During the placement of the source rock in the oil generation window, the primary migration mechanism plays a critical role in the transport of hydrocarbons through fractures and pores in the source rocks (Kalani et al. 2015a, b; Huang et al. 2023). The primary migration process is poorly understood, and several mechanisms have been proposed with varying effects. However, microfractures are shown to be more critical when transporting hydrocarbons over longer distances (Cordell 1973; England et al. 1987; Hedberg 1974, 1980; Hunt 1990; Lafargue et al. 1994; Lafargue et al. 1998; Momper 1978; Ougier-Simonin et al. 2016; Rudkiewicz et al. 1994; Snarskiy 1961; Tissot and Welte 2013; Kang et al. 2023). Experiments indicate that the conversion of kerogen into hydrocarbons results in the formation of microfractures that control the development of these fractures by anisotropy and mechanical properties of the rock (Glatz et al. 2016; Kobchenko et al. 2011; Vernik 1994; Bolotov et al. 2023). Previous shale research has revealed that many microfractures grow alongside lamination (Figueroa Pilz et al. 2017; Kobchenko et al. 2011; Panahi et al. 2018; Saif et al. 2016, 2017; Larki et al. 2023; Saberi and Hosseini-Barzi 2023a, b; Barati et al. 2023; Niu et al. 2023; Li et al. 2023). Jin et al. (2010) illustrated that the rate of development of microfracture and pressure from oil generation is directly related to temperature. Teixeira et al. (2017), by conducting experiments on the Green River oil shale, showed that the formation of microfracture networks was directly related to the number and distribution of kerogen and the state of differential stress. The compressive stress that is perpendicular to the lamination causes the fracture to grow in the vertical direction. However, the anisotropy associated with bedding causes microfractures to grow in the horizontal direction. If the initial kerogen is higher in the source rock, it is more likely that individual microfractures will attach. Kalani et al. (2015a, b) reported that the development of microfractures depends on several factors, including tectonic setting mineralogical composition, and chemical compaction. Saif et al. (2016, 2017) observed that the size of micro-voids increased with raising the temperature on Green River shales. This suggests that micro-voids might be essential to hydrocarbon movement parallel to the layering. The Pabdeh Formation is one of the youngest source rocks due to the production of hydrocarbons in a part of the Dezful embayment. Therefore, the study of micro fracturing factors, including the pore fluid pressure and carbon content, is of great importance. We utilized geochemistry data, scanning electron microscopy (SEM) images before and after artificial thermal maturation, and Iatroscan to investigate the effect of the mentioned factors on the microfracture opening in the Pabdeh source rock.

The NW–SE Zagros Fold-Thrust Belt (ZFTB) is divided into the Fars and Izeh zones, the Lurestan zone, the Dezful Embayment (in Iran), and the Kirkuk Embayment (in Iraq) (Fig. 1) (Casciello et al. 2009; Falcon 1974; Mouthereau 2012; Sherkati and Letouzey 2004; Stöcklin 1968). The Dezful Embayment is bounded on the northeast by the Mountain Front Fault (MFF), on the southeast by the Izeh Fault Zone (IFZ), on the east by the Kazerun Transfer Fault (KTF), on the west by the Balarud Transfer Fault (BTF), and on the southwest by the Zagros Foredeep Fault (ZFF) (Fard et al. 2006; Alavi 1994; Allen and Talebian 2011; Berberian 1995; Sepehr and Cosgrove 2005; Makarian et al. 2023a, b, c; Elyasi et al. 2023a). The Karanj oilfield in the Dezful Embayment was chosen as the study area because it is located at the axis of maximum subsidence of the Dezful Embayment (Fig. 1). As the second major source rock, the petroleum system of this area belongs to the Pabdeh Formation, which was deposited by Late Cretaceous tectonics that caused the transgression of the sea in the Paleocene-Eocene, neritic-basinal marls, and argillaceous limestones of the Pabdeh Formation.

Structural map of the ZFTB showing the location of the Karanj oilfield in the southern Dezful Embayment

The stratigraphic column from the ground level to the final depth had a natural order of formation (including Gachsaran, Asmari, Pabdeh, and Gurpi, Ilam). The upper boundary of the Pabdeh Formation with limestones of the Asmari Formation is gradational. The lower contact with the Gurpi Formation is disconformable (Fig. 2). The lithological column of these wells has been plotted based on petrophysical studies and petrographic observations, which have great compatibility and show periodic wells of shale and lime.

