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Crude oil exploration is a source of significant revenue in Africa via trade and investment since its discovery in the mid-19th Century. Crude oil has bolstered the continent’s economy and improved the wellbeing of the citizenry. Historically, Africa has suffered from conflicts due to uneven redistribution of crude oil revenue and severe environmental pollution. Advancements in geophysical survey techniques, such as magnetic and gravity methods, to seismic methods, have made the commercial exploration of crude oil possible for some other countries in Africa apart from Nigeria, Angola, Algeria, Libya, and Egypt. The occurrence of organic-rich, oil-prone Type I, II, and mixed II/III kerogens in sedimentary basins and entrapment within reservoir rocks with intrinsic petrophysical properties are majorly responsible for the large deposits of hydrocarbon in Africa. The unethical practices by some multinational oil corporations have resulted in social movements against them by host communities and human rights groups. The unscrupulous diversion of public funds, award of oil blocks, and production rights to certain individuals have impaired economic growth in Africa. The over-dependence on crude oil revenues has caused the economic recession in oil-producing countries due to plummeting oil prices and global pandemic. Most host communities of crude oil deposits suffer from a lack of infrastructure, arable soils, clean water, and their functioning capabilities are violated by crude oil exploratory activities, without adequate compensations and remedial actions taken by oil companies and the government. Thus, this review examines crude oil exploration in Africa and provides insight into the environmental and socio-economic implications of crude oil exploration in Africa. Furthermore, this report highlights some recommendations that may ensure ethical and sustainable practices toward minimizing negative impacts and improving the quality of life in affected communities.
Keywords:
Crude oil, Exploration technique, Environmental pollution, Socio-economic impact, Africa
The discovery and exploration of natural resources in any country have several socio-economic and environmental implications on the citizenry (Olujimi et al. 2011; Sojinu and Ejeromedoghene 2019; Faria 2020). The African continent accounts for five among the top thirty oil-producing nations in the world (Steyn 2009; Anyanwu et al. 2010; Akpata et al. 2013). The five countries are Nigeria, Angola, Algeria, Libya, and Egypt. In 2019, the aforementioned countries accounted for about 8 million barrels per day, which was almost 10% of global output (Graham and Ovadia 2019). The continent is endowed with vast deposits of crude oil reserves. In its original state, crude oil has little or no practical application and/or economic value (Dincer and Rosen 2013). Therefore, the need arises for the conversion of the unprocessed crude into more valuable products.
Africa currently produces about 7% of the world’s gas from a range of basins, including intracratonic sags, epicratonic embayments, and basins that form part of the rift-drift sequence caused by the post-Triassic break up of Pangaea (Selley and van der Spuy 2016). Over 2400 hydrocarbon deposits have been discovered in Africa, 700 of them were large enough for significant exploration (Hemstel 2003; EIA 2017). Petroleum occurs throughout the stratigraphic column from late to recent Archaean (Selley and van der Spuy 2016). Oil production is concentrated in North and West Africa, which holds seven of OPEC’s 14 members, producing about 7 mm bpd; however, minimal production has been recorded outside the North and West Africa (Nyemah 2011). There are two main geographical concentrations of hydrocarbon fields in Africa, namely; (1) West African coastal seaboard between the Niger Delta and the Congo and Cuanza basins and (2) North African basins (from Algeria, across Tunisia, Libya, and Egypt); other producing basins include, the Senegal basin, the Muglad basin in Sudan, and Quteniqua basin, offshore South Africa (Hemstel 2003; Ekweozor 2004).
Natural resources serve as a strong economic base for sustainable development in many African countries (Hachay 2017). The exploration of crude oil in several African countries has brought foreign earnings into those countries, which in turn should improve the living conditions of the population if properly harnessed and managed. Notwithstanding the cost of natural resources management in Africa is high due to lack of infrastructures, poor education, and over-dependence on foreign experts, managerial incompetence, and corruption which has disproportionately affected and hampered the economic growth and development of most African countries (Kalu and Ott 2019).
Severe environmental hazards have been attributed to crude oil exploration and processing in Africa, mostly arising from the discharge of wastes, including drilling fluids, atmospheric emissions, oily drill cuttings, oil spills, gas flares, well treatment fluids, and deck drainage, etc. (Beyer et al. 2020; Vargas et al. 2020). Noise, atmospheric, and marine pollution arises from onshore and offshore operations of oil rigs, distillation plants, tank farms, and vehicular emissions; which negatively impact water and air quality (Pathak and Mandalia 2012; Jiang et al. 2020). Besides, trace elements are introduced into surface waters from deep aquifers, as a result of the exploration processes, and many of these chemicals, such as cadmium, arsenic, mercury, copper, zinc, and lead, etc., are toxic to aquatic animals as well as humans (Ore and Adeola 2021).
There is the rarity of comprehensive literature overview of the significance and impact of crude oil exploration in Africa, which is essential for scientific awareness and policymaking toward mitigation of existing challenges peculiar to the African continent. This comprehensive review, therefore, provides useful insights into the occurrence, relative abundance, and exploration technologies of crude oil in Africa, as well as the socio-economic and environmental impacts of crude oil exploration and processing in Africa. This report also highlights existing and emerging remediation approaches suitable for oil/hydrocarbon-based pollution. The scope of the literature considered in this study was published articles, thesis, and books from reputable scientific journals and university repositories. Table presents the ranking of oil-producing countries in Africa according to World Bank, while Table presents the summary of remediation approaches with recent references. A systematic approach was adopted in the arrangement of relevant sections of this review to ensure clarity and provide suitable reference points for researchers.
The presence of viable source rock is an important factor governing the natural formation or occurrence of hydrocarbons (Dahl et al. 1994). In the past few decades, interest in the information on earth’s lithospheric (crust and upper mantle) structures has steadily grown to develop knowledge on the deeply submerged sediments, which are the main sources for replenishing crude oil of the twenty-first century and prospects for its abundance in oil-rich areas and new areas (Hachay 2017). The oil and gas sectors play a significant role in the economy of the continent. Most developing countries rich in petroleum resources depend on its sales for revenue and economic development (Graham and Ovadia 2019). The African continent is endowed with Earth’s minerals, however, comprehensive knowledge of relative abundance via a country-based assessment remains a challenge. The discoveries of new hydrocarbon fields in the continent, continue to provide economic leverage via trade and investment (African Development Bank (AfDB) 2009) and retains Africa on the list of a major exporting region in the world (Graham and Ovadia 2019). For many decades, hydrocarbon is a source of energy and they account for 83% of the current global consumption (Duissenov 2013).
