Article pubs.acs.org/EF
Thermal Maturity Assessment and Characterization of Selected Oil Samples from the Niger Delta, Nigeria S. J. Omotoye,† S. A. Adekola,*,† A. Adepoju,† and A. Akinlua‡ †
Department of Geology, and ‡Fossil Fuels and Environmental Geochemistry Group, Department of Chemistry, Obafemi Awolowo University, Ile-Ife, Nigeria ABSTRACT: A total of 17 crude oil samples from producing wells in the eastern Niger Delta were analyzed for their thermal maturity status. The study is aimed at establishing maturity trends across the area and identifying maturity parameters that can be reliably used for maturity assessment of the area. On the basis of the geography, the study area has been subdivided into eastern, western, and central areas. The oils were analyzed using gas chromatography (GC) and gas chromatography−mass spectrometry (GC−MS). The results showed that the pristane/phytane (Pr/Ph) ratio ranges from 2.3 to 5.1, which indicates that the oils were derived from mixed terrigenous/marine organic matter. The sterane and hopane results based on thermal maturity parameters were unreliable for oil maturity assessment. Aromatic maturity parameters worked better for thermal maturity assessment of the oil samples analyzed. The conclusion was based on the plots of 4-methyl dibenzothiophene/1-methyl dibenzothiophene (MDR), C27 17α (H)/C27 18α (H) (Tm/Ts), methyl phenanthrene ratio (MPR), monoaromatic steroid C21/triaromatic steroid C21 + monoaromatic steroid C28 (MAC21/TAC21 + MAC28), and 20S/(20S + 20R)C27 maturity parameters, which are in good agreement with regard to the maturity status of the oils analyzed and are, therefore, suitable for use in the thermal maturity assessment of oils in the study area. Maturity of the oils is found to increase from the east to west area.
1. INTRODUCTION Petroleum geochemistry is an established science concerned with the utilization of chemical principles to the study of the formation, migration, accumulation, and alteration of petroleum and the application of this understanding in the exploration and recovery of oil and gas. In this context, petroleum geochemistry has its useful modern applications in exploration and production of “conventional” hydrocarbons and also supports the development of “unconventional” resources, such as shale gas. In petroleum exploration, petroleum geochemistry has been found to be an indispensable tool at both the initial and advanced stages in identifying source rocks and classifying crude oils into families.1,2 A biological marker or biomarker is a molecule synthesized by a plant or animal and remained unchanged or having suffered only minor subsequent changes with preservation of the carbon skeleton.3 The biomarkers are therefore representative of the geochemical input and the pH/Eh conditions of the paleodepositional environments that resulted in organic matter becoming incorporated into the sediment. Petroleum contains a small amount (∼1% and less) of biomarkers.3 The biomarkers can described the genetic relationship between petroleum, the amount of petroleum expelled, and the quality and maturity of the source rock from which the petroleum originated.3 From the point of view of exploration studies, crude oil thermal maturation may be considered as one of the most important geochemical effects. Maturation processes involve cracking, isomerization, and aromatization reactions as well as alkylation and dealkylation of aromatic rings. These processes occur in the source rocks, although there are other post-generative alterations that also occur in the reservoir, which are secondary changes. During a long geological time, they have been affected by heat, pressure, and mineral catalysts, which resulted in the formation of thermodynamically more stable structural and stereochemical isomers or smaller molecules as well as transformation of saturated hydrocarbons into © 2015 American Chemical Society
aromatic hydrocarbons. There are reports to show that Niger Delta oils have been analyzed extensively in terms of their thermal maturity using their biomarker compositions.1,4,5 The maturity trend of the ExxonMobil joint venture area in the Niger Delta and the maturity parameters that worked better for the area have not been investigated, or where data are available, they remain as confidential data of the company that owned them. The purpose of the present work is to investigate new thermal maturity parameters that will be useful for thermal maturity assessment of crude oils using the ExxonMobil joint venture area of the eastern Niger Delta as a case study and with application in any sedimentary basin elsewhere.
