**5.1 Organic matter evolution, thermal regime changes during hydrocarbon generation, preservation and expulsion**

**Figures 2** and **4** illustrate that the end of the Cretaceous era saw uplift, denudation, subsidence and basin cooling in the Lower Benue Trough as well as increased


**Table 1.**

*Acquired TOC content and pyrolysis data with calculated parameters of the studied samples of Nkporo Formation, Nzam-1 well [7].*


*Perspective Chapter: Understanding Thermal Maturity Evolution and Hydrocarbon Cracking… DOI: http://dx.doi.org/10.5772/intechopen.106674*

> **Table 2.**

*Acquired TOC content and pyrolysis data with calculated parameters of the studied samples of Agwu Formation, Nzam-1 well (modified after*

 *[12]).*


#### **Table 3.**

*Acquired TOC content and pyrolysis data with calculated parameters of the studied samples of Nkporo Shales in Akukwa-2 well (modified after [7]).*

geothermal gradient to have caused complex processes of uplift, denudation, and basin cooling and heating (**Figure 13**).

The geology of Lower Benue Trough is associated with the tectonic activities that were recorded during the Cenomanian which produced uplift with a NE-SW trend

*Perspective Chapter: Understanding Thermal Maturity Evolution and Hydrocarbon Cracking… DOI: http://dx.doi.org/10.5772/intechopen.106674*


#### **Table 4.**

*Input Parameters (age, Heat flow and Eustatic Sea level) of Lower Benue Trough used to constrain the model.*



#### **Table 5.**

*Inputed data (Lithology, Geologic age in Million Years (Ma), Petroleum system elements(PSE), TOC) for the burial history and maturity model construction of Coniacian and late Campanian source rocks, Lower Benue Trough, Nzam-1 (A) and Akukwa-2 (B) wells.*

#### **Figure 6.**

*Paleo-temperature modeling in Akukwa-2 well calibrated using borehole temperature; showing correlation among Burial history with temperature overlay, measured temperature and modeled Temperature for the studied well, notice that the maximum temperature values of 120–145°C in the area was attained between mid-Paleocene and mid Miocene (60-15ma) on Coniacian Agwu Source strata, higher temperatures are associated with Santonian tectonic episode.*

#### **Figure 7.**

*Burial and thermal maturity histories of the Coniacian and upper Campanian source rocks for the studied well (Nzam-1 well) showing the positions of the oil window and the various hydrocarbon generation phases. Notice that Agwu Source rocks have entered the post maturity gas evolution and still generating gas to present day while the late Campanian Nkporo Source has entered the oil window and has marginal maturity. To the right the depth versus mean vitrinite reflectance plot indicating reasonable correlation between the measured and the modeled vitrinite reflectance.*

*Perspective Chapter: Understanding Thermal Maturity Evolution and Hydrocarbon Cracking… DOI: http://dx.doi.org/10.5772/intechopen.106674*

#### **Figure 8.**

*Showing a reasonable correlation between the modeled and the calculated vitrinite reflectance and the R2 of 0.2238 shows the correctness of the model.*

#### **Figure 9.**

*Evolution of the transformation ratio and rate of hydrocarbon generation with age from the Coniacian and late Campanian source strata in the studied well (Nzam-1 well). Notice the Coniacian Agwu Shale has a higher transformation ratio which lies between 5.55 and 75.10% and greater than that Nkporo Source strata with transformation ratio between 4.44 and 34.67%.*

#### **Figure 10.**

*Burial and thermal maturity histories of the Coniacian and late Campanian source rocks for the studied well (Akukwa-2 well) showing the positions of the oil window and the various hydrocarbon generation phases. Notice that Agwu Source rocks have entered the postmaturity gas evolution and still generating gas to present day while the late Campanian Nkporo Source has entered the oil window and is at the early generation stages. To the right the depth versus mean vitrinite reflectance plot indicating reasonable correlation between the measured and the modeled vitrinite reflectance.*

#### **Figure 11.**

*Evolution of the transformation ratio and rate of hydrocarbon generation with age from the Coniacian-late Campania source rocks in the studied well (Akukwa-2).*

*Perspective Chapter: Understanding Thermal Maturity Evolution and Hydrocarbon Cracking… DOI: http://dx.doi.org/10.5772/intechopen.106674*

