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Origin of Bahariya oil in Salam oil field, Western Desert- Egypt
Egyptian Journal of Petroleum xxx (2017) xxx–xxx
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Origin of Bahariya oil in Salam oil field, Western Desert- Egypt E.A. Abd El-Gawad a, D.A. Mousa b,⇑, M.A. Lotfy b, A.I. El-Shorbagy a a b
Al-Azhar University, Faculty of Science-Geology Department, 1 Al Mukhayam Al Ddayim St., Nasr City, Cairo 11884, Egypt Egyptian Petroleum Research Institute, Exploration Department, 1 Ahmed El-Zomor Street, El- Zohour Region, Nasr City, Cairo 11727, Egypt
a r t i c l e
i n f o
Article history: Received 27 July 2017 Revised 13 September 2017 Accepted 19 September 2017 Available online xxxx Keywords: Rock Eval -6 Kerogen type Geochemical analysis GC and GC/MS analysis
a b s t r a c t The origin of Bahariya oil is a debatable issue. Bahariya Formation produces oil from the Lower sandstone unit by normal pressure mechanism, while the Upper Bahariya shale produces oil by fracking mechanism. The main question is: is there any genetic relationship between the two oils. To answer this question, ‘‘50” ditch samples, ‘‘12” extract samples and ‘‘2” oil samples represent Khatatba and Bahariya formations and Abu Roash ‘G’ Member, collected from six wells drilled in Salam oil field, have been geochemicaly analyzed, using LECO SC632, Rock–Eval- 6 pyrolysis, GC and GC/MS techniques.The analysis shows that the Total Organic Carbon content (TOC) for the studied formations ranges from fair to v.good, with poor to good hydrocarbon potentiality. The maturity evaluation using Tmax, and calculated Vitrinite reflectance (Ro) showed that the studied samples have good thermal maturation reaching the stage of oil generation. Also the analysis revealed that the kerogen is a mixture of type II/III kerogen, reflecting the potential generation of oil and gas. The GC and GC/MS data showed that the organic matter is a mixed marine/terrestrial input deposited in transitional environment under prevailing reducing conditions. The oil samples fingerprint of the saturated hydrocarbons fraction from Baharyia reservoir (Lower and Upper) members suggest that the oil samples have a mixed organic source with significant terrestrial organic matter input deposited under saline to hypersaline environment with slightly oxidizing environment. Based on the obtained results, it is suggested that the Bahariya oil has been sourced mainly from deeper horizons (Khatatba Formation) with some contribution from upper and lower Bahariya source rocks. Ó 2017 Egyptian Petroleum Research Institute. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
1. Introduction The Western Desert comprises the area west of the Nile River and Delta. It extends from the Mediterranean Sea in the north to the Egyptian Sudanese borders in the south and from the Nile valley in the east to the Egyptian Libyan borders in the west. Many significant productive oil and gas fields have been discovered especially in North Western Desert e.g. Abu Gharadig, Abu Sennan, Badr El Din, Razzak, Alamein, Khalda, Safir, Meleiha, Um Barka, Aghar, Kanayis, Horns, WD-19, Aman, Dorra, Emry, Falak, Karnak, Lotus, Sitra, Hayat, Kahrman, Khalda, Salam, Tut, Yasser, Gpt, Gpy, Yidma, Ahram and Qarun -1 [1]. The study area lies between latitudes 30° 400 4700 – 30° 420 5000 N and longitudes 26° 570 3900 - 27° 000 5600 E. The six examined wells
Peer review under responsibility of Egyptian Petroleum Research Institute. ⇑ Corresponding author. E-mail addresses: [email protected] (E.A. Abd El-Gawad), doaa2_ali@ hotmail.com (D.A. Mousa), [email protected] (M.A. Lotfy), aliismail_m@ yahoo.com (A.I. El-Shorbagy).
(Salam 02- Salam-3X- Salam 52- Salam 05- Salam 35- Salam 16) were distributed evenly within the study area (Fig. 1). Salam-3x was first discovery by Khalda Petroleum Company. From this well, a significant quantity of oil and gas are produced from (Khatatba Formation) and Cretaceous (Alam El Bueib and Bahariya formations). The stratigraphic column of the North Western Desert is thick and includes most of the sedimentary succession from PreCambrian basement complex to recent formations (Fig. 2). The total thickness, despite some anomalies, increases progressively to the north and northeast from about 6000 ft in the southern region to reach about 25,000 ft along the coastal area [2].The lithology of the studied formations are descripted in the following paragraph: The Khatatba Formation consists mainly of bituminous shales, siltstones and sandstones commonly with carbonaceous debris in the lower part. The upper part of the Khatatba Formation contains more carbonate beds, Bahariya Formation consists of glauconitic and pyritic sandstone interbeded with shales, siltstones and carbonates, while Abu Roash ‘‘G” Member consists mainly of carbonates with shale and dolomite interbeds [2].
https://doi.org/10.1016/j.ejpe.2017.09.003 1110-0621/Ó 2017 Egyptian Petroleum Research Institute. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
Please cite this article in press as: E.A. Abd El-Gawad et al., Origin of Bahariya oil in Salam oil field, Western Desert- Egypt, Egypt. J. Petrol. (2017), https:// doi.org/10.1016/j.ejpe.2017.09.003
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E.A. Abd El-Gawad et al. / Egyptian Journal of Petroleum xxx (2017) xxx–xxx
2.4. Based on the screening data, selected samples are subjected to extraction using soxhlet apparatus with chloroform solvent in order to separate bitumen from rock samples. The followed method of bitumen extraction and analysis as described in [4]. Bitumen is extracted by pulverizing the rock ( 10 gm) and then soaking the pulverized rock for 12–36 h in an organic solvent (chloroform). The solvent is removed from the extracted bitumen by evaporation (this method of removal results in the loss of the lighter hydrocarbons, which have similar evaporation rate as the solvent). In practice, only hydrocarbons heavier than carbon number C15+ are retained for further analysis. The extracted bitumen is expressed as weight percent to the whole rock sample. Removal of elementary sulfur from extracted bitumen was performed by mercury. Asphaltene was separated from the extracted bitumen using n-hexane. The precipitated asphaltenes were then filtered off and expressed as weight percent of the whole extracted bitumen.
Fig. 1. Location map of the study area.
The main objectives of this study is to predict the source of the hydrocarbons generated from the Bahariya Formation in Salam oil field. For these purposes fifty (50) cutting samples of argillaceous dark-gray shales and limestones representing the Jurassic and Cretaceous rock units (Khatatba and Bahariya formations and Abu Roash ‘‘G” Member) were analysied. Twelve ‘‘12” extract samples and two (2) oil samples representing the same formations were analysed using Gas chromatoghraphy and Gas chromatoghraphy – Mass Spectrometry techniques. 2. Materials and methods Fifty (50) cutting samples of argillaceous dark-gray shales and limestones representing the Jurassic and Cretaceous rock units (Khatatba and Bahariya formations and Abu Roash ‘‘G” Member.) were analysed by LECO SC632 to determine the Total Organic Carbon (TOC) wt%, as well as by Rock-Eval 6 instrument for pyrolysis analysis. Twelve (12) extract samples and two oil samples representing the same formations were analysed by Gas Chromatography after fractionation. A brief explanation for the used techniques is given below: 2.1. Total organic carbon (TOC, wt%) and Rock-Eval pyrolysis followed standard methods, the samples were cleaned and crushed and 200 mesh samples were selected for geochemical analysis. 2.2. About 200 mg of sample was placed in a crucible with 5% HCl at 80 °C to remove carbonates. The total organic carbon content (TOC) was measured using a Leco SC-632 instrument. Samples with TOC content exceeding 0.5 wt% were selected to screening analysis using Rock-Eval-6 instrument [3]. 2.3. Rock-Eval pyrolysis was performed on pulverized whole rock samples, about (60 mg) of the sample were analysed using a Vinci Rock-Eval 6 pyro-analyzer in the bulk rock mode. The parameters of the rock Eval pyrolysis represents free hydrocarbons S1 (mg HC/g rock), residual petroleum potential S2 (mg HC/g rock), and S3 (CO2 results from pyrolysis of organic matter). The previous parameters are used in the present work to determine Hydrogen Index (HI mg HC/g TOC) and Oxygen Index (OI mg CO2/g TOC), To obtain the kerogen type of the study samples.
2.5. The saturated hydrocarbons fractions of rock extracts were subjected to gas chromatography and advanced Techniques GC–MS for Biomarker determination for ions (M/Z 191) and (M/Z 217). These analyses were Kindly done in the laboratories of the Egyptian Petroleum Research Institute [EPRI], completed with a report for one sample from Strato Chem Services Lab. (SCS). 3. Results and discussion Screening analysis including Total Organic Carbon (TOC) and Rock-Eval pyrolysis data for ‘‘16” ditch samples representing Khatatba Formation, ‘‘ 24” rock samples representing Upper and Lower Bahariya Formation and ”10” rock samples representing Abu Roash ‘‘G” Member was carried out. The analysis data and plots of data are represented in (Table 1) and (Figs. 3–6). 3.1. Organic richness and hydrocarbon potentiality The organic carbon richness of the rock samples, as expressed by weight percent of total organic carbon content (TOC wt%) [5]. Peters and Cassa [6] reported that rocks containing less than 0.5% TOC are considered as poor source rocks, between 0.5% and 1% TOC indicates fair source rock TOC% value between 1% and 2% indicates good source rocks whereas:-. TOC% values above 2% often indicate highly reducing environment with excellent source potential. The hydrocarbon potentiality S1 from 0 to 0.5 mg/g represents poor hydrocarbon potentiality, from 0.5 to 1 mg/g consider fair, from 1 to 2 mg/g good, 2–4 mg/g very good and more than 4 mg/ g is excellent [5] and [6]. The studied samples of Khatatba Formation, shows TOC ranges from 1.35 to 5.1 (Table 1) which indicates good to very good organic richness (Fig. 3a). The pyrolysis-derived S1 and S2 values of Khatatba Formation are 0.43–1.59 and 2.06 to 9.59 respectively (Table 1) indicating poor to good hydrocarbon potentiality S2 (Fig. 3B and C). Bahariya Formation has TOC ranges from 0.81 to 3.27%. (Table 1) revealing the organic richness of this formation varies from fair to very good (Fig. 3a). The Values of S1 and S2 range from 0.11 to 9.37 mg/g, 0.24 to 6.22 mg/g respectively (Table 1) (Fig. 3B and C) indicating poor to good generating source potential. Abu Roash ‘‘G” Member has TOC values ranging from 0.77 to 2.63% (Table 1) revealing the organic richness of this formation
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Fig. 2. Stratigraphic column of the Western Desert. (Khalda Petroleum Company, 2005).
varies from fair to very good (Fig. 3a). The pyrolysis-derived S1 and S2 value of Abu Roash ‘‘G” Member range from 0.11 to 6.58 mg/g and 1.03 to 8.04 mg/g, respectively (Table 1) (Fig. 3B and C) indicating poor to good generating source potential.