The first commercial quantities of oil in Africa were found in Oloibiri in Ogbia LGA of Bayelsa State, Niger Delta basin of Nigeria, West Africa in the year 1956, by the Shell D’Arcy (now Shell Petroleum Development Company). In less than 20 years, the region became known for holding some of the world’s largest reserves of oil and gas (Steyn 2009; Anyanwu et al. 2010; Akpata et al. 2013). Crude oil exploration began in East Africa in early 1920, beginning with Anglo-American’s Dudley Expedition to Abyssinia, and with the major efforts in Uganda and the Eritrean Red Sea where there was extensive shallow drilling around oil seeps. Eastern Africa is the emerging hydrocarbon province of the 21st Century. However, successful exploration was recorded only after several decades of unsuccessful hydrocarbons search. Subsurface Palaeozoic hydrocarbon exploration of the Sahara Desert province of Libya, Algeria, Tunisia, and Morocco in North Africa began in the early 1950s. The exploration was undertaken after the discovery in the 1930s and 1940s, due to the large Palaeozoic basin in the Sahara Desert of North Africa with a potential prospect for hydrocarbons. The first petroleum wildcat exploration drilling took place in Algeria in 1952 and the first discovery was made not until 1953 in non-commercial quantity, but in 1956 major discoveries were achieved (Traut et al. 1998).
Recent oil reserves have increased the importance of this resource in African economies. Five African countries dominate the upstream oil production accounting for 85% of the continent’s oil reserve. These countries are Nigeria, Libya, Algeria, Egypt, and Angola. Other oil-producing countries are Gabon, Congo, Cameroon, Tunisia, Equatorial Guinea, Democratic Republic of Congo, Cote d’Ivoire, and recently, Ghana (low output), while Mozambique and Tanzania have reportedly discovered crude oil (Figs. , ). Nonetheless, exploration has been undertaken in some other African countries, such as Chad, Sudan, Namibia, South Africa, and Madagascar, but these countries have yet to record success stories (ECOWAS-SWAC/OECD 2007; AfDB 2008, 2009; Anyanwu et al. 2010; Akpata et al. 2013; EIA 2017). Based on the data available in 2019, Nigeria was the leading oil producer in Africa producing about 101.4 million metric tons in the country. Angola and Algeria followed with 69.1 million and 64.3 million metric tons of oil, respectively (Faria 2020). The occurrence of giant hydrocarbon fields in sedimentary basins of Africa implies propitious convergence of geochemical factors that favored the development of excellent petroleum systems.
Open in a separate windowOpen in a separate windowCrude oil deposit is found within stratigraphic columns extending from geographically ubiquitous seepages in recent sediments to oil in fluid inclusions in the late Archaean sediments present in the Witwatersrand basin (England et al. 2002).
The Niger Delta is located at the southern end of a major series of rifts extending from what is now the Atlantic Ocean to the modern Mediterranean (Selley and van der Spuy 2016) and ranks among the world’s most prolific petroleum-producing Paleogene-Neogene deltas that together account for about 5% of the world’s oil and gas (Ajaegwu et al. 2014). The Niger Delta consists of three diachronous facies: the on-delta fluvial Benin Formation, delta front sands and muds of the Agbada formation, and the over-pressured slope muds of the Akata formation. This sediment pile prograded over the deep-water submarine channel and fan sands (Selley and van der Spuy 2016; Ogbe 2020).
The source rocks responsible for the formation of hydrocarbon for the Niger Delta basin have been the subject of controversy. This controversy has arisen because of the difficulty in locating source intervals sufficiently convincing to have given rise to the large volumes of oil trapped, so far, only traces of potential source rocks have been recorded (Bustin 1988). Depending on where you are in the delta, source rocks range in age from middle Eocene to Pliocene and they contain predominantly terrigenous organic matter (Haack et al. 2000). These source rocks generate light waxy oils or gas. Therefore gas-prone end-member of the organic facies’ spectrum was deposited in an anoxic depositional environment in which organic matter was poorly preserved (Haack et al. 2000). Oil-prone organic facies, however, were deposited in sub-toxic depositional environments in which enhanced preservation of terrigenous organic matter was possible (Haack et al. 2000). The differences in source facies undoubtedly result from variation in the composition of organic matter components, which contribute to the kerogen of the richer source facies (Bustin 1988; Haack et al. 2000).
Niger Delta basin has five depobelts namely the Northern Delta, Greater Ughelli, Central Swamp, Coastal Swamp, and the offshore depobelts (Fig. ). Each of the depobelts has source rocks responsible for the formation of hydrocarbon. The Northern Delta depobelt is a significant petroleum province in the Niger delta basin. Oluwajana et al. (2017) explained that Eocene source facies could be responsible for oil discoveries in Northern Delta depobelt. The Eocene source rock has 0.42–1.17VR0, suggesting a thermally immature to mature source rock. The TOC contents of the Upper Oligocene shale facies in the Greater Ughelli depobelt ranges from 1.7 to 31.8 wt.%, indicating good to excellent source rock (Oluwajana 2018a; b). It is assumed that the deeply buried upper Oligocene source facies entered the main oil window during Neogene and may have contributed some hydrocarbon to interbedded Agbada sandstones of the Greater Ughelli depobelt of Niger Delta Basin (Oluwajana 2018a,2018b).
Open in a separate windowThe Miocene source rocks of the Coastal Swamp depobelt are dominated by organic-clean and gas-prone Type III/IV kerogen, with a minor contribution from oil and gas-prone of mixed Type II/III kerogen, would have contributed minimally to the oil deposit of the Niger delta basin (Oluwajana 2019). Late Miocene-Early Pliocene source rock entered the early oil generation window during the Miocene age with a transformation ratio of less than 1%, suggesting that enough hydrocarbons have not been significantly expelled to adjoining reservoirs (Oluwajana, 2018b). Ekweozor (2004) suggested that the Cenomanian–Turonian anoxic sediments entered the oil window just before or during the Santonian tectonism, but the corresponding strata underlying the Niger delta in the deep offshore where the Paleogene-Neogene overburden is considerably thinned down ought to have generated huge amounts of liquid petroleum more recently to contribute to giant oil pools in the Niger delta basin.
