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Marine and Petroleum Geology 45 (2013) 304e314

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Marine and Petroleum Geology

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Geochemical characteristics of some crude oils from Alif Field in theMarib-Shabowah Basin, and source-related types

Mohammed Hail Hakimi a,*, Wan Hasiah Abdullah b

aGeology Department, Faculty of Applied Science, Taiz University, 6803 Taiz, YemenbDepartment of Geology, University of Malaya, 50603 Kuala Lumpur, Malaysia

a r t i c l e i n f o

Article history:Received 12 December 2012Received in revised form29 April 2013Accepted 14 May 2013Available online 29 May 2013

Keywords:Oil familiesBiomarkerDepositional environmentSource inputsMarib-Shabowah BasinYemen

* Corresponding author.E-mail address: ibnalhakimi@yahoo.com (M.H. Ha

0264-8172/$ e see front matter � 2013 Elsevier Ltd.http://dx.doi.org/10.1016/j.marpetgeo.2013.05.008

a b s t r a c t

The Marib-Shabowah Basin is an important hydrocarbon province in western Yemen, but the origin ofhydrocarbons is not fully understood. In this regard, geochemical characteristics are used to provideinformation on source organic matter input, depositional environment and the correlation betweencrude oils from different pay zones. Two oil families are present within the study area and classifiedbased on biomarker and non-biomarker parameters. The family I oils are characterized by low APIgravity, high sulfur and trace metal (Ni, V) contents and low Ph/Ph ratio <1.0. These oils were derivedfrom an alga organic matter that was deposited in a highly anoxic, hypersaline marine depositionalenvironment and generated at low maturity.

Family II oils have medium to high API gravity, low sulfur and trace metal contents and relatively highPr/Ph ratios (1.09e1.59). The family II oils were derived from mixed marine and terrigenous organicmatter and deposited under sub-oxic conditions. These oils were generated from source rocks with awide range of thermal maturity ranging from early to peak oil window. The oil characteristics suggestthat family I oils may be derived from the Tithonian age Safer calcareous shales and family II oils from thedeeper Kimmeridgian Madbi shales.

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1. Introduction

Sedimentary organic matter and crude oils contain complexassemblages of biological marker compounds (biomarkers) thatpreserve the molecular structure of various compounds thatconstitute the organisms. Biomarkers are widely used in the pe-troleum industry to identify groups of genetically related oils, tocorrelate oils with source rocks and to describe the probable sourcerock depositional environments for migrated oil of uncertain originand the degree of biodegradation (Moldowan et al., 1985; Petersand Moldowan, 1993; Peters et al., 2005).

Many oilfields have been discovered in the Marib-ShabowahBasin, an important hydrocarbon province in the western part ofYemen (Fig. 1), since oil was first discovered in the late 1980s. TheAlif Field, located in the central portion of the Marib-ShabowahBasin (Fig. 1), is one of the most prolific oilfields. The Marib-Shabowah Basin has attracted the interest of numerous re-searchers, authors and oil companies for the exploration of hy-drocarbons. The Marib-Shabowah Basin developed during the

kimi).

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Jurassic and is related to rifting of the Arabian plate from theGondwana supercontinent (Redfern and Jones, 1995; Beydounet al., 1996). The stratigraphic section in the Marib-Shabowah Ba-sin is dominated by a thick Mesozoic succession and ranges in agefrom Jurassic to Cretaceous (Fig. 2). The organic-rich shales ofMadbi Formation (Kimmeridgian) and Safer Member (Tithonian)are the prolific oil prone source rocks in the Marib-Shabowah Basin(Brannin et al., 1999; Csato et al., 2001; Hakimi and Abdullah, 2013).The Alif Member is considered the main reservoir in the Marib-Shabowah Basin (Fig. 2) and comprises over 90% of recoverableoil in the basin (JNOC, 2000 “personal communication”). Previousgeochemical studies on the Marib-Shabowah Basin oils are un-published. Within this perspective, we report the results of anorganic geochemical investigation on crude oils from the Alif Field.The objective is to use biomarker distributions together with thebulk geochemical parameters to characterize the oil types and toassess the respective depositional environment and thermalmaturity of their potential source rocks.