The stratigraphic column in the Karanj oilfield

This paper is based on our research using polarizing and fluorescence microscopes to locate hydrocarbon and constituent minerals and the type of organic materials. We also used the results of XRD, Iatroscan, and Geochemical analyses performed on samples selected from the Pabdeh Formation, which is the second primary source rock in the southern part of the Dezful Embayment in the Karanj oilfield. According to Behar et al. (2001), Rock–Eval pyrolysis measurements were performed utilizing a Rock–Eval 6 instrument from the National Iranian South Oil Company; we distinguished horizons of the Pabdeh Formation that act as source rock from other non-source horizons, allowing us to select precise samples for subsequent analyses (Peters et al. 2005; Elyasi et al. 2023b; Saberi et al. 2023).

Pyrolysis was performed on 18 rock samples from the Pabdeh Formation to determine several aspects of hydrocarbon geochemical characteristics, e.g., hydrogen index (HI), Tmax, and total organic carbon (TOC). Furthermore, by examining the XRD results, knowledge was gained about the minerals of the source rock. This knowledge was used to investigate the effect of constituent minerals on the creation and development of fractures in the samples. Therefore, according to geochemical data, four samples were prepared out of core slabs from Well No. 31 at depths of 3039.5, 3034, 3030, and 3026 m. They all contained type II kerogens and nonindigenous hydrocarbons that are in their early maturation stage and can produce oil when mature, and they were selected for artificial thermal maturity. Consequently, these selected samples were heated under nitrogen gas in unconfined conditions (without pressure) at the Petroleum Industry Research Institute (Iran) to study the effect of organic matter content and organic matter maturation on the development of microfractures in the two thermal patterns according to Tables 1 and 2. Moreover, microscopic analyses, including SEM, were performed at Shahid Beheshti University (Iran). SEM images captured before and after heating were compared to determine the extent of changes and transformations of clay minerals (especially smectite minerals) and the number of microfractures before and after thermal maturation. Then, Sample 18 (3039.5), with the highest amount of TOC, was given to the Iatroscan machine to ensure the Correct heating process and hydrocarbon production by kerogens of the sample so that the role of hydrocarbon production-induced pressure would be matched with the microfractures observed in the microscopic images.

5.1 Polarizing microscope

According to the petrographic data, organic matter is trapped in the matrix of this formation (Fig. 3).

A sample of thin section from Pabdeh Formation showing organic matter trapped parallel to the layering. In addition, the presence of pyrite grains and mudstone matrix are evidences of a calm and oxygen-free environment, which shows that there were suitable conditions for the preservation of organic matter in the Pabdeh Formation

5.2 Fluorescence microscope

5.2.1 Maceral vitrinite group

Usually, the first step in identifying maceral vitrinite is morphology. Vitrinite can be present as separate layers, lenticular masses, or rounded and angled grains in sedimentary layers. The shape of vitrinite is highly dependent on the cutting surface of the samples. Most vitrinite macerals appear as long lenses in sections with a surface perpendicular to the lamination (Creaney 1980) (Fig. 4). The color and reflection of vitrinites vary according to the degree of maturity. This maceral can contribute to the production of hydrocarbons, but in the lower stages of maturity, the role of vitrinite in the production of hydrocarbon has not been proven.

A, a Microscopic images of reflected light and fluorescence of vitrinite maceral from a polished sample cut vertically (Karanj Well 31, depth of 3032.5–3033.5 m). B, b Microscopic images of reflected light and fluorescence of maceral vitrinite from a polished sample cut vertically (Karanj Well 31, depth of 3039.5 m). C, c Microscopic images of reflected light and fluorescence of vitrinite maceral from a polished sample cut vertically (Karanj Well 31, depth of 3028.5 m)

5.2.2 Maceral leptinite group

Lipinitic macerals are derived from parts of hydrogen-rich organic plants such as sporopollenin, cotin, sabrin, resin, waxes, latex, acids, and fats, whose morphology and reflection are the most important characteristics (Neavel and Miller 1960). The most important difference between maceral leptinite and vitrinite is the much higher fluorescence of leptin than vitrinite (Radke and Mathis 1980). The following are the maceral subgroups of leptin in the identified samples of the Pabdeh Formation:

5.2.2.1 Sporinite

The term sporinite is used for the covering wall of spores and pollen. This wall is usually made of a substance called sporopollenin, which has a naphthenic structure. The fluorescence properties of these macerals have a distinct tendency towards orange and light orange. Sporonites with a relatively small size and high fluorescence were abundant in Pabdeh Formation (Fig. 5).

