**1. Introduction**

Hydraulic fracturing has been recognized as the most effective technique for economic recovery in tight oil and gas formations in North America [30], [36]. Hydraulically induced fractures increase well-reservoir contact area enormously; hence well productivity improves

© 2013 Taleghani et al.; licensee InTech. This is an open access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2013 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

greatly after stimulation. During a typical hydraulic fracturing treatment, a mixture of proppant and viscous fluids is injected into the formation to create a fracture. The main mechanism responsible for fracturing the rock is the generation of tensile stresses ahead of pressurized fracture. The direction of the fracture will be perpendicular to the direction of minimum principal in-situ stress [23]. Well-testing analysis done at the early production life of these wells provide estimations for hydraulically induced fracture surface areas which are much larger than the fracture dimensions estimated in fracturing design or predicted areas constrained by the scattering domain of microseismic events. Presence of microcracks might be indicated by increased pore volume and compressibility, as well. This finding is speculated to be related to microcracking [42] i.e. a large population of microcracks could essentially explain this result. It is notable that microcracks are not necessarily micron size. We call them microcrack because they are much smaller than the major hydraulic fractures (millimetres in size). This hypothesis becomes more plausible by considering the fact that a large number of these tight sand and shale gas reservoirs [17] are naturally fractured. Presence of natural fractures and their fractal distribution is a widely observed fact in various tight sand and shale formations. The significance and role of these pre-existing natural fractures on the performance of fracturing treatments and post-frac production are not well-understood; consequently, most analysis is mainly descriptive rather than quantitative. In summary, there is no model to predict the likelihood of opening these fractures in different scales. For instance, few models have been introduced to predict interaction of hydraulic fractures with large size natural fractures [18], [31]. Here, large size natural fractures are fractures with the lengths and heights comparable with the size of hydraulic fractures. Laboratory experiments [10] have confirmed the influence of these large fractures in changing the direction of fracture propagation, and earlier shallow depth mineback experiments have shown similar outcomes [45]. However, there is no similar study about the role of microfractures. Almost all published models in the literature are limited to the cases in which natural fractures have the same height as that of hydraulic fractures. Considering the fact that power-law distribution of natural fractures implies population of small size fractures to be orders of magnitudes more than that of the large size fractures, it is not surprising that induced large fractures are intersecting thousands of these fractures. Due to their small sizes, small natural fractures cannot be propped by proppants; their aperture and therefore their hydraulic conductivity is a function of the innerfracture fluid pressure. Due to their presence in large numbers, only partial reactivation of these natural microfractures may affect fluid flow pattern near the major fracture. These effects could be in the form of increasing the total effective wellbore-formation contact area and consequently improving hydrocarbon production, or oppositely, these microfractures could act as capillary traps for the fracturing fluid. The entrapped water, which is essentially part of the leakoff volume that will never produce, could hinder hydrocarbons flow from the forma‐ tion into the major hydraulic fracture.

under certain circumstances, it is possible to have tensile stresses. Two main mechanisms responsible for inducing tensile and/or shear forces on the surface of major fractures are thermal stresses and residual stresses due to the plastic deformation of the rock during

Secondary Fractures and Their Potential Impacts on Hydraulic Fractures Efficiency

http://dx.doi.org/10.5772/56360

775

Figure 1 shows a typical response of the bottomhole pressure and temperature measurement during a fracturing treatment. Fluid and proppants have been pumped for a period of time, and the termination is marked by a red line and followed by an extended period of shut-in that lasts much longer than the pumping time [23]. Of particular interest here is that minimum temperature, minimum fracturing fluid pressure and maximum leakoff fluid pressure occurs almost simultaneously within a short period of time after shut-in. Minimum downhole temperature and maximum pore pressure due to leakoff could be essential factors in reducing rock effective stress. The red mark also indicates the onset of depressurization which also

**Figure 1.** Bottomhole net pressure and temperature history during a typical fracturing treatment is shown above. The red line marks the most likely point for the initiation of secondary fractures as bottomhole temperature is at its lowest

point (maximum thermal stress) and unloading started due to pumping termination.

hydraulic fracturing.

locally develops tensile stresses.