3.2. Kerogen type Waples [7] used the hydrogen index values (HI) to differentiate between the types of organic matter. Hydrogen indices below
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Table 1 Pyrolysis data of the study samples. Formation
Well
Depth
TOC
S1
S2
S3
Tmax
HI
OI
PI
Cal. Ro
A/R G
SAL-02
5390 5660 5400 5650 5600 5700 5400 5700 5460 5560 6150 6450 6160 6220 6320 6000 6040 6150 6280 6380 6410 6800 5820 5860 5930 6070 6130 5920 5930 5960 6090 6100 6230 6260 11330 11390 11450 11480 11510 11540 11570 11600 11300 11310 11320 11340 11360 11370 11380 11400
0.84 0.77 0.8 1.16 1.41 1.69 1.77 2.03 2.63 2.63 0.97 0.85 0.81 0.94 0.88 1.62 1.28 1.25 1.30 1.97 1.52 1.16 1.76 2.01 1.86 2.14 1.56 1.85 1.72 1.37 1.26 1.31 3.27 1.52 1.85 1.65 2.55 2.2 3.06 1.59 2.98 1.35 4.27 1.5 2.95 5.1 1.62 1.79 2.05 2.1
0.12 0.11 0.43 0.6 2.23 1.93 5.33 6.58 6.02 4.23 0.13 0.11 0.79 0.93 0.91 1.75 1.80 1.98 0.19 2.47 2.33 1.9 7.13 9.37 7.8 7.70 6.17 5.18 6.12 4.25 3.65 3.53 6.08 3.8 0.7 0.58 0.75 0.7 1.11 0.53 0.85 0.66 0.97 0.43 0.97 1.59 0.47 0.61 0.65 0.46
2.44 1.03 2.09 1.93 4.23 5.64 5.62 4.95 8.04 3.77 0.93 1.25 1.32 1.52 1.27 3.53 2.57 2.57 0.24 2.78 2.39 1.77 4.11 2.27 4.65 4.68 3.43 4.56 4.11 2.99 2.52 2.66 6.22 3.1 2.62 2.26 4.86 3.84 7.71 2.4 7 2.55 9.05 2.06 5.21 9.59 2.19 2.88 2.99 3.05
1.23 1.07 0.97 0.82 1.31 2.36 1.54 0.8 3.65 2.86 0.8 0.89 0.95 1.22 1.64 1.09 0.03 0.47 0.06 1.38 1.54 0.57 0.08 1.18 1.66 0.12 0.78 3.44 2.67 2.19 1.98 2.65 3.25 2.9 0.98 0.99 0.9 0.93 0.91 0.75 1.05 0.86 0.69 0.67 0.63 0.5 0.75 1.57 0.91 1.3
433 436 433 438 432 433 434 437 437 397 440 436 435 435 429 431 430 433 433 430 427 431 433 436 435 431 432 440 399 438 435 435 438 435 452 454 444 449 444 448 444 442 447 448 445 447 448 445 447 441
290 133 261 166 300 334 318 244 306 143 95 147 163 162 144 218 201 205 18 141 157 152 234 113 250 219 220 246 239 218 200 203 190 204 142 137 191 175 252 151 235 189 212 137 177 188 135 161 146 145
146 138 121 70 93 140 87 39 139 109 82 104 117 130 186 67 2 38 5 70 101 49 5 59 89 6 50 186 155 160 157 202 99 191 53 60 35 42 30 47 35 64 16 45 21 10 46 88 44 62
0.05 0.1 0.17 0.24 0.35 0.26 0.49 0.57 0.43 0.53 0.12 0.08 0.37 0.38 0.42 0.33 0.41 0.43 0.44 0.47 0.49 0.52 0.63 0.64 0.63 0.62 0.64 0.53 0.6 0.59 0.59 0.57 0.49 0.55 0.21 0.2 0.13 0.15 0.13 0.18 0.11 0.21 0.1 0.17 0.16 0.14 0.18 0.17 0.18 0.13
0.63 0.69 0.63 0.72 0.62 0.63 0.65 0.71 0.71 -0.01 0.76 0.69 0.67 0.67 0.56 0.60 0.58 0.63 0.63 0.58 0.53 0.60 0.63 0.69 0.67 0.60 0.62 0.76 0.02 0.72 0.67 0.67 0.72 0.67 0.98 1.01 0.83 0.92 0.83 0.90 0.83 0.80 0.89 0.90 0.85 0.89 0.90 0.85 0.89 0.78
SAL-05 SAL-16 SAL-35 SAL-52 Bahariya
SAL-02 SAL-05
SAL-16
SAL-35
SAL-52
Khatatba
SAL-3X
N.B.: TOC: Total organic carbon(weight percent of the whole rock). S1: Free hydrocarbon (mg hydrocarbon/g rock). S2: Hydrocarbon potentiality (mg hydrocarbon/g rock). HI: Hydrogen index (mg hydrocarbon/g TOC). OI: Oxygen index (mg CO2/g TOC). Tmax: Temperature at which maximum emission of high temperature (S2) hydrocarbon occurs (deg.°C.). PI: Production index (S1/S1 + S2). (Calculated % VRo) = (0.0180) (Tmax) – 7.16 [7].
about 150 mg/g indicate a potential source for generating gas (mainly type III kerogen). Hydrogen indices between 150 and 300 mg/g contain more type III kerogen than type II and therefore are capable of generating mixed gas and oil but mainly gas .Kerogen with hydrogen indices above 300 mg/g contain a substantial amount of type II kerogen and thus are considered to have good source potential for generating oil and minor gas. Kerogen with hydrogen indices above 600 mg/g usually consists of nearly type I or type II kerogen, they have excellent potential to generate oil. The hydrogen index (HI) values of the Khatatba Formation ranges from 135 to 252 (mg/g) and oxygen index‘‘OI” ranges from
10 to 88 (mg/g) (Table 1) which suggest type II/III kerogen (Fig. 4). Bahariya Formation has hydrogen index (HI) range from 18 to 250 mg/g and oxygen index ‘‘OI” ranges from 2 to 202 mg/g (Table 1) which suggest type II/III kerogen. (Fig. 4). The hydrogen index (HI) values of the Abu Roash ‘‘G” Member range from 133 to 334 mg/g, and oxygen index ‘‘OI” range from 39 to 146 mg/g (Table 1) which indicate that the organic matter is classified as type II/III kerogen (mixed type) (Fig. 4). The plot of TOC vs. HI (Fig. 5) for the study samples reflect that the main expected generating hydrocarbons are fair oil with some gas [8].
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Fig. 3. Organic richness (A), hydrocarbon potentialities (B) and (C) Thermal maturity by Tmax (D) of the study samples.
3.3. Maturation In the present study, the thermal maturity level of the source rocks has been determined by the study of the geochemical parameters as Rock–Eval temperature pyrolysis ‘‘Tmax”, production index ‘‘PI” [3]. Peters and Cassa [6] and Bordenove et. al. [9] reported that oil generation from source rocks began at ‘‘Tmax” 435–465 °C, vitrinite reflectance ‘‘Ro%” between 0.5% and 1.35% and production index ‘‘PI” between 0.2 and 0.4, the organic matters are in immature stage when ‘‘Tmax” has a value less than 435 °C, ‘‘Ro%” less than 0.5 and ‘‘PI” less than 0.2 and the gas generation
from source rocks began at ‘‘Tmax” 470 °C, ‘‘Ro%” more than 1.35% and production index ‘‘PI” more than 0.4 The Khatatba Formation shows Tmax value ranges from 441 to 454 indicating mature source rock (Table 1) (Fig. 3d). The calculated vitrinite reflectance Ro, according to [10], of Khatatba Formation ranges from 0.78 to 1.01(Table 1) shows mature and oil generating potential of the source rock [6], Production index ‘‘PI” of this formation ranges from 0.1 to 0.21 reflecting mature source rock in the oil generation stage (Table 1). The relation between production index PI and ‘‘Tmax” (Fig. 6) indicates that the source rock of Khatatba is mature, Bahariya Formation has ‘‘Tmax” values that
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Fig. 4. Modified Van Krevelen Diagram Showing Kerogen Type of the study samples [11].
Fig. 6. Relation between Productivity Index (S1/S1 + S2) and Tmax.
0.05 to 0.57(Table 1) indicating that the samples lie in between oil generation and gas generation stages. The calculated vitrinite reflectance Ro of Abu Roash G Member ranges from 0.62 to 0.72 indicating the formation within the early stage of hydrocarbon generation to oil window. The relation between production index PI and ‘‘Tmax” (Fig. 6) indicates that the source rock of Abu Roash ‘‘G” Member is marginally mature approaching the main stage of hydrocarbon generation. 3.4. Biomarker characteristics of extracts, by GC and GC–MS analysis
Fig. 5. Source rock characterization using plot of HI versus TOC for the Study samples [8].
range from 399 °C to 440 °C (Table 1) reflecting that the samples lie in between immature to marginally mature stage (Fig. 3d) The calculated vitrinite reflectance Ro of Bahariya Formation range from 0.53 to 0.76 (Table 1) which places this formation within the early stage of hydrocarbon generation of oil window, Production index ‘‘PI” of this formation ranges from 0.08 to 0.64 (Table 1) indicating that the samples lie in between oil generation and gas generation stages. The relation between production index PI and ‘‘Tmax” (Fig. 6) indicates that the source rock of Bahariya Formation is marginally mature. The studied samples of Abu Roash ‘‘G” Member have ‘‘Tmax” values that range from 397 °C to 438 °C (Table 1) reflecting that the samples lie in between immature to marginally mature stage (Fig. 3d), Production index ‘‘PI” of this formation ranges from
3.4.1. C15+ normal alkanes Gas chromatography (GC) analysis carried out to the saturate fraction of the extract, with the calculation of n-alkanes and isoprenoids pristane (Pr) and Phytane (Ph) (Table 2). The study of fingerprints of Khatatba Formation extract represented by (Fig. 7A) reveals the dominance of peaks nC15-nC25 which indicates type II/III kerogen as the maximum peak concentration of C15-C30, and the isoprenoids Pr/Ph ratio ranges from 0.53 to 1.61 and Pr/nC17 and Ph/nC18 ranges from 0.22 to 0.32 and 0.18 to 0.34 respectively and CPI value ranges from 1.05 to 1.14 all reflects mixed organic matter input with significant terrestrial contribution under reducing environment (Table 2), (Fig. 8) [12,13]. The Bahariya Formation (Lower and upper) fingerprints of saturated hydrocarbon (Fig. 7B and C) shows peak concentration of nalkanes C17 to C25 with maximum of C17-C21 with CPI (1.07 and 1.06) (Table 2) indicating significant input of marine organisms with contribution of terrestrial organic remains. The isoprenoids (Pristane/phytane) ratio of the Bahariya Formation are 0.78 and 0.96 (Table 2) and Pr/nC17 and Ph/nC18 are 0.28 and 0.24 and 0.36 and 0.25 respectively. The isoprenoids data shows mainly marine organic matter input with contribution of terrestrial input deposited under reducing condition (Fig. 8). The Abu Roash ‘G’ gas chromatogram fingerprint of saturated hydrocarbon (Fig. 7D) shows an increase in normal alkanes from C15-C30 with slightly even carbon preference CPI of1.08 (Table 2) which reflect mixed organic matter input. The isoprenoid Pr/Ph for A/R ‘G’ Member is 0.92 and Pr/nC17 and Ph/nC18 is 0.72 and 0.65 (Table 2) respectively suggests mixed organic matter input deposited under transitional environment (Fig. 8).