#### **Figure 12.**

*Modeled Petroleum system elements of the studied (A) Nzam-1 and (B) Akukwa-2 Wells respectively; Both showing the positions of the two source strata under study (Coniacian Awgu and late Campanian Nkporo Source rocks, the positions of the Reservoir Rocks (Coniacian Agbani Sandstone and the Campanian Owelli Sandstone) and the positions of the Paleogene seals (majorly Imo Shale) all of which have demonstrated favorable conditions for Petroleum accumulations.*

and it gave way to the tectonic activities that took place in Santonian times, which resulted in the folding and uplifting of the Abakaliki Sector of the Trough and the subsidence of Anambra Platform. The latter event led to the formation of the

Anambra Basin and this constituted a major depocentre of clastic sediments and deltaic sequences [17, 18]

Based on the burial/thermal history model; the burial temperature within Agwu Formation in Nzam-1 well ranges from 30 to 145°C and that of Nkporo Formation ranges 28 to 125°C (**Figure 5**); From the burial/Thermal history of Akukwa-2 well the burial temperature in Agwu and Nkporo Formation ranges from 29.5 to 145°C and 28.5 to 95°C (**Figure 6**) respectively.

From the burial history model in Nzam-1 well (**Figure 5**), it was observed that before the Santonian tectonic episode (Pre-rift periods), the Kerogen in the Coniacian Awgu Shale experienced lower temperatures between the ranges of 30 and 55°C, it further experienced increased temperatures ranges between 120°C and 145°C between the Santonian and Miocene (83-15Ma) and (post-rift Periods) while in the burial model of the Lower Benue Sector in Akukwa-2 (**Figure 6**), the Kerogen in the Coniacian source strata has experienced lowest temperatures ranges of between 29.5 and 50°C before the Santonian times (Pre-rift) and exponential increased temperature ranges of 120 and 145°C between Santonian (83ma) up to present day. Consequently, the relatively high temperature and geothermal gradients experienced by the Coniacian Awgu strata between the Santonian and Miocene times aided the quickening of the organic matter maturation, oil generation and subsequent cracking of the oil to form gas. Since the temperature continued to decrease exponentially to the present day and such decrease in temperature have favored the preservation of the gas reservoirs and therefore the survival of hydrocarbons in the deeper strata can be guaranteed. More so the geothermics, the configuration of the hydrocarbon generation timing and reservoir cap development has favored accumulation (**Figure 12**) and the low geothermal field background after the formation of cracked gas has increased its chances of survival in their respective reservoirs within the Lower Benue Trough due to basin cooling and the resulting present day low heat flow (48m/Wm2). The moderate temperature values of up to 125°C of Nkporo Formation for the studied Nzam-1 has aided its maturity and this happened due to basin heating and considerable burial depth which has placed the organic matter of Nkporo on an advantage position to mature relative to the organic matter of the same Formation in Akukwa-2 well with the highest temperature value of less than 95°C has entered the threshold of oil generation in Late Maastrichtian (65Ma) and continues to remained within the onset of generation owing to lack of sufficient heat and shallow burial depth that is needed for it to exit this present hydrocarbon generation phase.

It may therefore be said that Temperature evolution affected the development of organic matter pores in strata and their gas adsorption capacity. In sum, a higher temperature and a greater extent of thermal evolution should have resulted in highly developed organic matter pores [19], whereas a lower temperature should have enhanced the gas adsorption capacity. As shown in **Figures 5** and **6**, the high temperature of the Coniacian Agwu source rocks, which may be attributed to the high temperature gradient and deeper burying level of these rocks and more so predates Santonian tectonic episode, was highly favorable for the maturity of organic matter and the development of their pores, whereas the increased heat process after the main hydrocarbon aided the oil cracking gas generation periods but however the reduction in heat benefited the preservation of source rock gas should the cooling continues.

The one-dimensional burial and maturity model of Nzam-1 and Akukwa-2 wells was modeled after [14, 15] kinetic models to ascertain the hydrocarbon generation potential of upper Cretaceous organic rich shaly intervals.

*Perspective Chapter: Understanding Thermal Maturity Evolution and Hydrocarbon Cracking… DOI: http://dx.doi.org/10.5772/intechopen.106674*

Once source rocks have reached their expulsion threshold, they may expel the hydrocarbons upward into the reservoirs [19]. The timing of hydrocarbon generated and expelled from the Coniacian Awgu and upper Campanian Nkporo source rocks were modeled. Oil generation is defined in this study by transformation ratios between 10% and 50% [19]. Immature source rocks have transformation ratios less than10% (no generation). Peak oil generation occur at a transformation ratio of 50% when the main phase of oil generation is reached. And transformation ratio greater 60% when gas phase of the hydrocarbon generation is reached. The calculation of the transformation ratios is based on the Vandenbroucke et al., (1999)-TIII- (North Sea) kinetic model for the Coniacian Agwu and late Campanian Nkporo source rocks (**Figures 9** and **11**).

