New Insights Into the Geochemical Characteristics of Petroleum Source Rocks and Oils From Southern Nigerian Sedimentary Basins

IF 1.7 4区 地球科学 Q3 GEOSCIENCES, MULTIDISCIPLINARY
Abdulkareem Toyin, Falilat Omotolani Idris, N'Guessan Francois De Sales Konan, Olabisi Adekeye
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In the present research, bulk geochemical analysis, which includes total organic carbon (TOC) and rock pyrolysis, molecular markers, and bulk and compound-specific carbon isotopes (CSIAs), in addition to organic petrological analysis was carried out on source rocks of Cretaceous age from the Anambra Basin and oils (both Anambra and Niger Delta Basins) in order to provide information on why there was a sudden seizure in liquid hydrocarbon production in the ANAR oilfield of the Anambra Basin and also to shed more light on the unending debate on the source of Cretaceous Niger Delta oils. From the results, bulk geochemical data and maceral abundances revealed that Nkporo shales from well-x and outcrop Mamu shales are dominantly of Types II and III organic matters and are capable of producing oil and gas upon attaining appropriate thermal maturity, whereas outcrop Mamu coals are of Types II and II/III organic matter, with good potential for oil generation but with minor gas, especially in the deeper section of the basin. Organic matter richness as deduced from TOC revealed that the Mamu coals are the richest (average TOC: 50.74 wt%), whereas Mamu shales are richer (average TOC: 2.89 wt%) than Nkporo shales (average TOC: 1.66 wt%). The hydrocarbon generative potentials of the analyzed source rocks as obtained through the hydrogen index are highest in the Mamu coals (average: 329.25 mg HC/g TOC), and are followed by Mamu shales (average: 130.89 mg HC/g TOC), whereas the least was obtained in Nkporo shales (average: 69.73 mg HC/g TOC). The maximum temperature (<i>T</i><sub>max</sub>) and the vitrinite/huminite reflectance values of the source rocks are 396–443°C, 417–430°C, and 417–421°C, and 0.38%–1.51%, 0.23%–0.42%, and 0.22%–0.46% in Nkporo shales, Mamu shales, and coals, respectively. The values revealed that Nkporo shales are in immature to early–late hydrocarbon generation stages, whereas Mamu shales and coals are dominantly thermally immature. Further, the analyzed source rocks were deposited under sub-oxic-to-oxic conditions based on molecular indices and petrographic evidence. In the Nkporo shales, there was dominant input from lacustrine organic matter, as evident from the high abundance of C<sub>28</sub>R sterane, higher C<sub>21</sub>TT, and <i>n</i>-alkane maxima at <i>n</i>-C<sub>20</sub> and <i>n</i>-C<sub>23</sub>. In contrast, the Mamu shales and coals and crude oil from the Anambra Basin received major input from terrigenous organic matter (high C<sub>29</sub> R sterane, C<sub>29</sub>/C<sub>27</sub> ratios, wax index, terrigenous/aquatic ratio (TAR), C<sub>19</sub> + <sub>20</sub>TT, and <i>n</i>-alkane maxima at <i>n</i>-C<sub>27</sub>–<i>n</i>-C<sub>29</sub>). The oils (crude oils and condensates) from the Niger Delta are dominated by C<sub>29</sub> R steranes, whereas C<sub>27</sub> and C<sub>28</sub> R steranes are in different proportions. Oil-source correlation parameters also revealed that crude oil produced in the Anambra Basin was generated by Nkporo shales from well-x and the thermally mature equivalents of Mamu shales and coals. In addition, the Mamu shales and coals are compositionally and genetically similar to oils from the onshore and offshore Niger Delta. On the basis of the oil-source correlation parameters, in addition to the presence of other elements of the petroleum system, the Upper Cretaceous (Mamu–Nkporo/Ajali) petroleum system (!) is proposed in the Anambra Basin. The present research concludes that the absence of abundant liptinitic oil–producing macerals and Type III nature of organic matter in Nkporo shales from the ANAR oil field of the Anambra Basin led to a sudden seizure in liquid hydrocarbon production. Again, there are deeply seated Cretaceous source beds within the Niger Delta Basin that are contributing to the Cretaceous oils. 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引用次数: 0