2. Samples and methods

The materials used in this study include 10 crude oil samplesrepresenting different petroleum reservoirs in the Alif Field, Marib-

M.H. Hakimi, W.H. Abdullah / Marine and Petroleum Geology 45 (2013) 304e314 305

Shabowah Basin (Table 1). The geographic locations of the wellschosen are shown in Figure 1.

The ratios of transition metals (vanadium and nickel) in crudeoil are useful in the determination of source rock type, depositionalenvironment and maturation because they remain unchangedirrespective of diagenetic and in-reservoir alteration effects(Barwise, 1990; Udo et al., 1992). Absolute concentrations of va-nadium and nickel can be used to classify and correlate oils. Thesemetals are the major metals in petroleum (Boduszynski, 1987). Themetals analysis was conducted at Geochem Laboratories Limited(USA).

Asphaltenes were precipitated from the crude oils by adding a40 fold excess of n-hexane. The precipitated asphaltenes werefiltered. The fractions of the hexane soluble organic matter wereseparated into saturated hydrocarbons, aromatic hydrocarbons andNSO compounds using liquid column chromatography. A chro-matographic column (30 � 0.72 cm) was packed with equal vol-umes of alumina and silica (both activated for 2 h at 200 �C).

The saturated hydrocarbon fractions were then analyzed by gaschromatography (GC) and gas chromatographyemass spectrom-etry (GCeMS). A FID GC with HP-5MS column and helium carriergas was used. A temperature program from 40 to 300 �C at a rate of4 �C/min and then held for 30 min at 300 �C was used for GCanalysis. GCeMS experiments were performed on a V 5975B inertMSD mass spectrometer with a GC attached directly to the ionsource (70 eV ionization voltages, 100 mA filament emission cur-rent, 230 �C interface temperature with full scan).

3. Results and discussion

Biomarker distributions and bulk oil parameters were used toassess the genetic relationship between hydrocarbon generationand their source rock depositional environments. Based on bulkgeochemical properties and fingerprints (GC and GCeMS), theinvestigated oils were classified into two genetic families. A

Figure 1. Location map of the fields in the Marib-Shab

description of the geochemical characteristics of the oil familiesfollows.

3.1. Non-biomarker characteristics

3.1.1. Bulk properties of crude oilsThe bulk crude oil properties and compositions for the studied

oils are presented in Table 1. The crude oils from the Alif Field have avariety of API gravity values in the range of 15.0e58.7� (Table 1).Low API gravity is generally associated with either biodegraded oilsor with immature sulfur-rich oils (Baskin and Peters, 1992).

Biodegradation may occur in an oil reservoir, and the processdramatically affects the fluid properties of the hydrocarbons (e.g.,Miiller et al., 1987). The early stages of oil biodegradation arecharacterized by the loss of n-alkanes or normal alkanes followedby loss of acyclic isoprenoids (e.g., pristane and phytane).Compared with those compound groups, other compound classes(e.g., highly branched and cyclic saturated hydrocarbons as well asaromatic compounds) are more resistant to biodegradation (Larteret al., 2005). In this respect, the analyzed oil samples contain acomplete suite of n-alkanes in the low-molecular weight regionand acyclic isoprenoids (e.g., pristane and phytane; Fig. 3). There-fore, there is no sign of biodegradation among the oil samples. Thisis also indicated by the oil samples generally containing moresaturated hydrocarbons than aromatic hydrocarbons with saturate/aromatic hydrocarbons ratios >1 (Table 1). On the other hand, therelationship between API gravity and sulfur content reflects thatthe low API gravity is associated with sulfur-rich oils (Fig. 4). Awiderange of bulk property values of the crude oils analyzed indicatesthat two oil families are represented (Table 1). Family I representfour crude oils, which have low API gravities, corresponding to highsulfur content of 3.03e6.00 wt% (Fig. 4), suggesting that these oilswere generated from clay-poor marine source rocks depositedunder highly reducing conditions (Gransch and Posthuma, 1973;Moldowan et al., 1985). In contrast, family II represents six crude oil

owah Basin including Alif Field and studied wells.

