Geochemistry of Liquid Hydrocarbons and Natural Gases Combined with 1D Basin Modeling of the Oligocene Shale Source Rock System in the Offshore Nile Delta, Egypt

Abstract

The current study aims to integrate the geochemical characteristics of the Oligocene shale source rock system, oil, condensate, and natural gas samples in the Oligocene sandstone reservoirs from three exploration wells located in the offshore Nile Delta, East Mediterranean Sea, using organic geochemistry and a 1D basin modeling scheme. The Tineh shales exhibit total organic carbon values ranging between 0.90 and 1.89 wt %, along with hydrogen index values in the range of 54–240 mg hydrocarbon/g rock. The geochemical characterization suggests that the shale intervals of the Oligocene Tineh Formation contain type II–III and type III kerogens and, thereby, could be regarded as promising oil- and gas-prone source rocks with high contributions of gas generation potential. The study also reconstructs the 1D thermal and burial history models, showing that the Oligocene Tineh source rock system is in the main oil and wet gas generation phases from the late Miocene to the present time. The simulated basin models reveal the transformation (TR) of 10–50% kerogen to oil during the late Miocene–early Pliocene period and that the Oligocene Tineh source rock system has larger oil generation and expulsion competency, with a TR value of up to 65% during the early Pliocene–Pleistocene time period. The thermogenic gas was also formed during this time and continued to the present day. This study also investigated the presence of oil and condensate in the Oligocene sandstone reservoir samples and revealed that they were generated from mature source rock, ranging from moderately to highly mature stages. This source rock unit was deposited in fluvial to fluvial-deltaic environments under oxic mixed organic conditions and accumulated during the Tertiary time, as evidenced by the presence of the oleanane biomarker dating indicator. The molecular and isotope compositions of natural gases revealed that most of the natural gases in the Oligocene sandstone reservoir are mainly thermogenic methane gases that were generated from mainly mixed organic matter. The thermogenic methane gases were formed mainly from secondary cracking of oil and gas, with small contributions of primary kerogen cracking. The properties of natural gases together with oil and condensate in the Oligocene reservoir rocks suggest that most of the thermogenic methane gases and associated liquid hydrocarbons are derived primarily from the Oligocene shale source rock system and formed by primary kerogen cracking and secondary oil and oil/gas cracking in different thermal maturity stages. Therefore, the Oligocene Tineh Formation can be regarded as self-source generation and self-reservoir rock; hence, an intensive oil exploration and production program can be recommended whenever the Tineh source rock system is is well developed and deeply buried.

1. Introduction

Exploration across the offshore Mediterranean Sea has a long history of challenges, successes, and failures. Hydrocarbon exploration is yet to continue from shelf to deep and ultradeep water to unlock the potential and find other giant gas fields like the Zohr gas field.^1,2 Recently, exploration activities increased in the Mediterranean Sea to secure the increasing energy demand.

The Nile Delta Basin is a promised hydrocarbon province that produces gas, condensate, and small amounts of oil and is supported by a well-established infrastructure for hydrocarbon production and transportation. The discoveries include numerous fields, which have focused on a number of deep plays and prospects in the Pliocene slope-channel play. However, the petroleum system in the offshore Nile Delta is unclear despite recent big oil and gas findings since few wells have reached the pre-Miocene succession.² Successful exploration in the Nile Delta Basin is found in the Baltim fields, where the natural gas was reservoired in the Abu Madi Formation.³

Over the last decades, many researchers have dealt with evaluating the hydrocarbon-bearing reservoirs in the offshore Nile Delta and characterizing its source rock potentiality through analyzing the available petrophysical, geological, well logging, and geochemical data.⁴⁻¹¹ However, several published studies are believed to have mainly discovered natural gases in most of the fields of the western offshore Nile Delta, which were sourced from the organic-rich sedimentary rocks of the late Mesozoic–late Cenozoic era (i.e., Oligocene–Pliocene).^10,12,13 The main source of gas and condensate in the western offshore Nile Delta is considered to be the Oligocene–early Miocene formations.¹⁴

Major oil and gas findings have resulted from recent exploration in the Nile Delta Basin; nevertheless, source-reservoir linkages in the onshore portion of the basin remain unclear. This is a result of the thick Oligocene–Pliocene limited penetrations and restricted sample availability, which restricts a full comprehensive evaluation of the plays’ creative potential. Discussing the potential contribution of the Oligocene Tineh Formation, as a self-source generation and self-reservoir rock in deeply buried systems, is another important task; if achieved, it will favor further intensive oil exploration and production activity in the offshore Nile Delta. Therefore, more analyses are still needed in the whole Nile Delta Basin, more specifically of the Oligocene rocks, to investigate its source rock potential and maturity as well as to detect sources of liquid hydrocarbon and natural gas accumulations and their related source rocks. The use of organic geochemical data sets, along with a 1D basin modeling, will play a vital role in understanding the whole petroleum system in the study area. The basin-scale model will help in setting a future roadmap for detailed scientific investigations in the Nile Delta. In this regard, the current study came as an attempt to investigate the source characteristics and hydrocarbon potential of the Oligocene deposits, together with the intricate processes by which the hydrocarbons (oil, condensate, and gas) are supplied, charged, mixed, and transformed in the offshore Nile Delta, East Mediterranean Sea (Figure 1A).

Figure 1.

(A) Location map of the studied wells in the offshore Nile Delta region. (B) Map showing the main structural trends in the offshore Nile Cone and location of the study area.