Low required energy for the re-opening of natural fractures makes them susceptible to reopening if large enough tensile or shear stresses are somehow generated on the surface of major fractures. Then, depending on the distribution of natural fractures and the strength of their digenetic cements, their possible reactivation may influence hydrocarbon flow consid‐ erably. Despite the predominantly compressive stress regime around pressurized fractures under certain circumstances, it is possible to have tensile stresses. Two main mechanisms responsible for inducing tensile and/or shear forces on the surface of major fractures are thermal stresses and residual stresses due to the plastic deformation of the rock during hydraulic fracturing.

greatly after stimulation. During a typical hydraulic fracturing treatment, a mixture of proppant and viscous fluids is injected into the formation to create a fracture. The main mechanism responsible for fracturing the rock is the generation of tensile stresses ahead of pressurized fracture. The direction of the fracture will be perpendicular to the direction of minimum principal in-situ stress [23]. Well-testing analysis done at the early production life of these wells provide estimations for hydraulically induced fracture surface areas which are much larger than the fracture dimensions estimated in fracturing design or predicted areas constrained by the scattering domain of microseismic events. Presence of microcracks might be indicated by increased pore volume and compressibility, as well. This finding is speculated to be related to microcracking [42] i.e. a large population of microcracks could essentially explain this result. It is notable that microcracks are not necessarily micron size. We call them microcrack because they are much smaller than the major hydraulic fractures (millimetres in size). This hypothesis becomes more plausible by considering the fact that a large number of these tight sand and shale gas reservoirs [17] are naturally fractured. Presence of natural fractures and their fractal distribution is a widely observed fact in various tight sand and shale formations. The significance and role of these pre-existing natural fractures on the performance of fracturing treatments and post-frac production are not well-understood; consequently, most analysis is mainly descriptive rather than quantitative. In summary, there is no model to predict the likelihood of opening these fractures in different scales. For instance, few models have been introduced to predict interaction of hydraulic fractures with large size natural fractures [18], [31]. Here, large size natural fractures are fractures with the lengths and heights comparable with the size of hydraulic fractures. Laboratory experiments [10] have confirmed the influence of these large fractures in changing the direction of fracture propagation, and earlier shallow depth mineback experiments have shown similar outcomes [45]. However, there is no similar study about the role of microfractures. Almost all published models in the literature are limited to the cases in which natural fractures have the same height as that of hydraulic fractures. Considering the fact that power-law distribution of natural fractures implies population of small size fractures to be orders of magnitudes more than that of the large size fractures, it is not surprising that induced large fractures are intersecting thousands of these fractures. Due to their small sizes, small natural fractures cannot be propped by proppants; their aperture and therefore their hydraulic conductivity is a function of the innerfracture fluid pressure. Due to their presence in large numbers, only partial reactivation of these natural microfractures may affect fluid flow pattern near the major fracture. These effects could be in the form of increasing the total effective wellbore-formation contact area and consequently improving hydrocarbon production, or oppositely, these microfractures could act as capillary traps for the fracturing fluid. The entrapped water, which is essentially part of the leakoff volume that will never produce, could hinder hydrocarbons flow from the forma‐

Low required energy for the re-opening of natural fractures makes them susceptible to reopening if large enough tensile or shear stresses are somehow generated on the surface of major fractures. Then, depending on the distribution of natural fractures and the strength of their digenetic cements, their possible reactivation may influence hydrocarbon flow consid‐ erably. Despite the predominantly compressive stress regime around pressurized fractures

tion into the major hydraulic fracture.

774 Effective and Sustainable Hydraulic Fracturing

Figure 1 shows a typical response of the bottomhole pressure and temperature measurement during a fracturing treatment. Fluid and proppants have been pumped for a period of time, and the termination is marked by a red line and followed by an extended period of shut-in that lasts much longer than the pumping time [23]. Of particular interest here is that minimum temperature, minimum fracturing fluid pressure and maximum leakoff fluid pressure occurs almost simultaneously within a short period of time after shut-in. Minimum downhole temperature and maximum pore pressure due to leakoff could be essential factors in reducing rock effective stress. The red mark also indicates the onset of depressurization which also locally develops tensile stresses.

**Figure 1.** Bottomhole net pressure and temperature history during a typical fracturing treatment is shown above. The red line marks the most likely point for the initiation of secondary fractures as bottomhole temperature is at its lowest point (maximum thermal stress) and unloading started due to pumping termination.