The Congo Basin contains the Congo Delta Composite Total Petroleum System, consisting of Lower Cretaceous to Tertiary source and reservoir rocks. The Cuanza-Namibe Assessment Unit is defined in the Cuanza Composite Total Petroleum System (Brownfield and Charpentier, 2006). In the offshore Lower Congo and outer Kwanza Basins of Angola, this syn-rift event produced the lacustrine source rocks of the Bucomazi Formation which is as much as 1500 m thick (McHargue, 1990). The source rocks in the middle units of the Bucomazi Formation contain Type I kerogens and have TOC as high as 20 wt.%, the source rocks of the lower and upper units of the Bucomazi contain Type I and Type II kerogens and average 2–3 wt.% TOC, although some organic-rich claystone locally contains more than 10 wt.% TOC (Brice et al. 1982; Schoellkopf and Patterson 2000). Hydrocarbon source rocks within the early syn-rift section of the outer Kwanza Basin contain thick, organic-rich, lacustrine shales, which have abundant Type I kerogen (Pasley et al. 1998).
In the northern part of the Congo Basin, potential source rocks namely the lacustrine Pointe Noire Marl, and Sialivakou Shale. The lacustrine Pointe Noire Marl contains Type I and Type II saprolitic organic matter averaging from 1 to 5 wt.% TOC; some source rocks contain more than 20 wt.% TOC (Baudouy and Legorjus 1991). The Sialivakou Shale contains Type II and Type III organic matter and has TOC contents averaging 1 wt.% (Brownfield and Charpentier 2006). In the central and southern Congo Basin, the Paleocene to Eocene source rocks of the Landana Formation consists primarily of deep-water shales with TOC contents as high as 3–5 wt.%, similar to those of the Iabe Formation (Brownfield and Charpentier 2006). The mid-Oligocene to Miocene Malembo Formation generally has TOC contents of 1–2 wt.%; the lower and upper parts of the formation contain from 2 to 5 wt.% TOC in the form of Type II and Type II/III kerogens. The offshore section now contains deep marine source rocks in fault-controlled troughs (Lunde et al. 1992). Offshore marine source rocks with Type II and Type II/III kerogens contain 2–10 wt.% TOC (Raposo and Inkollu 1998), and the oil compositions in discoveries in the outer Kwanza Basin also suggest a marine source.
In Congo, Angola, and Gabon, petroleum is trapped in Tertiary submarine fan sands, in Cretaceous carbonate reservoirs associated with complex salt tectonics, and in pre-salt lacustrine carbonates and turbidite sands sourced by inter-fingering non-marine organic-rich shale (Selley and van der Spuy 2016).
The Frasnian organic-rich shales have been mapped in parts of Morocco, Algeria, southern Tunisia, western Libya, and the Western Desert of Egypt (Lüning et al. 2003). The Frasnian black shales form an important petroleum source rock in North Africa and account for about 10% of all Paleozoic-sourced hydrocarbons in North Africa (Fig. ) (Lüning et al. 2003; Selley and van der Spuy 2016).
Open in a separate windowFrasnian hot shales are organically the richest and thickest hot shale package developed in eastern Algeria. The hot shales are absent in the southern part of the Ahmet Basin and reach maximum values in the central and eastern parts of Algeria (Lüning et al. 2003). The discovery of paraffinic oil in 1980 in the Adrar area, the west part of the Algerian Sahara within the Sbaa half-graben depression, opens a new oil- and gas-bearing region in Algeria (Baghdadli 1988). The organic content in the Frasnian shales of the Sbaa Basin rarely exceeds 1.2% and the present-day thermal maturities range between 0.6 and 1.2 R0%, the peak of hydrocarbon generation from the Frasnian organic-rich shales in the Sbaa basin is estimated to have occurred (Lüning et al. 2003). Thermoluminescence indicates the provenance for the Sbaa sands was the crystalline basement Cambrian and Ordovician sections (Mehadi 1990). Gas and wet gas deposits are related to sandstone reservoirs of Cambrian-Ordovician age at depths of 1500–2000 m (4920 to 6562 ft) (Baghdadli 1988).
The Ghadames Basin is a large intracratonic basin, covering portions of Algeria, Tunisia, and Libya (Echikh 1998). The sedimentary section within the Ghadames (Berkine) ranges from Cambrian to the present and is approximately 7000 m (23000 ft) thick in the depocenter. The basin has experienced several tectonic events, which have modified its architecture and affected the petroleum systems and hydrocarbon pathways (Aissaoui et al. 2016). The main petroleum systems of the Ghadames (Berkine)/Illizi Basin are represented by the Silurian Tannezuft hot shale source rock with Ordovician Djeffara and Silurian Acacus reservoirs, by Silurian Tannezuft hot shale with Kirchaou reservoirs, and by the Devonian Aouinette Ouinine Formation Member III source rock with Kirchaou reservoirs (Aissaoui et al. 2016). The Frasnian organic-rich shales of the Ghadames (Berkine)/Illizi Basin are termed “Argile Frasnienne Radioactive” in eastern Algeria and, in southern Tunisia, are part of ‘term III’ (Frasnian) of Aouinet Quenine Formation (Lüning et al. 2003).
The high organic matter content of the Frasnian hot shale in eastern Algeria (up to 14% of oil-prone type I–II kerogen of the Ghadames Basin) makes it an important petroleum source rock (Lüning et al. 2003). Estimates revealed that the core phase of generating hydrocarbons from the Frasnian hot shales started in Mid-Cretaceous times (Daniels and Emme 1995; Ghenima 1995). The Frasnian shales underwent an initial, minor generative phase in the central depression during the Carboniferous. However, the main generation occurred during the late Jurassic–Cenozoic in the western and central depressions. The Frasnian shales are currently only marginally mature in the eastern part of the basin (Underdown and Redfern 2008). The Lower Silurian Tanezzuft source rock underwent two main phases of hydrocarbon generation. The first phase occurred during the Carboniferous, and the second started during the Cretaceous, generating most hydrocarbons in the eastern (Libyan) basin (Underdown and Redfern 2008).