2. Geological Setting

The deep-sea fan of the Nile Delta was formed as a result of the Messinian Salinity Crisis during the late Miocene,¹⁵ where three major fault trends define the complicated structural pattern of the whole area (Figure 1B).^6,7 The Messinian salt basin is defined by the E–W faults, the NE–SW-oriented trend, and the NW–SE-oriented Misfaq–Bardawil trend.^4,16

The stratigraphic column of the Nile Delta shows rock units ranging in age from Jurassic to Quaternary (Figure 2). The Jurassic formations mark the end of the penetrated sedimentary succession in the Nile Delta (Figure 2), which are considered the oldest rock units in the area.¹⁶ The Neogene–Quaternary clastics represent the rock units that have petroleum potential.^17,18 The lithological constituents are mainly sandstone and shale beds, which are frequently intercalated, with minor thin beds of limestone.

Figure 2.

Stratigraphic correlation chart for the Nile Delta region showing the Mesozoic–Cenozoic successions.

The drilled stratigraphic units (in the studied wells) from the base to the top can be summarized as the following: the Oligocene and early Miocene clastics (Tineh and Qantara formations), with significant hydrocarbon fields of the El Qantara, Temsah, Raven, and Nouts fields. Siliciclastic fluvial facies of high thickness have represented Oligocene rock units.^19,20 The Tineh and Qantara formations were followed by the middle-to-late Miocene deposits of the Sidi Salem, Qawasim, and Abu Madi formations. The evaporitic composition is represented mainly by the Rosetta member, which acts as a marker in seismic data interpretation and also as a regional seal for the underlying hydrocarbon reservoirs. The Pliocene and Pleistocene deposits that are represented mainly by the Kafr El Sheikh, El Wastani, and Mit Ghamr/Bilqas formations. However, marine facies which are represented in the Kafr El-Sheikh Formation covered the Nile Delta Basin during the lower Pliocene²⁰⁻²² (Figure 2).

3. Material and Experimental Methods

3.1. Geochemical Analyses of the Oligocene Shale Formation

In the current study, sixty-eight cutting shale samples of the Oligocene Tineh Formation were collected from one exploration well (Jh 64-1R) located in the northwest Damietta (NWD) concession (Figure 1A). These shale samples were subjected to total organic carbon content (TOC) and programmed pyrolysis (Rock-Eval). These geochemical analyses were carried out by StratoChem Services (Cairo, Egypt).

The shale samples were crashed to a 40-mesh size, and then a selected weight of 200 mg was put in contact with diluted HCl to remove the carbonate content. The samples are then subjected to measurement of the TOC content using a LECO C230 system.

The programmed pyrolysis was conducted on approximately 100 mg of the powdered samples using a Rock-Eval 6 instrument; the 100 mg amount was heated up to 600 °C within a helium atmosphere following the scheme designed by Espitalie et al.²³ The oven’s temperature was maintained at 300 °C for 3 min and then increased to 25 °C per minute. The parameters that were evaluated during the pyrolysis scheme included free hydrocarbon (S₁), the remaining hydrocarbon (S₂), the amount of CO₂ during the thermal alteration of the oxygenated organic compounds (S₃), and the temperature at the maximum S₂ (T_max), as shown in Table 1. The estimation of the parameters above was instrumental in deriving the hydrogen index (HI), oxygen index (OI), and petroleum yield (PY) using Peter and Cassa’s Rock-Eval scheme²⁴ (1994).

Table 1. Geochemical Results of the Analyzed Shales from the Oligocene Tineh Formation in the Jh 64-1R Well, Including TOC Content, Rock-Eval Pyrolysis, and Calculated Vitrinite Reflectance (% VR_o)^a.