2. GEOLOGY OF THE STUDY AREA The Niger Delta is located in southern Nigeria between longitude 4° and 9° E and latitude 4° and 6° N (Figure 1). It is the most important sedimentary basin in Nigeria from the point of view of both size and thickness of sediments. The Delta covers an area of about 105 000 km2.6 It extends in the east−west direction from southwestern Cameroun to Okitipupa Ridge. Its apex is situated southeast of the confluence of the Niger and Benue Rivers. It falls mainly in the Gulf of Guinea to the southwest of Benue Trough and constitutes the most important Cenozoic deltaic construction in the southern Atlantic. The Niger Delta occupies an area restricted by the Benin Flank, the Calabar Flank, the Anambra Basin, and the Senonian Abakaliki Uplift. It is generally agreed that the modern Niger Delta is built on an oceanic crust. The supporting arguments come from the precontinental drift reconciliation.7 This indicates an important Received: August 25, 2015 Revised: December 7, 2015 Published: December 14, 2015 104
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Table 1. Geochemical Ratios and Parameters Calculated from the Distribution of n-Alkanes and Acyclic Isoprenoid Hydrocarbons of Niger Delta Oils
Figure 1. Map of the Niger Delta showing the location of the study area.
overlap of northeast Brazil on the present Niger Delta and from a series of geological and geographical observations, e.g., the presence of a series of linear subdued and alternatively positive and negative anomalies beneath the Niger Delta, interpreted by Burke et al.8 as seafloor spreading lineation.9 There has been much discussion about the source rock for petroleum in the Niger Delta.1,2,10−13 Possibilities include variable contributions from the marine interbedded shale in the Agbada Formation and the marine Akata Shale.2,10,11,14−18
sample number
Pr/Ph
Pr/n-C17
Ph/n-C18
OEP
CPI
A1 A4 A6 A7 A9 A10 A11 A12 A13 A14 A15 A16 A17 A18 A19 A20 A21
5.1 4.6 2.7 3.2 3.1 4.5 3.6 3.3 3.9 3.5 4.6 2.3 3.2 2.8 2.9 3.3 2.9
1.1 1.0 1.1 1.1 1.0 1.6 2.3 1.3 1.7 1.4 1.3 1.8 0.9 0.9 1.1 1.3 0.9
0.2 0.3 0.5 0.4 0.4 0.4 0.7 0.4 0.5 0.4 0.3 0.8 0.3 0.4 0.4 0.4 0.4
1.01 1.03 1.05 0.99 1.00 1.00 1.01 1.00 1.00 1.00 1.02 1.00 1.01 1.01 1.00 1.01 1.04
1.07 1.06 1.06 1.03 1.05 1.07 1.06 1.04 1.09 1.06 1.07 1.04 1.05 1.06 1.07 1.05 1.08
Table 2. Data on Terane Source and Maturity Biomarker Parameters of the Investigated Oil Samples from Niger Delta Determined Using GC−MSa
3. MATERIALS AND METHODS Oil samples were fractionated using open-column liquid chromatography (OCLC) into saturates, aromatics, and nitrogen-, sulfur-, and oxygen-containing compounds (NSO) using analytical-grade n-hexane, dichloromethane, and a mixture of methanol and dichloromethane using a ratio of 9:1, respectively.4 All of the chemicals and reagents are of analytical grade (Sigma-Aldrich, St. Louis, MO). The separated fractions were concentrated by evaporating the solvent in a stream of nitrogen gas. Saturated and aromatic hydrocarbon fractions separated from the crude oils were analyzed using gas chromatography−mass spectrometry (GC−MS) on an Agilent 7683B series with an Agilent 5973 inert mass selective detector (MSD) equipped with a DB-5 MS capillary column of 30 m × 0.50 mm inner diameter coated with a 0.50 μm thin film. The mass spectrometer was operated at an electron energy of 70 eV. The temperature program for aromatic analysis started from 80 °C for 2 min, increased from 80 to 200 °C at 5 °C/min, and then increased from 200 to 310 °C at 3 °C/min, with a final temperature of 310 °C held for 8 min. The starting temperature for saturate hydrocarbon was 75 °C for 2 min, increased from 75 to 200 °C at 5 °C/min, and then increased from 200 to 310 °C/min at 3 °C/min, with a final temperature of 310 °C held for 8 min. The carrier gas was helium, with a flow rate of 2 mL/min. Gas chromatography (GC) was used for the whole oil analysis of the crude oil samples. This was carried out using an Agilent gas chromatograph model 7890A with a HP Ultra-1 column (25 × 0.32 mm internal diameter and 0.52 μm film thickness). The analysis was performed with helium (He) as the carrier gas with a split injection mode. A flame ionization detector (FID) detected separated components. The temperature program went from 4 to 320 °C in 79 min, and the final temperature was held for 20 min. Identification of the peaks was based on the retention times and a comparison to standards. The peak integration was achieved using the Agilent ChemStation software.