In the Illizi Basin, organic carbon content is generally less than 6 wt.%. The kerogen is predominantly oil-prone to mixed kerogen facies (Lüning et al. 2003). The Libyan part of the Ghadames (Berkine) Basin has a highly radioactive carbonate-black shale/marl interval. Frasnian paleoenvironments in the Libyan part of the Ghadames Basin ranges between the fully marine outer shelf and marginal marine (Lüning et al. 2003). The organically richest Frasnian shales in the western Desert Basin are reported from the northwestern part of the basin (Lüning et al. 2003) and possess a maximum TOC value of 6.27 wt.%. The Silurian and Devonian source rocks occur across large parts of the basin and have generated volumes of hydrocarbon (Echikh 1998).
The fundamental exploration techniques currently employed remains the same as those employed in the early scientific oil exploration of 1912 in the discovery of Cushing Field in Oklahoma, USA, but modern technology and engineering have greatly improved the performance and safety of crude oil exploration today united nations environmental programme (UNEP 1997). To exploit oil and gas maximally, several exploration methods and technologies, and processing techniques are employed in the oil and gas industries. The oil and gas industry is made of two categories: ‘upstream’—the exploration and production sector of the industry; and ‘downstream’—the sector which deals with refining and processing of crude oil and gas products, their distribution, and marketing. The exploration and production processes together are referred to as E&P. The facilities and systems employed in oil and gas industries are broadly defined based on exploration, upstream/downstream, midstream, refining, and petrochemical (UNEP 1997; Devold 2013).
The search for hydrocarbon-bearing rock formations involves the desk studies of geological maps to identify major sedimentary basins; use of aerial photography and land-satellite imagery to identify favorable oil landscape formations such as faults or anticlines; and the use of geophysical and geochemical exploration techniques (Assaad 2009; Economides and Nikolaou 2011; Sharma and Chaturvedi 2014; Graham and Ovadia 2019; Karolyté et al. 2020; Murray and Power 2020). To derive detailed information for oil exploration, field geological assessment is done, and this is followed by the use of surface (indirect) and subsurface (direct) geophysical methods that take place before the development of a field is finalized (Telford et al. 1990). Surface and subsurface geophysical methods employ the principles of physics to characterize the earth’s subsurface features in order to determine the zone of viable geologic interests. The main surface geophysical methods used in crude oil exploration include potential field methods (gravity and magnetics) and seismic methods (reflection and refraction). The surface geophysical methods determine the density, magnetic, and acoustical properties of a geologic medium. The seismic surveys are the most essential in crude oil exploration. The surveys are carried out in already outlined and delineated location(s) from the other reconnaissance surface geophysical methods. Due to the high amount of money, resources, and logistics required for seismic surveys, a high level of expertise is required starting from desk studies to reconnaissance surveys and seismic field (onshore and offshore) surveys, as well as their data processing and interpretation. The other geophysical methods used in crude oil exploration involve the subsurface or direct geophysical methods employing well drilling techniques (vertical, horizontal, and deviated wells) and geophysical well logging. The choice of method(s) selected depends on the type of desired geologic information, the nature of the subsurface materials, and the cultural interference (Telford et al. 1990; Assaad 2009). The integration of all these geophysical methods provides more details about the subsurface geology favorable for hydrocarbon exploration compared to relying solely on one or two methods.
Magnetic and gravity methods are used only in primary (reconnaissance) surveys where little is known of the subsurface geology and/or the thickness of sediments of potential interest (Telford et al. 1990; Parasnis 1993; Kearey et al. 2002; Assaad 2009). A magnetic survey carried out either on land (often known as ground magnetics), or in the air (known as aero- or airborne-magnetics), or at sea (referred to as shipborne/marine magnetics) employing an instrument known as “magnetometer” is primarily used to explore for oil and minerals. Magnetic exploration is based on the fact that the earth acts as a magnet (with dipoles) caused by magnetic minerals—mainly magnetite and pyrrhotite in the earth’s crustal formations. The positioning of any magnetic material in an external field will bring about an inducement of magnetic poles on its surface. The strength of the induced magnetization is directly proportional to the strength of the applied field; this is as a result of the one-directional placement of the applied field and induced magnetization. The magnetic inclination or that of the earth’s field is the measuring parameter for the location of an area relative to the magnetic poles (Assaad 2009; Clark 2014). The aeromagnetic survey developed primarily for detecting submerged submarines during the world war has since become considerably used and recorded several successful results in crude oil and mineral exploration. The numerous advantages of this method over that of ground survey include coverage of vast areas (regional reconnaissance survey) at a shorter period; coverage of irregular, difficult, or inaccessible terrains; removal of erratic near-surface features causing a nuisance in groundwork; and easier interpretation of the data due to its smoother nature. The shipborne or marine magnetic survey, on the other hand, employing ship provides no additional advantage and incurs considerable cost increase, except when integrated with other surfaces geophysical oil exploration methods. It is mainly applicable in large-scale oceanographic surveying related to crude oil search (Telford et al. 1990; Kearey et al. 2002).
The gravity method is based on the variations in lateral changes in the density of earth materials in the vicinity of the measurements. Gravity survey either on the ground, or in the air, or at sea employs an instrument called “gravimeter or gravity meter”, which are of two types—stable and unstable gravimeters. Usually, the unstable gravimeters known for their high precisions and accuracy are employed in crude oil search. The earth’s gravitational attraction at a particular location is dependent on the density of subsurface geologic formations due to the characteristic range of rocks’ densities which may differ from one laterally adjacent rock to another rock. The variations may be attributed to changes in rock porosity, degree of fluid saturation, fractures, and varying thickness of sediments consolidation or overburden cover. Besides the field precautions to achieve accurate results, some corrections, such as drift, latitude, elevation (free-air, Bouguer and terrain corrections), tidal, and Eotvos (when vehicular motion is involved), are applied to the gravity dataset to remove variations associated with instrument, latitude, elevation, the topography of surrounding terrain, earth tides, and density variation in the subsurface (Telford et al. 1990; Parasnis 1993; Kearey et al. 2002). The results after the values of Bouguer and free-air anomalies have been obtained are then analyzed qualitatively or quantitatively to map deep crustal structures hosting the hydrocarbon and controlling their migration. In oil exploration, aeromagnetic along with surface gravity is done as a preliminary survey before the seismic survey to establish appropriate depth, topography, and the character of the bedrock’s architecture. The magnetic methods also have important corrections that must be applied to annul the effects of variations, such as secular and diurnal variations, and magnetic storms.
