is contained per unit volume. The standard unit of measurement adopted in the oil and gas industry, especially in the United States, is the degree of American Petroleum Institute (API) gravity. A lower API value indicates a higher density and vice versa. Normally, oils below 20o API gravity are defined as heavy which may be as low as 4o for bitumen with high tar content [3, 5]. Oil viscosity, on the other hand, defines its resistance to gradual shear or tensile deformation when subjected to shear or tensile stress respectively. A viscous fluid exhibits resistance to shear stress and, thus, its flow is reduced where shear stresses are applied. Oil viscosity has an inverse relationship with temperature; it varies greatly by becoming less viscous as temperature increases. The flow rate of reservoir fluids is a key parameter and because of the direct link between viscosity, temperature and the ease of flow, oil viscosity is considered to be more important than oil density during production [3, 5]. Thus, viscosity, rather than density is used as a measure of the heaviness of oil. Under reservoir conditions, heavy oils have viscosities >100 cp [3]. Apparently, there is no direct correlation between density and viscosity, largely due to the influence of temperature. Low-density oils in shallow reservoirs, where the temperatures are cooler, may have higher viscosities in comparison to oils at hotter deep reservoirs.

Oil shale is a fine-grained sedimentary rock richly composed of organic matter [8], in the form of kerogen [2]. Kerogen is a solid mixture of organic compounds and is the primary source of hydrocarbons from oil shale. This type of hydrocarbon is referred to as shale oil, which is unconventional and different from tight oil naturally present in shales and ultra-low permeability sandstones, carbonates and siltstones [9]. Kerogen, also known in some instances as total or bitumen-free organic matter, consist of more than 80% organic matter; however, a major proportion of this is not readily soluble in ordinary organic solvents under moderate conditions [2]. Therefore, it is more challenging to extract in comparison to crude oil from conventional reservoirs because of high costs and negative environmental impacts [10]. To remove shale oil from oil shales, it is imperative to decompose the insoluble organic matter with heat. This is achieved by thermal dissolution, hydrogenation or pyrolysis [11–13]. The three methods require very high temperatures.

Tight oil is light crude oil found in shales and very low permeability and low porosity sandstones, carbonates and siltstones [9]. Although the term is sometimes used interchangeably with shale oil normally contained in oil shales (e.g., [9, 14]), there are distinctions. As at 2015 the world's technically recoverable tight oil from shale formations was estimated at 418.9 billion barrels (bbl). A large proportion of this amount is located at United States (78 bbl), Russia (75 bbl), China (32 bbl), Argentina (27 bbl), Libya (26 bbl), United Arab Emirates (23 bbl), Chad (16 bbl), Venezuela (13 bbl) and Mexico (13 bbl) [15]. Typical porosity and permeability of tight oil formations are below 12% and 0.1 mD respectively, though a broader definition of tight oil reservoirs can generally refer to those with very low porosity and permeability [9]. The low- porosity and permeability characteristics furthers the need to stimulate tight oil reservoirs for successful production.

Worldwide, the commercial production of unconventional hydrocarbons is in constant increase. This supplements supply from conventional reservoirs resulting in an overall increase in hydrocarbon production globally and a decrease in prices [16].

### *Production from Unconventional Petroleum Reservoirs: Précis of Stimulation Techniques… DOI: http://dx.doi.org/10.5772/intechopen.106318*

This inverse relationship between oil production and oil prices is illustrated in Monge *et al*. [14], where an increase in U. S. oil production from the shale oil boom drives down *West Texas Intermediate* (WTI) oil prices.

Other forms of unconventional gas resource are gas hydrates and coalbed methane reservoirs. Gas hydrates are crystalline ice-like forms of water with a structured molecular framework joined together to create cavities such that gas molecules, which are mostly methane, are trapped within it [17]. Other entrapped guest gases include ethane, isobutene and propane [18]. Natural gas hydrates were only discovered a few decades ago and 98% of deposits occur in upper sedimentary layers underneath the seafloor [7]. It is extensively spread in oceans and polar areas with a reserve that is 10 times greater than global conventional gas [18]. The creation and stability of gas hydrates rely on the properties of both the water and composition of gas, temperature and pressure [18, 19]. The formation of gas hydrate is exothermic, which implies the release of heat during this stage. On the other hand, heat is required for dissociation of hydrates [18–20]. The dissociation of hydrates is an endothermic process relying on the surrounding heat. Gas hydrates are stable at high pressure and low temperature conditions; therefore, depressurisation is an effective means of inducing the release of gas from hydrate deposits [20–22].

Coal seams are dark-banded deposits of coal trapped between layers of rock. They differs from conventional gas reservoirs in terms of their pore structure, porosity, permeability, fluid flow mechanism, gas-water relative permeability and other reservoir characteristics [23]. Coal is both heterogeneous and anisotropic; it is characterised by a dual porosity comprising a porous matrix with micro pores enclosed by a larger scale medium of cleats, which constitute the macro pores [23–25]. Coal porosity and permeability is mostly defined by the micro pores and macro pores, respectively [23]. Usually, water permeates coal seams, which helps to retain the adsorbed gas on the coal surface [25]. Coal seams are unconventional reservoirs containing a variety of gases including methane, hydrogen, ethane, nitrogen and carbon dioxide [26]. It contains a significant proportion of methane, which is more easily extracted in comparison to some of the other gas constituents (e.g., hydrogen and nitrogen). This is due to the reduced affinity coal has for methane. The concentration of methane in the gas content can be as high as 99.95% [27]. The chemical composition of coalbed methane—also known as coal seam gas—is the same as natural gas obtained from conventional reservoirs. The gas is contained in three ways: adsorbed on the surface of micro pores; in a free state in macro pores, i.e., the natural fractures (cleats) within the coal material; and dissolved in the formation water [23, 25, 28].