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E.A. Abd El-Gawad et al. / Egyptian Journal of Petroleum xxx (2017) xxx–xxx Table 2 GC data for the study samples. Formation
Well name
Depth (ft)
Pr/Ph
Pr/n-C17
Ph/n-C18
CPI
Khatatba (Extract)
Salam-3X
U. Bahariya (Ex) L. Bahariya (Ex) A/R ‘G’ (Extract) U. Bahariya (oil) L. Bahariya (oil)
Salam-52
10980 11090 11300 11340 11350 11390 11450 11510 11570 5960 6260
0.53 0.77 1.29 1.61 1.2 1.07 0.66 0.76 0.78 0.96 0.78
0.25 0.28 0.27 0.29 0.22 0.23 0.32 0.28 0.29 0.24 0.28
0.23 0.27 0.21 0.18 0.18 0.20 0.34 0.31 0.31 0.25 0.36
1.08 1.05 1.1 1.12 1.14 1.10 1.07 1.06 1.06 1.06 1.07
5560 5830 6223
0.92 5.47 2.54
0.72 0.39 0.86
0.65 0.1 0.21
1.08 1.09 1.02
Salam-52 Salam-02 Salam-16
N.B. Pr: Pristane. Ph: Phytane. CPI: Carbon Preference Index.
Fig. 7. Gas chromatogram of the C15+ saturated hydrocarbons for the extract of the studied samples. (A) Khatatba Formation (B) L. Bahariya Member (C) U. Bahariya Member (D) A/R ‘‘G” Member.
3.4.2. Tricyclic terpanes and hopanes Results of Gas Chromatography/Mass spectrometry (GC/MS) chromatograms using triterpanes (M/Z 191) and steranes (M/Z 217) for the saturated fractions of the study rock and oil samples are used in the present study, due to their valuable interpretative data. In the present study four representative samples of source rock hydrocarbon extracts from Khatatba Formation (1 sample from Salam-3X well), Lower and Upper Bahariya members (2 samples
from Salam-52 well) and Abu Roash ‘G’ Member (1 sample from Salam-52 well). Two oil samples representing, Lower Bahariya from Salam-16 well and Upper Bahariya from Salam-02 well were analysed by gas chromatography (GC) and gas chromatography/ mass spectrometry (GC/MS). The fingerprint (M/Z 191) gas chromatography/mass spectrometry analysis for Khatatba Formation from well Salam-3X (Fig. 9A) shows a relative abundance of tricyclic terpane indicating mixed organic source with significant terrestrial organic matter contribu-
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tion [14] [15] with mature source rock indicated by Ts/Tm value (Table 3)[16][17]. Lower and Upper Bahariya members fingerprint (M/Z 191) (Fig. 9B and C) show slightly high contribution of tricyclic terpanes with C25/C26 ratio (2.1–2.13) and Ts/Tm value (0.86–0.74) (Table 3) may reflect marine origin of organic matter with input of terrestrial organic matter deposited under lacustrine and/or marine carbonate environment with slightly mature source
Table 3 GC–MS data for the biomarkers of the study samples.
Fig. 8. Plot of Pristane/n-C17 vs. Phytane/n-C18 of Khatatba Formation and Lower Bahariya, Upper Bahariya and A/R ‘G’ member samples [12,13].
Type of sample
Extract
Well name
Salam-52
Formation
Bahariya
Depth (ft) C27 C28 C29 Hopane/sterane Ts/Tm Ts/Ts+Tm C34/C35 hopane C35/C34 hopane C25/C26 Diasterane index
5960 40.7 32.5 26.8 3.95 0.86 0.79 9.48 0.41 2.1 41.2
Oil
6260 40.4 32.6 27 6.2 0.74 0.43 7.47 0.13 2.13 67.1
Salam-3X
Salam-16
A/R ‘G’
Khatatba
Bahariya
5560 38.5 35.3 26.2 1.7 0.97 0.49 2.42 0.41 2.18 26.3
– 33 37 30 – – – – – – –
6223 34.2 26.3 39.5 12.1 0.45 0.31 3.1 0.75 0.73 16.2
Fig. 9. Gas chromatogram- mass spectrometry of terpanes (M/Z 191) For the saturated hydrocarbon fraction of the extract of the studied samples. (A) Khatatba Formation (B) L. Bahariya Member (C) U. Bahariya Member (D) A/R ‘‘G” Member.
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Fig. 10. Gas chromatogram- mass spectrometry of steranes (M/Z 217) of the saturated hydrocarbon fractions for extract of the study samples. (A) Khatatba Formation (B) L. Bahariya Member (C) U. Bahariya Member (D) A/R ‘‘G” Member.
Fig. 11. Triangular plots showing the relative concentration of C27, C28 and C29 regular steranes for the study samples [19,20].
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rock. The C24 relative abundance and C35 homohopane index (0.41– 0.13) reflects reducing environment of deposition and integrated with C29, C30 norhopane abundance in the study samples [18]. The fingerprint of A/R ‘G’ Member (M/Z 191) (Fig. 9D) have moderate abundance of tricyclic terpanes with C25/C26 ratio 2.18 with Ts/Tm value 0.97(Table 3) shows moderately mature source rock deposited under lacustrine saline and/or marine carbonate or marine calcareous environment. The C35/C34 hopanes ratio of A/R ‘G’ Member is 0.41 with relative abundance of C29 and C30 norhopanes reflecting calcareous facies with reducing environment [18]. 3.4.3. Steranes and diasteranes The fingerprint of GC/MS (M/Z 217) for Khatatba Formation (Fig. 10A) shows abundance of C29 steranes relative to C27 steranes which implies significant terrestrial contribution relative to marine
input. The diasteranes/sterane shows that Khatatba Formation is more mature than the other studied formations. The Lower and Upper Bahariya member’s fingerprint of GC/MS (M/Z 217) (Fig. 10B and C) shows the distribution of regular sterane of C27, C28 and C29. The C27 regular sterane percent (40.4– 40.7%), C28 regular sterane percent (32.6–32.5%) and C29 regular sterane (27–26.8%) (Table 3) suggest mixed organic source input with significant marine organic matter deposited in marine carbonate environment .The diasterane index of Bahariya Formation is (67.1 and 41.2) (Table 3) confirming the same result. The diasterane/sterane of Bahariya Formation reflects moderately mature source rock. The Abu Roash ‘G’ Member extract fingerprint of GC/MS (M/Z 217) (Fig. 10D) have C27, C28 and C29 regular sterane ratio 38.5, 35.3 and 26.2% respectively (Table 3) This data may suggest mixed terrestrial and marine organic matter input, with a diasterane
Fig. 12. Gas chromatogram of the C15+ saturated hydrocarbon in Lower Bahariya oil sample in Salam-16 well.
Fig. 13. Gas chromatogram of the C15+ saturated hydrocarbon in Upper Bahariya oil sample from Salam-02 well.
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index 26.3, which reflects mixed terrestrial and marine organic matter input deposited in marine carbonate and/or marine calcareous source rock facies with moderately mature source rock. The relative concentration of C27, C28 and C29 regular steranes for the study samples plotted on the ternary diagram [19,20] (Fig. 11) confirm the previously mentioned depositional environment. 3.5. Oil characterization Two oil samples representing Baharyia reservoirs are analysed. The oil sample fingerprint of saturated hydrocarbon from Lower
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Bahariya reservoir in well Salam-16 (Fig. 12) and Upper Bahariya reservoir in well Salam-02 (Fig. 13) shows predominance of C15C30 with CPI 1.02 and 1.09 respectively (table 2). The isoprenoid data for the oil sample Pr/Ph is 2.54 and 5.47, the Pr/nC17 and the Ph/nC18 are 0.86 and 0.21 and 0.39 and 0.1 respectively. This data suggested that the oil samples have a mixed organic source with significant terrestrial organic matter input deposited under oxidizing environment (Fig. 8). The fingerprint of GC/MS (M/Z 191) for the studied oil sample from Lower Bahariya reservoir (Fig. 14) shows a relatively moderate abundance of triterpanes with high concentration of C30 hopane peak, with Ts/Tm and C35/C34 homohopane ratio of 0.45
Fig. 14. Gas chromatogram- mass spectrometry of terpanes (M/Z 191) of saturated hydrocarbon fraction in Lower Bahariya oil sample.
Fig. 15. Gas chromatogram- mass spectrometry of steranes (M/Z 217) of saturated hydrocarbon fraction in Lower Bahariya oil sample.
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and 0.75 respectively, this data reflects mixed organic matter with significant terrestrial input deposited under saline to hypersaline environment with slightly oxidizing environment. The saturated fraction GC/MS fingerprint (M/Z 217) of Lower Bahariya reservoir (Fig. 15) represents the distribution of steranes and diasteranes. The predominance of C29 regular sterane 39.5% (Table 3) and C28 & C27 values are 26.3 and 34.2 respectively suggests significant terrestrial organic matter input with marine organic matter. Interpretation of the ternary diagram (Fig. 11) confirms this conclusion. The diasterane index for the study samples equals
16.2 (Table 3) this value indicates lacustrine saline and/or marine calcareous environment of deposition.
3.6. Oil – source rock correlation In the present study, the oil – source correlation carried out between oil produced from Bahariya reservoir and the extracts of Khatatba and Bahariya formations, as well as, Abu Roash ‘‘G” member, throughout the parameters derived from fingerprints of GC and GC/MS (Figs. 16–18 and Tables 2–3). according to [15–21].
Fig. 16. Oil-Source rock correlation with C15+ diagram of the study samples.
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Fig. 17. Oil-Source rock correlation using terpane (M/Z 191) of the study samples.