Seismic refers to vibrations of the earth from either earthquake or artificially generated elastic sound waves (or seismic waves) that penetrate the earth’s subsurface measuring at the frequency range of about 10–100 Hz. The depths investigated for a sound wave to propagate into the earth and return to the surface were as much as tens of kilometers. The elastic waves generated travel at different velocities and are being refracted or reflected at geologic boundaries with contrasting acoustic impedance. Seismic data acquisition employs shot points at different survey lines at the earth’s surface to obtain high-quality seismic data. The energy required for oil exploration is generated through the use of explosives (TNT or dynamite) or vibroseis (both may be used onshore), and airguns (offshore). The generated sound waves are detected by channel of geophones (for the onshore survey) or hydrophones (for the offshore survey); these are electrochemical transducers that convert ground motion into an electrical analog signal (Telford et al. 1990; Kearey et al. 2002; Assaad 2009; Akingboye and Ogunyele 2019). The seismic signals received from the surveyed site are summed automatically by the seismograph, canceling out the surface waves and other extraneous impulses, and the primary reflected wave is prominently displayed on the cathode ray tube. Seismic methods can reveal the subsurface geological conditions and map undulating interfaces of very deep depth extents (Economides and Nikolaou 2011; Akingboye and Ogunyele 2019).
The seismic refraction method was the earliest and principal method employed in the search for hydrocarbon-bearing structures. Nowadays, hydrocarbon exploration depends mostly on a variety of seismic reflection methods and their two-, three- and four-dimensional (2D, 3D, and 4D) modeling techniques. Nevertheless, seismic refraction is occasionally used for resolving complex structures associated with hydrocarbon exploration. The seismic refraction method measures the travel times of seismic waves refracted at the interfaces between subsurface layers of different velocities (Carpenter et al. 2003; Cramer and Hiltunen 2004; Hiltunen and Cramer 2006; Economides and Nikolaou 2011; Akingboye and Ogunyele 2019). In seismic reflection hydrocarbon exploration, the reflected seismic waves at different subsurface interfaces which are recorded as travel times in the form of seismic traces are processed using several forms of data processing techniques to remove surface waves (ground rolls), heat waves, and some refracted waves when they constitute noise to the mapping of hydrocarbon geologic structures, such as stratigraphic and structural traps. Besides, the reflection times on seismic traces have to be corrected for time differences caused by near-surface irregularities, which have the effect of shifting reflection events on adjacent traces out of their true time relationships. These data processing techniques include shot gather, common mid-point (CMP) gather or common depth point (CDP) as an older term used by seismic industries, and normal move out (NMO) for correcting each trace to the equivalent of a zero-offset trace, among others (Telford et al. 1990; Quigley 2006; Assaad 2009).
The interpretation of seismic results involves the extraction of all available information from the seismic data, such as geologic structures, rock stratigraphy/layering, reservoir properties (e.g., porosity), and reservoir fluid changes in space and time (in 4D seismic interpretation) (King 2009; Tsvankin et al. 2010; Economides and Nikolaou 2011; Gao 2011). 3D seismic technology results can perform reservoir characterization of unparalleled quality with essential effects on exploration finding rates and volumes of roughly order of magnitude, oil and gas recovery, reserves replacement, reduction in the risk of drilling dry holes or marginal wells, etc. As the discoveries of crude oil deposits are increasingly found in challenging locations, the use of 3D seismic imaging technology remains relevant for both technical and economic reasons (Nestvold 1993; Weimer and Davis 1996).
In recent years, the emerging computational efficiency and cost reduction technologies have made it profitable to conduct multiple 3D seismic surveys in the same field over time; hence, this kind of survey is known as time-lapse or 4D seismic (Parker et al. 2003). The time-lapse or 4D seismic survey is carried out by repeated shooting of 3D (and often 3C) surveys over a producing field at regular intervals (Kearey et al. 2002). 4D seismic technology depends on comparing data from seismic experiments separated by a few years as the reservoir produces. Through this, values of several variables associated with the reservoir, for instance, fluid location and saturation (water, oil, and gas), pressure, and temperature, can be inferred and used in reservoir management plans, such as well and facilities placement or production optimization. This is particularly important for offshore oil applications, where the drilling and production cost of oil is high, and where the vast majority of 4D seismic surveys are employed (Iyer et al. 1998; Saputelli et al. 2005). Today, most development in seismic technology is mainly focused on interpretation for efficient synthesis combining elaborate numerical results in order to resolve any complexity associated with oil exploration (Economides and Nikolaou 2011).
The subsurface geophysical crude oil exploration methods are employed for the purpose of having direct contact with the subsurface lithologies, and formation reservoir identified from the interpretation of the surface geophysical crude oil exploration methods and subsurface structural models, and to allow the wellbore to be logged immediately after drilling (open well) or after the well is cased using geophysical logging tools. The logging tools are used to determine the formation temperature, degree of water, and hydrocarbon saturation, and are useful in the estimation of the optimum yield of hydrocarbon. All derived information from these methods prepares the wellbore for development to exploit the hydrocarbon for use.
The crude oil drilling techniques are used when promising geological structures hosting hydrocarbon of economic quantity are identified either onshore or offshore. The purpose of drilling in crude oil exploration is enormous, and the wells drilled serve different purposes. Some of these wells are drilling to verify the presence or absence of a hydrocarbon reservoir and to quantify the reserves; this type of drilling is known as the exploratory or wildcat well. It also determines the thickness and internal pressure of a reservoir to be developed for exploitation. Furthermore, the appraisal well drilled after the success of exploratory drilling is used to determine the economic viability of the hydrocarbon reservoir for development, size, and nature of the reservoir, the number of confirming or appraisal wells required in some cases, and whether any further seismic work is needed. This is followed by the development and production well to produce oil and gas from the reservoir through formation pressure, artificial lift, and probably employing the use of hydraulic fracturing, an advanced recovery technique, for optimum hydrocarbon recovery from tight reservoirs (Assaad 2009; Steyn 2009; Ofwona 2010).