well	depth (m)	TOC wt %	Rock-Eval pyrolysis data							calculated VRo (%)
			S1-HC (mg/g)	S2-HC (mg/g)	S3-CO2 (mg/g)	Tmax (°C)	HI (mg/g)	OI (mg/g)	PY (mg/g)
Jh 64-1R	4885	1.10	0.11	2.62	0.95	438	238	86	2.73	0.72
	4890	1.02	0.11	2.38	0.9	439	233	88	2.49	0.74
	4945	0.95	0.13	2.28	1.46	440	240	154	2.41	0.76
	4950	1.23	0.14	2.63	1.13	438	214	92	2.77	0.72
	4955	1.29	0.17	2.85	1.11	437	221	86	3.02	0.71
	4960	1.34	0.15	2.74	1.37	440	204	102	2.89	0.76
	4965	1.46	0.13	3.07	1.03	439	210	71	3.2	0.74
	4970	1.31	0.12	2.71	1.78	438	207	136	2.83	0.72
	4975	1.39	0.12	2.87	1.08	441	206	78	2.99	0.78
	4980	1.31	0.14	2.89	1.29	439	221	98	3.03	0.74
	4985	1.37	0.16	2.85	2.11	442	208	154	3.01	0.80
	4990	1.10	0.11	2.34	1.24	441	213	113	2.45	0.78
	4995	1.07	0.1	2.22	1.05	442	207	98	2.32	0.80
	5000	1.00	0.10	2.00	1.08	440	201	108	2.23	0.76
	5005	1.17	0.15	2.48	1.2	441	212	103	2.25	0.78
	5015	1.07	0.14	2.19	1.21	442	205	113	2.43	0.80
	5020	1.09	0.11	1.74	1.10	442	160	101	1.62	0.80
	5030	0.97	0.10	1.64	0.78	443	169	80	2.32	0.81
	5035	0.97	0.09	2.01	1.09	443	208	113	2.3	0.81
	5040	0.93	0.11	1.83	1.19	441	198	129	2.38	0.78
	5045	1.41	0.11	2.20	1.07	440	156	76	2.29	0.76
	5055	1.08	0.11	1.75	0.90	442	162	83	2.33	0.80
	5070	0.94	0.11	1.83	1.55	442	195	165	2.17	0.80
	5075	0.99	0.09	2.06	1.29	441	209	131	2.3	0.78
	5080	1.00	0.08	1.77	1.59	438	178	160	2.22	0.72
	5085	1.08	0.1	1.78	1.31	440	165	121	2	0.76
	5100	1.20	0.13	2.31	1.11	442	192	93	1.97	0.80
	5105	1.08	0.11	1.87	0.68	442	173	63	1.6	0.80
	5108	1.11	0.13	2.19	1.21	444	197	109	1.67	0.83
	5115	1.20	0.1	2.1	1.16	443	175	97	1.72	0.81
	5120	1.25	0.12	2.25	1.16	442	180	93	1.49	0.80
	5125	1.33	0.13	2.38	1.13	441	179	85	1.07	0.78
	5130	1.30	0.1	2.13	1.07	443	164	82	1.01	0.81
	5135	1.22	0.1	2.15	1.07	444	176	88	0.76	0.83
	5140	1.32	0.13	2.3	1.31	443	174	99	0.9	0.81
	5145	0.97	0.12	1.5	1.12	446	155	116	0.84	0.87
	5150	1.20	0.13	2.19	1.18	444	183	98	0.98	0.83
	5155	1.26	0.11	2.19	1.14	445	174	90	1.43	0.85
	5160	1.33	0.11	2.27	1.11	444	171	83	1.61	0.83
	5165	1.24	0.14	2.15	2.75	443	173	222	1.72	0.81
	5170	1.27	0.14	2.19	1.42	445	172	112	1.47	0.85
	5175	1.26	0.13	2.04	1.12	444	162	89	1.31	0.83
	5180	1.26	0.14	2.16	1.3	442	171	103	1.53	0.80
	5185	1.28	0.13	2.09	1.03	444	163	80	1.54	0.83
	5195	1.16	0.18	1.82	1.43	445	157	123	1.55	0.85
	5200	1.29	0.09	1.88	1.16	442	146	90	1.66	0.80
	5210	1.07	0.06	1.54	1.06	444	144	99	1.56	0.83
	5215	1.11	0.07	1.6	1.04	443	144	94	1.8	0.81
	5220	1.26	0.07	1.65	1.7	444	131	135	1.77	0.83
	5225	1.01	0.07	1.42	1.55	446	141	153	1.73	0.87
	5285	1.89	0.05	1.02	1.37	443	54	72	2.23	0.81
	5290	1.25	0.05	0.96	2.02	445	77	162	2.25	0.85
	5295	1.30	0.06	0.7	2.18	446	54	168	2.43	0.87
	5300	0.94	0.06	0.84	2.32	446	90	248	1.62	0.87
	5305	1.06	0.06	0.78	1.97	445	74	186	2.32	0.85
	5310	1.15	0.07	0.91	4.12	444	79	358	2.3	0.83
	5330	0.99	0.07	1.36	1.44	446	138	146	2.38	0.87
	5385	1.11	0.09	1.52	1.09	447	137	98	2.29	0.89
	5390	1.08	0.08	1.64	1.15	446	152	106	2.33	0.87
	5395	0.99	0.08	1.39	1.19	448	140	120	2.17	0.90
	5450	0.90	0.07	1.24	1.14	446	138	127	2.3	0.87
	5610	0.96	0.07	1.46	1.04	445	151	108	2.22	0.85
	5615	1.00	0.07	1.47	1.27	446	148	128	2	0.87
	5620	0.99	0.07	1.48	1.74	446	149	176	1.97	0.87
	5625	1.10	0.09	1.57	2.3	449	143	209	1.6	0.92
	5630	0.98	0.09	1.47	1.9	447	150	193	1.67	0.89
	5640	1.01	0.09	1.71	1.97	446	169	195	1.72	0.87
	5645	0.98	0.09	1.68	1.97	448	171	200	1.49	0.90
	5675	0.90	0.09	1.64	1.54	450	183	172	1.07	0.94

^aTOC = total organic carbon; S₁-peak = free contents of hydrocarbon (mg HC/g rock); S₂-peak = remaining hydrocarbon potential (mg HC/g rock); S₃-peak = produced carbon dioxide (mg CO₂/g rock); HI = hydrogen index [S₂ × 100/TOC (mg HC/g rock)]; OI = oxygen index [S₃ × 100/TOC (mg CO₂/g TOC)]; T_max = maximum temperature at the peak of S₂ (°C); calculated VR = calculated vitrinite reflectance from T_max according to the equation (Ro = 0.018 × T_max – 7.16).

3.2. 1D Basin Modeling

The geological and geochemical data together with thermal maturity calibration data were used as input data for reconstructing burial and thermal history models of the Oligocene Tineh source rock system using Schlumberger’s PetroMod 1D modeling platform. In this case, the studied exploration well (Jh 64-1R) that was drilled to a total depth of up to 5760 m (Table 2) was used to build the basin modeling scheme. Some essential parameters for reconstructing the 1D model, including sedimentary rock types and depositional and erosional periods, were mustered from the reports of this well (Table 2). The age of sedimentary successions mentioned in Table 2 was derived from the data published by Krott et al.²⁵

Table 2. Basin Model Input Data Used to Reconstruct the Burial and Thermal History of One Well Location (Jh 64-1R) in the Offshore Nile Delta, the Eastern Mediterranean Sea (Egypt), as Shown in Figure 1.