A, a Reflected light and microscopic fluorescence images of maceral sporinite (Karanj Well 31, depth of 3029.5–3030.5 m). B, b Microscopic images of reflected light and fluorescence of maceral sporinite from a polished sample cut vertically (Karanj Well 31, depth of 3030.5–3031.5 m). C, c Microscopic images of reflected light and fluorescence of maceral sporinite (Karanj Well 31, depth of 3039.5 m)

5.2.2.2 Alginite

These algal carpets are composed of green and blue algae, often desmoplasia and diatoms, which also contain n-C16 and n-C18 structures in their chemical composition. Normal alkanes n-C15 and n-C17 are characteristic of the structural composition of algae. In contrast, acids with odd carbon are rarely found in them. In Pabdeh Formation, alginite maceral is distinguished from other macerals with high fluorescence and luminosity (Fig. 6).

A, a Reflected light and fluorescence microscopic images of maceral alginite from a polished sample cut vertically (Karanj Well 31, depth of 3028.5 m). B, b Microscopic images of reflected light and fluorescence of maceral alginite from a polished sample cut vertically (Karanj Well 31, depth of 3032.5–3033.5 m). C, c Reflected light and microscopic fluorescence images of maceral alginite along with pyrite from a polished sample cut vertically (Karanj Well 31, depth of 3028.5 m)

5.2.2.3 Cutinite

Cutinites are the covering material of leaves, buds, roots, and some thin stems (Neavel and Miller 1960). Their thickness can vary from 0.003 to 0.02 mm, and the fluorescence intensity of thick-layer cutinites is higher than that of thin-layer cutinites. In dry environments, the frequency of thick cutinites is higher than that of thin cutinites (Crelling and Bensley 1980; Neavel Miller 1960). Cutinites have long chain structures that are waxy in nature. During thermal maturation, alkanes are produced from cutinites. Figure 7 displays microscopic images of maceral cutinite in the Pabdeh Formation as narrow and elongated strips under fluorescent light.

A, a Microscopic images of reflected light and fluorescence of maceral cutinite from a polished sample cut vertically (Karanj Well 31, depth of 3039.5 m). B, b microscopic images of reflected light and fluorescence of maceral cutinite from a polished sample cut vertically (Karanj Well 31, depth of 3029.5–3030.5 m)

5.2.2.4 Liptodetrinite

These liptodetrinites result from destroying resinite, sporinite, and sabrinite macerals. Figure 8 shows microscopic images of maceral liptodetrinite in fluorescent and reflective light. Liptodetrinites of the Pabdeh Formation are detected with less length and thickness than cutinite.

Reflected light and microscopic fluorescence images of maceral liptodetrinite from a polished sample cut vertically (Karanj Well 31, depth of 3028.5 m)

5.2.3 Amorphous organic matter group

Microscopic studies demonstrate that the conditions prevailing in the sediments of this formation have been reductive, which is the reason for the high concentration of amorphous organic matter in the studied sections (Tyson and Idris 1984, Tyson 1987). Note that amorphous organic matter is much more concentrated in sedimentary carbonate environments such as the Pabdeh Formation than other organic matter. Figure 9 depicts the microscopic images (fluorescence and optics) of amorphous organic matter.

The presence of brown amorphous organic substances resulting from the destruction of phytoplankton and bacteria fragments during microbiological activities, which are either scattered in the matrix or fill the cracks

5.2.4 Cyanobacteria and thiobacteria

Organic matter of bacterial origin has different geochemical compositions, and constituents of type I to IV kerogen are formed in the Formation. Modern green–blue algae have the geochemical composition of type I to II kerogens (Horsfield 1984), while the degraded cyanobacterial sheets show the geochemical properties of type III kerogen (Kenig et al. 1990). Finally, the activity of green–blue algae has caused the formation of organic matter in the Pabdeh Formation. The presence of irregular shapes under fluorescent light is a prominent feature (Fig. 10).