Hydrocarbon wells are drilled using any of the drilling techniques which include percussion or cable drilling, rotary drilling, dual-wall reverse-circulation drilling, electro-drilling, and directional drilling (Funnell 2016). Traditionally, oil and gas production is accomplished using vertical well drilling; however, the directional drilling techniques of hydrocarbon wells, namely the horizontal-, sidetrack-, and deviated-drilling, is intentionally employed in the deviation drilling of a wellbore from the vertical at an angle to reach different parts of the formation for optimum oil and gas recovery. The horizontal well drilling is a type of drilling where the hydrocarbon well is drilled at an angle of more than 80 degrees from the vertical to retrieve oil and gas in situations in which the shape of the reservoir is abnormal or difficult to access, and it allows the access to the subsurface reservoir that may not be accessible from directly above. Today, modern wells are drilled with large horizontal offsets to reach different parts of the structure and achieve higher production (Economides and Nikolaou 2011; Devold 2013).
Geophysical well (borehole) logging, also known as downhole geophysical surveying or wire-line logging, involves measuring the physical properties of surrounding rocks with a sensor housed in a borehole logging device called “sonde” to derive additional information about the sequence of the rocks penetrated. The record of the measurements as a function of depth is called a well log. Any of the standard geophysical surveying techniques may be adapted for use in borehole logging. These methods include mechanical methods; passive and several active electrical methods involving self-potential, resistivity, induction, and induced polarization; several nuclear (radiometric) methods (natural γ-ray detection and observations from induced nuclear reactions); acoustic (seismic) logging; and measurement of magnetic and thermal properties (Asquith and Gibson 1982; Sheriff 1991; Kearey et al. 2002; Ofwona 2010; Miroslav 2011).
The properties of penetrated subsurface formations and their fluid contents by these methods are recorded on geophysical logs, measuring their electrical resistivity and conductivity, ability to transmit and reflect sonic energy, natural radioactivity, hydrogen ion content, and temperature and density, etc. The logs are then interpreted in terms of lithology, porosity, permeability, and fluid content. However, drilling mud, mud filtrate, formation water, and hydrocarbon affect the logging measurements (Pickett 1970; Schlumberger 1972, 1974, 1979; Telford et al. 1990; Assaad 2009; Honório et al. 2012). Borehole logs can define the depth to geological interfaces or beds with characteristic geophysical signatures, identify geological formations and formation fluids, provide a means of correlating geological information between boreholes, obtain information on the in situ properties of the wall rock, and evaluate the productive capabilities of reservoir formations (Kearey et al. 2002; Ofwona 2010; Miroslav 2011).
During hydrocarbon borehole drilling, a porous and permeable formation is penetrated by the drill bit; the drilling mud invades the formation as mud filtrate as shown in Fig. . The borehole environment of a wellbore in Fig. shows the borehole diameter (dh), the outside diameter of the drill bit describing the borehole size of the wellbore; and the drilling mud (Rm) acting as the circulating fluid with special viscosity and density to help remove the cutting from the wellbore, lubricate and cool the drill bit, and keep the hydrostatic pressure in the mud column greater than the formation pressure. The invasion of the porous and permeable formation by mud filtrate creates the invasion zones (Ri and Rxo) and an uninvaded zone (Rt). The invaded zone consists of a flushed zone (Rxo) where the mud filtrate has completely flushed out the formation’s hydrocarbons. The transition zone or annulus zone (Rj) occurring between the flushed zone (Rxo) and the uninvaded zone (Rt) consists of mixed formation fluids and mud filtrate. The depth of invasion of the mud filtrate into the invaded zone known as the diameter of invasion (di) and (dj) depends on the permeability of the mud cake and not on the porosity of the rock (Schlumberger 1977; Asquith and Gibson 1982; Assaad 2009).
Open in a separate windowThe specific geophysical log types used in hydrocarbon exploration include spontaneous potential (SP), resistivity, porosity, and gamma-ray logs. SP log record directs current–voltage differences between the naturally occurring potential of a moveable electrode running down the wellbore and that of a fixed electrode located at the surface, measured in mV. The SP log is used only with conductive (saltwater-based) drilling muds, to detect permeable beds and their boundaries, and to determine formation water resistivity and the volume of shale (Vsh) in permeable beds. The magnitude of SP deflection is due to the difference in resistivity between mud filtrate and formation water, and not on the amount of permeability. In hydrocarbon-bearing zones, the amount of SP reduction is greater than the Vsh; this is known as hydrocarbon suppression. The resistivity log is an electric log for determining the resistivity, porosity, and hydrocarbon against the water-bearing zone in order to identify the formation’s permeable zones. The resistivity logs include the induction electric log and the dual induction focused log, consisting of the deep induction log, medium induction log, and spherically focused log resistivity curves which measure the resistivities of the deep zone (Rt of the uninvaded zone), medium zone (invaded zone), and shallow zone (flushed zone), respectively. Also, the electrode resistivity logs using salt-saturated drilling mud are included; examples are: normal, lateral, Laterolog, Microlog (a pad type resistivity device that records Rmc), and Microlaterolog and Proximity Log (both measures flushed zone resistivity), and Spherically Focused Log. The Deep Laterolog and Shallow Laterolog record the resistivities of the uninvaded and invaded zones, respectively, while the microspherical focused log records the resistivity of the flushed zone. The resistivities of the formation, drilling mud, mud cake and filtrate, and formation water are affected by temperature. The porosity logs include sonic logs, and density and neutron logs (also known as nuclear logs). The sonic log records formation’s matrix porosity. The density log helps to determine evaporite minerals, gas-bearing zones, hydrocarbon density, and to evaluate shaley sand reservoirs and complex lithologies. On the other hand, the neutron logs measure the hydrogen ion concentration in a formation. The lithology logs used in hydrocarbon exploration involve the gamma-ray logs (a type of radiometric logs) which measure natural radioactivity to identify lithologies, correlate zones, and calculate the Vsh. Low radioactive concentration with low gamma-ray value is attributed to shale-free sandstones and carbonate; however, as the shale content increases, the gamma-ray log response also increases. Nevertheless, the presence of potassium-feldspar, micas, and glauconite also give rise to gamma-ray response in a shale-free formation (Schlumberger 1972, 1974, 1979; Dresser 1979; Hilchie 1978, 1982; Asquith and Gibson 1982; Telford et al. 1990; Kearey et al. 2002; Assaad 2009; Miroslav 2011).
