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PSComparison of Hydrous Pyrolysis Petroleum Yields and Composition from Nigerian Lignite and Associated Coaly Shale in the Anambra Basin*
Samuel Akande1, Olabisi Adekeye1, Olusola Ojo1, Michael Lewan2, Mark Pawlewicz2, Sven Egenhoff3, and Olukayode Samuel4
Search and Discovery Article #40647 (2010)
Posted November 30, 2010
*Adapted from poster presentation at AAPG Convention, Calgary, Alberta, Canada, September 12-15, 2010
1Department of Geology, University of Ilorin, Ilorin, Nigeria ([email protected])
2Organic Geochemistry Division, USGS, Denver, USA
3Department of Geosciences, Colorado State University, Fort Collins, USA
4School of Engineering & Geosciences, Newcastle University, Newcastle Upon Tyne, UK
The Anambra Basin in Southern Nigeria is one of the sub-basins of the Benue rift structure which form a part of the West African Rift System (WARS). The basin is bounded to the south by the northern portion of the Niger Delta and extends into Benue rift basins on the north side (Figure 1).
Several studies have reported the source rocks for the oil and gas in the Niger Delta as consisting predominantly of terrigenous organic matter (e.g. Ekweozor and Okoye, 1980; Bustin et al.,1988). Recent reports in the last decade (e.g. Haack et al., 2000) have also outlined the possibilities of lacustrine and marine organic matter sources for the oils and gas accumulations. Haack et al. (2000) reported three categories of petroleum systems for the delta. These include the Lower Cretaceous lacustrine dominated petroleum system, the Upper Cretaceous to Paleocene marine dominated and the Tertiary terrigenous dominated deltaic petroleum systems. Eneogwe and Ekundayo (2003) and Samuel et al. (2009) also reemphasized the presence of the three oil families across the delta with more marine dominated organo-facies producing the deepwater oils. The trend of terrigenous through less terrigenous to more marine sourced oils in the offshore to the deep offshore segments was noted from the previous work of (Haack et al., 2000 and Samuel et al., 2009).
We have carried out detailed mapping of the successions of lignites, shales, claystones, siltstones and sandstones exposed in the Anambra Basin on the northern fringes of the Niger Delta Basin. Preliminary geochemical assessment was complemented with GC, GC-MS, GC-MS-MS analysis of oils and gas expelled from the potential source rocks. In this paper, we report the results of geochemical assessment of lignites and interbedded carbonaceous shales of the Neogene Ogwashi-Asaba Formation.
Sediments of the Anambra Basin form a part of the initial proto-Niger Delta sequences and consists of the marine Campanian Enugu/Nkporo shales with the deltaic Owelli Sandstone equivalent. These are overlain by the Lower Maastrichtian deltaic coal bearing Mamu Formation, the Middle Maastrichtian fluvio-deltaic to tidal Ajali Sandstones and overlain by the fluvio-deltaic Nsukka Formation (Figure 1). The outcropping Paleogene Imo Shales (marine) overlain by the regressive Ameki Sandstone (Eocene) and the Neogene paralic Ogwashi Asaba Formation is capped by the continental Benin Sandstones constitute the Tertiary Niger Delta petroleum system. Sections through the Ogwashi-Asaba Formation are exposed in the Ihioma, Oba and Azagba-Ogwashi on the south side of the Anambra Basin. These consist of interbedded successions of shales, lignite claystones, siltstones and sandstones in a coarsening upwards cycle.
A bed by bed sampling of the section at Azagba-Ogwashi was carried out to collect the bottom, middle and top parts of the lignite seam and the overlying shale in this location. A similar procedure was adapted for the sampling of the Oba and Ihioma seams (see Figure 1). A total of 31 lignites and shale samples were obtained from the three seams with 13 from Ihioma, 8 from Oba and 10 samples from Azagba-Ogwashi. These were subjected to preliminary organic petrologic and organic geochemical studies. After the initial screening, samples from Azagba-Ogwashi were subjected to further detailed studies comprising the following:
a) Vitrinite reflectance (VRom) to determine the maturity of the coals and shales complemented by maceral analysis;
b) Leco TOC determination;
c) Rock-Eval pyrolysis;
d) sequential hydrous pyrolysis (HP) experiments on two Azagba-Ogwashi samples (the lignite AZ-01 and shale AZ-02) at 3300 C for an initial 72 hours.