formation	lithology	deposition ages (Ma)		erosion ages (Ma)		erosion thickness (m)	Jh 64-1R well
		from	to	from	to		top (m)	bottom (m)	thickness (m)	calibration thermal maturity data
										calculated vitrinite		temperature
										depth (m)	% Ro	depth (m)	°C
Mit Ghamr	sandstone, claystone, siltstone	0.012	0.00				76.5	1184.0	1107.5	5000	0.76	1183	54
El-Wastani	sandstone, claystone	2.58	0.012				1184.0	1688.0	504	5020	0.80	1688	62
Kafr El-Sheikh	sandstone, claystone, siltstone	5.33	2.58				1688.0	3307.0	1619	5040	0.78	3337	106
Abu Madi	sandstone, claystone, siltstone, anhydrite	7.25	5.33	15.97	13.82	800	3307.0	3412.5	105.5	5070	0.80	3612	108
Qawassim	sandstone, claystone, siltstone, anhydrite	11.63	7.25				3412.5	3908.0	495.5	5085	0.76	3990	116
Sidi Salim	sandstone, claystone, siltstone, limestone	15.97	11.63				3908.0	4530.0	622	5108	0.83	4525	124
Qantara	sandstone, claystone, limestone	23.30	15.97				4530.0	5017.0	487	5130	0.81	4725	136
Tineh	sandstone, claystone, siltstone	27.82	23.30				4800.0	5760.0	960	5150	0.83	4800	141
total depth							5760			5170	0.85	5760	170
										5195	0.85
										5225	0.87
										5300	0.87
										5385	0.89
										5395	0.90
										5620	0.87
										5625	0.92
										5645	0.90
										5675	0.94

In this study, the measured vitrinite reflectance data for the different rock units encountered in the studied well are not available. In this case, the reliable maximum temperature (T_max) of the S₂ hydrocarbon yield was used to calculate the vitrinite reflectance (VRo), according to Jarvie’s equation (VRo = 0.018 × T_max – 7.16).²⁶ The calculated vitrinite reflectance from T_max data helped establish the thermal maturation level of the Oligocene shale source rock system within the Tineh Formation in the studied well.

3.3. Physical and Chemical Analyses of Liquid Hydrocarbons

In the current study, three liquid hydrocarbon (2 oils and 1 condensate) samples representing the Oligocene sandstone reservoir were collected from two exploration wells (Jh 64-1R and a nearby well, X1) located in the northwest Damietta (NWD) concession and the offshore Nile Delta (Figure 1A). These oil and condensate samples were studied by several physical and geochemical analyses, including API degree gravity, bulk fractionation process of whole composition (SARA), gas chromatography (GC), and GC–mass spectrometry (GC–MS) of the saturated and aromatic hydrocarbon factions.

The whole oil and condensate samples were subjected to specific gravity (SG) analysis, and then, the API gravity was calculated, according to the equation: API = (141.5/SG)-131.5. This analysis was carried out at StratoChem Laboratories (Cairo, Egypt), and they supplied the results.

Afterward, the oil and condensate samples were subjected to SARA analysis to be broken down into their individual components, which include saturated, aromatic, resin, and asphaltene fractions, following ASTM guidelines (D 4124). For the SARA analysis, the asphaltene fraction was precipitated from the studied oils by dissolution in hexane. Other fractions, i.e., saturate, aromatic, and resin, were thereafter fractionated using medium-pressure liquid chromatography (MPLC) with a smart line system and solvents of different polarities, including n-hexane, dichloromethane, and methanol, respectively.

The saturated HC fraction was then reserved for further GC analysis. GC analysis was carried out on the aliphatic fraction of the studied oil and condensate samples using a Hewlett-Packard 6890N column with a capillary column with a length of 60 m, an inner diameter of 0.25 μm, and a film thickness of 0.25 μm. The samples were warmed from 30 to 300 °C (at 5 °C/min rate), after which the temperature was held at 320 °C for 23 min. The hydrocarbon compounds were identified through analyses of a known standard, Norwegian Oil Standard NGR NSO-1.

Later, GC–MS was utilized to separate the compounds in the saturated and aromatic hydrocarbon fractions of the analyzed oil and condensate samples. The test was performed on an Agilent Technologies 7890B instrument with a flame ionization detector. Within the GC–MS furnace, the capillary column had a length of 60 m and a diameter of 0.25 mm. The samples were warmed from 100 to 170 °C (at a rate of 1.5 °C/min), after which the temperature was held at 320 °C for 20 min. Finally, the biomarker compositions and their ratio and parameters in the aliphatic and aromatic HC fractions were detected and quantified based on their peak heights using particular ions, such as m/z 178, m/z 184, m/z 191, m/z 192, m/z 217, and m/z 253 mass fragmentograms.

3.4. Chemical Analyses of Natural Gases

Fifteen natural gas samples picked up from the gas-bearing sandstone reservoirs of the Oligocene sequence were also collected from the three exploration wells (Jh 64-1R, well X1, and well X2) located in the northwest Damietta (NWD) concession and the offshore Nile Delta (Figure 1A). These natural gas samples were studied by several geochemical analyses, including molecular gas and isotopic compositions. Most of the geochemical analyses for natural gas samples were also performed at StratoChem Laboratories (Cairo, Egypt) and offered by the Egyptian General Petroleum Corporation (EGPC), along with other data sets.

In this regard, components of individual hydrocarbon gases (C₁–C₅) and N₂ and CO₂ gases (permanent gases) were separated using three capillary and packed columns, respectively. Both capillary and packed columns are connected to one oven, whose temperature is raised from 50 to 180 °C at a rate of 10 °C/min.