Formation’s water saturation (Sw), which is calculated from the formation of water occupying pores divided by total pore space in the rock, represents an important log interpretation concept because it can be used to determine the hydrocarbon saturation in a formation by subtracting the water saturation from unity (1), which indicate 100% water saturation (Schlumberger 1977; Dresser 1979; Asquith and Gibson 1982). See given references above for the estimation of other formation parameters that are crucial in hydrocarbon exploration, e.g., formation’s water saturation (Sw), static spontaneous potential (SSP), sonic porosity (which depends on the interval transit time of formation and fluid in wellbore, and formation’s matrix velocity), formation’s true porosity, Vsh, and gamma-ray index (IGR).
The geochemical oil exploration methods are also conducted to reduce problems associated with exploration and to identify molecular composition and isotropic composition of gases; biomarker composition of oils and hydrocarbon maturity, a continuation of the reservoir; and hydrocarbon migration and accumulation processes. The biomarker found in oils, rock extracts, sediments, and soil extracts is analyzed using gas chromatography and a mass spectrometer to estimate the migration pathway of hydrocarbon deposits. The isotopic analysis involving isotopic ratios is analyzed to determine the origin of hydrocarbon and to estimate the accumulation of oil and gas (Sharma and Chaturvedi 2014). Besides, when the well has recovered from the effects of cooling during drilling, a flow test is conducted to evaluate its mass flow rate, enthalpy, and chemical characteristics of the discharged fluids. This test is very important because different wells are discharged under different control conditions to get the characteristic curve and to select the operating conditions for the turbines in the power plant (Ofwona 2010).
In almost all crude oil refineries, the first processing unit is the crude oil distillation unit (CDU). The CDU is designed and tasked with the distillation of the unprocessed crude into several fractions according to their boiling points (Kister 1992). The crude distillation unit (CDU) system is divided into two; the atmospheric distillation unit (ADU) and the vacuum distillation unit (VDU). Alongside these two integral components, a CDU system also incorporates crude oil furnaces, heat exchangers network (HEN), and distillation towers. A schematic diagram showing the setup of a crude oil distillation unit is shown in Fig. . The numerous physical and chemical processes undertaken by crude oil in an oil refinery are geared toward the production of useful products such as gasoline, jet fuel, diesel fuel, kerosene, etc. The basic principle employed in petroleum refining is the longer the carbon chain, the higher the temperature at which the compound boils (Dincer and Rosen 2013).
Open in a separate windowCrude oil distillation begins with the fractionation of the crude oil in an atmospheric distillation column according to their respective boiling point ranges. The varying products obtained can be classified in order of increasing volatility into residuum, gas oils, middle distillates, light distillates, and gases. The crude oil is first desalted, the desalted crude is then sent to the atmospheric distillation column for fractionation into straight-run products such as naphtha, gas oil, kerosene, etc. The residual is then sent to the vacuum distillation column for further distillation at higher temperatures (Cheremisinoff and Rosenfeld 2009). The primary end-products of crude oil distillation are described shortly below.
Gasoline is a clear petroleum-derived flammable liquid that is used primarily as a fuel in most spark-ignited internal combustion engines. Upon enhancement using various additives, its main components are organic compounds gotten from the fractional distillation of crude oil (EIA 2017). Gasoline’s combustive ability is aided by the presence of oxygen-containing compounds. The specific gravity of gasoline ranges from 0.71 to 0.77 (Demirel 2012). Early ignition, known to reduce efficiency in engines and cause knocking, is a property that must be avoided in a good gasoline blend. This property is mirrored by the gasoline’s octane rating. Lead and its compounds were once commonly used in a bid to increase the octane rating of fuels, controlling corrosiveness, and improving chemical stability. However, it has been prohibited in many countries (Kessler 2013).
Kerosene is a relatively low viscous clear liquid obtained as a product from the fractional distillation of crude oil between 150 and 275 °C. It contains compounds with carbon chains between 10 and 16 carbon atoms per molecule (Collins 2007). These compounds (accounting for 75% by volume) are majorly straight/branched-chain alkanes and cycloalkanes, regardless of the source or processing technology applied to the crude oil, while aromatic hydrocarbons in kerosene account for less than 25% by volume (AIP 2010).
Diesel fuel is any liquid fuel used in diesel engines, whose fuel ignition takes place, without any spark, as a result of compression of the inlet air mixture and then injection of fuel (Knothe et al. 2006). Diesel is mainly composed of 75% paraffin and 25% aromatics (Date 2011).
Liquefied petroleum gas finds extensive usage as a refrigerant and aerosol propellant. In a bid to reducing the damage done to the ozone layer, it has successively displaced the initial use of chlorofluorocarbons. It is referred to as Autogas when used as a vehicle fuel. It is also a promising feedstock for the production of olefins e.g., propylene, ethylene, butene, etc., in the petrochemical industry (Li et al. 2020; Orozco et al. 2020).
The exploration and processing of crude oil in Africa has its attendant socio-economic impacts. At the end of 2007, Africa was referred to as the fastest-growing source of energy with 117.481 billion barrels of crude oil or 9.49% of the world's reserves (Nyemah 2011). Largely, oil exploration has its benefits to the economy of a nation and the world at large for example, the revenue from the oil sector has been the mainstay of the economy of the countries producing it in Africa; as it is also infused into other sectors for developmental purposes (Olujimi et al. 2011; Mensah and Casadevall 2019). In today’s modern society, however, the quest for rapid development and making life comfortable for human beings has rather taken overriding priority over environmental safety.