Figure 2. Regional stratigraphic nomenclature in the Marib-Shabowah Basin, Republic of Yemen.

Table 1Bulk organic geochemical properties of crude oil samples from Alif Field, Marib-Shabowah Basin.

Wells Crudeoils

Oilfamily

Depths(ft)

Reservoir rocks Chemical properties Metals Hydrocarbons Non-hydrocarbons Saturate/aromatic

WaxinessdegreeS(n-C21en-C31)/S(n-C15en-C20)

API gravity(�)

Sulfur(wt%)

Ni(ppm)

V(ppm)

V þ Ni(ppm)

Saturate Aromatic Resins þ asphaltenes

Alif-9 SFCU-2 I 4367 Safer-sandstone 14.0 3.03 3.80 36.3 40.1 33.4 24.1 42.5 1.39 0.55SFCU-3 I 5893 Safer-sandstone 19.4 5.86 5.50 20.8 26.3 28.7 12.0 59.3 2.39 0.54

Alif-16 SFCU-4 I 4193 Safer-sandstone 15.0 6.00 6.10 42.5 48.6 33.5 21.3 45.2 1.57 0.30Alif-2 SFCU-1 I 5370 Safer-sandstone 16.3 5.90 4.20 39.0 43.2 33.0 20.8 46.2 1.59 0.53

SECU-1 II 6390 Seen-sandstone 39.2 1.13 0.13 1.16 1.29 47.3 11.4 41.3 4.15 1.13SECU-2 II 6540 Seen-sandstone 39.0 0.11 0.14 1.38 1.52 41.5 15.8 42.7 2.63 0.98

Alif-1 AFCU-1 II 5270 Alif-sandstone 58.7 0.17 0.17 1.10 1.27 57.8 14.5 27.7 3.99 0.64AFCU-2 II 5700 Alif-sandstone 40.1 0.31 0.11 0.44 0.55 68.3 23.9 7.8 2.86 0.67MECU-1 II 8080 Meem-sandstone 35.8 0.17 0.11 1.60 1.71 34.0 27.9 38.1 1.27 0.82MECU-2 II 8510 Meem-sandstone 38.8 0.80 0.14 1.05 1.19 35.6 30.5 33.9 1.17 0.95

Figure 3. Gas chromatography traces of whole crude oil for representative two oilfamilies in this study.

Figure 4. Plot of the API gravity versus the sulfur content (wt%) for crude oils fromvarious reservoir rocks in the Alif Field, Marib-Shabowah Basin.

Figure 5. Relationship between sulfur content (wt%) and degree of the waxiness forthe investigated crude oils in the Alif Field, Marib-Shabowah Basin.

Figure 6. Relationship between total concentration of (V þ Ni) and degree of waxinessS(n-C21en-C31)/S(n-C15en-C20) for investigated crude oils from Alif Field, Marib-Shabowah Basin.

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samples, which exhibit medium to high oil API gravities between35.8� and 58.7�. These oils have a variety of sulfur contents, rangingfrom 0.11 to 1.13 wt% (Fig. 4), suggesting they have been generatedfrom clay-rich source rocks (Hedberg, 1968; Gransch andPosthuma, 1973; Moldowan et al., 1985).

The degree of waxiness S(n-C21en-C31)/S(n-C15en-C20) is usedto categorize the amount of land derived organic material in oil,assuming that terrigenous material contributes a high molecularweight normal paraffin component to the oil (Connan and Cassou,1980; Johns, 1986). The calculated ratio of S(n-C21en-C31)/S(n-C15en-C20) generally indicates a low degree of waxiness <1 (Table 1),suggesting that these oils have been derived from algal and/orbacterial organic matter (Brooks et al., 1969; Tissot and Welte,

1984). The correlation between the degree of waxiness and sulfurcontent also reflects two different oil families (Fig. 5). The family Ioil samples have low waxiness values (<0.6) and high sulfur con-tent (>3 wt. %) suggesting that they have been derived frommainly

Figure 7. Gas chromatography traces of saturated hydrocarbons for representative oil samples in this study, showing two oil families.

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Table 2Selected biomarker parameters of the crude oil samples illustrating source and maturity differences between the two oil families.