From the burial history model of Nzam-1 well with transformation overlay (**Figure 9**), it is clear that the Awgu has a higher transformation ratio as compared to Nkporo and this is consequent to their thermal maturity which is confirmed in the Transformation-Time plot with Awgu shale having higher curve. The transformation ratio of Awgu and Nkporo Shales in Nzam-1 well is 5.55–75.10% and 4.44–34.67% respectively (**Figure 9**) while the transformation ratios for Agwu Formation in Akukwa-2 well are 2.32–69.83% for upper strata and 2.00–79.05% for the lower strata while the Nkporo Formation had no transformation ratio (**Figure 11**). The transformation- Time plot shows that the thermal maturity and the transformation of organic matter increase with time and depth. Therefore, a reasonable correlation can be drawn between the burial plot and Transformation Time plot (**Figures 9** and **11**).

The hydrocarbon generation and expulsion modeling of Nzam-1 well model shows that the Agwu Shale reached early phase of oil generation in late Campanian and extended from 75 Ma to 69 Ma. Subsequently, main phase of oil generation began during early Paleocene and extended from 65 Ma to 62 Ma. The gas phase began at mid Eocene and extended from 48Ma to present day. The model has also shown that the expulsion of hydrocarbon from Agwu Source rocks occurred between 62 Ma up to present day and peak expulsion at 34 Ma during late Eocene (**Figures 7** and **9**).

As for the late Campanian Nkporo Source rock, the Model of Nzam-1 has shown that the Nkporo Shale reached early phase of oil generation in early Paleocene and extended from 65 Ma to 60 Ma. Subsequently, main phase of oil generation began during late Paleocene and extended from 56 Ma to 42 Ma. The model has also shown that the expulsion of oil from Nkporo Source rocks occurred between 42 Ma to present day and peak expulsion at 30 Ma during early Oligocene (**Figures 7** and **9**).

The hydrocarbon generation and expulsion modeling of Akukwa-2 well shows that the Agwu Shale reached early phase of oil generation in early Santonian and extended from 85 Ma to 78 Ma. Subsequently, main phase of oil generation began during late Campanian and extended from 75 Ma to 70 Ma. The gas phase began at mid Paleocene and extended from 58Ma up to present day. The model has also shown that the expulsion of hydrocarbon from Agwu Source rocks occurred between 70Ma and up to present day and peak expulsion at 57 Ma during late Paleocene (**Figures 10** and **11**).

The hydrocarbon generation and expulsion model of Akukwa-2 well has also shown that the late Campanian Nkporo Source rocks has just entered the early phase of oil generation late Maastrichtian (67Ma) to present day; However, the late Campanian Nkporo Formation did not reach the main phase of oil generation and expulsion owing to the fact that it lacks the requisite burial depth, temperature and pressure in favor of oil generation and expulsion prevent further generation and expulsion in the upper Campanian source strata in this Formation (**Figures 10** and **11**). From the above, it can be said that the organic matter in Coniacian Awgu source rocks has

reached the post maturity evolution phase and the expected hydrocarbon product is gas. While the late Campanian Nkporo source rocks on the other hand is at early maturity to peak maturity evolution Phase and the expected hydrocarbon product is oil.

Petroleum accumulation depends on the configuration of hydrocarbon generation as well as migration, Formation, and evolution of the reservoir and its sealing conditions [19]. Considering the Petroleum System Elements (PSE) models, the Coniacian Awgu source rocks reached their oil and gas generation peaks in the Late Paleocene to early Eocene (58-52ma) and continued to generate gas to present day in the Nzam-1 model (**Figures 7, 9**, and **12**) whereas reached its peak generation in late Campanian to msid Paleocene (80-58ma) and continued to generate gas to present day in Akukwa-2 well (**Figures 10**–**12**) and the generation took place later than the formation of the regional reservoir rocks (Coniacian Agbani and late Campanian Owelli Sandstone Members) and the Paleogene seal rocks majorly Imo Shales (**Figure 10**). While the late Campanian Nkporo source rocks reached their oil generation peaks in the early Eocene to mid Oligocene (55-32ma) and continued to present day in Nzam-1 well (**Figures 7, 9** and **12**) and only entered the hydrocarbon generation threshold up to present day in Akukwa-2 well (**Figures 10**–**12**). The Petroleum System Elements (PSE) model revealed a viable petroleum system comprising of two source rocks dated Coniacian (89Ma) and Campanian (78Ma); two reservoir rocks dated also Coniacian (88Ma) and Campanian (78Ma) and the cap rock is dated Paleocene (65Ma) which indicates that hydrocarbon generation and expulsion occurred later than the formation of the regional reservoir rocks basically Coniacian Agbani and late Campanian Owelli Sandstone members and the seal rocks majorly the Juxtaposed Paleocene Imo Shales. The hydrocarbon generation period provided favorable conditions for the accumulation of oil and gas from these Coniacian and late Campanian source rocks in the Lower Benue Trough. Given the multiple phases of hydrocarbon generation, the Coniacian Agwu source rocks had more favorable conditions for hydrocarbon accumulation than those of the late Campanian Nkporo Source rocks (**Figure 12**). The Paleogene Shale Units within the Lower Benue Trough are the most important oil and gas seal. Therefore, it is possible hydrocarbons were generated and expelled from Agwu Shale and evidence can be seen in heavy crude seepage from the Owelli Sandstone at Egwueme, Lower Benue Trough. And valid petroleum system elements exist in the basin with relative differences in the generation and expulsion periods of hydrocarbon generation.

