*2.2.3 Transverse vertical fractures along horizontal wells*

For horizontal wells, the primary recovery method for reservoir stimulation is hydraulic fracturing, whereby transverse fractures that intersect the well are created (**Figures 2** and **3**). This instigates a substantial pressure drop that intensifies fluid flow towards the wellbore, thus increasing its performance [52]. Hydraulically fractured horizontal wells perform better than their vertical counterparts (**Figure 2c**). Fractures are orientated either longitudinally or transversely to the well (**Figure 2a** and **b**). Longitudinal fractures are aligned in the same direction as the horizontal well; i.e., along the lateral direction parallel to the well (**Figure 2b**). Horizontal wells with longitudinal fractures are better suited for reservoirs with permeability values that are relatively higher and have a comparable performance as fractured vertical wells [52–54]. On the contrary, under the same conditions, transversely fractured horizontal wells perform better in comparison to both fractured vertical wells and longitudinally fractured horizontal wells [52–54]. To maximise productivity, the optimal number of transverse fractures intersecting the horizontal well should be determined; this usually depends on the fluid and reservoir properties [53].

### *2.2.4 Surfactant treatment*

Surfactants are amphiphilic organic compounds and divided into hydrophobic and hydrophilic groups. For enhanced oil recovery (EOR), they normally serve as viscofiers or are used to reduce strong capillary forces in the pores of the reservoir rock [55, 56]. Oil shales are characterised by their ultra-low permeability. Strong capillary forces exist in their pores, which hold the oil to the rock surface. To recover the oil, it is necessary to lessen these capillary forces by altering the interfacial tension, contact angle and wettability [55–57]. Surfactants are used to:


Surfactants are also commonly classified as ionic and non-ionic. Ionic surfactants are further categorised as anionic (e.g., Alkyl Aryl Sulfonates, Sodium Dodecyl Sulfate (SDS) and Alpha-Olefin Sulfonate (AOS)) and cationic (e.g., Cetyl Trimethyl Ammonium Bromide (CTAB), Ethoxylated Alkyl Amine and Dodecyl Trimethyl Ammonium bromide (DTAB)) [61]. Non-ionic surfactants are *Production from Unconventional Petroleum Reservoirs: Précis of Stimulation Techniques… DOI: http://dx.doi.org/10.5772/intechopen.106318*

**Figure 2.**

*Configuration of (a) transverse fractures in horizontal well, (b) longitudinal fractures in horizontal well, and (c) fractures in conventional vertical well [50].*

#### **Figure 3.**

*Relating fracture to horizontal wellbore orientation [51].*

not charged; examples of these are Alkyl Polyglycoside (APG), Nonylphenol "N" Ethoxylate and Polyethoxylated Alkyl Phenols) [61]. Other groups of surfactant reported in Negin *et al.* [61] are bio and Zwitterionic surfactants.

#### **Figure 4.**

*Mechanism for the alteration of wettability in a pore, from oil-wet to water-wet. Squares are anionic active organic compounds and circles are cationic surfactants [58].*

#### **Figure 5.**

*Mechanism for the alteration of wettability in a rock surface, from oil-wet to water-wet. Circles are cationic surfactants (R-N+ (CH3)3), large squares are crude oil carboxylates and small squares are additional polar compounds [59].*

#### **Figure 6.**

*Alterations in wettability as contact (wetting) angle reduces [60].*

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

### *2.2.4.1 Wettability*

Wettability is the tendency of a fluid to remain in contact with the surface of a solid. For a given wetting fluid, there is an inverse relationship between wettability and contact angle. This means that its wettability decreases when there is a rise in contact angle [62, 63]. The injection of fracturing liquid in the reservoir alters the dynamics of wettability because it introduces another liquid phase to the system. Where two liquids co-exist, one will be wetting and the other non-wetting.

In a multiphase reservoir, such as oil shale, consisting of more than one type of immiscible fluids (e.g., water and shale oil), the wetting fluid preferentially wets the rock surface due its low mobility and stronger attractive forces with the rock. For an oil-water reservoir fluid, water is the denser of the two phases and preferentially wets the rock when the contact angle is less than 90o , the adhesion tension is negative, and the interfacial tension between the water-rock interface exceeds that for the oil-rock interface [64]. The adhesion tension is the difference between the oil-rock and water-rock interfacial tensions. Conversely, oil will be the preferential wetting fluid if the contact angle of water is between 90° and 180°, the adhesion tension is positive, and the interfacial tension between the oil-rock interface exceeds that for the water-rock interface [64]. Water imbibition is boosted as the water-wet wettability increases, resulting in a reduction in the saturation of residual oil [65].