Crudeoils

Oilfamily

n-alkane and isoprenoids Triterpanes and terpanes (m/z191) Steranes and diasteranes (m/z217)

Pr/Ph Pr/C17 Ph/C18 CPI C32 22S/(22S þ 22R)

C29/C30 Ts/Tm MC30/HC30 H index G/C30 C29 20S/(20S þ 20R)

C29 bb/(bb þ aa)

C29/C27 Regular steranes (%) Diasterane/sterane

C27 C28 C29

SFCU-2 I 0.42 0.43 1.47 0.91 0.59 0.63 0.29 0.06 0.12 1.13 0.35 0.35 0.26 71 11 18 0.31SFCU-3 I 0.50 0.71 2.68 0.94 0.58 0.23 0.30 0.10 0.17 0.99 0.43 0.39 0.67 51 16 33 0.40SFCU-4 I 0.27 0.23 1.10 0.74 0.60 0.70 0.18 0.07 0.22 1.05 0.42 0.42 0.44 61 12 27 0.44SFCU-1 I 0.30 0.82 3.24 0.81 0.56 0.44 0.50 0.16 0.16 0.23 0.43 0.38 0.84 50 14 36 0.23SECU-1 II 1.09 0.64 0.66 1.06 0.56 0.68 0.91 0.20 0.08 e 0.50 0.54 0.92 43 16 41 1.09SECU-2 II 1.53 0.63 0.46 1.06 0.62 0.43 2.00 0.11 0.05 e 0.50 0.41 0.79 45 18 36 0.69AFCU-1 II 1.24 0.52 0.43 0.99 0.63 0.62 1.06 0.11 0.06 e 0.51 0.45 0.88 37 21 41 0.68AFCU-2 II 1.52 0.59 0.44 1.02 0.59 0.36 1.50 0.10 0.07 e 0.48 0.38 1.14 42 22 37 0.54MECU-1 II 1.59 0.40 0.29 1.07 0.63 0.30 4.00 0.10 0.06 e 0.52 0.55 1.00 40 20 40 0.71MECU-2 II 1.36 0.40 0.28 1.04 0.62 0.46 5.00 0.12 0.08 e 0.51 0.55 1.06 38 22 40 0.77

Pr: pristane.Ph: phytane.CPI: carbon preference index (2[C23 þ C25 þ C27 þ C29]/[C22 þ 2{C24 þ C26 þ C28}þC30]).Ts: (C27 18a(H)-22,29,30-trisnorneohopane).Tm: (C27 17a(H)-22,29,30-trisnorhopane).C29/C30: C29 norhopane/C30 hopane.MC30/HC30: C30 moretane/C30 hopane.H Index: (C35/(C31 � C35)) homohopane.G/C30: Gammacerane/C30 hopane.

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marine algal origin. On the other hand, family II oils have a rela-tively high waxiness values (>0.6) and low sulfur content, sug-gesting a relatively higher marine algal organic matter and lowerterrigenous organic matter contribution.

3.1.2. Nickel and vanadium contentsNickel and vanadium can be successfully used to distinguish

between oils from different geographical areas (Hedberg, 1968).The concentrations of the V and Ni can be also used to classify andcorrelate petroleum. In general, oils from marine carbonates orsiliciclastics show low wax content, moderate to high sulfur andhigh concentrations of Ni and V elements (Barwise, 1990), whereasland plant-derived oils contain high wax, low sulfur, and very lowmetal contents (Wenger et al., 2002). The investigated oils have awide range of Ni and V content values, ranging from 0.44 to42.5 ppm and 0.11 to 6.10 ppm, respectively. These values withsulfur content and degree of waxiness S(n-C21en-C31)/S(n-C15en-C20) values (Table 1) indicate a marine or perhaps slightly restrictedmarine environment.

The correlation of the total concentration of (V þ Ni) vs. degreeof waxiness S(n-C21en-C31)/S(n-C15en-C20) are shown in Figure 6.The results indicate that trace metals are sensitive to changes in the

Figure 8. Phytane to n-C18 alkane (Ph/n-C18) versus pristane to n-C17 alkane (Pr/n-C17).

source input and reflects two different oil families. However, thelatter figure shows that the family II oils considered to be derivedfrom source rock contain a higher terrigenous organic mattercontribution compared to family I oil samples.