3.7. Oil – source rock correlation based on GC The results show that the GC fingerprint of the Khatatba extract (Fig. 16) has the dominance of peaks nC15-nC25 which indicates type II/III kerogen as the maximum peak concentration at C15- C30. While the Lower and upper Bahariya members
extract reveals peak concentration of n-alkanes C17 to C25 with maximum of C17-C21 indicating significant input of marine organisms with contribution of terrestrial organic remains. The Abu Roash ‘G’ Member extracts shows increasing in normal alkanes from C15-C30, suggests mixed organic matter input. On the other side, The oil samples fingerprints from the Lower Bahariya
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Fig. 18. Oil-Source rock correlation using steranes (M/Z 217) of the study samples.
reservoir in well Salam-16 and Upper Bahariya reservoir in well Salam-02 (Fig. 16) shows predominance of C15-C30, this data suggested mixed organic source with significant terrestrial organic matter input. Khatatba Formation shows the isoprenoids Pr/Ph ratio ranges from 0.53 to 1.61. Pr/nC17 and Ph/nC18 ratio ranges from 0.22 to 0.32 and 0.18 to 0.34 respectively, with CPI value ranges from 1.05 to 1.14 (table 2), all reflects mixed organic matter input with significant terrestrial contribution under reducing environment (Fig. 8). The isoprenoids (Pristane/phytane) ratio of the Bahariya Formation are 0.78 and 0.96,and Pr/nC17 and Ph/nC18 are 0.28 and 0.24 and 0.36 and 0.25 respectively(Table 2) The isoprenoids
data shows mainly marine organic matter input with contribution of terrestrial input deposited under reducing condition. The isoprenoid Pr/Ph for A/R ‘G’ Member is 0.92 with Pr/nC17 and Ph/ nC18 ratio is 0.72 and 0.65 respectively, with CPI value 1.08 (Table 2) suggests mixed organic matter input deposited under transitional environment. For oil samples, the isoprenoid data for the oil sample Pr/Ph is 2.54 and 5.47 and the Pr/nC17 and the Ph/nC18 are 0.86 and 0.39 and 0.21&0.1 respectively (Table 2), with CPI 1.02 and 1.09. This data suggested that the oil samples has mixed organic source with significant terrestrial organic matter input deposited under oxidizing environment (Fig. 8).
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3.8. Oil – source rock correlation based on GC/MS
4. Conclusions
The fingerprint (M/Z 191) gas chromatography/mass spectrometry analysis of the Khatatba Formation from well Salam- 3X (Fig. 17) shows a relative abundance of tricyclic terpane indicating mixed organic source with significant terrestrial organic matter contribution, with mature source rock indicating from Ts/Tm value(Table 3) [18].while in the Lower and Upper Bahariya members (Fig. 17) shows slightly high contribution of tricyclic terpanes with C25/C26 ratio (2.13–2.1) and Ts/Tm value (0.74–0.86) may reflect marine origin of organic matter with input of terrestrial organic matter deposited under lacustrine and/or marine carbonate environment with slightly mature source rock. The C24 relative abundance and C35 homohopane index (0.13–0.41) reflects reducing environment of deposition and integrated with C29, C30 norhopane abundance in the study samples. The fingerprint of A/R ‘G’ Member have moderate abundance of tricyclic terpanes with C25/C26 ratio 2.18 with Ts/Tm value 0.97 (Table 3) shows moderately mature source rock deposited under lacustrine saline and/or marine carbonate or marine calcareous environment. The C35/C34 hopanes ratio is 0.41 with relative abundance of C29 and C30 norhopanes reflect calcareous facies with reducing environment. On other hand, The fingerprint (M/Z 191) of oil sample from Lower Bahariya reservoir (Fig. 18) shows a relatively moderate abundance of triterpanes with high concentration of C30 hopane peak, with Ts/Tm and C35/C34 homohopane ratio are 0.45 and 0.75 respectively (Table 3), this data reflects mixed organic matter with significant terrestrial input deposited under saline to hypersaline environment with slightly oxidizing environment. The study of steranes and diasteranes biomarkers in saturated fractions of the study samples reflect that the Khatatba Formation (Fig. 18) shows abundance of C29 steranes relative to C27 steranes which implies significant terrestrial contribution relative to marine input. The diasteranes/sterane shows that Khatatba Formation is more mature than the other formations. While The fingerprint of Lower and Upper Bahariya members shows the distribution of regular sterane of C27, C28 and C29, the C27 regular sterane percent (40.4–40.7%), C28 regular sterane percent (32.6–32.5%) and C29 regular sterane (27–26.8%) suggest mixed organic source input with significant marine organic matter deposited in marine carbonate environment .The diasterane index of Bahariya Formation is (67.1 and 41.2) confirming the previous result. The diasterane/ sterane ratio reflects moderately mature source rock. The Abu Roash ‘G’ Member extract fingerprint has C27, C28 and C29 regular sterane ratio 38.5, 35.3 and 26.2% respectively (Table 3). This data may suggest mixed terrestrial and marine organic matter input, with a diasterane index (26.3), deposited in marine carbonate and/or marine calcareous source rock facies with moderately mature source rock. For the oil sample, the saturated fraction fingerprint of Lower Bahariya oil represents the distribution of steranes and diasteranes, with predominance of C29 regular sterane 39.5% and C28 and C27 values are 26.3 and 34.2 respectively suggests significant terrestrial organic matter input with marine organic matter. The diasterane index for the study samples equals 16.2 this value indicates lacustrine saline and/or marine calcareous environment of deposition. The ternary diagram (Fig. 11) confirms this conclusion. Therefore, comparing the studied source rocks extracts and the corresponding crude oils it is clear that there is a correlation between the extract samples of Khatatba source rocks and crude oils from Salam oil field, indicating a good correlation. While each of the extract of Bahariya and Abu Roash source rocks show slight correlation. These evidences indicate that Khtataba source rocks seem to act as the main source for oil generating in Salam oil field with some contribution from Baharyia source rocks., This is agreeing with the conclusions of [22,23].
1. The representative samples of Khatatba Formation have good to very good organic richness with poor to good hydrocarbon potentiality, with type II/III kerogen. It shows a relative abundance of tricyclic terpane indicating mixed organic source with significant terrestrial organic matter contribution deposited under reducing environment . 2. The Bahariya Formation (Lower and upper) has organic richness varies from fair to very good, and poor to good generating source potential with type II/III kerogen. The isoprenoids data shows mainly marine organic matter input with the contribution of terrestrial input deposited under reducing conditions. The biomarker data reflect marine origin of organic matter with the input of terrestrial organic matter deposited under lacustrine and/or marine carbonate environment with slightly mature source rock. 3. Abu Roash ‘‘G” Member reveals organic richness varies from fair to very good, with poor to good generating source potential classified as type II/III kerogen (mixed type). The isoprenoid data suggest mixed organic matter input deposited under transitional environment. The biomarker data show moderately mature source rock deposited under lacustrine saline and/or marine carbonate or marine calcareous environment. 4. The fingerprints of the saturated hydrocarbon fraction of the Baharyia reservoir (Lower and Upper) suggests that the oil samples have a mixed organic source with significant terrestrial organic matter input deposited under saline to hypersaline environment with slightly oxidizing environment. 5. Based on the obtained results, it is suggested that the Baharyia oil has been mainly sourced from deeper horizons (Khatatba Formation) with some contribution from Upper & Lower Baharyia source rocks). Acknowledgements The authors are greatly thankful for the Egyptian General Petroleum Corporation and Khalda Petroleum company for providing the rock and oil samples to complete this research. Gratitudes are due to the Geochemistry Lab, the Exploration Department of the Egyptian Petroleum Research Institute (EPRI); for support in performing the Lab analysis (Rock-Eval 6 analyses, GC and GCMS). Thanks are also extended for two anonymous reviewers for their careful and constructive comments to improve the manuscript. References [1] EGPC (Egyptian General Petroleum Corporation), Western Desert, oil and gas fields (a comprehensive overview). Unpublished Internal Report, 1996, pp. 9– 29. [2] EGPC, (Egyptian General Petroleum Corporation), Western Desert, oil and gas fields, A comprehensive overview, EGPC 11th Petrol. Explor. and Prod. Confer., Cairo, 1992, p. 431. [3] J. Espitalie, G. Deroo, F. Marquis, Rock-Eval pyrolysis and its application, Inst. Fr. Pet. Preprint 33578 (1985) 72. [4] K.E. Peters, J.M. Moldowan, The Biomarker Guide, Interpreting Molecular Fossils in Petroleum and Ancient Sediments, Prentice-Hall, Englewood Cliffs, NJ, 1993, p. 363. [5] K.E. Peters, Guidelines for evaluating petroleum source rock using programmed pyrolysis, AAPG Bull. 70 (1986) 318–329. [6] K.E. Peters, M.R. Cassa, Applied source rock geochemistry. in: L.B. Magoon, W. G. Dows (Eds.), The petroleum system-from source to trap, AAPG, Tulsa, OK, pp. 93–117. [7] D.W. Waples, Geochemistry in Petroleum Exploration, International Human Resources Development Corporation, Boston, 1985, p. 232. [8] K.S. Jackson, P.J. Hawkins, A.J.R. Bennett, Regional facies and geochemical evaluation of southern Denison Trough, APEA J. 20 (1985) 143–158. [9] M.L. Bordenove, J. Espitalie, P. Leplat, J.L. Oudin, M. Vandenbroucke, (Screening techniques for source rock evaluation. in: M.L. Bardenove (Ed.), Applied Petrol. Geochem., Paris Editions Technip., 1993, pp. 217–278.
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[10] Daniel M. Jarvie, Brenda Claxton, Bo Henk, John Breyer, Oil and Shale Gas from Barnett Shale,Ft. Worth Basin,Texas AAPG National Convention, Denver, CO, 2001. [11] J. Espitalie, L. Laporte, M. Madec, F. Marquis, P. Leplat, J. Paulet, A. Boutefeu, Methode rapid de caracterisation des rocks meres, de leur potential petrolier et leur degree devolution, Rev. Inst. Fr. Petrol. 32 (1977) 23–42. [12] G. Shanmugam, Significance of coniferous rain frost and related organic matter in generating commercial quantities of oil, Gipps-land basin, Australia, AAPG Bull. 69 (8) (1985) 1241. [13] K.E. Peters, J.W. Snedden, A. Sulaeman, J.F. Sarg, R.J. Enrica, A new geochemical sequence stratigraphic model for the Mahakan delta and Makassar slope, Kalimantan, Indonesia, AAPG Bull. 84 (2000) 12–44. [14] J.H. Hunt, Petroleum Geochemistry and Geology, second ed., Freeman and Company, New York, 1996, p. 743. [15] D.W. Waples, T. Machihara, Biomarkers for geologists. A practical guide to the application of steranes and triterpanes in petroleum geology. AAPG, Tulsa, Oklahoma, 1991. [16] G.W. Van Grass, Biomarker maturity parameters of high maturities: calibration of the working range up to the oil/condensates threshold, Organic Geochemistry., vol. 16, 1990, pp. 1025–1032. [17] W.K. Seifert, J.M. Moldowan, Use of biological markers in petroleum exploration. in: R.B. Johns (Ed.), Methods in Geochemistry and Geophysics, 24, 1986, pp. 261–290.