Fracturing fluid is frequently pumped with the temperature very close to the surface temper‐ ature; hence its temperature at the bottomhole usually differs from the initial temperature of the reservoir, especially in the case of deep and hot formations. The temperature gradient between the fracturing fluid and formation is a function of formation temperature, injection rate, casing/tubing diameter, the distance from perforations to the surface, heat capacity of fluids, fracture width and treatment pressure [8]. For most cases, fracturing fluid does not have enough time to reach the formation temperature due to its high velocity in the tubing. Because of the fluid migration and heat transfer in the reservoir, such differential temperature induces thermal stresses. The tensile and shear stresses induced by this temperature difference could be large enough to initiate small cracks on the fracture surface or in the case where pre-existing natural fracture are present, these stresses may open them. Thermal cracking happens when induced stresses inside the rock due to cooling exceed the in-situ stress of the formation, this phenomenon is well-documented in waterfloodings of brittle hot rocks [39] and geothermal systems with cold water circulation [46]. Thermal cracking may lead to the formation of clusters of small cracks, or so-called secondary fractures, which are very similar to pavement cracks but on the surface of the main hydraulic fracture.

lation of opened natural fractures clustered rather than uniform. Additionally, their model

Secondary Fractures and Their Potential Impacts on Hydraulic Fractures Efficiency

http://dx.doi.org/10.5772/56360

777

Thermal stresses are not necessarily the only driving force behind formation of microfractures or opening of pre-exiting natural fractures. Plastic deformation induced during fracture pressurization results in tensile residual stress upon reduction of fracturing fluid pressure. Therefore, microcrack initiations can be enhanced upon unloading, as long as the pressuriza‐ tion at the pumping stage induces plastic deformation in rock. Cracking due to stress release resulted from unloading is a well-established mechanism in indentation experiments [16]. Choi et al. (2012) explains that plasticity is playing the main role in nucleation of microfractures during unloading. They showed the nucleation of microfractures from microscopic voids during unloading of hydraulic fracture. Plastic deformation induced during pressurization of main hydraulic fracture creates a tensile residual stresses during depressurization of hydraulic fracture. Therefore, these tensile residual stresses initiate the nucleation of microfractures; but compared to microcracks induced by thermal gradient, the effect of tensile residual stresses due to plasticity has not been studied so much. In this paper, the effect of plastic deformation on opening the natural fractures has been studied. In terms of methodology for modelling natural fracture reactivation, this paper is an extension of the work done by Dahi-Taleghani

As it mentioned before, thermal stresses and plasticity induced residual stresses may generate some microfractures or reactivate pre-existing natural fractures, but activation of these fractures does not necessarily lead to production enhancement due to the increase in contact area. If microfractures act as capillary traps, contact area and productivity index can be considerably influenced. Capillary trapping occurs when hydraulic pressure cannot overcome the capillary entrance pressure of microfracture to open it, and it's a function of pore geometry, rock-fluid interaction and fluid flow inside the pores; therefore, considering capillary pressure effect and trapping mechanism is quite important to achieve a realistic prediction of fractured well productivity and the amount of producible leakoff fluid volume. Pore geometry and rockfluid interaction control capillary trapping. Capillary trapping effect can become a quite interesting topic in hydraulic fractured reservoirs and naturally fractured reservoirs. To activate natural fractures, fracturing fluid pressure should go beyond the in-situ rock stresses; however, due to small aperture size of these fractures, if the hydraulic pressure cannot overcome the capillary entry threshold pressure of microfracture, formation fluid may not flow

Due to the limited knowledge about the presence of natural fractures and their potential distribution in different formations, their contribution has been ignored or at least has not received enough attention. Only recent advances in characterization of natural fractures and verification of power-law distribution of fractures in different length scales [35], as well as the development of more sophisticated mechanistic models for fracture initiation and propagation such as cohesive crack models, made the investigation about the role of these natural fractures

The remainder of the paper is organized as follows. In the next section, we talk about distri‐ bution of natural fractures, which is followed by sections about rock plasticity and a section

considered interaction between propagating fractures.

et al. [19] regarding the effect of plastic residual stresses.

via the microfracture to reach the main fracture.

possible.