#### *2.2.4.2 Effect of contact angle on wettability*

It may not always be easy to define the wettability of a reservoir in a straightforward manner since it is influenced by other factors such as contaminants, surface roughness and time [62, 66]. Nonetheless, the contact angle can serve as a criterion to distinguish between wetting and non-wetting liquids. Whereas, the contact angle of the wetting liquid with the rock is below 90o , for a non-wetting liquid it is between 90o and 180°. If the reservoir consists of both oil and water, the wetting fluid will form a contact angle that is less than 90o [63]. The wetting fluid attaches and spreads along the rock surface thereby enhancing the mobility of the non-wetting fluid. The choice of an appropriate hydraulic fluid should account for this. For instance, water-based fracturing fluids applied in a reservoir will serve as wetting fluids whilst boosting the flow of preexisting hydrocarbons, and the degree of its wettability—in other words, the ease of spread on the rock surface—increases as the contact angle decreases.

#### *2.2.5 Water imbibition*

The periodic injection of water into unconventional reservoirs enhances oil recovery because of the imbibition of water by the rock matrix and the displacement of oil trapped within the pores [45]. This technique is fit for shales with a higher water than oil uptake. Shale has a higher affinity for water, which is reflected by larger rates of imbibition [67]. However, it is possible for water blockage to occur resulting in negative impacts on the recovery process [45, 68]. To circumvent this, well-shut operations can be used to drive water further into deeper water-wet sections [45]. Alternatively, surfactants are introduced to improve the water-wet wettability or to completely change the wetting fluid from oil to water [45, 69].

Imbibition is a form of diffusion where a liquid is absorbed into a solid particle resulting in an increase in volume of the particle. It is normally instigated in response to a concentration gradient between the solid (absorbent) and the liquid leading,

potentially, to movement of the liquid towards the solid particle. Imbibition is also described as the displacement of an immiscible fluid by another one within a porous medium. This is a typical phenomenon in hydrocarbon reservoirs involving the displacement of the non-wetting fluid out of the pores of the reservoir rock by the wetting fluid [70–72]. It is another means of primary and secondary oil recovery [72]. Water flooding is a form of secondary oil recovery that involves imbibition, where water is injected to displace residual oil in the reservoir [73]. In a water-wet reservoir rock, water—the wetting phase—displaces oil, which is the non-wetting phase [72]. Imbibition is an important process that aid recovery of oil in fractured reservoirs [72, 74, 75].

Imbibition is a complex phenomenon encompassing the multifarious interactions between gravity, capillary and viscous forces. Whereas, gravity and viscous forces are external agents that could be used to drive imbibition, capillary forces are generated internally within the porous medium. On this basis, there are two categories of imbibition: spontaneous/natural and forced. Spontaneous or natural imbibition is the process whereby a wetting fluid displaces a non-wetting fluid within a reservoir rock due to capillary pressure [70, 72, 76, 77]; for instance, water displacing oil in an oil-saturated reservoir rock. On the other hand, forced imbibition are caused by viscous and gravity forces. These external agents create pressure gradients that enable the displacement of non-wetting by wetting fluids. The manner of flow between the wetting and non-wetting fluid determines the type of spontaneous imbibition. Co-current spontaneous imbibition happens where the directions of flow between the wetting and non-wetting fluid are the same. Contrastingly, counter-current spontaneous imbibition happens when the wetting and non-wetting fluid are flowing in opposing directions [70, 75, 78]. In a water-wet reservoir rock, the prevalence of any type of spontaneous imbibition—hence, oil recovery process—depends on the extent of exposure of the rock to water. Oil recovery is dominated by co-current imbibition when the rock is not wholly in contact with water [78]. This form of imbibition is the predominant process that produces oil and occurs in the region of the rock surface in contact with oil. Co-current imbibition evokes a much higher oil recovery rate in comparison to counter-current imbibition, implying a greater production efficiency; in other words, the rock surface in contact with oil produces more oil in contrast to the surface in contact with water [78]. The linear rate of co-current imbibition is shown by Unsal *et al.* [79] to be up to four times higher than counter-current imbibition.