[18] H.I. Ten Haven, J.W. De Leeuw, P.A. Schenck, Organic geochemical studies of a Messinian evaporitic basin, northern Apennines (Italy), hydrocarbon biological Markers for a hypersaline environment, Geochim. Cosmochim. Acta 49 (1985) 2181–2191. [19] W.Y. Huang, W.G. Meinschein, Sterols as ecological indicators, Geochim. Cosmochim. Acta. 43 (1979) 739–745. [20] J.M. Moldowan, W.F. Seifert, E.J. Gallegos, Relationship between petroleum composition and depositional environment of petroleum source rock, AAPG Bull. 69 (1985) 1255–1268. [21] K.E. Peters, C.C. Walters, J.M. Moldowan, The Biomarker Guide, 2nd Edition, Part I, ‘‘Biomarkers and Isotopes in the Environmental and Human History”, and Part II ‘‘Biomarkers and Isotopes in Petroleum Exploration and Earth History”, Cambridge University Press, 2005, p. 1155. [22] M.M. El Nady, F.M. Harb, Geochemical correlation of oils and source rock extracts of some wells in the North Western Desert, Egypt, J. Energy Sources 32 (13) (2010) 1215–1223. [23] M.I. Roushdy, M.M. El Nady, Y.M. Mostafa, N. Sh, El Gendy, Hager R. Ali, Specific geochemical parameters and oil: source rock correlations of some oilfields in the North Western Desert, Egypt, J. Am. Sci. 7 (5) (2011) 715–729.
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Full Length Article
Origin of Bahariya oil in Salam oil field, Western Desert- Egypt E.A. Abd El-Gawad a, D.A. Mousa b,⇑, M.A. Lotfy b, A.I. El-Shorbagy a a b
Al-Azhar University, Faculty of Science-Geology Department, 1 Al Mukhayam Al Ddayim St., Nasr City, Cairo 11884, Egypt Egyptian Petroleum Research Institute, Exploration Department, 1 Ahmed El-Zomor Street, El- Zohour Region, Nasr City, Cairo 11727, Egypt
a r t i c l e
i n f o
Article history: Received 27 July 2017 Revised 13 September 2017 Accepted 19 September 2017 Available online xxxx Keywords: Rock Eval -6 Kerogen type Geochemical analysis GC and GC/MS analysis
a b s t r a c t The origin of Bahariya oil is a debatable issue. Bahariya Formation produces oil from the Lower sandstone unit by normal pressure mechanism, while the Upper Bahariya shale produces oil by fracking mechanism. The main question is: is there any genetic relationship between the two oils. To answer this question, ‘‘50” ditch samples, ‘‘12” extract samples and ‘‘2” oil samples represent Khatatba and Bahariya formations and Abu Roash ‘G’ Member, collected from six wells drilled in Salam oil field, have been geochemicaly analyzed, using LECO SC632, Rock–Eval- 6 pyrolysis, GC and GC/MS techniques.The analysis shows that the Total Organic Carbon content (TOC) for the studied formations ranges from fair to v.good, with poor to good hydrocarbon potentiality. The maturity evaluation using Tmax, and calculated Vitrinite reflectance (Ro) showed that the studied samples have good thermal maturation reaching the stage of oil generation. Also the analysis revealed that the kerogen is a mixture of type II/III kerogen, reflecting the potential generation of oil and gas. The GC and GC/MS data showed that the organic matter is a mixed marine/terrestrial input deposited in transitional environment under prevailing reducing conditions. The oil samples fingerprint of the saturated hydrocarbons fraction from Baharyia reservoir (Lower and Upper) members suggest that the oil samples have a mixed organic source with significant terrestrial organic matter input deposited under saline to hypersaline environment with slightly oxidizing environment. Based on the obtained results, it is suggested that the Bahariya oil has been sourced mainly from deeper horizons (Khatatba Formation) with some contribution from upper and lower Bahariya source rocks. Ó 2017 Egyptian Petroleum Research Institute. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
1. Introduction The Western Desert comprises the area west of the Nile River and Delta. It extends from the Mediterranean Sea in the north to the Egyptian Sudanese borders in the south and from the Nile valley in the east to the Egyptian Libyan borders in the west. Many significant productive oil and gas fields have been discovered especially in North Western Desert e.g. Abu Gharadig, Abu Sennan, Badr El Din, Razzak, Alamein, Khalda, Safir, Meleiha, Um Barka, Aghar, Kanayis, Horns, WD-19, Aman, Dorra, Emry, Falak, Karnak, Lotus, Sitra, Hayat, Kahrman, Khalda, Salam, Tut, Yasser, Gpt, Gpy, Yidma, Ahram and Qarun -1 [1]. The study area lies between latitudes 30° 400 4700 – 30° 420 5000 N and longitudes 26° 570 3900 - 27° 000 5600 E. The six examined wells
Peer review under responsibility of Egyptian Petroleum Research Institute. ⇑ Corresponding author. E-mail addresses: [email protected] (E.A. Abd El-Gawad), doaa2_ali@ hotmail.com (D.A. Mousa), [email protected] (M.A. Lotfy), aliismail_m@ yahoo.com (A.I. El-Shorbagy).
(Salam 02- Salam-3X- Salam 52- Salam 05- Salam 35- Salam 16) were distributed evenly within the study area (Fig. 1). Salam-3x was first discovery by Khalda Petroleum Company. From this well, a significant quantity of oil and gas are produced from (Khatatba Formation) and Cretaceous (Alam El Bueib and Bahariya formations). The stratigraphic column of the North Western Desert is thick and includes most of the sedimentary succession from PreCambrian basement complex to recent formations (Fig. 2). The total thickness, despite some anomalies, increases progressively to the north and northeast from about 6000 ft in the southern region to reach about 25,000 ft along the coastal area [2].The lithology of the studied formations are descripted in the following paragraph: The Khatatba Formation consists mainly of bituminous shales, siltstones and sandstones commonly with carbonaceous debris in the lower part. The upper part of the Khatatba Formation contains more carbonate beds, Bahariya Formation consists of glauconitic and pyritic sandstone interbeded with shales, siltstones and carbonates, while Abu Roash ‘‘G” Member consists mainly of carbonates with shale and dolomite interbeds [2].
https://doi.org/10.1016/j.ejpe.2017.09.003 1110-0621/Ó 2017 Egyptian Petroleum Research Institute. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
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2.4. Based on the screening data, selected samples are subjected to extraction using soxhlet apparatus with chloroform solvent in order to separate bitumen from rock samples. The followed method of bitumen extraction and analysis as described in [4]. Bitumen is extracted by pulverizing the rock ( 10 gm) and then soaking the pulverized rock for 12–36 h in an organic solvent (chloroform). The solvent is removed from the extracted bitumen by evaporation (this method of removal results in the loss of the lighter hydrocarbons, which have similar evaporation rate as the solvent). In practice, only hydrocarbons heavier than carbon number C15+ are retained for further analysis. The extracted bitumen is expressed as weight percent to the whole rock sample. Removal of elementary sulfur from extracted bitumen was performed by mercury. Asphaltene was separated from the extracted bitumen using n-hexane. The precipitated asphaltenes were then filtered off and expressed as weight percent of the whole extracted bitumen.
Fig. 1. Location map of the study area.
The main objectives of this study is to predict the source of the hydrocarbons generated from the Bahariya Formation in Salam oil field. For these purposes fifty (50) cutting samples of argillaceous dark-gray shales and limestones representing the Jurassic and Cretaceous rock units (Khatatba and Bahariya formations and Abu Roash ‘‘G” Member) were analysied. Twelve ‘‘12” extract samples and two (2) oil samples representing the same formations were analysed using Gas chromatoghraphy and Gas chromatoghraphy – Mass Spectrometry techniques. 2. Materials and methods Fifty (50) cutting samples of argillaceous dark-gray shales and limestones representing the Jurassic and Cretaceous rock units (Khatatba and Bahariya formations and Abu Roash ‘‘G” Member.) were analysed by LECO SC632 to determine the Total Organic Carbon (TOC) wt%, as well as by Rock-Eval 6 instrument for pyrolysis analysis. Twelve (12) extract samples and two oil samples representing the same formations were analysed by Gas Chromatography after fractionation. A brief explanation for the used techniques is given below: 2.1. Total organic carbon (TOC, wt%) and Rock-Eval pyrolysis followed standard methods, the samples were cleaned and crushed and 200 mesh samples were selected for geochemical analysis. 2.2. About 200 mg of sample was placed in a crucible with 5% HCl at 80 °C to remove carbonates. The total organic carbon content (TOC) was measured using a Leco SC-632 instrument. Samples with TOC content exceeding 0.5 wt% were selected to screening analysis using Rock-Eval-6 instrument [3]. 2.3. Rock-Eval pyrolysis was performed on pulverized whole rock samples, about (60 mg) of the sample were analysed using a Vinci Rock-Eval 6 pyro-analyzer in the bulk rock mode. The parameters of the rock Eval pyrolysis represents free hydrocarbons S1 (mg HC/g rock), residual petroleum potential S2 (mg HC/g rock), and S3 (CO2 results from pyrolysis of organic matter). The previous parameters are used in the present work to determine Hydrogen Index (HI mg HC/g TOC) and Oxygen Index (OI mg CO2/g TOC), To obtain the kerogen type of the study samples.