A plot of measured vitrinite reflectance against the modeled vitrinite reflectance was computed and the RSME is found to be 0.2238 which indicates good correlation and hence the correctness of the model (**Table 6** and **Figure 8**).

From the Plot of Hydrogen Index (HI) against Maximum Temperature (Tmax), calculated Vitrinite Reflectance after [11] and calculated Vitrinite Reflectance after [16] showing Kerogen quality and thermal maturity stages for the studied sediments Nkporo Marine Shale and Agwu Marine Shales in the Lower Benue Trough sedimentary section of the Nzam-1 well indicated that Kerogen from Nkporo is immature to early maturity and is also Predominantly type II-III kerogen which is mixed oil/gas prone with minor occurrences of type II and type III While kerogen from Agwu shale has attained peak maturity to post maturity and the organic matter is predominantly consist of type II-III kerogen perhaps with minor occurrences of type II Kerogen (**Figure 14**).

Cross plot of Production Index against Tmax revealed that samples from Agwu Formation fall within the oil and gas window and the organic matter has experienced high level conversion which is also an indication of Peak maturity to post maturity (**Figure 15**).


*Perspective Chapter: Understanding Thermal Maturity Evolution and Hydrocarbon Cracking… DOI: http://dx.doi.org/10.5772/intechopen.106674*

#### **Table 6.**

*Showing the calculated and the modeled vitrinite reflectance values with the resultant Root mean square error of 0.178092*

And from the cross plot of Production Index against Tmax and calculated Vitrinite Reflectance after [11] and [16] suggested that the Kerogen from Agwu Formation has undergone an intensive generation expulsion and the samples fall within the oil window and gas window, it also indicated that the organic matter has undergone high level conversion and has entered the over mature zone (**Figure 15** and **16**). This implies that the expected hydrocarbon type is oil, Condensate-wet gas and dry gas. It can therefore be inferred that the samples from Agwu Formation of the Nzam-1 Well have attained peak to post thermal maturity.

The measured Vitrinite reflectance (Ro) in both Nzam-1 and Akukwa-2 wells (**Figures 7, 8** and **10**) has a reasonable correlation with the modeled vitrinite reflectance after [14]. The heat flow histories used in the calculations are also plotted in

#### **Figure 14.**

*Plot of Hydrogen Index (HI) against Maximum Temperature (Tmax), calculated Vitrinite Reflectance after [11] and calculated Vitrinite Reflectance after [16] showing Kerogen quality and thermal maturity stages for the studied sediments Nkporo Marine Shale and Agwu Marine Shales in the Lower Benue Trough sedimentary section of the Nzam-1 well indicating that Kerogen from Nkporo is immature to early maturity and is also Predominantly type II-III kerogen which is mixed oil/gas prone with minor occurrences of type II and type III While kerogen from Agwu shale has attained peak maturity to post maturity and the organic matter is predominantly consist of type II-III kerogen perhaps with minor occurrences of type II Kerogen.*

#### **Figure 15.**

*Plot of Production Index against Tmax showing Kerogen Conversion/Maturity of late Campanian Nkporo Shales at immature-early mature stages and Coniacian Awgu Shales at peak maturity to post maturity stages in the sedimentary section of the Lower Benue Trough, Nzam-1 well indicating that the Nkporo Shale is at early maturity stages while Awgu is at peak/post maturity stages and has expelled hydrocarbon.*

(**Figures 2** and **4**). In Nzam-1 well, heat flow values range between 48 and 72 mW/m<sup>2</sup> while in Akukwa-2 well it ranges 48 and 75 mW/m2 and this can be attributed to the variability of heat flow and geothermal gradient in the earth subsurface.