After the collection of generated gas and expelled oil, the pyrolysed samples and water were re-sealed in the reactor and heated for additional 72 hours at 3550 C. This was complemented by GC-MS analysis of the expelled oils and carbon isotope determination of the gas expelled by the lignite sample AZ-01 and the shale sample AZ-02.
In the Azagba-Ogwashi section, maceral analyses reveal about equal proportions (ca. 45%) of huminite and liptinite with a huminite; liptinite and inertinite (H:L:I) ratio of 46:44:10 in the lignite seam and 71:21:8 for the overlying shale unit. Vitrinite reflectance values range from 0.32 to 0.36 VRom for the lignite and 0.38-0.41 VRom for the shales.
Rock-Eval Pyrolysis of Original Samples
The TOC of the lignite samples range from 42.2 to 68.0 wt% averaging 57.6 wt% for six samples whereas those of the shales range from 11.4 to 12.3%, averaging 12.1 wt% for four samples. S1 yields for the lignites range from 10.1 to 25.9 mgHC/g rock and S2 yields range from 113.4 to 434.7 mgHC/grock. In the shale samples S1 yields range from 2.6 to 3.2 mgHC/grock whereas S2 yields range from 24.4 to 32.2 mgHC/grock. The Hydrogen Index (HI) values all exceed 200 ranging from 268 to 639 for the lignites averaging 417 mgHC/gTOC, whereas in the shales HI range from 201 to 260 mgHC/gTOC averaging 230 mgHC/gTOC, Tmax values range from 413 to 4210 C in the lignites while those of the shales range from 415 to 4260 C (Figure 2).
Post Hydrous Pyrolysis Rock-Eval and Biomarker Data
Compared with the original lignite sample with TOC of 63.4 wt%, the recovered coal gives a TOC of 77.2 and 79.9 % at 330 and 3550 C respectively. S1 yields in the original sample changed from 6.9 mgHC/grock to 168.26 at 3300 C and 75.5 mgHC/grock at 3550 C. In the shale sample, TOC values vary from 10.3 wt% in the original shale to 10.28 at 3300 C and 9.47 wt% at 3550 C. S1 yields increased from 0.66 mgHC/grock in the original shale to 1.5 at 3300 C and 1.35 mgHC/grock at 3550 C. S2 yields decreased in both samples with increasing maturity; decreasing from 305.5 mgHC/grock in the original lignite to 100.67 mgHC/grock at 3550 C. Similarly the S2 yield in the original shale decreased from 19.7 to 1.98 mgHC/grock at 3550 C. HI index followed a similar diminishing trend decreasing from 481 mgHC/gTOC in the original lignite to 126 mgHC/gTOC at 3550 C. HI’s in the original shale decreased from 191 to 21 mgHC/gTOC at 3550 C. VRom of the original lignite increases with maturity from 0.36 to 1.49 at 3550 C whereas VRom of the shale increased form 0.4 to 1.34% at 3550 C. The VRom of both samples at 3300 C are identical with 1.09 Ro in the lignite and 1.18% in the shale samples. The total amount of expelled oil in the sequential HP experiment is 259 mg/g of original total organic carbon TOC(orig), while expelled oil from the overlying shale is only 15 mg/gTOC(orig). This small quantity of expelled oil had to be collected from the reactor with a benzene rinse so only the C15+ fraction after solvent evaporation could be characterised by gas chromatography Figure 3.
Gas Yields from The Lignite and Carbonaceous Shale (Figure 4)
The generated gas yields from the two samples show notable differences. The total hydrocarbon gas yields range from 25 mg/gTOC(orig) for the lignite to 29 mg/gTOC(orig) for the carbonaceous shale. The amount of 13 C decreases from butane (nC4), through propane (nC3), ethane (nC2) and methane (nC1) as evident by the progressively lighter carbon isotope ratios.