### *2.2.6 Thermal treatment*

Kerogen, which is a solid, insoluble and rich source of organic compounds in oil shale and other sedimentary rocks, can be converted to shale oil by thermal dissolution, hydrogenation or pyrolysis. These are ex situ processes conducted at the ground surface after mining the oil shale and entails the use of very high heat to extract shale oil. Pyrolysis is the thermal decomposition of the organic matter component in solid fuel in an inert environment, and hydrogenation is a chemical treatment involving the reaction between molecular hydrogen and another compound/element with or without the presence of a catalyst. The process can be used to saturate or reduce organic compounds. Hydrogenation can be used to attain high oil yields from oil shales by converting its organic matter content to heavy oil, petrol, etc. [80]. Thermal dissolution is a hydrogen-donor solvent refining process [12]. It is a technique of shale oil extraction, whereby a hydrogen donor solvent such as *tetralin* is introduced into the solid fuel at high temperatures resulting in the depolymerisation, dissolution and cracking of the dissolved organic matter [12, 81, 82].

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

#### *2.2.7 Acidisation*

The injection of certain types of acid into oil shales can lead to rock matrix dissolution—whereby, for instance, sediments and mud solids are dissolved—increasing its permeability and porosity [83]. This technique can be applied to release oil and gas trapped in very small quantities within the rock matrix by repairing a previously damage formation (reflected by a restoration of permeability) and/or enhancing the natural permeability through the creation of additional pores [83]. Examples of acids used in practice are hydrogen chloride (HCL), hydrofluoric acid (HF), and organic forms such as methanoic (formic) acid (HCO2H or HCOOH) and acetic acid (CH3COOH). To improve performance, acid blends are frequently used. HCL can be combined with HF or sodium hydroxide (NaOH) [2] or organic acids.

For this technique to be successful, the rock must be, at least, partially soluble in acid. Carbonates are readily soluble in acid; thus, this approach is suitable for carbonate rocks—sedimentary rocks mainly composed of carbonate minerals e.g., limestone and dolostone [84]. Acidisation is also effectively applied to formations composed primarily of silicate minerals (e.g., sandstone, consisting majorly of aluminosilicates and quartz); however, the two reservoirs (carbonate and silicate reservoirs) are responsive to different types of acids. Sandstones are not soluble in HCL, although this acid is highly acidic. They are more reactive to the relatively weaker HF. HCL is more effective in formations with a rich content of carbonate minerals. Since many formations may be a combination of carbonate and silicate minerals, a blend consisting of a mixture of two or more types of acids is common in practice [2, 45, 83].

Two acidisation techniques are notably used for reservoir stimulation: matrix acidisation and acid fracturing [84]. Matrix acidisation entails the injection of acid into the formation at a pressure below the fracturing point (fracturing pressure). Hence, the formation is not fractured; instead, the acid forming new pathways for fluid flow etches the rock. The key mechanisms include mineral dissolution and the mobilisation of fragmented rock particles resulting in the creation of wormholes [84].

Acid fracturing is analogous to hydraulic fracturing but with the use of acids to react and etch channels within the walls of the fracture. The central difference between matrix acidisation and acid fracturing is the injection rate. In acid fracturing, the solution is pumped into the formation at a high rate leading to a build-up in the fracture pressure, and the initiation and proliferation of fractures. The high flow rate implies that there will be a shorter reaction time and the acid solution is not retained long enough to etch long channels on fracture walls.

Acidisation is less suitable for shale than in other rocks; nonetheless, it can still be applied in stimulating shale formations rich in carbonates [2, 45, 85]. Wormholes are not easily created in shales because of its low permeability, therefore matrix acidisation will likely not be effective [45]. Acid fracturing is the preferred and most suited strategy whereby new fractures are created within the formation and then, together with existing fractures, are roughened by the etching process to further enhance permeability and porosity. For oil shale formations, further improvement in reservoir conductivity is observed through the use of acid blends (e.g., sodium hydroxide mixed with hydrochloric acid (NaOH-HCL) and hydrochloric acid mixed with hydrofluoric acid (HCL-HF)). This is demonstrated in Alhesan *et al.* [2]; however, sufficient enhancement in permeability and porosity can still be established by applying a single type of acid, e.g., HCL, on shales which are rich in carbonates (e.g., [45, 85]). Carbonate minerals such as calcite (calcium carbonate, CaCO3), a constituent of carbonate-rich shale, dissolve in HCL.

