**1. Introduction**

Petroleum (oil and gas) accounts for up to 95% of the Nigeria's foreign earnings and has remained the major supporter of its economy since it was first discovered in commercial quantity in 1956. Globally, petroleum as an energy source will continue to dominate other primary energy sources and is expected to account for up to 56% of the world energy demand in the year 2030 [1]. This makes source rock studies and evaluation now to be of key interest to oil industry players, the Academia and other research interest groups and as a result research has also been intensified in the Lower Benue Trough as well.

The thermal states of sedimentary basins affect hydrocarbon generation, migration, and accumulation processes, and therefore reconstructing a basin's thermal history is significant for petroleum accumulation analyses. The maturity of organic matter is primarily controlled by the temperature of the source rock [2].

We are interested in thermal evolution and hydrocarbon cracking because of its importance in modeling the oil degradation processes that compete with oil expulsion during maturation of petroleum source rock over geologic time periods.

As a source rock begins to mature, it generates hydrocarbons. As an oil-prone source rock matures, the generation of heavy oil is succeeded by medium and light oils and condensates. Above a temperature of approximately 100°C, only dry gas is generated and incipient metamorphism is imminent. The maturity of a source rock reflects the ambient temperature as the conditions favorable for hydrocarbon generation. Understanding the maturation and thermal cracking of hydrocarbon helps to define the quality of the expected products.

Following the increased interest in the exploration of petroleum resources, Assessment of generative potential and characteristics of source rocks is fundamental in hydrocarbon exploration and its success depends largely on the employed organic geochemical method and this calls for a more refined and integrated approach by both the industry and the academia so as to discover more hydrocarbon prospects and despite the fact that published data gives a vast amount of information on the geology, sedimentology, lithostratigraphy and the hydrocarbon generation potentials of the Lower Benue Trough yet of the several Geochemical approaches for source rock evaluation employed in the studied area by some of the existing works which include using vitrinite as a maturity tool; there are only but a few among these previous researches that integrated the other source rock evaluation techniques with burial history and Maturity Modelling which could have given a clearer and better understanding of the thermal evolution, hydrocarbon generation and timing of the organic matter (kerogen) in this section (Nkporo and Agwu Formations) of the Lower Benue Trough.

Ehinola [3] investigated and presented results on subsurface geological models of the Anambra basin using the Petromod Software. The models produced were based on a clear understanding of how sedimentary rocks are formed, modified and perform as source rocks, reservoirs and traps employing lithostratigraphic principles, rock mineralogy and depositional modeling. The study revealed that thermal maturity of the source rock units in Anambra basin increases toward the Abakaliki Anticlinorium and with depth towards the western part of the basin. Imo shale, Mamu Formation, Nkporo Shale, Awgu Shale, Eze-Aku shale and Asu River group reached hydrocarbon generation at 51.23, 61.42, 56.30, 66.11,84 and 92Ma respectively which show that the Asu River Group and Ezeku-Aku Formation shale commenced Hydrocarbon generation prior to the Santonian tectonism. This maybe reflected by the presence of

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

seepages, oil and gas in the Owelli, Agwu and Eze-Aku Formation interval respectively in the Anambra Basin while the matured Post Santonian succession would generate and charge both the upper Cretaceous reservoir and possibly the sub-Niger Delta successions in the subsurface. The study also revealed that the Maastrichtian-Paleocene sediment in the South-western part of the basin maybe considered as the major strata with liquid hydrocarbon potential whereas the Pre-Santonian sediment exhibit potential for gaseous hydrocarbon.

Oluwajana [4] carried out a hydrocarbon-charge modeling and its consequence on shale gas and shale oil resource systems within the Cretaceous strata of the Anambra Basin using organic geochemical data, 2D seismic line and stratigraphic well data of exploratory wells drilled in the basin to generate conceptual models, improve understanding on hydrocarbon generation and timing, and identify potential shale plays in the basin and the study helped to identify potential shale resource system in the Anambra basin namely the upper Cenomanian–lower Turonian marine facies. Two main shale play types involving the upper Cenomanian–lower Turonian were identified.

Akaegbobi et al. [5] revealed that the organic matter in majority of Nkporo samples and few of Owelli samples can be classified as predominantly Type II-III kerogen, while the organic matter in the rest of Owelli and Mamu formation samples is majorly Type III and Type IV kerogens and further revealed that the analyzed samples were deposited in normal marine environment with samples from Mamu Formation tending towards freshwater depositional millieux".

Akaegbobi et al. [5] investigated the shales, siltstones and shale heteroliths, collected from the Nkporo, Owelli and Mamu formations of Anambra Basin were subjected to bulk and molecular geochemical analyses (total organic carbon content determination, pyrolysis analysis, bitumen extraction and gas chromatography) to provide further insight on the quantity, quality and thermal maturity of organic matter within the sediments, the source input and paleodepositional conditions of the organic matter, hydrocarbon generation potential and the study revealed that the organic matter has fair to good hydrocarbon generation potential and the majority of the analyzed sediments from Nkporo Formation are oil and gas prone, while the others are mainly gas prone. The Molecular geochemical data further suggested that the organic matter within the sediments was derived from mixed aquatic algae and land plant source input and was deposited under suboxic paleodepositional conditions.