In addition, the carbon (δ¹³C) and hydrogen (δD) isotopic compositions of hydrocarbon gases were detected with a Thermo Finnigan Deltaplus XL mass spectrometer. A gas chromatograph was used to separate the gas components, which were then injected into the mass spectrometer. Isotope values are reported in per-mile units (‰) attributed to the PDB (common Pee Dee Belemnite) and SMOW (Vienna Standard Mean Ocean Water) standards (the analytical precision of the δ¹³C and δ D measurements is approximately ±0.2 and ±2‰, respectively).²⁷

4. Results

4.1. Source Rock Geochemical Results

Table 1 presents a summary of the geochemical results obtained from the shale samples of the Oligocene Tineh Formation extracted from the Jh 64-1R well under investigation. Important parameters, including TOC content, S₁, S₂, S₃, T_max, HI, OI, and GP, collectively offer an extensive perspective on the organic makeup of the sediment and its potential for generating petroleum. These parameters play a vital role in evaluating the source rock’s capacity for petroleum generation under thermal maturation conditions, as elucidated by Jarvie²⁸ and Peters.²⁹

The TOC content in the Oligocene Tineh Formation’s shale ranges from 0.90% to 1.89 wt %. The majority of the samples (53) surpass 1 wt %, with the other 15 samples falling within the range of 0.90%–0.99 wt % (Table 1).

The S₂ values obtained from kerogen pyrolysis are notably low and range from 0.70 to 3.07 mg of HC/g of rock, and most samples from the studied well exhibit S₂ values less than 2 mg of HC/g of rock (Table 1). Additionally, most of the analyzed samples show S₂ generation values greater than 1, leading to a reliable Rock-Eval T_max range from 437 to 450 °C (Table 1). Moreover, the research computed HI and OI values utilizing the S₂ and S₃ outcomes, encompassing a spectrum of 54–240 mg of hydrocarbon/g of rock and 63–358 mg of CO₂/g of rock, respectively (please consult Table 1 for details). Following the Rock-Eval results, the majority of the samples from the examined well display HI values less than 200 mg of HC/g of TOC, spanning from 54 to 198. Other samples demonstrate slightly higher HI values, ranging from 201 to 240 mg of HC/g of TOC (as indicated in Table 1).

4.2. Characteristics of Liquid Hydrocarbons

4.2.1. Physical and Bulk Geochemical Composition

Herein, the API degree for the analyzed oil and condensate samples was calculated (Table 2). The examined samples have high API values in the range of 34.4–46.0° (Table 3). However, the API values provide genetic information and classification of the hydrocarbons, i.e., oil or condensate. Accordingly, the sample that has high API values of more than 40° (46.0°) is considered to be the condensate, while the two oils have relatively low API values, between 34.4 and 34.6° (Table 3), and are classified as light crude oil. However, the high API value of the analyzed oil and condensate samples suggests that these hydrocarbons are nonbiodegraded and were generated from highly mature source rock because API values increased with an increase in the degree of thermal maturity.

Table 3. Physical and Geochemical Characteristics of the Examined Oil and Condensate Samples from the Oligocene Sandstone Reservoirs in the Two Studied Wells (Jh 64-1R and X-1), in the Offshore Nile Delta, Eastern Mediterranean Sea (Egypt), Including API Values, δ¹³C Isotope Compositions (‰), and Bulk Oil Composition (i.e., Saturated, Aromatic, Resin, and Asphaltene), as Well as n-Alkane and Isoprenoids of the Saturated Hydrocarbon Fraction^a.

wells	samples	API	δ13C isotope compositions (‰)		bulk hydrocarbon composition (%)				saturate/aromatic ratio	n-alkane and isoprenoids
			δ13C saturate	δ13C aromatic	saturate	aromatic	resin	asphaltene		Pr/Ph	Pr/C17	Ph/C18	CPI	WI
X-1	oil	34.4	–28.34	–25.87	58.43	27.28	11.71	2.57	2.14	3.34	0.33	0.10	1.07	0.97
X-2	oil	34.6	–28.38	–25.85	56.67	26.94	14.49	1.91	2.10	3.35	0.33	0.11	1.08	0.95
Jh64-1R	condensate	46.0	–28.20	26.40	79.23	14.33	6.02	0.43	5.53	5.16	0.39	0.09	1.05	0.76

^aPr = pristane; Ph = phytane; CPI = carbon preference index (1): {2 [C₂₃ + C₂₅ + C₂₇ + C₂₉]/[C₂₂ + 2 (C₂₄ + C₂₆ + C₂₈) + C₃₀]}; WI = waxiness degree: Σ(n-C₂₁ – n-C₃₁)/Σ(n-C₁₅ – n-C₂₀).

Furthermore, the relative proportions of saturated, aromatic, resin, and asphaltene fractions within the oil and condensate samples were separated and calculated, with these comparative ratios outlined in Table 3. The data reveal that the saturated fraction predominates, constituting 56.67–79.23% of the composition, followed by the aromatic hydrocarbon, which constitutes 14.33–27.28% (Table 3). However, the prevalence of saturated hydrocarbon is influenced by the thermal maturity level of their source rock. In this regard, the saturated HC enrichment in the current study indicates that the samples were generated from mature source rocks, with a highly mature level of the condensate sample.

In addition, the polar component (resin + asphaltene) shows a low amount of all samples, ranging from 6.45 to 16.40% (as elaborated in Table 3). From this point of view, the studied oil and condensate samples are nonbiodegradable and generated from highly mature source rock, as reported by a saturated HC enrichment and very low amounts of asphaltene (Table 3).

4.2.2. Bulk Stable δ¹³C Composition

Comprehensive bulk stable carbon isotope (δ¹³C) analysis, encompassing both the aliphatic and aromatic hydrocarbon fractions, was performed on two oil samples and one condensate. The outcomes of this analysis unveiled a range of carbon isotopic values (δ¹³C) for the aliphatic hydrocarbons from −28.20 to −28.38‰ and for the aromatic hydrocarbons from −25.85 to −26.40‰, as detailed in Table 3.