As mentioned earlier, when the induced stresses inside the rock overcome formation in-situ stresses, re-opening of natural fractures may also occur. However, the spacing and geometry of opened cracks, in addition to previously mentioned parameters, are also functions of natural fractures distribution. Although these thermal induced cracks and re-opened parts of the preexisting natural fractures have small size in comparison to the main hydraulic fracture, they can tremendously increase the well-formation contact area. For the case of no capillary trapping, the fluid flux inside these secondary fractures is roughly proportional to the cube of the fracture width and to the inverse of spacing length. Based on thermoelasticity analysis for closely spaced fractures, the fracture width is proportional to fracture spacing. Therefore, the fluid flux inside the thermal induced fracture is a quadratic function of spacing length [5]. Moreover, Bazant et al. [5] showed that the ratio of crack depth-to-spacing in pavements (elastic half-space) is a sensitive function of temperature profile inside the crack. Heat transfer for hydraulic fracturing has been studied in the last couple of decades. For instance, Biot et al. [8] proposed a one-dimensional analytical solution for heat transfer in the plane strain geometry. The fundamental solution for a centre of dilation and a point source fluid injection was provided earlier by Cleary [13]. Clifton and Wang [14] utilized this fundamental solution for a pseudo-three dimensional hydraulic fracturing simulations. However, these models are mainly investigating local changes of in-situ stresses rather than the likelihood of initiating secondary fractures. Study on the effect of stress redistribution on fractures due to thermal gradient of rock mass and fracturing fluid received more attention for geothermal reservoirs due to the presence of large temperature differences [3], [5], [46]. Zhou et al. [46] adapted this problem in the context of initiation of secondary fractures from a hydraulic fracture in hot dry geothermal systems with brittle rocks. Dahi-Taleghani et al. [19] considered the effect of induced thermal stress during hydraulic fracturing on opening of cemented natural fractures. They used the concept of cohesive interfaces in the framework of three dimensional finite element methods to show how thermal conductivity of the rock mass could make the popu‐ lation of opened natural fractures clustered rather than uniform. Additionally, their model considered interaction between propagating fractures.

Fracturing fluid is frequently pumped with the temperature very close to the surface temper‐ ature; hence its temperature at the bottomhole usually differs from the initial temperature of the reservoir, especially in the case of deep and hot formations. The temperature gradient between the fracturing fluid and formation is a function of formation temperature, injection rate, casing/tubing diameter, the distance from perforations to the surface, heat capacity of fluids, fracture width and treatment pressure [8]. For most cases, fracturing fluid does not have enough time to reach the formation temperature due to its high velocity in the tubing. Because of the fluid migration and heat transfer in the reservoir, such differential temperature induces thermal stresses. The tensile and shear stresses induced by this temperature difference could be large enough to initiate small cracks on the fracture surface or in the case where pre-existing natural fracture are present, these stresses may open them. Thermal cracking happens when induced stresses inside the rock due to cooling exceed the in-situ stress of the formation, this phenomenon is well-documented in waterfloodings of brittle hot rocks [39] and geothermal systems with cold water circulation [46]. Thermal cracking may lead to the formation of clusters of small cracks, or so-called secondary fractures, which are very similar to pavement

As mentioned earlier, when the induced stresses inside the rock overcome formation in-situ stresses, re-opening of natural fractures may also occur. However, the spacing and geometry of opened cracks, in addition to previously mentioned parameters, are also functions of natural fractures distribution. Although these thermal induced cracks and re-opened parts of the preexisting natural fractures have small size in comparison to the main hydraulic fracture, they can tremendously increase the well-formation contact area. For the case of no capillary trapping, the fluid flux inside these secondary fractures is roughly proportional to the cube of the fracture width and to the inverse of spacing length. Based on thermoelasticity analysis for closely spaced fractures, the fracture width is proportional to fracture spacing. Therefore, the fluid flux inside the thermal induced fracture is a quadratic function of spacing length [5]. Moreover, Bazant et al. [5] showed that the ratio of crack depth-to-spacing in pavements (elastic half-space) is a sensitive function of temperature profile inside the crack. Heat transfer for hydraulic fracturing has been studied in the last couple of decades. For instance, Biot et al. [8] proposed a one-dimensional analytical solution for heat transfer in the plane strain geometry. The fundamental solution for a centre of dilation and a point source fluid injection was provided earlier by Cleary [13]. Clifton and Wang [14] utilized this fundamental solution for a pseudo-three dimensional hydraulic fracturing simulations. However, these models are mainly investigating local changes of in-situ stresses rather than the likelihood of initiating secondary fractures. Study on the effect of stress redistribution on fractures due to thermal gradient of rock mass and fracturing fluid received more attention for geothermal reservoirs due to the presence of large temperature differences [3], [5], [46]. Zhou et al. [46] adapted this problem in the context of initiation of secondary fractures from a hydraulic fracture in hot dry geothermal systems with brittle rocks. Dahi-Taleghani et al. [19] considered the effect of induced thermal stress during hydraulic fracturing on opening of cemented natural fractures. They used the concept of cohesive interfaces in the framework of three dimensional finite element methods to show how thermal conductivity of the rock mass could make the popu‐