2.5. The saturated hydrocarbons fractions of rock extracts were subjected to gas chromatography and advanced Techniques GC–MS for Biomarker determination for ions (M/Z 191) and (M/Z 217). These analyses were Kindly done in the laboratories of the Egyptian Petroleum Research Institute [EPRI], completed with a report for one sample from Strato Chem Services Lab. (SCS). 3. Results and discussion Screening analysis including Total Organic Carbon (TOC) and Rock-Eval pyrolysis data for ‘‘16” ditch samples representing Khatatba Formation, ‘‘ 24” rock samples representing Upper and Lower Bahariya Formation and ”10” rock samples representing Abu Roash ‘‘G” Member was carried out. The analysis data and plots of data are represented in (Table 1) and (Figs. 3–6). 3.1. Organic richness and hydrocarbon potentiality The organic carbon richness of the rock samples, as expressed by weight percent of total organic carbon content (TOC wt%) [5]. Peters and Cassa [6] reported that rocks containing less than 0.5% TOC are considered as poor source rocks, between 0.5% and 1% TOC indicates fair source rock TOC% value between 1% and 2% indicates good source rocks whereas:-. TOC% values above 2% often indicate highly reducing environment with excellent source potential. The hydrocarbon potentiality S1 from 0 to 0.5 mg/g represents poor hydrocarbon potentiality, from 0.5 to 1 mg/g consider fair, from 1 to 2 mg/g good, 2–4 mg/g very good and more than 4 mg/ g is excellent [5] and [6]. The studied samples of Khatatba Formation, shows TOC ranges from 1.35 to 5.1 (Table 1) which indicates good to very good organic richness (Fig. 3a). The pyrolysis-derived S1 and S2 values of Khatatba Formation are 0.43–1.59 and 2.06 to 9.59 respectively (Table 1) indicating poor to good hydrocarbon potentiality S2 (Fig. 3B and C). Bahariya Formation has TOC ranges from 0.81 to 3.27%. (Table 1) revealing the organic richness of this formation varies from fair to very good (Fig. 3a). The Values of S1 and S2 range from 0.11 to 9.37 mg/g, 0.24 to 6.22 mg/g respectively (Table 1) (Fig. 3B and C) indicating poor to good generating source potential. Abu Roash ‘‘G” Member has TOC values ranging from 0.77 to 2.63% (Table 1) revealing the organic richness of this formation
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Fig. 2. Stratigraphic column of the Western Desert. (Khalda Petroleum Company, 2005).
varies from fair to very good (Fig. 3a). The pyrolysis-derived S1 and S2 value of Abu Roash ‘‘G” Member range from 0.11 to 6.58 mg/g and 1.03 to 8.04 mg/g, respectively (Table 1) (Fig. 3B and C) indicating poor to good generating source potential.
3.2. Kerogen type Waples [7] used the hydrogen index values (HI) to differentiate between the types of organic matter. Hydrogen indices below
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Table 1 Pyrolysis data of the study samples. Formation
Well
Depth
TOC
S1
S2
S3
Tmax
HI
OI
PI
Cal. Ro
A/R G
SAL-02
5390 5660 5400 5650 5600 5700 5400 5700 5460 5560 6150 6450 6160 6220 6320 6000 6040 6150 6280 6380 6410 6800 5820 5860 5930 6070 6130 5920 5930 5960 6090 6100 6230 6260 11330 11390 11450 11480 11510 11540 11570 11600 11300 11310 11320 11340 11360 11370 11380 11400
0.84 0.77 0.8 1.16 1.41 1.69 1.77 2.03 2.63 2.63 0.97 0.85 0.81 0.94 0.88 1.62 1.28 1.25 1.30 1.97 1.52 1.16 1.76 2.01 1.86 2.14 1.56 1.85 1.72 1.37 1.26 1.31 3.27 1.52 1.85 1.65 2.55 2.2 3.06 1.59 2.98 1.35 4.27 1.5 2.95 5.1 1.62 1.79 2.05 2.1
0.12 0.11 0.43 0.6 2.23 1.93 5.33 6.58 6.02 4.23 0.13 0.11 0.79 0.93 0.91 1.75 1.80 1.98 0.19 2.47 2.33 1.9 7.13 9.37 7.8 7.70 6.17 5.18 6.12 4.25 3.65 3.53 6.08 3.8 0.7 0.58 0.75 0.7 1.11 0.53 0.85 0.66 0.97 0.43 0.97 1.59 0.47 0.61 0.65 0.46
2.44 1.03 2.09 1.93 4.23 5.64 5.62 4.95 8.04 3.77 0.93 1.25 1.32 1.52 1.27 3.53 2.57 2.57 0.24 2.78 2.39 1.77 4.11 2.27 4.65 4.68 3.43 4.56 4.11 2.99 2.52 2.66 6.22 3.1 2.62 2.26 4.86 3.84 7.71 2.4 7 2.55 9.05 2.06 5.21 9.59 2.19 2.88 2.99 3.05
1.23 1.07 0.97 0.82 1.31 2.36 1.54 0.8 3.65 2.86 0.8 0.89 0.95 1.22 1.64 1.09 0.03 0.47 0.06 1.38 1.54 0.57 0.08 1.18 1.66 0.12 0.78 3.44 2.67 2.19 1.98 2.65 3.25 2.9 0.98 0.99 0.9 0.93 0.91 0.75 1.05 0.86 0.69 0.67 0.63 0.5 0.75 1.57 0.91 1.3
433 436 433 438 432 433 434 437 437 397 440 436 435 435 429 431 430 433 433 430 427 431 433 436 435 431 432 440 399 438 435 435 438 435 452 454 444 449 444 448 444 442 447 448 445 447 448 445 447 441
290 133 261 166 300 334 318 244 306 143 95 147 163 162 144 218 201 205 18 141 157 152 234 113 250 219 220 246 239 218 200 203 190 204 142 137 191 175 252 151 235 189 212 137 177 188 135 161 146 145
146 138 121 70 93 140 87 39 139 109 82 104 117 130 186 67 2 38 5 70 101 49 5 59 89 6 50 186 155 160 157 202 99 191 53 60 35 42 30 47 35 64 16 45 21 10 46 88 44 62
0.05 0.1 0.17 0.24 0.35 0.26 0.49 0.57 0.43 0.53 0.12 0.08 0.37 0.38 0.42 0.33 0.41 0.43 0.44 0.47 0.49 0.52 0.63 0.64 0.63 0.62 0.64 0.53 0.6 0.59 0.59 0.57 0.49 0.55 0.21 0.2 0.13 0.15 0.13 0.18 0.11 0.21 0.1 0.17 0.16 0.14 0.18 0.17 0.18 0.13
0.63 0.69 0.63 0.72 0.62 0.63 0.65 0.71 0.71 -0.01 0.76 0.69 0.67 0.67 0.56 0.60 0.58 0.63 0.63 0.58 0.53 0.60 0.63 0.69 0.67 0.60 0.62 0.76 0.02 0.72 0.67 0.67 0.72 0.67 0.98 1.01 0.83 0.92 0.83 0.90 0.83 0.80 0.89 0.90 0.85 0.89 0.90 0.85 0.89 0.78
SAL-05 SAL-16 SAL-35 SAL-52 Bahariya
SAL-02 SAL-05
SAL-16
SAL-35
SAL-52
Khatatba
SAL-3X
N.B.: TOC: Total organic carbon(weight percent of the whole rock). S1: Free hydrocarbon (mg hydrocarbon/g rock). S2: Hydrocarbon potentiality (mg hydrocarbon/g rock). HI: Hydrogen index (mg hydrocarbon/g TOC). OI: Oxygen index (mg CO2/g TOC). Tmax: Temperature at which maximum emission of high temperature (S2) hydrocarbon occurs (deg.°C.). PI: Production index (S1/S1 + S2). (Calculated % VRo) = (0.0180) (Tmax) – 7.16 [7].
about 150 mg/g indicate a potential source for generating gas (mainly type III kerogen). Hydrogen indices between 150 and 300 mg/g contain more type III kerogen than type II and therefore are capable of generating mixed gas and oil but mainly gas .Kerogen with hydrogen indices above 300 mg/g contain a substantial amount of type II kerogen and thus are considered to have good source potential for generating oil and minor gas. Kerogen with hydrogen indices above 600 mg/g usually consists of nearly type I or type II kerogen, they have excellent potential to generate oil. The hydrogen index (HI) values of the Khatatba Formation ranges from 135 to 252 (mg/g) and oxygen index‘‘OI” ranges from
10 to 88 (mg/g) (Table 1) which suggest type II/III kerogen (Fig. 4). Bahariya Formation has hydrogen index (HI) range from 18 to 250 mg/g and oxygen index ‘‘OI” ranges from 2 to 202 mg/g (Table 1) which suggest type II/III kerogen. (Fig. 4). The hydrogen index (HI) values of the Abu Roash ‘‘G” Member range from 133 to 334 mg/g, and oxygen index ‘‘OI” range from 39 to 146 mg/g (Table 1) which indicate that the organic matter is classified as type II/III kerogen (mixed type) (Fig. 4). The plot of TOC vs. HI (Fig. 5) for the study samples reflect that the main expected generating hydrocarbons are fair oil with some gas [8].
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Fig. 3. Organic richness (A), hydrocarbon potentialities (B) and (C) Thermal maturity by Tmax (D) of the study samples.
3.3. Maturation In the present study, the thermal maturity level of the source rocks has been determined by the study of the geochemical parameters as Rock–Eval temperature pyrolysis ‘‘Tmax”, production index ‘‘PI” [3]. Peters and Cassa [6] and Bordenove et. al. [9] reported that oil generation from source rocks began at ‘‘Tmax” 435–465 °C, vitrinite reflectance ‘‘Ro%” between 0.5% and 1.35% and production index ‘‘PI” between 0.2 and 0.4, the organic matters are in immature stage when ‘‘Tmax” has a value less than 435 °C, ‘‘Ro%” less than 0.5 and ‘‘PI” less than 0.2 and the gas generation
from source rocks began at ‘‘Tmax” 470 °C, ‘‘Ro%” more than 1.35% and production index ‘‘PI” more than 0.4 The Khatatba Formation shows Tmax value ranges from 441 to 454 indicating mature source rock (Table 1) (Fig. 3d). The calculated vitrinite reflectance Ro, according to [10], of Khatatba Formation ranges from 0.78 to 1.01(Table 1) shows mature and oil generating potential of the source rock [6], Production index ‘‘PI” of this formation ranges from 0.1 to 0.21 reflecting mature source rock in the oil generation stage (Table 1). The relation between production index PI and ‘‘Tmax” (Fig. 6) indicates that the source rock of Khatatba is mature, Bahariya Formation has ‘‘Tmax” values that
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Fig. 4. Modified Van Krevelen Diagram Showing Kerogen Type of the study samples [11].
Fig. 6. Relation between Productivity Index (S1/S1 + S2) and Tmax.