Abstract

The Anambra and the Niger Delta Basins are well-known hydrocarbon-producing sedimentary basins in Southern Nigeria. In the present research, bulk geochemical analysis, which includes total organic carbon (TOC) and rock pyrolysis, molecular markers, and bulk and compound-specific carbon isotopes (CSIAs), in addition to organic petrological analysis was carried out on source rocks of Cretaceous age from the Anambra Basin and oils (both Anambra and Niger Delta Basins) in order to provide information on why there was a sudden seizure in liquid hydrocarbon production in the ANAR oilfield of the Anambra Basin and also to shed more light on the unending debate on the source of Cretaceous Niger Delta oils. From the results, bulk geochemical data and maceral abundances revealed that Nkporo shales from well-x and outcrop Mamu shales are dominantly of Types II and III organic matters and are capable of producing oil and gas upon attaining appropriate thermal maturity, whereas outcrop Mamu coals are of Types II and II/III organic matter, with good potential for oil generation but with minor gas, especially in the deeper section of the basin. Organic matter richness as deduced from TOC revealed that the Mamu coals are the richest (average TOC: 50.74 wt%), whereas Mamu shales are richer (average TOC: 2.89 wt%) than Nkporo shales (average TOC: 1.66 wt%). The hydrocarbon generative potentials of the analyzed source rocks as obtained through the hydrogen index are highest in the Mamu coals (average: 329.25 mg HC/g TOC), and are followed by Mamu shales (average: 130.89 mg HC/g TOC), whereas the least was obtained in Nkporo shales (average: 69.73 mg HC/g TOC). The maximum temperature (Tmax) and the vitrinite/huminite reflectance values of the source rocks are 396–443°C, 417–430°C, and 417–421°C, and 0.38%–1.51%, 0.23%–0.42%, and 0.22%–0.46% in Nkporo shales, Mamu shales, and coals, respectively. The values revealed that Nkporo shales are in immature to early–late hydrocarbon generation stages, whereas Mamu shales and coals are dominantly thermally immature. Further, the analyzed source rocks were deposited under sub-oxic-to-oxic conditions based on molecular indices and petrographic evidence. In the Nkporo shales, there was dominant input from lacustrine organic matter, as evident from the high abundance of C28R sterane, higher C21TT, and n-alkane maxima at n-C20 and n-C23. In contrast, the Mamu shales and coals and crude oil from the Anambra Basin received major input from terrigenous organic matter (high C29 R sterane, C29/C27 ratios, wax index, terrigenous/aquatic ratio (TAR), C19 + 20TT, and n-alkane maxima at n-C27n-C29). The oils (crude oils and condensates) from the Niger Delta are dominated by C29 R steranes, whereas C27 and C28 R steranes are in different proportions. Oil-source correlation parameters also revealed that crude oil produced in the Anambra Basin was generated by Nkporo shales from well-x and the thermally mature equivalents of Mamu shales and coals. In addition, the Mamu shales and coals are compositionally and genetically similar to oils from the onshore and offshore Niger Delta. On the basis of the oil-source correlation parameters, in addition to the presence of other elements of the petroleum system, the Upper Cretaceous (Mamu–Nkporo/Ajali) petroleum system (!) is proposed in the Anambra Basin. The present research concludes that the absence of abundant liptinitic oil–producing macerals and Type III nature of organic matter in Nkporo shales from the ANAR oil field of the Anambra Basin led to a sudden seizure in liquid hydrocarbon production. Again, there are deeply seated Cretaceous source beds within the Niger Delta Basin that are contributing to the Cretaceous oils. This research has significant implications for future oil and gas explorations in the Southern Nigeria sedimentary basins and will contribute to the existing knowledge in the West and Central African Rift Systems (WCARS) basins and the Gulf of Guinea.