However, these δ¹³C values serve as a means to differentiate between terrestrial and marine organic matter (OM) inputs, as suggested by Sofer³⁰ and Summons et al.³¹ Specifically, lower δ¹³C values (less negative) are indicative of a terrigenous origin, while higher and moderately lighter δ¹³C values (more negative) suggest a marine OM source.³⁰ Consequently, the examined oil and condensate samples appear to be generated from source rock containing mixed OM input, with a highly significant contribution from terrigenous OM. This interpretation is supported by the Sofer diagram, which displays the saturated (δ¹³C sat.) and aromatic (δ¹³C aro.) isotopic composition (Figure 3).

Figure 3.

“Sofer plot” of δ¹³C_aro versus δ¹³C_sat for the examined liquid HC (oil and condensate) samples in the studied wells (Jh 64-1R and X-1).

4.2.3. Hydrocarbon and Biomarker Distributions

The hydrocarbon and biomarker distributions, including normal alkane, isoprenoids, terpanes, and steranes in the saturated fraction of the examined oil and condensate samples, were determined using GC and m/z 191 and m/z 217 mass fragmentograms on GC–MS.

In this case, both oil and condensate samples display unimodal distributions of n-alkane compounds across the C₄–C₄₁ range, as illustrated in Figure 4A. This distribution of hydrocarbons shows a predominance of low- to medium-chain n-alkane molecules between C₄ and C₂₀, with significant quantities of normal alkanes of more than n-C₂₃ (Figure 4A), resulting in carbon preference index (CPI) values ranging from 1.05 to 1.08 and waxy degree values spanning from 0.76 to 0.97, as summarized in Table 3.

Figure 4.

(A) GC, (B) m/z 191, and (C) 217 mass fragmentograms of the aliphatic hydrocarbon fraction in the examined liquid HC (oil and condensate) samples in the studied wells (Jh 64-1R and X-1).

In addition, pristane (Pr) and phytane (Ph) isoprenoids were also observed within this unimodal distribution (Figure 4A). The chromatograms show that the majority of the examined samples typically dominated Pr over Ph, resulting in a high Pr/Ph ratio ranging from 3.35 to 5.16, as indicated in Table 3. In this regard, the condensate sample has a higher Pr/Ph ratio than the oil samples (Table 3). Moreover, when comparing isoprenoid concentrations to n-alkanes (specifically, C₁₇–C₁₈), n-C₁₇ and n-C₁₈ exhibited relative prevalence compared to Pr and Ph (Figure 4A), leading to Pr/n-C₁₇ and Ph/n-C₁₈ ratios in the range of 0.33–0.39 and 0.09–0.11, respectively (Table 3).

The GC–MS analysis also encompassed the identification of hopanoid biomarkers within the saturated portion using a m/z 191 mass fragmentogram. This revealed the presence of various hopanes, including C₃₀ hopanes, C₂₉ norhopanes, and homohopanes ranging from C₃₁ to C₃₄, as depicted in Figure 4B. The C₂₉/C₃₀ hopane values ranged from 0.69 to 0.75 (Table 4), with most samples exhibiting values smaller than 1. However, the C₃₁R/C₃₀ hopane ratio ranged from 0.13 to 0.16 due to the generally lower occurrence of C₃₁R homohopanes compared to C₃₀ hopanes (Figure 4B). The homohopane distributions in the m/z 191 mass fragmentogram resulted in C₃₂ homohopane 22S/(22S + 22R) ratios spanning from 0.56 to 0.59, as presented in Table 4. A noteworthy feature was the presence of oleanane in the m/z 191 mass fragmentogram, resulting in an oleanane index (oleanane/C₃₀ hopane) ranging from 0.45 to 2.13, as listed in Table 4.

Table 4. Biomarker Ratios of the Saturated and Aromatic Hydrocarbon Fractions of the Examined Oil and Condensate Samples from the Oligocene Sandstone Reservoirs in the Two Studied Wells (Jh 64-1R and X-1), the Offshore Nile Delta, the Eastern Mediterranean Sea (Egypt), Illustrating Source Organic Matter, Depositional Environment Conditions, and Thermal Maturity^a.

wells	samples	saturated biomarker parameters and ratios														aromatic biomarker parameters and ratios
		triterpanes and terpanes (m/z 191)								steranes (m/z 217)						m/z 178 + 184	methyl phenanthrenes m/z 178 + 192		monoaromatic m/z 253
		hopanes					tricyclic terpanes			C29 20S/(20S + 20R)	C29 ββ/(ββ + αα)	C29/C27 regular steranes	regular steranes (%)
		C32 22S/(22S + 22R)	C29/C30	HCR31/HC30	Ts/Tm	OL/C30	C26Ti/C25Ti	C24Ti/C23Ti	C22Ti/C21Ti				C27	C28	C29	DBT/P	MPI	% Rc-MPI	C27	C28	C29
X-1	oil	0.58	0.69	0.15	1.69	0.45	1.22	0.55	0.25	0.44	0.47	2.27	20.65	32.38	46.97	0.19	0.65	0.76	36.28	23.49	40.24
X-1	oil	0.56	0.71	0.16	0.83	0.45	1.52	0.65	0.30	0.44	0.54	2.26	20.74	32.28	46.97	0.20	0.64	0.75	33.60	23.49	39.46
Jh 64-1R	condensate	0.59	0.75	0.13	1.88	2.13	1.66	0.50	0.44	0.51	0.58	2.47	18.28	36.50	45.22	0.08	1.01	1.01	38.89	28.24	40.86

^aTs: [C₂₇ 18α(H)-22,29,30-trisnorneohopane], Tm: [C₂₇ 17α(H)-22,29,30-trisnorhopane], C₂₉/C₃₀: C₂₉norhopane/C₃₀hopane, HCR₃₁/HC₃₀: C₃₁regular homohopane/C₃₀hopane, M₃₀/C₃₀: C₃₀moretane/C₃₀hopane, and OL/C₃₀: oleanane/C₃₀hopane. MPI: methylphenanthrene index = 1.5 × (2 MP + 3 MP)/(P + 1 MP + 9 MP), % Rc-MPI = (0.6 × MPI-1) + 0.4.