cracks but on the surface of the main hydraulic fracture.

776 Effective and Sustainable Hydraulic Fracturing

Thermal stresses are not necessarily the only driving force behind formation of microfractures or opening of pre-exiting natural fractures. Plastic deformation induced during fracture pressurization results in tensile residual stress upon reduction of fracturing fluid pressure. Therefore, microcrack initiations can be enhanced upon unloading, as long as the pressuriza‐ tion at the pumping stage induces plastic deformation in rock. Cracking due to stress release resulted from unloading is a well-established mechanism in indentation experiments [16]. Choi et al. (2012) explains that plasticity is playing the main role in nucleation of microfractures during unloading. They showed the nucleation of microfractures from microscopic voids during unloading of hydraulic fracture. Plastic deformation induced during pressurization of main hydraulic fracture creates a tensile residual stresses during depressurization of hydraulic fracture. Therefore, these tensile residual stresses initiate the nucleation of microfractures; but compared to microcracks induced by thermal gradient, the effect of tensile residual stresses due to plasticity has not been studied so much. In this paper, the effect of plastic deformation on opening the natural fractures has been studied. In terms of methodology for modelling natural fracture reactivation, this paper is an extension of the work done by Dahi-Taleghani et al. [19] regarding the effect of plastic residual stresses.

As it mentioned before, thermal stresses and plasticity induced residual stresses may generate some microfractures or reactivate pre-existing natural fractures, but activation of these fractures does not necessarily lead to production enhancement due to the increase in contact area. If microfractures act as capillary traps, contact area and productivity index can be considerably influenced. Capillary trapping occurs when hydraulic pressure cannot overcome the capillary entrance pressure of microfracture to open it, and it's a function of pore geometry, rock-fluid interaction and fluid flow inside the pores; therefore, considering capillary pressure effect and trapping mechanism is quite important to achieve a realistic prediction of fractured well productivity and the amount of producible leakoff fluid volume. Pore geometry and rockfluid interaction control capillary trapping. Capillary trapping effect can become a quite interesting topic in hydraulic fractured reservoirs and naturally fractured reservoirs. To activate natural fractures, fracturing fluid pressure should go beyond the in-situ rock stresses; however, due to small aperture size of these fractures, if the hydraulic pressure cannot overcome the capillary entry threshold pressure of microfracture, formation fluid may not flow via the microfracture to reach the main fracture.

Due to the limited knowledge about the presence of natural fractures and their potential distribution in different formations, their contribution has been ignored or at least has not received enough attention. Only recent advances in characterization of natural fractures and verification of power-law distribution of fractures in different length scales [35], as well as the development of more sophisticated mechanistic models for fracture initiation and propagation such as cohesive crack models, made the investigation about the role of these natural fractures possible.

The remainder of the paper is organized as follows. In the next section, we talk about distri‐ bution of natural fractures, which is followed by sections about rock plasticity and a section regarding cohesive interface constitutive equations to model mechanical behaviour of preexisting cemented natural fractures. At the end, numerical results of implementing this model for several examples will be presented to examine the significance of induced thermal stress in different situations.