The largest oil producers globally are the United States, Russia, and Saudi Arabia accounting for 54% of the total world production (Investopedia 2020) with Africa also not relenting currently with 10 oil-producing countries. In global trade, oil and gas are the major internationally traded commodities and this is because they are easy to transport. There have been more than 275 new oil fields discovered in West Africa since 2000, according to a U.S. Geologic Survey Fact Sheet issued in February 2010 (Kramer 2010). Proper management of natural resources and the revenue generated from trade and investment in petrochemicals and affiliated products, can be harnessed for economic growth, reduce unemployment, infrastructural development, alleviate property and hunger in the African continent (Nyemah 2011; Faria 2020). However, despite the discovery of oil fields and deposits in Africa within the last century, poor resource management, lack of local investment, and corruption have inhibited desired growth and development, yet the adverse effect of exploration and processing is enormous.
The Nigerian government, for instance, exercises absolute control over property rights. In other words, they exercise the sovereign power to take seizure of any landed property for use (Boele et al. 2001; Agbogidi et al. 2005). Earlier reports suggested that the total wealth accrued from crude oil exploration in Nigeria get siphoned by only 1% of the entire population (Junger 2007; Brown and Tari 2015). Reports between 1970 and 2020 and the average price of barrel oil and a gallon of gas between the period in review, suggest that $669 billion in revenue was generated from the sales of crude oil between 1970 and 2010. Furthermore, between 1999 and 2010, over 742 million cubic meters of gas were produced, if harnessed would have been equivalent to $192 billion, and 587,375,000 cubic meters were flared, which represents a loss in revenue of around $151.3 billion (Audu et al. 2016). Nigeria is regarded as the number one crude oil producer in Africa, the seventh-largest exporter of crude oil in the world, and holds the 10th biggest processed gas reserve in the world (Amnesty International 2006; Donwa et al. 2015). Despite the massive earning from oil, Nigeria is ranked among the poorest and heavily indebted countries in the world (Agbiboa 2013; Investopedia 2020). Over 70% of its estimated 200 million people live on less than $2 US per day, due to corruption and mismanagement of resources and revenue according to the corruption perception index (CPI) reports (Hope 2017). The diversion of funds from public coffers to certain individuals, and award of oil blocks, contracts, licensing, and production rights to individuals have impaired economic growth and led to civil war, banditry, and insurgency in Nigeria.
The rampant corruption of government officials, particularly in Africa, is a downside to the exploration and processing of crude oil in Africa. A large number of host communities of crude oil deposits in Africa suffer from a lack of infrastructure. Fertile soils and clean rivers are integral resources required by residents of local communities to ensure their economic wellbeing, which has been negatively impacted by crude oil processing, exploration, and transportation (Ehirim et al. 2018). Most of the communities are deprived of a potable water supply due to oil spills emanating from crude oil exploration (Junger 2007). The resulting influence of the oil spills into water bodies is a threat to aquatic life which then results in aggravating hunger and poverty (Pittock et al. 2018). Agricultural farmlands are also affected in the process due to runoffs from crude oil deposit areas, thus turning originally fertile soils into wastelands. The economic downturn of this is a reduction in crop yield and productivity (Sam et al. 2017; Chijioke et al. 2018), thus affecting sales and subsequently the gross domestic product from agriculture. Gas flaring is characterized by the release of harmful gases and particulate may pose health threats to both humans and animals (Otitoloju and Dan-Patrick 2010). Over 250 toxins, which include polycyclic aromatic hydrocarbons (PAHs), hydrogen sulfide, toluene, benzene, sulfur dioxide, nitrogen dioxides, xylene, etc., have been detected in flared gases; some of which are responsible for acid rain, ozone depletion, global warming, cancer, and other harmful effects (PAHs) (Giwa et al. 2019). Thus, the indiscriminate release of particulate matter and precursor gases around oil-producing communities may call for concern.
Furthermore, quite a large number of oil-producing nations in Africa are heavily reliant on the output from the processing of crude oil. The corruption embedded in the system makes little room for accountability and as such lump sums are siphoned elsewhere. This leads to an impairment in the infrastructural development of oil processing since most of the money is being siphoned elsewhere. The socio-economic structure of many African countries has been altered, as a result of the operation of crude oil exploration activities, resulting in a lack of accountability and less citizen participation (Kyomugasho 2016). Table reveals a significant discrepancy in the human development indices to the amount of oils produced by most of the Countries listed. Countries with significantly lesser revenue generated from oil production fared better in terms of human development and capacity building. This points to the fact that revenues do not automatically transform poor economies into thriving ones, except the revenue is efficiently managed, effectively redistributed, and properly harnessed for diversified local investments.
Nigeria continues to experience national under-development despite her enormous exploration and processing of crude oil. This is largely due to neglect experienced by other sectors of the economy as a result of the large revenue incurred from crude oil, thus making the nation a mono-culture economy (Adefolaju 2014). The failure of most African governments to mitigate corruption and associated risks of oil pollution has reportedly contributed to militant activities in the crude oil-producing regions (Tantua and Kamruzzaman 2016; Babatunde et al. 2018). In addition, poverty is a major experience of crude oil-host communities in Africa (Sam and Zabbey 2018). Crude oil is majorly found in rural areas in Africa. The technological expertise required for its exploration and processing is oftentimes imported due to the low level of education of persons living in such communities. It was reported that about 70% of individuals resident in the Niger Delta area of Nigeria are living below US$1 per day (Amnesty International 2006).
In Angola, even though the first commercial oil discovery was made in 1955 and the oil industry has grown exponentially since then, yet economic growth has fluctuated substantially averaging just about 5% per annum between 1985 and 2015 (Mohammed 2018). In the wake of oil discovery, civil war struck in Angola between 1975 and 2002, thus limit expected growth and development (Malaquias 2001). However, between 2006 and 2015, oil accounted for 97% of Angola’s export and 45% of its gross domestic product (GDP) (World Bank, 2017). In Angola to date, over-dependence on oil exports as the major contributor to economic growth is a major concern for policymakers, especially due to the falling price of oil and global recession during the COVID-19 pandemic.
Libya is renowned traditionally for agriculture until the discovery of oil in 1959 (Blake 1969). Since its discovery, crude oil is the major source of revenue (50% of GDP, 97% of exports, and 75% of national revenue), and plays a dominant role in the socio-economic development of Libyan society (El-Sharif 2005). Although the advent of oil has brought about tremendous prosperit
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