S/N
Ts/Tm
20S/(20S + 20R)C27
ββ/(ββ + αα)C29
A1 A4 A6 A7 A9 A10 A11 A12 A13 A14 A15 A16 A17 A18 A19 A20 A21
0.70 0.60 0.70 0.80 0.80 0.40 0.50 0.80 0.60 0.70 0.70 0.60 0.70 0.60 0.70 0.80 0.70
0.25 0.30 0.39 0.35 0.38 0.28 0.36 0.35 0.36 0.32 0.23 0.47 0.41 0.42 0.41 0.41 0.40
0.241 0.241 0.223 0.230 0.227 0.217 0.227 0.235 0.208 0.218 0.223 0.199 0.222 0.213 0.218 0.217 0.228
a Ts, 22,29,30-trinor-17α-neohopane; Tm, 22,29,30-trinor-17α-hopane; and sterane, 20S/(20S + 20R).
The analyzed oils have a pristane (Pr)/phytane (Ph) ratio of 2.30−5.10, with an average of 3.5. The Ph/n-C18 ratios range from 0.20 to 0.70, averaging 0.42, while the Pr/n-C17 ratio ranges from 0.90 to 2.30, with an average of 1.36. The carbon preference index (CPI) values range from 1.03 to 1.09, with an average of 1.06, while the odd/even ratio ranges between 0.99 and 1.05, with an average of 1.02 (Table 1). The Pr/Ph values of >3.0 for these oils suggest an oxidizing depositional environment for the source rocks. Pr/Ph ratios for the analyzed oils indicate a dysoxic depositional environment and significant contribution of humic organic matter in the source rocks from which these oils were generated.19 Also, the high Pr/Ph ratios, which are greater than 3 for most of the oil samples analyzed, mean that the oils were generated from organic matter at maturation levels corresponding to the main phase of oil generation as proposed by Diessel.20
4. RESULTS AND DISCUSSION The data derived from geochemical analyses carried out on the 17 selected oils are presented in Tables 1−3. Panels a and b of Figure 2 show typical gas chromatograms of the analyzed oils. 105
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Energy & Fuels Table 3. Maturity Ratios Calculated from the Abundance of Mono- and Triaromatic Steroids S/N
MA(I)/MA(I + II)
TA(I)/TA(I + II)
TAC26/TAC20 + TAC27
MAC21/TAC21 + MAC28
A1 A4 A6 A7 A9 A10 A11 A12 A13 A14 A15 A16 A17 A18 A19 A20 A21
0.1 0.2 0.2 ? 0.3 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.03 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
0.27 0.32 0.29 0.30 0.29 0.30 0.30 0.30 0.32 0.33 0.34 0.35 0.34 0.33 0.33 0.34 0.30
0.41 0.56 0.41 0.50 1.00 0.71 0.97 1.04 0.87 0.85 0.94 1.09 0.97 0.84 1.09 1.04 0.65
Figure 2. (a) Representative GC of the aliphatic hydrocarbon fraction of non-biodegraded oils. (b) Representative GC for slightly biodegraded oils.