尼日利亚南部沉积盆地烃源岩及原油地球化学特征新认识
阿南布拉盆地和尼日尔三角洲盆地是尼日利亚南部著名的产油气沉积盆地。在目前的研究中,体积地球化学分析,包括总有机碳(TOC)和岩石热解,分子标记,体积和化合物特异性碳同位素(CSIAs),此外,还对阿南布拉盆地白垩系烃源岩和油气(包括阿南布拉盆地和尼日尔三角洲盆地)进行了有机岩石学分析,以提供阿南布拉盆地ANAR油田液态烃产量突然中断的原因,并为白垩系尼日尔三角洲油气来源的争论提供更多的线索。结果表明,x井的Nkporo页岩和露头的Mamu页岩以II型和III型有机质为主,达到适宜的热成熟度后具有产油能力,而露头的Mamu煤则以II型和II/III型有机质为主,具有良好的生油潜力,但含气较少,特别是在盆地深部。有机质丰度计算结果显示,马木页岩有机质丰度最高(平均TOC为50.74 wt%),而Nkporo页岩有机质丰度最高(平均TOC为2.89 wt%),平均TOC为1.66 wt%。氢指数分析结果表明,烃源岩的生烃潜力在马木煤中最高(平均为329.25 mg HC/g TOC),其次是马木页岩(平均为130.89 mg HC/g TOC),在恩波罗页岩中最低(平均为69.73 mg HC/g TOC)。Nkporo页岩、Mamu页岩和煤的烃源岩最高温度(Tmax)为396 ~ 443℃、417 ~ 430℃和417 ~ 421℃,镜质组/腐质组反射率分别为0.38% ~ 1.51%、0.23% ~ 0.42%和0.22% ~ 0.46%。结果表明,Nkporo页岩处于不成熟-早-晚生烃阶段,而Mamu页岩和煤则以热不成熟为主。此外,根据分子指标和岩石学证据,分析的烃源岩在亚氧-氧条件下沉积。Nkporo页岩中C28R甾烷丰度高,C21TT高,正构烷烃在n-C20和n-C23处最大,湖相有机质输入占主导地位。相比之下,阿南布拉盆地的Mamu页岩和煤、原油主要来自陆源有机质(高C29 R甾烷、C29/C27比值、蜡指数、陆源/水生比(TAR)、C19 + 20TT、正构烷烃最大值在n-C27-n-C29)。尼日尔三角洲原油(原油和凝析油)以C29 R甾烷为主,C27和C28 R甾烷比例不同。油源对比参数还表明,Anambra盆地原油产自Nkporo页岩x井和Mamu页岩及煤热成熟当量。此外,Mamu页岩和煤炭的成分和基因与尼日尔三角洲陆上和海上的石油相似。根据油源对比参数,除存在其他含油气系统要素外,认为阿南布拉盆地存在上白垩统(Mamu-Nkporo /Ajali)含油气系统。短句来源研究认为,ANAR油田Nkporo页岩缺乏丰富的脂质类产油组分和有机质的III型性质是导致该地区液态烃产量骤停的主要原因。同样,在尼日尔三角洲盆地中,深层的白垩纪烃源层对白垩纪石油有贡献。这项研究对未来尼日利亚南部沉积盆地的油气勘探具有重要意义,并将为西非和中非裂谷系统(WCARS)盆地和几内亚湾的现有知识做出贡献。
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来源期刊
Journal of Petroleum Geology
Journal of Petroleum Geology 地学-地球科学综合
CiteScore
3.40
自引率
11.10%
发文量
22
审稿时长
6 months
期刊介绍: Journal of Petroleum Geology is a quarterly journal devoted to the geology of oil and natural gas. Editorial preference is given to original papers on oilfield regions of the world outside North America and on topics of general application in petroleum exploration and development operations, including geochemical and geophysical studies, basin modelling and reservoir evaluation.
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