3.2. Biomarker characteristics

3.2.1. Normal alkanes and isoprenoidsThe gas chromatograms of saturated hydrocarbon fractions from

representative oil samples are shown in Figure 7 and derived pa-rameters are listed in Table 2. The saturated gas chromatograms ofthe oil samples display a full suite of saturated hydrocarbons be-tween C13eC35 n-alkanes and isoprenoids pristane (Pr) and phytane(Ph) (Fig. 7). The differences in the distribution patterns of n-al-kanes and acyclic isoprenoids suggest that the investigated oils arederived from two different sources.

The n-alkane distribution of family I oils shows a predominanceof low to medium molecular weight compounds (n-C14en-C20),suggesting a significant contribution of algal derived organic

Figure 9. Cross plot of dibenzothiophene/phenanthrene (DBT/Phe) versus pristane/phytane (Pr/Ph) ratios provides a powerful way to infer crude oil source rock depo-sitional environments and lithologies (Hughes et al., 1995).

Figure 10. The distributions of triterpanes m/z 191 mass fragmentograms of saturated hydrocarbons representative of the two oil families in the Alif Field, Marib-Shabowah Basin,showing two oil families.

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matter from amarine environment, whereas family II oils also showa predominance of low to medium molecular weight compounds(n-C14en-C20) with the presence of significant waxy alkanes (þn-C23) thus gave moderate CPI values (Table 2), suggesting a highercontribution of marine organic matter with minor terrigenousorganic matter contribution (Brooks et al., 1969; Powell andMcKirdy, 1973; Tissot et al., 1978; Ebukanson and Kinghorn, 1986;Murray and Boreham, 1992).

Acyclic isoprenoids occur in a significant amount in all studiedoil samples (Fig. 7) and diagnostic biomarker ratios are listed inTable 2. The phytane being the most dominant peak in the satu-rated gas chromatograms of the family I oil samples studied (Fig. 7);phytane concentration is always higher than n-C18, thus givingdistinctively high phytane/n-C18 ratios of 3.24e1.10. Comparativelylower values for these ratios (0.29e0.66) were displayed by familyII oil samples, which generally possess relatively, lower amounts of

acyclic isoprenoids (compared to n-alkanes) than the family I oilsamples (Fig. 8). The pristane/phytane (Pr/Ph) ratio is also one ofthe most commonly used geochemical parameters and has beenwidely invoked as an indicator of the redox conditions in thedepositional environment and source of organic matter (Didyket al., 1978; Powell, 1988; Chandra et al., 1994; Large and Gize,1996). Organic matter originating predominantly from land plantswould be expected to contain high Pr/Ph > 3.0 (oxidizing condi-tions), low values of (Pr/Ph) ratio (<1.0) indicate anoxic conditionsand values between 1.0 and 3.0 suggest intermediate conditions(sub-oxic conditions) (Philp, 1985; Amane and Hideki, 1997). ThePr/Ph ratios of the investigated oil samples range from 0.27 to 1.59(Table 2), suggesting two oil types and derived from differentsource rocks. The family I oils have Pr/Ph ratio values <1.0, whereasfamily II oils have moderately Pr/Ph ratios in the range of 1.09e1.59.The Pr/Ph ratios indicate that the family I oils considered to be

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derived from source rocks containing mainly marine algal-derivedorganic matter which was deposited in a more reducing environ-ment compared to family II oil samples (sub-oxic). This is consistentwith the observed of high phytane/n-C18 ratios of family I oilsamples compared to family II oil samples (Fig. 8). Furthermore, theratios of dibenzothiophene/phenanthrene and pristane/phytanecan be also used to infer crude oil source rock depositional envi-ronments and lithologies (Hughes et al., 1995). The cross plot ofdibenzothiophene/phenanthrene versus pristane/phytane in-dicates that Alif oils have been derived from two different sourcerock (Fig. 9). The family I oils were derived from marine carbonateand marl sediments whereas the family II oils were derived frommarine shales (Fig. 9).