The cross-plot of Pr/n-C17 versus Ph/n-C18 shows that most of the oil samples were derived from terrestrial organic matter deposited under dysoxic conditions21 (Figure 3a). Some oil samples from east and western parts of the study area are plotted
in the mixed marine organic source/transitional environments. The cross-plot of Pr/Ph against CPI (Figure 3b) also indicates that the oils were generated from organic matter deposited in more oxidizing environments. This shows that these oils have 106
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Figure 3. (a) Plot of Pr/n-C17 versus Ph/n-C18 showing that the organic matter from which oils were derived is mainly of terrestrial origin deposited under oxic conditions.21 (b) Plot of Pr/Ph versus CPI of the analyzed oils, indicating that the oils were generated from organic matter deposited in more oxidizing environments. This also indicates that the oils have identical source rocks but at different levels of thermal maturity.
The values of 20S/(20S + 20R)C27 and ββ/(ββ + αα)C29 in the studied samples ranged between 0.23 and 0.47 and between 0.199 and 0.241, respectively (Table 2). The cross-plot of Ts/Tm against other thermal maturity parameters, such as TAC26/TAC20 + TAC27, 4-MDBT/1-MDBT, and MPR shows a positive correlation, with a progressive increase in the thermal maturity of the oils from east to west in the study area (Figure 5). A negative correlation is observed from the cross-plots of steranes with other parameters that worked, which means that steranes did not work for the oils (panels a and b of Figure 6). This could be as a result of the isomerization reaction of 20R to 20S that was incomplete before the oil window,24 which is peculiar to Tertiary oils. The incomplete sterane isomerization of the oil samples may also be due to their generation from terrestrial source rocks under low heating conditions that usually characterize deltaic oils. It has been suggested that the extent of cracking in side chains of mono- and triaromatic steroid hydrocarbons can be used to provide information regarding maturity.23,24 The abundance ratios of the short- to long-chain components have frequently been used as a maturity parameter. The ratios MA(I)/MA(I + II) {MA (I) C21 + C22/MA (I) C21 + C22 + MA (II) sum of C27−C29}
identical source rocks but with a varied level of thermal maturity. Figure 4a displays m/z 191 tri- and pentacyclic terpanes, while Figure 4b shows m/z 217 sterane and diasterane components of the analyzed oils. The distribution of the various classes of biomarkers in the selected oils is typical of Niger Delta oils previously reported.22,23 Oleanane peaks are noted to be prominent in all of the studied oil samples. 4.1. Thermal Maturity. A number of different maturity parameters were hitherto deduced from both aliphatic and aromatic hydrocarbons to ascertain the parameters that work better for thermal maturity of oils from the study area. There is a need for reliable evaluation of maturity parameters and their applicability in oil−oil and oil−source rock correlations in the Niger Delta; this requires the critical consideration of all known maturity parameters. Some factors must be taken into consideration when applying maturity parameters. For instance, equilibria of a number of isomerization reactions, e.g., moretanes → hopanes, 22R → 22S hopanes; 14α (H) 17α (H) → 14β(H)17β(H) steranes, and 20R → 20S steranes, could be attained before the end of catagenetic changes of organic matter of the source rock. All of the oil samples analyzed have very similar distributions of the regular C27−C29 steranes, implicating a common source. 107
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Figure 4. (a) Representative m/z 191 mass fragmentogram showing tri- and pentacyclic terpane distribution. (b) Representative m/z 217 mass fragmentogram showing sterane and diasterane distribution.