The expelled waxy oil from the lignite contains abundant high molecular weight n-alkanes maximising at C29 and an extremely high pristane/phytane ratio of 6.5. This GC fingerprints resemble oils with strong terrigenous organic matter and/or coaly source rocks. Typical oil samples having high pristane/phytane ratios and abundant higher molecular weight n-alkane are present in the onshore/shelf and the shallow offshore accumulations of the Niger Delta (Samuel et al., 2009). The rinsed oil expelled from the overlying carbonaceous shales contains n-alkanes that gradually decrease in content from n-C16 to n-C36 and a pristane/phytane ratio of 2.6. An almost unimodal n-alkane distribution that maximizes at around C19 is displayed on the GC trace. This is a diagnostic fingerprint of source rock with significant marine algal contribution and hence a marine source. Similar fingerprints with decreasing contents of the high molecular weight n-alkanes are characteristic of some crude oils in shallow and deepwater accumulations of the Niger delta. Gases generated from the lignite and shales are different in their isotopic characteristics but show a progressive enrichment in the light isotopes with decreasing carbon number (Figure 4). This is consistent with the kinetic isotopic effect resulting from the thermal cracking of light hydrocarbons from heavier components (Peters et al., 2005). In general the lignite gases appear lighter (particular nC1 to nC3) than the shale gas (with the exception of nC4) thus reflecting the enrichment of lighter gases from the terrigenous kerogen source material compared to the shale gas from the marine kerogen source.
An on-going controversy regarding the source of accumulated oils especially in the deepwater portion of the Niger Delta has invoked the possibility of either the Cretaceous section and the Tertiary successions as contributors (Katz, 2006; Samuel 2009). The concern has emerged from the characteristics of the marine derived oils in the Tertiary (Oligocene/Miocene) reservoirs in deep waters. Whereas Samuel et al. (2009) argue for some similarities in the geochemical nature of extracts from Upper Cretaceous Type II/III enriched intervals in the Dahomey Basin with the oils in Western Niger Delta, Katz (2006) suggests that the Mid-Cretaceous sections with significant oil prone source intervals if present and proximal to the Niger Delta could have generated and expelled liquid hydrocarbons prior to the deposition of the reservoirs and/or formation of viable traps. Katz (2006) emphasized the significant similarities in the geochemistry of oils in the Oligocene oil prone intervals with deepwater oils with indications that the deepwater oils contain similar relative concentrations of biomarkers such as hopanes and steranes.
This suggestion that oils in the deepwater are probably derived from an Oligocene source that has a mixed typeII/III affinity strengthens our thoughts that the matured structurally dipping paralic sequence of the Oligocene/Miocene Ogwashi Asaba Formation with mixed terrigenous/marine source intervals could be an important intradelta source for the deepwater marine oils. Such a geochemical interpretation provides significant constraint in basin modelling by stratigraphically limiting the source intervals. Furthermore, several considerations of coals as a major oil source has also been a major subject of controversy worldwide despite the early recognition of coal beds as important gas producers.
Oil accumulations have been attributed as mostly generated from the conventional shales and carbonates associated with the coal beds (see Katz, 1994, and the reviews by Hunt, 1991). Our current data argue in favour of the capabilities of coals to expel large volumes of heavy hydrocarbons generated at maturity levels compared with the earlier thoughts that the generated hydrocarbons are mostly retained in the pore network (Katz, 1994). Our pilot study of coals in the paralic sequence of the Ogwashi Asaba Formation indicate that source rocks can change from terrigenous to marine organic matter over narrow stratigraphic intervals of only 2 meters, hence the subsurface equivalents in the Agbada Formation of the Niger Delta Basin could contribute both terrigenous and marine sourced oils. Although previous reports suggest that marginal marine shales associated with the coals in deltaic environments normally serve as the primary source for the petroleum accumulation, eg. as in the Indo-Australian region (see Katz, 1994), this pilot study reveals the contrary in such associations.
This work received the financial support of the Nigerian Petroleum Technology Development Fund (PTDF) to the senior author during his sabbatical leave period at the Colorado State University, Fort Collins, USA and the Alexander von Humboldt Foundation Fellowship for a study visit to the Technical University Berlin for the preliminary organic petrology studies.
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