0.05 to 0.57(Table 1) indicating that the samples lie in between oil generation and gas generation stages. The calculated vitrinite reflectance Ro of Abu Roash G Member ranges from 0.62 to 0.72 indicating the formation within the early stage of hydrocarbon generation to oil window. The relation between production index PI and ‘‘Tmax” (Fig. 6) indicates that the source rock of Abu Roash ‘‘G” Member is marginally mature approaching the main stage of hydrocarbon generation. 3.4. Biomarker characteristics of extracts, by GC and GC–MS analysis
Fig. 5. Source rock characterization using plot of HI versus TOC for the Study samples [8].
range from 399 °C to 440 °C (Table 1) reflecting that the samples lie in between immature to marginally mature stage (Fig. 3d) The calculated vitrinite reflectance Ro of Bahariya Formation range from 0.53 to 0.76 (Table 1) which places this formation within the early stage of hydrocarbon generation of oil window, Production index ‘‘PI” of this formation ranges from 0.08 to 0.64 (Table 1) indicating that the samples lie in between oil generation and gas generation stages. The relation between production index PI and ‘‘Tmax” (Fig. 6) indicates that the source rock of Bahariya Formation is marginally mature. The studied samples of Abu Roash ‘‘G” Member have ‘‘Tmax” values that range from 397 °C to 438 °C (Table 1) reflecting that the samples lie in between immature to marginally mature stage (Fig. 3d), Production index ‘‘PI” of this formation ranges from
3.4.1. C15+ normal alkanes Gas chromatography (GC) analysis carried out to the saturate fraction of the extract, with the calculation of n-alkanes and isoprenoids pristane (Pr) and Phytane (Ph) (Table 2). The study of fingerprints of Khatatba Formation extract represented by (Fig. 7A) reveals the dominance of peaks nC15-nC25 which indicates type II/III kerogen as the maximum peak concentration of C15-C30, and the isoprenoids Pr/Ph ratio ranges from 0.53 to 1.61 and Pr/nC17 and Ph/nC18 ranges from 0.22 to 0.32 and 0.18 to 0.34 respectively and CPI value ranges from 1.05 to 1.14 all reflects mixed organic matter input with significant terrestrial contribution under reducing environment (Table 2), (Fig. 8) [12,13]. The Bahariya Formation (Lower and upper) fingerprints of saturated hydrocarbon (Fig. 7B and C) shows peak concentration of nalkanes C17 to C25 with maximum of C17-C21 with CPI (1.07 and 1.06) (Table 2) indicating significant input of marine organisms with contribution of terrestrial organic remains. The isoprenoids (Pristane/phytane) ratio of the Bahariya Formation are 0.78 and 0.96 (Table 2) and Pr/nC17 and Ph/nC18 are 0.28 and 0.24 and 0.36 and 0.25 respectively. The isoprenoids data shows mainly marine organic matter input with contribution of terrestrial input deposited under reducing condition (Fig. 8). The Abu Roash ‘G’ gas chromatogram fingerprint of saturated hydrocarbon (Fig. 7D) shows an increase in normal alkanes from C15-C30 with slightly even carbon preference CPI of1.08 (Table 2) which reflect mixed organic matter input. The isoprenoid Pr/Ph for A/R ‘G’ Member is 0.92 and Pr/nC17 and Ph/nC18 is 0.72 and 0.65 (Table 2) respectively suggests mixed organic matter input deposited under transitional environment (Fig. 8).
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E.A. Abd El-Gawad et al. / Egyptian Journal of Petroleum xxx (2017) xxx–xxx Table 2 GC data for the study samples. Formation
Well name
Depth (ft)
Pr/Ph
Pr/n-C17
Ph/n-C18
CPI
Khatatba (Extract)
Salam-3X
U. Bahariya (Ex) L. Bahariya (Ex) A/R ‘G’ (Extract) U. Bahariya (oil) L. Bahariya (oil)
Salam-52
10980 11090 11300 11340 11350 11390 11450 11510 11570 5960 6260
0.53 0.77 1.29 1.61 1.2 1.07 0.66 0.76 0.78 0.96 0.78
0.25 0.28 0.27 0.29 0.22 0.23 0.32 0.28 0.29 0.24 0.28
0.23 0.27 0.21 0.18 0.18 0.20 0.34 0.31 0.31 0.25 0.36
1.08 1.05 1.1 1.12 1.14 1.10 1.07 1.06 1.06 1.06 1.07
5560 5830 6223
0.92 5.47 2.54
0.72 0.39 0.86
0.65 0.1 0.21
1.08 1.09 1.02
Salam-52 Salam-02 Salam-16
N.B. Pr: Pristane. Ph: Phytane. CPI: Carbon Preference Index.
Fig. 7. Gas chromatogram of the C15+ saturated hydrocarbons for the extract of the studied samples. (A) Khatatba Formation (B) L. Bahariya Member (C) U. Bahariya Member (D) A/R ‘‘G” Member.
3.4.2. Tricyclic terpanes and hopanes Results of Gas Chromatography/Mass spectrometry (GC/MS) chromatograms using triterpanes (M/Z 191) and steranes (M/Z 217) for the saturated fractions of the study rock and oil samples are used in the present study, due to their valuable interpretative data. In the present study four representative samples of source rock hydrocarbon extracts from Khatatba Formation (1 sample from Salam-3X well), Lower and Upper Bahariya members (2 samples
from Salam-52 well) and Abu Roash ‘G’ Member (1 sample from Salam-52 well). Two oil samples representing, Lower Bahariya from Salam-16 well and Upper Bahariya from Salam-02 well were analysed by gas chromatography (GC) and gas chromatography/ mass spectrometry (GC/MS). The fingerprint (M/Z 191) gas chromatography/mass spectrometry analysis for Khatatba Formation from well Salam-3X (Fig. 9A) shows a relative abundance of tricyclic terpane indicating mixed organic source with significant terrestrial organic matter contribu-
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tion [14] [15] with mature source rock indicated by Ts/Tm value (Table 3)[16][17]. Lower and Upper Bahariya members fingerprint (M/Z 191) (Fig. 9B and C) show slightly high contribution of tricyclic terpanes with C25/C26 ratio (2.1–2.13) and Ts/Tm value (0.86–0.74) (Table 3) may reflect marine origin of organic matter with input of terrestrial organic matter deposited under lacustrine and/or marine carbonate environment with slightly mature source
Table 3 GC–MS data for the biomarkers of the study samples.
Fig. 8. Plot of Pristane/n-C17 vs. Phytane/n-C18 of Khatatba Formation and Lower Bahariya, Upper Bahariya and A/R ‘G’ member samples [12,13].
Type of sample
Extract
Well name
Salam-52
Formation
Bahariya
Depth (ft) C27 C28 C29 Hopane/sterane Ts/Tm Ts/Ts+Tm C34/C35 hopane C35/C34 hopane C25/C26 Diasterane index
5960 40.7 32.5 26.8 3.95 0.86 0.79 9.48 0.41 2.1 41.2
Oil
6260 40.4 32.6 27 6.2 0.74 0.43 7.47 0.13 2.13 67.1
Salam-3X
Salam-16
A/R ‘G’
Khatatba
Bahariya
5560 38.5 35.3 26.2 1.7 0.97 0.49 2.42 0.41 2.18 26.3
– 33 37 30 – – – – – – –
6223 34.2 26.3 39.5 12.1 0.45 0.31 3.1 0.75 0.73 16.2
Fig. 9. Gas chromatogram- mass spectrometry of terpanes (M/Z 191) For the saturated hydrocarbon fraction of the extract of the studied samples. (A) Khatatba Formation (B) L. Bahariya Member (C) U. Bahariya Member (D) A/R ‘‘G” Member.
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Fig. 10. Gas chromatogram- mass spectrometry of steranes (M/Z 217) of the saturated hydrocarbon fractions for extract of the study samples. (A) Khatatba Formation (B) L. Bahariya Member (C) U. Bahariya Member (D) A/R ‘‘G” Member.
Fig. 11. Triangular plots showing the relative concentration of C27, C28 and C29 regular steranes for the study samples [19,20].
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rock. The C24 relative abundance and C35 homohopane index (0.41– 0.13) reflects reducing environment of deposition and integrated with C29, C30 norhopane abundance in the study samples [18]. The fingerprint of A/R ‘G’ Member (M/Z 191) (Fig. 9D) have moderate abundance of tricyclic terpanes with C25/C26 ratio 2.18 with Ts/Tm value 0.97(Table 3) shows moderately mature source rock deposited under lacustrine saline and/or marine carbonate or marine calcareous environment. The C35/C34 hopanes ratio of A/R ‘G’ Member is 0.41 with relative abundance of C29 and C30 norhopanes reflecting calcareous facies with reducing environment [18]. 3.4.3. Steranes and diasteranes The fingerprint of GC/MS (M/Z 217) for Khatatba Formation (Fig. 10A) shows abundance of C29 steranes relative to C27 steranes which implies significant terrestrial contribution relative to marine
input. The diasteranes/sterane shows that Khatatba Formation is more mature than the other studied formations. The Lower and Upper Bahariya member’s fingerprint of GC/MS (M/Z 217) (Fig. 10B and C) shows the distribution of regular sterane of C27, C28 and C29. The C27 regular sterane percent (40.4– 40.7%), C28 regular sterane percent (32.6–32.5%) and C29 regular sterane (27–26.8%) (Table 3) suggest mixed organic source input with significant marine organic matter deposited in marine carbonate environment .The diasterane index of Bahariya Formation is (67.1 and 41.2) (Table 3) confirming the same result. The diasterane/sterane of Bahariya Formation reflects moderately mature source rock. The Abu Roash ‘G’ Member extract fingerprint of GC/MS (M/Z 217) (Fig. 10D) have C27, C28 and C29 regular sterane ratio 38.5, 35.3 and 26.2% respectively (Table 3) This data may suggest mixed terrestrial and marine organic matter input, with a diasterane
Fig. 12. Gas chromatogram of the C15+ saturated hydrocarbon in Lower Bahariya oil sample in Salam-16 well.
Fig. 13. Gas chromatogram of the C15+ saturated hydrocarbon in Upper Bahariya oil sample from Salam-02 well.
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index 26.3, which reflects mixed terrestrial and marine organic matter input deposited in marine carbonate and/or marine calcareous source rock facies with moderately mature source rock. The relative concentration of C27, C28 and C29 regular steranes for the study samples plotted on the ternary diagram [19,20] (Fig. 11) confirm the previously mentioned depositional environment. 3.5. Oil characterization Two oil samples representing Baharyia reservoirs are analysed. The oil sample fingerprint of saturated hydrocarbon from Lower
11
Bahariya reservoir in well Salam-16 (Fig. 12) and Upper Bahariya reservoir in well Salam-02 (Fig. 13) shows predominance of C15C30 with CPI 1.02 and 1.09 respectively (table 2). The isoprenoid data for the oil sample Pr/Ph is 2.54 and 5.47, the Pr/nC17 and the Ph/nC18 are 0.86 and 0.21 and 0.39 and 0.1 respectively. This data suggested that the oil samples have a mixed organic source with significant terrestrial organic matter input deposited under oxidizing environment (Fig. 8). The fingerprint of GC/MS (M/Z 191) for the studied oil sample from Lower Bahariya reservoir (Fig. 14) shows a relatively moderate abundance of triterpanes with high concentration of C30 hopane peak, with Ts/Tm and C35/C34 homohopane ratio of 0.45
Fig. 14. Gas chromatogram- mass spectrometry of terpanes (M/Z 191) of saturated hydrocarbon fraction in Lower Bahariya oil sample.
Fig. 15. Gas chromatogram- mass spectrometry of steranes (M/Z 217) of saturated hydrocarbon fraction in Lower Bahariya oil sample.