samples analyzed, the values of TA(I)/TA(I + II) range from 0.03 to 0.20, while MA(I)/MA(I + II) ranges from 0.1 to 0.3 (Table 3). It was observed from the cross-plots of TA(I)/(TA(I + II) versus MA(I)/MA(I + II) and also with other maturity
and TA(I)/TA(I + II) {TA (I), C20 + C21/TA (I) C20 + C21 + TA (II) sum of C26−C28} increase during thermal maturation from 0 to 100%23,25 because of (1) conversion of long- to shortchain aromatic steroids, (2) preferential cracking of the long chain rather than the short chain,26 or (3) both.27 In the crude oil 108
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Figure 5. Cross-plot of MDR versus Tm/Ts, showing a maturity increase from east to west (MDR = 4MDBT/1MDBT).
Figure 7. (a) Cross-plot of TA(I)/TA(I + II) versus MA(I)/MA(I + II). (b) Ts/Tm against TAC26/TAC20 + TAC27, showing a positive correlation.
Figure 6. (a) Cross-plot of 20S/(20S + 20R)C27 versus ββ/(ββ + αα)C29, showing a negative correlation. (b) Cross-plot of MDR against 20S/(20S + 20R)C27, showing a negative correlation.
parameters that the parameters cannot be recommended for the thermal maturity study of the oils under investigation, because no reasonable conclusion could be deduced from the plots (Figure 7a). MAC21/TAC21 + MAC28 and TAC26/TAC20 + TAC27 were also derived from mono- and triaromatic hydrocarbons to further check the usefulness of ratios from these compounds for the evaluation of thermal maturity of the crude oil samples investigated. The cross-plot of these ratios with other parameters shows that the parameters could be used for the characterization of the oil samples studied (Figure 7b). A thermal maturity increase is seen from east to west of the study area. In the studied oils, the methylphenanthrene index-1 (MPI-1 index) values range between 0.70 and 0.90. A positive correlation is observed from the cross-plot of methylphenanthrene index-3 (MPI-3) and MPI-1, with a thermal maturity increase from east to west (Figure 8a). The cross-plot of MPI-3 against the
Figure 8. (a) Cross-plot of MPI-3 versus MPI-1, showing a positive correlation. (b) Cross-plot of MPI-3 against MPR, showing a positive correlation. MDR = 4MDBT/1MDBT (methyldibenzothiophene ratio). The arrows imdicate a maturity increase. 109
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Energy & Fuels methylphenanthrene ratio (MPR) indicates that these parameters can work better for the thermal maturity determination of the examined oil samples. This is as a result of the positive correlation that existed between the parameters (Figure 8b). In the oil samples investigated, the methyldibenzothiophene ratio (MDR) values range from 1.60 to 3.50. A positive correlation is displayed by the cross-plot of the parameters 4-MDBT/1-MDBT, MPDF, Ts/Tm, and TAC26/TAC20 + TAC27, with a varied level of maturity noticed at the eastern part of the study area and the highest maturity occurring in the western part of the study area. The plot of this ratio with other maturity parameter shows that it can be used for the thermal maturity determination of the oils under examination (Figure 9a). The cross-plot of 4-MDBT/
Figure 10. (a) Comparison of all of the maturity parameters tested in this study against the sample number to see those parameters that can be used to evaluate thermal maturity in the study area. (b) Line plot of MDR, Tm/Ts, MPR, MAC21/TAC21 + MAC28, and MPR versus sample number, indicating the maturity parameters that work better for crude oils from the ExxonMobil joint venture area.
marine/terrestrial organic matter. The studied oils showed variability in their maturity status. Maturity parameters derived mainly from aromatic hydrocarbons, 4-MDBT/1-MDBT, MAC21/ TAC21 + MAC28, MPR, 20S/(20S + 20R)C27, and Tm/Ts proved to be reliable tools for thermal maturity assessment of the oils investigated. Sterane- and hopane-based maturity parameters could not be used reliably to assess maturity of crude oils studied probably because the ratios had reached their respective equilibrium values before the oil window.
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Figure 9. (a) Cross-plot of MPI-1 versus MDR, displaying a positive correlation. (b) Cross-plot of MDR against MPDF, showing a positive correlation.
AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected]. Notes
1-MDBT against other maturity parameters shows a progressive increase in thermal maturity from east to west (Figure 9b). Those that agree were separated and re-examined to properly identify those parameters that can be readily used for the thermal maturity determination in the study area. Panels a and b of Figure 10 show a comparison of the maturity parameters tested in this study. Both plots show that MDR, Ts/Tm, MPR, MAC21/ TAC21 + MAC28, and 20S/(20S + 20R)C27 maturity parameters are in good agreement in indicating the maturity status of the oils analyzed and are, therefore, suitable for use in the thermal maturity assessment of oils in the study area.
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The authors are grateful to the management of Mobil Producing Nigeria Unlimited for allowing the publication of these data and permission to use the Geochemistry Facilities at Qua Iboe Terminal in Eket, Akwa Ibom, Nigeria, for this study. The efforts of Dr. C. I. Eneogwe, Martin Iyasele, Okolusi, and other Operation Technical 202 Geoscience Unit staff members are highly appreciated.
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5. CONCLUSION A normal alkane and isoprenoid hydrocarbon distribution in the oils indicates that the oils were derived from mixed 110
NOMENCLATURE SAT = saturate hydrocarbon ARO = aromatic hydrocarbon DOI: 10.1021/acs.energyfuels.5b01902 Energy Fuels 2016, 30, 104−111
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(23) Seifert, W. K.; Moldowan, M. J. Geochim. Cosmochim. Acta 1978, 82−94. (24) Grantham, P. J. Org. Geochem. 1986, 9, 293−304. (25) Mackenzie, A. S.; Brassell, S. C.; Eglinton, G.; Maxwell, J. R. Science 1982, 217, 491−504. (26) Peters, K. E.; Walters, C. C.; Moldowan, J. M. The Biomarker Guide; Cambridge University Press: Cambridge, U.K., 2005; Vol. 1 and 2, pp 134−175. (27) Beach, F.; Peakman, T.; Abbott, G. D.; Sleeman, R.; Maxwell, J. R. Org. Geochem. 1989, 14, 109−111. (28) Peters, K. E.; Moldowan, J. M. The Biomarker GuideInterpreting Molecular Fossils in Petroleum and Ancient Sediments; Prentice Hall: Englewood Cliffs, NJ, 1993; pp 363. (29) Tissot, B. P.; Welte, D. H. Petroleum Formation and Occurrence, 2nd ed.; Springer: Berlin, Germany, 1984; pp 669. (30) Radke, M.; Welte, D. H.; Willsch, H. Geochim. Cosmochim. Acta 1982, 46, 1−10. (31) Radke, M.; Willsch, H.; Leythaeuser, D.; Teichmuller, M. A. Geochim. Cosmochim. Acta 1982, 46, 1831−1848. (32) Kvalheim, O. M.; Christy, A. A.; Telnaes, N.; Bjorseth, A. Geochim. Cosmochim. Acta 1987, 51, 1883−1888. (33) Radke, M.; Welte, D. H.; Willsch, H. Org. Geochem. 1986, 10, 51− 63.
NSO = nitrogen-, sulfur-, and oxygen-containing compounds Pr/Ph = pristane/phytane OEP = odd/even preference CPI = carbon preference index Ts/Tm = C27 18α (H)/C27 17α (H) MA = monoaromatic steroid MA (I) = C21 + C22 MA (II) = sum of C27−C29 TA = triaromatic steroid TA (I) = C20 + C21 TA (II) = sum of C26−C28 MPI-1 = methylphenanthrene index-128 MPI-3 = methylphenanthrene index-329,30 MPDF = methylphenanthrene distribution factor31 MPR = methylphenanthrene ratio32 MDR = methyldibenzothiophene ratio33 4-MDBT = 4-methyldibenzothiophene 1-MDBT = 1-methyldibenzothiophene
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