Microscopic images of reflected light and fluorescence of organic matter resulting from the activity of bacteria from a polished sample cut horizontally (Karanj Well 31, depth of 3041 m)

5.3 Rock–Eval

The results of the pyrolysis of samples from the Pabdeh Formation of Karanj oilfield were investigated to determine the type and amount of organic matter, thermal maturity, and hydrocarbon production potential. We selected the sample with the highest organic matter content and high generative potential (marked in red in the diagrams) to create the artificial thermal maturity that will be discussed below (Table 3).

5.3.1 Migrated hydrocarbons

Non-indigenous hydrocarbons can be detected if S1 is high and TOC is low. Therefore, the TOC versus S1 diagram was used to separate migrated hydrocarbons from non-migrated ones in the bituminous rock samples from the studied area (Fig. 11a). Thus, some of the analyzed samples were plotted in the indigenous hydrocarbons field, reflecting no external contribution of migrated hydrocarbons to the bituminous rocks of the area.

a TOC versus S1 diagram used to separate migrated hydrocarbons from non-migrated ones (adapted from Hunt 1996) b HI against depth (Akinlua et al. 2005), determining the type of hydrocarbon produced from the studied samples (adapted from Peters and Cassa 1994) c Plot of hydrogen index (HI) versus Rock–Eval T_max for the studied samples indicating that the Pabdeh Formation has lower maturity (After Akinlua et al. 2005) d T_max against PI used to estimate the thermal maturity of the source rock (Peters et al. 2005)

5.3.2 Organic matter type

Determining the type of organic matter is an essential step in evaluating source rock because it controls the amount and type of hydrocarbons produced by thermal maturity (Hunt 1996; Peters 1986). The results of the HI/depth diagram (adapted from Peters 1986) show that the Pabdeh Formation in the Karanj oil field can produce oil and gas when matured (Fig. 11b).

5.3.3 Thermal maturity of OM

According to Fig. 11c, the examination of the HI versus Tmax chart (Akinlua et al. 2005) demonstrating the position of the samples on the curve shows a vitrinite reflectance (RO%) of about 0.62%, and Pabdeh Formation is at the beginning of the oil generation. Tmax values can be plotted against PI to estimate the thermal maturity of the source rock (Peters et al. 2005) (Figs. 11c, d).

5.4 XRD

Based on Table 4 and the XRD results of two of the four samples selected from the Pabdeh Formation, we found that the mineral percentage of quartz, illite/smectite, dolomite, and pyrite increases (which can increase the brittleness of the source rock) from the shallower sample to the deeper sample (Kalani et al. 2015a, b; Nelson 2009; Hill et al. 2002; Ni et al. 2009; Tan 2009; Ding et al. 2012; Zeng et al. 2013; Nelson 2009). Additionally, kaolinite and iron-bearing dolomite minerals decrease, and other minerals do not follow a specific trend. This heterogeneous distribution of minerals in different sizes and shapes during the layering of the source rock makes anisotropy cause microfracturing and hydrocarbon movement (Fawad et al. 2010).

6.1 Evolution of the fracture network with carbon content changes (the first experiment)

6.1.1 Carbon content

Microfractures are filled with hydrocarbon generated by kerogen (Littke et al. 1988). Microfractures seem to result from the growth and development of pores in the corners of organic matter (e.g., Petmecky et al. 1999; Muñoz et al. 2004). Increasing TOC increases the potential for hydrocarbon production in the source rock, so the organic matter is probably the main factor in microfracture development in shale (Zeng et al. 2013) because of the local pressure generated around the mature organic carbon in the source rock. Therefore, shale has less permeability; the expulsion of the produced hydrocarbons will be less; and local pressure is provided to create microfractures (Fig. 12a). Consequently, the organic matter reduces the strength of the rock and the formation of microfractures by producing hydrocarbons that create pore fluid pressure Furthermore, the configuration of kerogen can control the direction of microfracturing (Fig. 12b). If the kerogen is thin and flat, microfractures will grow in the lamina direction. However, if the kerogen is round, it causes the growth of microfractures perpendicular to the lamination (Figs. 1c, d) (Lash and Engelder 2005; Horseman et al. 1999; Özkaya 1988). In addition, the quality of organic matter per unit rock mass is determined by the HI and S2, which control the potential for oil production (e.g., Palciauskas 1991; Schwarzkopf 1992). The Rock–Eval pyrolysis data showed that the samples selected from Pabdeh Formation contain type II kerogen (oil-prone).