3.2.2. TriterpanesThe distributions of terpanes are commonly studied using GCe

MS bymonitoring the ionsm/z 191 (Brooks et al., 1969; Peters et al.,2005) as a legend to Figure 10. For peak assignments see Table A1 inAppendix 1. Individual components were identified by comparisonof their retention times and mass spectra with published literature(Philp, 1985; Peters and Moldowan, 1993).

The differences in the distribution patterns of m/z 191 massfragmentograms suggest that the investigated oils are classifiedinto two oil families (Fig. 10). The m/z 191 mass fragmentograms ofthe saturated hydrocarbon fractions of all the oil samples analyzedshow high proportions of hopanes relative to tricyclic terpanes asshown in Figure 10. The relative abundance of C29 norhopane isgenerally half or less than that of C30 hopane in most of the studiedsamples (Fig. 10), with C29/C30 17a (H) hopane ratios in the range of0.23e0.70 (Table 2). The predominance of C30 hopane is frequentlyassociated with clay-rich source rocks (Gürgey, 1999).

The investigated oils possess a wide range of Ts/Tm ratiovalues and ranging from 0.18 to 5.00 (Table 2). Values of Tm (C2717a(H)-22,29,30-trisnorhopane) and Ts (C27 18a(H)-22,29,30-trisnorneohopane) are well known to be influenced by matura-tion, type of organic matter, and lithology (Moldowan et al., 1985).In the present study, the main difference is controlled by organicfacies and lithology, with a maturation overprint within each oilfamily. Furthermore, the ratio of diasterane/sterane is plottedagainst Ts/Tm ratio, suggesting that family I oils have been associ-ated with more carbonate lithology compared to family II oilsamples (Fig. 11) as indicated by dibenzothiophene/phenanthreneand pristane/phytane ratios (Fig. 9). Extended hopanes are

Figure 11. Relationship between Ts/Tm ratio and Diasterane/sterane ratio for theinvestigated crude oils in the Alif Field, Marib-Shabowah Basin.

dominated by the C31 homohopane and generally decreasing to-ward the C35 homohopane (Fig. 10). The ab hopanes are moreprominent than the ba hopanes while the S isomers are moredominant than the R isomers among the homohopane (C31eC35).The distribution of the extended hopanes or homohopanes (C31e

C35) has been used to evaluate redox conditions based on homo-hopanes index (Peters et al., 2005). This, in turn, suggests that thefamily I oils were derived from source rock deposited in a morereducing environment than the family II oil samples source rock. Insupport, relatively higher homohopanes index were obtained forfamily I oils compared to the family II oil samples (Table 2). HighC35/C34 hopanes ratios have been reported in highly reducing ma-rine oils (Moldowan et al., 1985; Peters and Moldowan, 1991). Thisis consistent with the observed of high C35/C34 hopanes ratios offamily I oil samples (Fig. 10).

In addition, gammacerane has been recorded in family I oilsamples (Fig. 10), is a strong indicator of high-salinity conditionsand water column stratification during deposition of the sourcerocks (Moldowan et al., 1985; ten Haven et al., 1989; Sinninghe-Damsté et al., 1995; Peters et al., 2005). The occurrence of gam-macerane in the family I oils is also consistent with Safer shalesassociation with interbedded evaporites (refer to stratigraphicsection in Fig. 2) (Rohrback, 1981; Mello et al., 1988).

3.2.3. SteranesThe distributions of diasteranes and the steranes (C27, C28 and

C29) are characterized by them/z 217 ion chromatograms (Fig. 12).Peaks labels are listed on Table A1 in Appendix 1 and the derivedparameters are listed in Table 2. The relative amounts of C27eC29steranes can be used to give indication of source differences(Seifert and Moldowan, 1979). The relative distribution of C27, C28and C29 steranes is graphically represented in the form shown fora regular steranes in a ternary diagram (Fig. 13, Huang andMeinschein, 1979). The original classification of Huang andMeinschein (1979) related C27 steranes to strong algal influenceand C29 steranes to strong higher plant influence. The differencesin the distribution of regular steranes (C27eC29) suggest that theoils are derived from different types of organic matter (Fig. 13).The family I oil samples display a strong predominance of C27steranes (Table 2), which suggest a dominance of marine algalorganic matter (Fig. 11), while the family II oils that composed ofC27eC29 steranes which is an indicator of the mixed marine/terrigenous origin for the oil as indicated by Pr/n-C17 and Ph/n-C18ratios (Fig. 8). This is consistent with the observed of low C29/C27sterane ratios of family I oil samples compared to family II oilsamples (Table 2).