Additionally, the examined oil and condensate samples exhibited limited quantities of tricyclic terpanes ranging from C₁₉ to C₂₆ (Figure 4B). The distribution of the tricyclic terpanes was used to calculate several tricyclic terpane ratios, such as C₂₄ tri/C₂₃ tri, C₂₆ tri/C₂₅ tri, and C₂₂ tri/C₂₁ tri (Table 4), which are used to assess the OM input and the depositional environmental setting of the probable source rock for the studied oil and condensate samples.

In the saturated hydrocarbon fraction, steranes and diasteranes were also identified using the m/z 217 mass fragmentogram (Figure 4C). In general, steranes were more abundant than diasteranes in the samples. The distribution of regular steranes, particularly C₂₇–C₂₉ steranes, was mainly composed of C₂₉ regular steranes, with lesser amounts of C₂₇ and C₂₈ regular steranes (Figure 5C). This resulted in relative percentages ranging from 45.22 to 46.97% for C₂₉, 32.28 to 36.50% for C₂₈, and 18.28 to 20.65% for C₂₇, as summarized in Table 4. Additionally, standard sterane ratios, such as C₂₉/C₂₇ regular, C₂₉ 20S/(20S + 20R), and C₂₉ ββ/(ββ + αα), were calculated for further analysis, as presented in Table 4.

Figure 5.

Burial overlap with thermal maturity and thermal gradient history (colored areas) across all rock units (left) and models of Easy % Ro maturity and geothermal history in the studied well (Jh 64-1R) (right).

In the examined oil and condensate samples, the analysis of heterocyclic and polycyclic aromatic compounds in the aromatic hydrocarbon fraction was also carried out using multiple ions in the m/z 178, m/z 184, m/z 192, and m/z 253 mass fragmentograms. Notable aromatic hydrocarbons identified in these ions included dibenzothiophene (DBT), phenanthrene (P), methylphenanthrene (MP), and monoaromatic steroids (MAS). In this case, certain ranges of biomarker aromatic parameters and ratios were examined, including the dibenzothiophene/phenanthrene ratio (DBT/P) and the methylphenanthrene index (MPI). The DBT/P ratio in the examined oil and condensate samples varied from 0.08 to 0.20 (Table 4). The MPI-1 values were estimated and fell within the range of 0.64–1.01 (Table 3). These MPI-1 values were used to determine equivalent vitrinite reflectance (% Rc MPI) and were found to be in the range of 0.75–1.01%, as specified in Table 4.

In addition, the distribution of monoaromatic steroids, particularly C₂₇–C₂₉ MAS, was mainly composed of C₂₉ MAS, with significant amounts of C₂₇ and C₂₈ MASs, with relative percentages in the range of 39.46–40.86, 30.89–36.28, and 23.49–28.24%, respectively (Table 4).

4.3. Molecular Composition of Natural Gases

The molecular composition of studied natural gases shows that most of the samples dominate by a methane content of more than 70% in the range of 71.71–90.82%, except three gas samples from the X2 and X1 wells, which have a relatively low methane content with values between 63.92 and 65.60% (Table 5). These natural gases also have homologue gas components (C₂–C₅) in low concentrations of less than 10% (Table 5). In addition, the dominant nonhydrocarbon gases, i.e., N₂ and CO₂, are also presented with low amounts for most of the analyzed natural gases (Table 5). Most of the natural gas samples from Jh 64-1R and well X1 have N₂ gases of less than 5%, except two samples from the X2 well, which contain a relatively high concentration of nitrogen gas with values up to 8.15 and 8.30% (Table 5).

Table 5. Molecular Composition and Stable Carbon and Hydrogen Isotopic Compositions of the Examined Natural Gas Samples from the Oligocene Sandstone Reservoirs in the Three Studied Wells (Jh 64-1R, X-1, and X-2), the Offshore Nile Delta, the Eastern Mediterranean Sea (Egypt)^a.