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and 0.75 respectively, this data reflects mixed organic matter with significant terrestrial input deposited under saline to hypersaline environment with slightly oxidizing environment. The saturated fraction GC/MS fingerprint (M/Z 217) of Lower Bahariya reservoir (Fig. 15) represents the distribution of steranes and diasteranes. The predominance of C29 regular sterane 39.5% (Table 3) and C28 & C27 values are 26.3 and 34.2 respectively suggests significant terrestrial organic matter input with marine organic matter. Interpretation of the ternary diagram (Fig. 11) confirms this conclusion. The diasterane index for the study samples equals
16.2 (Table 3) this value indicates lacustrine saline and/or marine calcareous environment of deposition.
3.6. Oil – source rock correlation In the present study, the oil – source correlation carried out between oil produced from Bahariya reservoir and the extracts of Khatatba and Bahariya formations, as well as, Abu Roash ‘‘G” member, throughout the parameters derived from fingerprints of GC and GC/MS (Figs. 16–18 and Tables 2–3). according to [15–21].
Fig. 16. Oil-Source rock correlation with C15+ diagram of the study samples.
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Fig. 17. Oil-Source rock correlation using terpane (M/Z 191) of the study samples.
3.7. Oil – source rock correlation based on GC The results show that the GC fingerprint of the Khatatba extract (Fig. 16) has the dominance of peaks nC15-nC25 which indicates type II/III kerogen as the maximum peak concentration at C15- C30. While the Lower and upper Bahariya members
extract reveals peak concentration of n-alkanes C17 to C25 with maximum of C17-C21 indicating significant input of marine organisms with contribution of terrestrial organic remains. The Abu Roash ‘G’ Member extracts shows increasing in normal alkanes from C15-C30, suggests mixed organic matter input. On the other side, The oil samples fingerprints from the Lower Bahariya
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Fig. 18. Oil-Source rock correlation using steranes (M/Z 217) of the study samples.
reservoir in well Salam-16 and Upper Bahariya reservoir in well Salam-02 (Fig. 16) shows predominance of C15-C30, this data suggested mixed organic source with significant terrestrial organic matter input. Khatatba Formation shows the isoprenoids Pr/Ph ratio ranges from 0.53 to 1.61. Pr/nC17 and Ph/nC18 ratio ranges from 0.22 to 0.32 and 0.18 to 0.34 respectively, with CPI value ranges from 1.05 to 1.14 (table 2), all reflects mixed organic matter input with significant terrestrial contribution under reducing environment (Fig. 8). The isoprenoids (Pristane/phytane) ratio of the Bahariya Formation are 0.78 and 0.96,and Pr/nC17 and Ph/nC18 are 0.28 and 0.24 and 0.36 and 0.25 respectively(Table 2) The isoprenoids
data shows mainly marine organic matter input with contribution of terrestrial input deposited under reducing condition. The isoprenoid Pr/Ph for A/R ‘G’ Member is 0.92 with Pr/nC17 and Ph/ nC18 ratio is 0.72 and 0.65 respectively, with CPI value 1.08 (Table 2) suggests mixed organic matter input deposited under transitional environment. For oil samples, the isoprenoid data for the oil sample Pr/Ph is 2.54 and 5.47 and the Pr/nC17 and the Ph/nC18 are 0.86 and 0.39 and 0.21&0.1 respectively (Table 2), with CPI 1.02 and 1.09. This data suggested that the oil samples has mixed organic source with significant terrestrial organic matter input deposited under oxidizing environment (Fig. 8).
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3.8. Oil – source rock correlation based on GC/MS
4. Conclusions
The fingerprint (M/Z 191) gas chromatography/mass spectrometry analysis of the Khatatba Formation from well Salam- 3X (Fig. 17) shows a relative abundance of tricyclic terpane indicating mixed organic source with significant terrestrial organic matter contribution, with mature source rock indicating from Ts/Tm value(Table 3) [18].while in the Lower and Upper Bahariya members (Fig. 17) shows slightly high contribution of tricyclic terpanes with C25/C26 ratio (2.13–2.1) and Ts/Tm value (0.74–0.86) may reflect marine origin of organic matter with input of terrestrial organic matter deposited under lacustrine and/or marine carbonate environment with slightly mature source rock. The C24 relative abundance and C35 homohopane index (0.13–0.41) reflects reducing environment of deposition and integrated with C29, C30 norhopane abundance in the study samples. The fingerprint of A/R ‘G’ Member have moderate abundance of tricyclic terpanes with C25/C26 ratio 2.18 with Ts/Tm value 0.97 (Table 3) shows moderately mature source rock deposited under lacustrine saline and/or marine carbonate or marine calcareous environment. The C35/C34 hopanes ratio is 0.41 with relative abundance of C29 and C30 norhopanes reflect calcareous facies with reducing environment. On other hand, The fingerprint (M/Z 191) of oil sample from Lower Bahariya reservoir (Fig. 18) shows a relatively moderate abundance of triterpanes with high concentration of C30 hopane peak, with Ts/Tm and C35/C34 homohopane ratio are 0.45 and 0.75 respectively (Table 3), this data reflects mixed organic matter with significant terrestrial input deposited under saline to hypersaline environment with slightly oxidizing environment. The study of steranes and diasteranes biomarkers in saturated fractions of the study samples reflect that the Khatatba Formation (Fig. 18) shows abundance of C29 steranes relative to C27 steranes which implies significant terrestrial contribution relative to marine input. The diasteranes/sterane shows that Khatatba Formation is more mature than the other formations. While The fingerprint of Lower and Upper Bahariya members shows the distribution of regular sterane of C27, C28 and C29, the C27 regular sterane percent (40.4–40.7%), C28 regular sterane percent (32.6–32.5%) and C29 regular sterane (27–26.8%) suggest mixed organic source input with significant marine organic matter deposited in marine carbonate environment .The diasterane index of Bahariya Formation is (67.1 and 41.2) confirming the previous result. The diasterane/ sterane ratio reflects moderately mature source rock. The Abu Roash ‘G’ Member extract fingerprint has C27, C28 and C29 regular sterane ratio 38.5, 35.3 and 26.2% respectively (Table 3). This data may suggest mixed terrestrial and marine organic matter input, with a diasterane index (26.3), deposited in marine carbonate and/or marine calcareous source rock facies with moderately mature source rock. For the oil sample, the saturated fraction fingerprint of Lower Bahariya oil represents the distribution of steranes and diasteranes, with predominance of C29 regular sterane 39.5% and C28 and C27 values are 26.3 and 34.2 respectively suggests significant terrestrial organic matter input with marine organic matter. The diasterane index for the study samples equals 16.2 this value indicates lacustrine saline and/or marine calcareous environment of deposition. The ternary diagram (Fig. 11) confirms this conclusion. Therefore, comparing the studied source rocks extracts and the corresponding crude oils it is clear that there is a correlation between the extract samples of Khatatba source rocks and crude oils from Salam oil field, indicating a good correlation. While each of the extract of Bahariya and Abu Roash source rocks show slight correlation. These evidences indicate that Khtataba source rocks seem to act as the main source for oil generating in Salam oil field with some contribution from Baharyia source rocks., This is agreeing with the conclusions of [22,23].
1. The representative samples of Khatatba Formation have good to very good organic richness with poor to good hydrocarbon potentiality, with type II/III kerogen. It shows a relative abundance of tricyclic terpane indicating mixed organic source with significant terrestrial organic matter contribution deposited under reducing environment . 2. The Bahariya Formation (Lower and upper) has organic richness varies from fair to very good, and poor to good generating source potential with type II/III kerogen. The isoprenoids data shows mainly marine organic matter input with the contribution of terrestrial input deposited under reducing conditions. The biomarker data reflect marine origin of organic matter with the input of terrestrial organic matter deposited under lacustrine and/or marine carbonate environment with slightly mature source rock. 3. Abu Roash ‘‘G” Member reveals organic richness varies from fair to very good, with poor to good generating source potential classified as type II/III kerogen (mixed type). The isoprenoid data suggest mixed organic matter input deposited under transitional environment. The biomarker data show moderately mature source rock deposited under lacustrine saline and/or marine carbonate or marine calcareous environment. 4. The fingerprints of the saturated hydrocarbon fraction of the Baharyia reservoir (Lower and Upper) suggests that the oil samples have a mixed organic source with significant terrestrial organic matter input deposited under saline to hypersaline environment with slightly oxidizing environment. 5. Based on the obtained results, it is suggested that the Baharyia oil has been mainly sourced from deeper horizons (Khatatba Formation) with some contribution from Upper & Lower Baharyia source rocks). Acknowledgements The authors are greatly thankful for the Egyptian General Petroleum Corporation and Khalda Petroleum company for providing the rock and oil samples to complete this research. Gratitudes are due to the Geochemistry Lab, the Exploration Department of the Egyptian Petroleum Research Institute (EPRI); for support in performing the Lab analysis (Rock-Eval 6 analyses, GC and GCMS). Thanks are also extended for two anonymous reviewers for their careful and constructive comments to improve the manuscript. References [1] EGPC (Egyptian General Petroleum Corporation), Western Desert, oil and gas fields (a comprehensive overview). Unpublished Internal Report, 1996, pp. 9– 29. [2] EGPC, (Egyptian General Petroleum Corporation), Western Desert, oil and gas fields, A comprehensive overview, EGPC 11th Petrol. Explor. and Prod. Confer., Cairo, 1992, p. 431. [3] J. Espitalie, G. Deroo, F. Marquis, Rock-Eval pyrolysis and its application, Inst. Fr. Pet. Preprint 33578 (1985) 72. [4] K.E. Peters, J.M. Moldowan, The Biomarker Guide, Interpreting Molecular Fossils in Petroleum and Ancient Sediments, Prentice-Hall, Englewood Cliffs, NJ, 1993, p. 363. [5] K.E. Peters, Guidelines for evaluating petroleum source rock using programmed pyrolysis, AAPG Bull. 70 (1986) 318–329. [6] K.E. Peters, M.R. Cassa, Applied source rock geochemistry. in: L.B. Magoon, W. G. Dows (Eds.), The petroleum system-from source to trap, AAPG, Tulsa, OK, pp. 93–117. [7] D.W. Waples, Geochemistry in Petroleum Exploration, International Human Resources Development Corporation, Boston, 1985, p. 232. [8] K.S. Jackson, P.J. Hawkins, A.J.R. Bennett, Regional facies and geochemical evaluation of southern Denison Trough, APEA J. 20 (1985) 143–158. [9] M.L. Bordenove, J. Espitalie, P. Leplat, J.L. Oudin, M. Vandenbroucke, (Screening techniques for source rock evaluation. in: M.L. Bardenove (Ed.), Applied Petrol. Geochem., Paris Editions Technip., 1993, pp. 217–278.
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Please cite this article in press as: E.A. Abd El-Gawad et al., Origin of Bahariya oil in Salam oil field, Western Desert- Egypt, Egypt. J. Petrol. (2017), https:// doi.org/10.1016/j.ejpe.2017.09.003