The diasterane/regular sterane ratios and two different steranethermal maturity parameters, C29 20S/(20S þ 20R) and the C29 abb/(abb þ aaa), are calculated and listed in Table 2. The higher dia-sterane/sterane ratios in the family II oil samples compared tofamily I oil samples correspond to the higher clay contents in theformer (Gürgey, 1999).

3.3. Maturity of crude oils

The components in oil, NSO compounds, asphaltenes andsaturated and aromatic hydrocarbons undergo increased crackingduring thermal maturation. A variety of oil characteristics has beenused to evaluate the level of thermal maturity of the investigatedoils; these include biomarker and non-biomarker parameters. Thebiomarker and non-biomarker parameters are listed in Tables 1 and2, and are discussed in more detail below. In gas chromatographyemass spectrometry (GCeMS), biomarker maturation parameterssuch as C32 22S/(22S þ 22R) homohopane, moretane/hopane and20S/(20S þ 20R) and bb/(bb þ aa) C29 sterane ratios, was used as

Figure 12. The distributions of steranes m/z 217 mass fragmentograms of saturated hydrocarbons for representative two oil families in the Alif Field, Marib-Shabowah Basin.

M.H. Hakimi, W.H. Abdullah / Marine and Petroleum Geology 45 (2013) 304e314312

maturity indicators (Mackenzie et al., 1980; Waples and Machihara,1991). The ratios of 22 S/(22R þ 22S) for C32 17a (H), 21b (H)-hopanes are between 0.56 and 0.63 (Table 2) suggesting that theyhave reached equilibrium. The 20S/(20S þ 20R) and bb/(bb þ aa)C29 sterane ratios of the oils are between 0.35 and 0.52, and 0.35e0.55, respectively (Table 2). These biomarker maturation parame-ters are indicating that the oils are expelled from source rocks thatwere exposed to thermal maturity level equivalent to the early topeak oil window stage of petroleum generation. The correlationbetween two biomarker maturity parameters is shown in Figure 14(Peters and Moldowan, 1993). This correlation reflects that thefamily I oils are early mature, whereas the family II oils are earlymature to peak oil window (Fig. 14). The relationship betweenisoprenoids Pr/n-C17 and Ph/n-C18 ratios (Fig. 8) reflects the same

interpretation as do the moretane/hopane ratios (Waples andMachihara, 1991).

Non-biomarker parameters such as API gravity, sulfur and metalcontents have alsobeenused to evaluate the level of thermalmaturityof the investigatedoils (El-Gayaret al., 2002). The concentrationsofNiand V varied strongly with the maturity of oils and high maturitycrude oils contained only small amounts of Ni and V elements(Barwise, 1990). This is consistent the observed of low Ni and Vcontent of family II oil samples compared to family I oil samples(Table 1). The correlation between API gravity and sulfur content(Fig. 4), and between sulfur content and concentrations of (V þ Ni)values (Table 1) are indicated that the levels of metals and sulfur incrude oil decrease with increasing maturity, whereas the API gravityincrease. This is consistent with previous biomarker observations.

Figure 13. Ternary diagram of regular steranes (C27eC29) showing the relationshipbetween sterane compositions, source input, and depositional environment for theanalyzed crude oils (modified after Huang and Meinschein, 1979).

Figure 14. Cross plot of two biomarker parameters sensitive to thermal maturity of thestudied oil samples (modified after Peters and Moldowan, 1993).

Table A1Peak assignments for alkane hydrocarbons in the gas chromatograms of aliphaticfractions in the m/z 191 (I) and 217 (II) mass fragmentograms compoundabbreviation.