Adeleye et al. [6] attempted to evaluate aspects of the source rock potential for hydrocarbon generation of the Imo Shale Formation penetrated by the Akukwa II and Nzam-Iwells in Anambra basin, and concluded that the sediments have potential for hydrocarbon generation with possibility of gas. Organic matter contained in the sediments is predominantly type IV kerogen sourced from terrestrial materials which does not yield significant amounts of hydrocarbon. Thermal maturity derived from Rock-eval data revealed that the Imo Formation samples are immature with respect to hydrocarbon generation.

Adeleye et al. [7] employed Total Organic Carbon (TOC) content and Rock-eval Pyrolysis to evaluate source rock potential for hydrocarbon generation of Nkporo Formation in the Lower Benue trough penetrated by Nzam-1 well and it was revealed that the sediments contain poor to fair source rock for hydrocarbon with kerogen type III as the predominating organic matter, which is capable of generating dry gas. Tmax and other pyrolysis data suggest that the organic matter in the Nkporo Formation is at the peak of thermal maturity to post maturity with respect to hydrocarbon generation. And the study revealed that the heat energy generated from post mature part of the studied section together with the thermal maturity peak to late maturity generally observed for the sediments may have resulted in the dry gas prospect.

Adebayo et al. [8] carried out a Palynological, organic petrographic, and organic geochemical analyses of the Campanian-Maastrichtian sediments in Akukwa-2 well to infer their paleoenvironments, origin of the organic matter, and hydrocarbon generation potentials and the study revealed that the organic matter within the sediments is also likely to generate mainly gas. This is in agreement with the petrographic observations, which revealed that the analyzed shale samples contain abundant vitrinite macerals, apart from bituminite, alginite, cutinite, and resinite. Also, the sediments are immature to early mature in terms of hydrocarbon generation as indicated by vitrinite reflectance, biomarker maturity, and pyrolysis Tmax data. Biomarker distribution ratios, palynomorphs assemblage, and organic petrographic observations further point out that the organic materials within the sediments were of mixed aquatic and terrigenous origin and were deposited under suboxic paleodepositional conditions. Based on sedimentological, palynological, and biomarker characteristics, the environment of deposition of the analyzed sediments was inferred to be a relatively quiet, shallow marine with fluvial incursion, most especially at the upper part of the intervals studied and consequently, it is a delta associated depositional environment with a fluviatile influence. The sediments were therefore suggested to be deposited in a paleogeographic setting close to vegetation source.

Following the increased interest in the exploration of petroleum resources, Assessment of generative potential and characteristics of source rocks is fundamental in hydrocarbon exploration and its success depends largely on the employed organic geochemical method and this calls for a more refined and integrated approach by both the industry and the academia so as to discover more hydrocarbon prospects and despite the fact that published data gives a vast amount of information on the geology, sedimentology, lithostratigraphy and the hydrocarbon generation potentials of the Lower Benue Trough yet of the several Geochemical approaches for source rock evaluation employed in the studied area by some of the existing works which include using vitrinite as a maturity tool; there are only but a few among these previous researches that integrated the other source rock evaluation techniques with burial history and Maturity Modelling which could have given a clearer and better understanding of the thermal evolution, hydrocarbon generation and timing of the organic matter (kerogen) in this section (Nkporo and Agwu Formations) of the Lower Benue Trough.

Therefore, this current study attempts to evaluate the characteristics of the source rocks and their viability, hydrocarbon generation potential and timing, and predict the various thermal maturity levels of the possible shale plays in the Coniacian Agwu Formation and late Campanian Nkporo Formation sediments within this section of the Lower Benue Trough as penetrated by the Nzam-1 well and Akukwa-2 wells respectively. A quantitative one dimensional basin modeling was carried out for evaluating the thermal histories and timing of hydrocarbon generation and expulsion of the Coniacian and late Campanian source rocks in the part of Lower Benue Trough. More so, the reconstruction of the burial, thermal and maturity histories were modeled in order to evaluate the remaining hydrocarbon potential using Schlumberger's PetroMod (1D) modeling software so as to provide the basis for Petroleum resource evaluation of the Upper Cretaceous sediments of the basin. Also, in this study, a detail evaluation of the acquired TOC and Rock-Eval pyrolysis data was carried out which provided information on the quantity, quality and maturity of the organic matter which served as the verification for the results and interpretations from the model.

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

#### **Figure 1.**

*A Geological map of Nigeria showing the location of the studied exploratory well, Nzam-1 [8].*

The study area is carved out of the Lower Benue Trough (**Figure 1**), in South Eastern Nigeria as penetrated by the Exploratory wells, Nzam-1 and Akukwa-2. The area comprises the geographical location of the following states: Abakaliki, Anambra, Ebonyi, Enugu, and Imo and lies within Latitude N 6°27<sup>0</sup> 17.07″ and Longitudes E6° 43<sup>0</sup> 10.75″ on the Geological map of Nigeria employing the ArcGIS Software (**Figure 1**).