#### **2. Natural facture distribution**

Fracture is a mechanical discontinuity in the rock mass formed due to the presence of stress fields in earth's crust (Figure 2). There are wide scale ranges for fractures from micrometre (microfractures) to kilometres (lineaments). Presence of fractures in earth's crust can influence underground fluid flow and physical properties of rock like rock strength. Fractures can influence the velocity of elastic waves and rock elastic moduli [41]. Natural fractures are categorized into four groups [40] based on their genesis : (1) tensile fractures due to compres‐ sive stresses, (2) shear fractures due to compressive stresses, (3) tensile fractures due to unloading of compressive stresses, (3) natural hydraulic fractures. Despite indeterministic nature of the aforementioned mechanisms, a large number of outcrop studies have revealed pattern and identifiable organization in fracture orientation and spacing. Due to the limited access to the subsurface to map fractures and limited precision of seismic techniques, outcrops are the main source to speculate fracture's geometry in the subsurface. There are different distribution models used to describe fracture size like fracture length, aperture and tangential or perpendicular displacement due to fracture. Scale-limited laws (lognormal, exponential, gamma and power law) are methods in literature to characterize fracture systems [9], but it should be mentioned that scaling exponents alone cannot act as good criterion to define the whole pattern of fracture networks. Moreover, Bonnet et al. [9] showed that there is a linear relationship between rupture area and frequency scale of tensile fractures in seismometers acting. Field studies have confirmed the existence of a critical threshold that cracks with aperture less than this threshold are fully filled with digenetic materials [34]. Although microfractures are filled with calcite or quartz cements, laboratory measurements have proved that these filled natural fractures may still act as weak surfaces, or in other words, potential paths for rock failure. For instance, lab measurements for Barnett shale samples have shown tensile strength of cemented cracks to be about 10 times less than the tensile strength of intact rocks [27]. There exist some integrated models in the literature that can be utilized for this purpose [33]. By combining the knowledge of natural fracture patterns, cement properties and current in-situ stresses, it is possible to build a model to make a realistic prediction about the distribution of natural fractures in the case of limited core and outcrop data.

**3. Elastoplastic effect in fracturing**

Cardott. [25])

considerable plasticity unless in very weak formations

The mechanical behaviour of quartz or calcite is essentially identified as elastic and brittle, however, clay/organic dominated regions can undergo significant plastic strains. Hence, it is not surprising that excessive fluid pressure present during hydraulic fracturing treatments may induce plastic deformations. This issue has been the subject of several studies in the literature [37], [38], [44]. For instance, it has been shown that plasticity causes shorter and wider fractures. However, most of these plastic deformations are due to high stress near the tip of the hydraulic fracture. The excess pressure in the main fracture may be only 1 or 2 MPa higher than the minimum in-situ stress, and this amount of additional stress may not cause a

**Figure 2.** Natural fractures present in a wide range of size and spacing. A pen is used as the scale in this outcrop pic‐ ture. Depending on the magnitude of induced stresses and others conditions only a portion of these cracks may be reactivated. Effective contact area is determined based on the population of opened fractures (Photo courtesy of Brian

Secondary Fractures and Their Potential Impacts on Hydraulic Fractures Efficiency

http://dx.doi.org/10.5772/56360

779

These papers were mainly focused on plastic deformations induced at the tip of fractures due to stress concentration at the tip of fractures, while plastic deformation of the surrounding rocks and its possible effects was out of the scope of these papers. Irreversible strain charac‐ terizes the plasticity when stress reaches a certain point. After this yielding point, the material

Proppants cannot move into microfractures opened during hydraulic fracturing due to their small aperture, which is less than a couple of microns. However, hydraulic pressure can open the microfractures if it goes beyond the local closure stress; therefore, activation of microfrac‐ tures is function of confining pressure and pore pressure. As it mentioned earlier, contact area between rock-fluid can be considerably affected by the presence of microfractures in large quantities despite their small aperture and depth.

Secondary Fractures and Their Potential Impacts on Hydraulic Fractures Efficiency http://dx.doi.org/10.5772/56360 779

**Figure 2.** Natural fractures present in a wide range of size and spacing. A pen is used as the scale in this outcrop pic‐ ture. Depending on the magnitude of induced stresses and others conditions only a portion of these cracks may be reactivated. Effective contact area is determined based on the population of opened fractures (Photo courtesy of Brian Cardott. [25])