(I) Peak no.Ts 18a(H),22,29,30-trisnorneohopane TsTm 17a(H),22,29,30-trisnorhopane Tm29 17a,21b(H)-nor-hopane C29 hop30 17a,21b(H)-hopane Hopane3M 17 b,21a (H)-Moretane C30Mor31S 17a,21b(H)-homohopane (22S) C31(22S)31R 17a,21b(H)-homohopane (22R) C31(22R)32S 17a,21b(H)-homohopane (22S) C32(22S)32R 17a,21b(H)-homohopane (22R) C32(22R)33S 17a,21b(H)-homohopane (22S) C33(22S)33R 17a,21b(H)-homohopane (22R) C33(22R)34S 17a,21b(H)-homohopane (22S) C34(22S)34R 17a,21b(H)-homohopane (22R) C34(22R)35S 17a,21b(H)-homohopane (22S) C35(22S)35R 17a,21b(H)-homohopane (22R) C35(22R)(II) Peak no.a 13b,17a(H)-diasteranes 20S Diasteranesb 13b,17a(H)-diasteranes 20R Diasteranesc 13a,17b(H)-diasteranes 20S Diasteranesd 13a,17b(H)-diasteranes 20R Diasteranese 5a,14a(H), 17a(H)-steranes 20S aaa20Sf 5a,14b(H), 17b(H)-steranes 20R abb20Rg 5a,14b(H), 17b(H)-steranes 20S abb20Sh 5a,14a(H), 17a(H)-steranes 20R aaa20R

M.H. Hakimi, W.H. Abdullah / Marine and Petroleum Geology 45 (2013) 304e314 313

4. Conclusions

Geochemical characterization based upon biomarker compo-nents coupled with the bulk geochemical parameters was used toarrive at a clear characterization and classification of the Marib-Shabowah Basin crude oils. The fingerprints have been derivedfrom the acyclic isoprenoids, triterpane and sterane biomarkers.Two oil families are observed and represented in the suite ofinvestigated oil samples according to their sources.

Family I oils are characterized by low API gravity, high sulfurand metal contents and low Pr/Ph ratios (<1.0) indicating astrongly reducing marine conditions. This is supported by highC35 homohopane index and C35/C34 hopane. These oils werederived from marine alga inputs, consistent which thus display astrong predominance of C27 regular steranes and supported bylow C29/C27 sterane ratio. The presence of gammacerane in theseoils is a very good indicator of high-salinity conditions and watercolumn stratification during deposition of the source rocks.Previous work by Hakimi and Abdullah (2013) on the Safer shales

in the basin shows similar characteristics to these oils, suggestingthat the family I oils are derived the interbedded Safer calcareousshales.

Family II oils have medium to high API gravity and low sulfurand metal contents. Oils from the family II display relatively highPr/Ph ratios (1.09e1.59), relatively low C35 homohopane index andhigh diasteranes relative steranes, indicating a marine clay sourcerock deposited in sub-oxic conditions. These oils type arecomposed of C27eC29 regular steranes suggest that these oils weregenerated from source facies contain a mixture of marine withland plant organic matter deposited in a marine or perhapsslightly restricted marine environment. This is consistent theobserved of low trace metal (Ni, V) content and relatively highwaxiness values. The characteristics of these oils are consistentwith their sourcing from the Madbi shales as described by Hakimiet al. (2010).

On the basis of the biomarker maturity and non-biomarkerparameters, the investigated oils in the Alif Field are thermallymature and ranging from early mature to peak oil window. Thefamily II oil samples were generated from source rocks with awide range of thermal maturity and have entered early mature topeak oil windowwhereas the family I oil samples are early matureoils.

Acknowledgments

The authors thank the Petroleum Exploration and ProductionAuthority (PEPA) and Safer Oil Company, Yemen for supplying thedata and samples for this study. The authors are more grateful tothe Department of Geology, University Malaya for providing facil-ities to complete this research. Special thanks are offered to Dr.Lloyd R. Snowdon for his helpful comments and corrections on anearlier version of the manuscript.

Appendix 1

M.H. Hakimi, W.H. Abdullah / Marine and Petroleum Geology 45 (2013) 304e314314

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