Slice of samples showing the density of microfractures (red discs) and fluid migration (dark cells), proving the direct relationship between the amount of hydrocarbons and the pore fluid pressure and their effect on the formation of microfracture

6.1.2 Pore fluid pressure

The transformation of solid kerogen to bitumen/oil with low density leads to a 30% increase in volume compared to the volume of kerogen; and by raising the thermal maturation of the organic matter, a network of hydrocarbon expansion is formed (Passey, personal communication; Thyberg et al. 2010; Vatandoust et al. 2020; Vidal and Dubacq 2009; Wang et al. 2009, Xu et al. 2015; Vernik 1994; Hunt 1996; Capuano et al. 1993; Jin et al. 2010). The hydrocarbon production rate is directly related to pore fluid pressure (Bredehoeft et al. 1994). Because shale has tiny pore throats, making it difficult to discharge hydrocarbons, the rate and amount of hydrocarbon generation from kerogen control the amount of pore fluid pressure; generally, a rock's fracture strength is greater than the displacement pressure. If the hydrocarbon production rate is slow and the force of hydrocarbon expulsion is less than the displacement pressure, then the hydrocarbons will be trapped in the pores, and the local pressure of the pores will not reach the rock's fracture strength.

Suppose the hydrocarbon production rate in the source rock is moderate. In that case, the driving force of hydrocarbons is greater than the displacement pressure, such that the hydrocarbons will flow until the degree of hydrocarbon production and seepage becomes balanced. Suppose the hydrocarbon production rate is high, and hydrocarbon production is more than the seepage amount. In that case, the hydrocarbons will accumulate in the source rock, the overpressure of the pores will increase until it reaches the rock's fracture strength, and the fractures can be formed more easily. In fact, increasing maturity and hydrocarbon production causes local pressure, which is an essential factor in the formation of microfractures (Guo et al. 2011). Pore fluid pressure from hydrocarbon production can change the stress state of the rock matrix. Microfractures in the rock develop when driving forces such as tensile strength and shearing strength reach the rock's fracture strength (Engelder and Lacazette 1990), so the distribution of microfractures corresponds to the position of pore fluid pressure in the laminae (Ma et al. 2017) (Fig. 12). Therefore, in this experiment, under the same temperature conditions, Sample 18 (3039.5) with the most organic matter (4.72 wt%) can create a damage zone around kerogens by producing hydrocarbons and increasing the pore fluid pressure from each kerogen, and eventually, the probability of overlapping of the damage zone and microfracture increases (Fig. 13).

Scanning electron micrograph after heating of the samples, showing the effect of different amounts of organic matter on microfracturing. In Samples 11, 14, and 16, with the low production of hydrocarbons and pore fluid pressure, individual microfractures are formed; but in Sample 18 with a TOC of 4.72, by increasing the pore fluid pressure and the production of hydrocarbons compared to previous samples, the microfracture density rises

6.2 Evolution of the fracture network with temperature variations (the second experiment)

6.2.1 Temperature

In natural catagenesis, with increasing temperature and pressure, hydrocarbon production decreases, leading to the subsequent cracking of hydrocarbons with high molecular weight. Furthermore, reactions that control catagenesis increase when the temperature rises. At temperatures above 200 °C, fractures are primarily caused by organic matter's maturation and inorganic matter's decomposition (Saif et al. 2016, 2017). At temperatures of 340–360 °C, smectite minerals are converted into illite, water, and quartz, which increase the brittleness of the rock and contribute to the creation of microfractures. Furthermore, if microfractures are observed in the sample below 200 °C, they are associated with the mineral decomposition of dawsonite and analcime, and other minerals may also contribute to fracturing in the 200–400 °C range (Smith and Milton 1966; Beard et al. 1974; McKay and Chong 1983; Le et al. 2013). Within the oil window range (R_o ≤ approx. 1.4%), by increasing the thermal maturity, the physical properties of kerogen change during thermal maturation. Kerogen density rises by at least 30% during thermal maturation. Moreover, the density is linearly and negatively related to the H/C ratio. It has a linear and positive relationship with the aromatic carbon content, and the content of aromatics and alkaline rises during maturation. Measurement of the pore surface area of kerogen revealed that its size increases during thermal maturation. The increased surface area of kerogen involves the development of pores in the structural network of aromatic carbons, which results in the cracking and expulsion of aliphatic carbons from aromatic clusters during maturation and petroleum production (Craddock et al. 2018). A condition for controlling microfractures is the final temperatures (340 °C, 380 °C, 420 °C, 460 °C) applied to the samples in the laboratory. Furthermore, observations and statistical analysis demonstrated that the final temperature is directly related to fracture intensity and density during the same condition. In this experiment, microfractures were formed by the production of hydrocarbons during the rise in temperature and thermal maturation of organic matter (Meng et al. 2010) (Fig. 14).