Generally, the mineralogy of shale varies between formations and impinges upon its mechanical properties [86, 87]. Shale may content a significant amount of any or a combination of clay, calcite or quartz minerals. Although HCL augments the porosity and permeability of calcite-rick shales, it is observed to have contrary effects on shales with low calcite or high clay content; this is caused by formation damage or impairment as a result of clay swelling and related acid-rock reactions [85]. HCL reaction with calcite is typical presented as [87]:

$$\text{CaCO}\_3 + 2\text{HCl} \rightarrow \text{CaCl}\_2 + \text{H}\_2\text{O} + \text{CO}\_2 \tag{1}$$

### **2.3 Tight reservoirs**

Tight oil/gas reservoirs are sometimes referred to as shale reservoirs, but a broader and more accurate definition given in Zhang *et al.* [9] describes it as an ultra-low permeability reservoir rock (sandstone, siltstone, shale and carbonate rocks) closely related to oil shales. The latter concept is adopted in this discourse; notwithstanding, discussions are largely focused on tight sandstones with intermittent allusions to other types of tight oil/gas reservoirs. What qualifies a reservoir to the termed 'tight' is primarily based on its permeability, porosity, and closeness to (or interbedding with) source rocks [9, 88]. Threshold values of 12% for porosity [9] and 0.1 mD for permeability [6, 9, 88] are usually the main distinguishing set of criteria. Recovery from tight reservoirs can be achieved through methods including hydraulic fracturing, water imbibition, surfactant treatment/flooding, acidisation and the generation of an electro-kinetic potential [83, 89–92].

#### *2.3.1 Hydraulic fracturing: tight reservoirs*

In a broad sense, the concept of hydraulic fracturing, is generic for all reservoirs, as described in Section 2.2.2. The discussion in this section is not stand-alone; rather, it complements the narrative in Section 2.2.2 and Section 2.2.3. There are three typical approaches for implementing hydraulic fracturing [91, 93]: hydraulic proppant fracturing, water fracturing and hybrid fracturing. The choice of technique is dependent on the formation, and rock and fluid type. Hydraulic proppant fracturing is the conventional technique involving the injection of very viscous gels mixed with a high concentration of proppants. Proppants prop the created fractures thereby maintaining an elevated conductivity. This method creates comparatively short fractures and is suitable for formations of moderate to high permeability [91].

Water fracturing is the injection of water composed of slick water (friction reducers) and a low concentration of proppant to produce extensive but low-width fractures. A conceptual representation of a fracture geometry is illustrated in **Figure 7**. The lengthy geometry of the fracture allows it to connect the wellbore to distant reservoir areas. Water fracturing is appropriate for low permeability (< 1 mD) reservoirs, since fractures with small widths are not effective in moderate to high permeability formations [91, 95, 96]. A key leverage of water fracturing is the considerable cheaper cost in relation to other hydraulic fracturing methods (i.e., hydraulic proppant fracturing and hybrid fracturing), whereas a major weakness is proppant settlement due to the low viscosity of injected fluids, which causes a non-uniform proppant distribution within the propped fracture [95].

Hybrid fracturing is a combination of different hydraulic fracturing stimulation methods, borrowing the advantages of individual treatment approaches. In essence and in the context of the discussion here, it is a blend of hydraulic proppant fracturing and water fracturing. Succinctly, the procedure entails an initial injection

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

**Figure 7.** *Fracture geometry as produced by a vertically oriented wellbore [94].*

of slick water to create fractures, followed by a treatment with a cross-linked gel consisting of the desired concentration of proppants. The cross-linked gel is conveyed to the extreme ends of the fracture [91]. Hybrid fracturing combines the benefits of both conventional fracturing and water fracturing. Effective fracture half-lengths and fracture conductivities are higher in the induced fractures [93] and the polymer loading in the cross-linked gel is considerably less than what is used for conventional hydraulic proppant fracturing. This has a knock-on effect on the extent of polymer damage [91]. Some of the issues associated with hydraulic proppant fracturing are applicable to hybrid treatment [91].

The choice of hydraulic fracturing technique for tight reservoirs depends on several factors. If cost is a chief factor, water fracturing is preferred.