Scanning electron micrograph after heating of the samples, showing the effect of different maturation levels on microfracturing. As the thermal maturity increases, the density of microfractures and their inclination towards each other is increased and, finally, a network of microfractures is formed in the rock

6.2.2 Thermal maturation

Iatroscan data from the first to fourth samples showed that as the thermal maturity increases, the amount of asphaltene and resin decreases, and the amount of aromatics and saturation increases. This indicates that the samples in this experiment did not pass the oil production peak and the catagenesis was not complete, so the H/C ratio and hydrocarbon production increased during the experiment. When the first sample 18–1 was heated under 340 °C for 30 min, the structure of kerogen began to crack and raises the H/C ratio, which is directly related to the elevation in the volume of kerogen and accumulates stress at the tip and edges of kerogen. Eventually, by creating a damage zone around kerogen, the hydrocarbons produced at this level of maturity were expulsed through them (Fig. 14). As the production of hydrocarbons increased, Samples 18–2 and 18–3 at 380 and 420 °C provided the force required for the growth of individual microfractures, and the microfracture density in the samples increased compared to the first sample. Finally, in Samples 18–4, with raising the temperature, the hydrocarbon production increased, leading to the development and interconnection of individual microfractures and the creation of a network of microfractures in the source rock (Fig. 14).

6.2.3 Itroscan

The Itroscan data of the first to fourth samples in the second test revealed that with a rise in thermal maturity and temperature, the amount of asphaltene and resin decreases, and the amount of aromatics and saturation increases, thereby providing the pore fluid pressure necessary to cause microfractures in the samples (Fig. 15).

The amount and type of hydrocarbons produced in Sample 18 of Well 31 of the Karaj oil field

In this experiment, with increasing temperature and thermal maturity and increasing H/C ratio in kerogen, kerogen volume increased and kerogen density decreased (Craddock et al. 2018) (Fig. 16a). According to the formula ρ = m/V (ρ = density, m = mass, V = volume), there is an inverse relationship between density and volume, and this increase in kerogen volume up to 30% has been previously reported (Fig. 16b) (Cunfei et al. 2016; Craddock et al. 2018, Passey, personal communication). Hydrocarbon production due to temperature provided the necessary pressure to create a damage zone around the kerogen. Initial microfractures started at the tip/edge of kerogen (Fig. 16c) (Cunfei et al. 2016) and were filled by hydrocarbons (Fig. 16d) (first phase of microfracture formation). But according to the Iatroscan data, in four temperature stages (340, 380, 420, 480 °C), with the progress of catagenesis, the H/C ratio of kerogen decreases and it is released into hydrocarbons (saturated, aromatic, resin, asphaltene). Therefore, the conversion of solid kerogen to bitumen/oil with a higher volume compared to kerogen produces more pressure than the previous phase (Capuano 1993; Hunt 1996; Jin et al. 2010; Passi, personal communication; Pellet and Tissot 1971; Wernick 1994). On the other hand, the Pabdeh Formation has small porethroats and prevents the expulsed effectively. Therefore, the pore fluid pressure inside the initial microfractures increases (Figs. 16e, f, g, h). In addition, the stress increases with the accumulation of pore fluid pressure produced by hydrocarbon production until it reaches the rock's fracture strength, causing the expansion and growth of fractures that were created in the first phase (increasing the volume of kerogen) (Figs. 16e, f, g, h). During the expansion process, microfractures are preferably grown in low-strength pathways such as lithology changes, the boundary of laminae, and pre-existing microfractures (Fig. 16f). If the porous pressure created by each kerogen overlaps, the individual micro-fractures can interconnect and create a network of microfractures in the source rock (Figs. 16g, h).

The evolution of the expulsion fracture pattern (Cunfei et al. 2016)