well name	age	hydrocarbon gas composition (mol %)								C1/(C2 + C3)	C2/C3	Ln C1/C2	Ln C2/C3	nonhydrocarbon gas composition (mol %)		gas dryness (%)	gas wetness (%)	stable carbon and hydrogen isotopic compositions
																		δ13C (‰, VPDB)				δ2H (‰, VSMOW)
		CH4	C2H6	C3H8	iC4H10	C4H10	iC5H12	C5H12	C6H14					CO2	N2			δ13C1	δ13C2	δ13C3	δ13C4	δ2H–C1 (δ D–C1)
Jh 64-1R	Oligocene	86.55	4.46	1.37	0.29	0.30	0.11	0.07	0.09	14.85	3.26	2.97	1.18	5.82	0.74	93.32	6.68	–42.3	–28.3	–26.5	–25.9
		86.33	4.47	1.39	0.30	0.32	0.12	0.08	0.12	14.73	3.22	2.96	1.17	5.75	0.89	93.25	6.75	–42.3	–28.2	–26.8	–26.6
		87.06	4.50	1.38	0.29	0.31	0.11	0.07	0.11	14.81	3.26	2.96	1.18	5.86	0.25	93.29	6.71	–42.1	–28.3	–26.9	–26.1
X-1		71.95	2.64	1.17	0.17	0.21	0.05	0.03	0.07	18.88	2.26	3.31	0.81	22.23	1.22	94.67	5.33	–50.8	–31.9	–32.2	–31.4	–177
		85.03	3.51	1.55	0.21	0.24	0.05	0.03	0.04	16.80	2.26	3.19	0.82	6.46	2.30	94.10	5.90	–50.6	–32.1	–32.3	–31.1	–179
		83.36	4.08	1.77	0.24	0.27	0.05	0.03	0.06	14.25	2.31	3.02	0.84	7.32	2.24	93.13	6.87	–50.4	–32.1	–32.2	–31.2	–182
		71.71	9.12	7.75	2.02	2.77	0.93	0.70	0.74	4.25	1.18	2.06	0.16	3.45	0.62	77.90	22.10	–51.9	–33.0	–31.4	–30.1	–187
		63.92	2.03	0.63	0.08	0.09	0.02	0.01	0.02	24.03	3.22	3.45	1.17	27.89	4.67	95.85	4.15	–51.8	–32.7	–31.3	–29.7	–185
		78.57	2.84	0.68	0.08	0.08	0.02	0.01	0.01	22.32	4.18	3.32	1.43	15.40	2.00	95.60	4.40	–51.9	–33.1	–31.1	–29.5	–185
		65.60	3.51	1.27	0.19	0.25	0.08	0.05	0.10	13.72	2.76	2.93	1.02	27.55	1.13	92.81	7.19	–51.5	–32.8	–30.8	–24.5	–184
X-2		83.68	8.08	2.86	0.73	0.73	0.27	0.16	0.23	7.65	2.83	2.34	1.04	0.05	2.52	87.61	12.39	–40.9	–28.0	–25.7	–24	–146
		82.65	6.08	1.68	0.34	0.30	0.11	0.06	0.08	10.65	3.62	2.61	1.29	3.34	4.23	91.05	8.95	–41.0	–27.8	–25.2	–24.4	–140
		88.06	5.24	1.22	0.21	0.19	0.06	0.03	0.06	13.63	4.30	2.82	1.46	0.89	3.54	92.95	7.05	42.9	–28.9	–26.2	–24.9	–148
		64.17	3.62	0.83	0.09	0.14	0.03	0.02	0.08	14.42	4.36	2.88	1.47	20.56	8.30	93.29	6.71	–38.0	–25.8	–24.9		–127
		81.70	3.88	1.04	0.20	0.22	0.08	0.05	0.11	16.61	3.73	3.05	1.32	2.31	8.15	94.03	5.97	–40.0	–27.9	–25.1	–24.7	–143

^aNote: dryness index (%) = 100 × C₁/(∑C₁–C₅); wetness index (%) = 100 × ∑(C₂–C₅)/∑(C1–C₅).

Unlike most of the natural gas samples from the Jh 64-1R and X2 wells, which have CO₂ gases of more than 2% and up to 27.89%, two samples from the X1 well contain a very low concentration of carbon dioxide gas, with values between 0.05 and 0.89% (Table 5). However, the CO₂ gas may result from the thermal cracking of OM, decomposition of marine carbonates, the atmosphere, and mantle degassing.³²

The dryness and wetness indices of the studied gases are also calculated based on the hydrocarbon gases (C₁–C₅), listed in Table 5. Most of the studied gases from the studied wells display high dryness values in the range of 87.61–95.85, except one sample from the X1 well, which has relatively low values of the dryness degree, with a value of 77.9 (Table 5). On the other hand, the wetness values of the studied gas samples range widely between 4.15 and 22.1 (Table 5). In this case, most of the studied gas samples have a relatively high wetness index of more than 5 and up to 22.1, except for two samples from the X1 well that have relatively low values of the wetness index in the range of 4.15–4.40 (Table 5). The high wetness index of more than 5 suggests that most of the studied gas samples can be classified as wet gases according to Schoell.³³

4.4. Isotope Composition of Natural Gases

The methane gases in the studied samples from the X1 well have relatively lighter δ¹³C values (more negative), while the studied natural gas samples from other wells have lower δ¹³C values (less negative), as shown in Table 5.

The stable carbon isotopic distribution of methane (CH₄) is lighter (more negative) than that of its homologues (C₂–₅). The δ¹³C–CH₄ values show that most of the natural gases from the studied wells are mainly thermogenic methane gases, with lighter δ¹³C values of more than −55‰. However, the studied natural samples have heavier isotopic compositions of ethane, propane, and butane, ranging from −33.1 to −25.8‰, −32.2 to 24.9‰, and −31.4 to −24.0‰ (Table 5). In this case, the studied natural gases are characterized by a normal pattern (δ¹³C–CH₄ < δ¹³C–C₂H₆ < δ¹³C–C₃H₈ < δ¹³C–C₄H₁₀).

In addition, the hydrogen isotopic values of methane gases (δ²H–CH₄) are also measured for most of the gas samples from the X2 and X1 wells (Table 5). Accordingly, the δ²H–CH₄ values range between −187 and −127‰, with an average value of −165‰ (Table 5).

4.5. Geothermal History Evolution and Its Consequences on Organic Maturation

The role of thermal geohistory development for any basin is critical as it influences the source rock maturation timing as well as the petroleum generation over the geological time.³⁴⁻³⁸ The sedimentation rate, erosional record, temperature fluctuation during the burial, and paleo-heat flow (HF) developments are some of the critical components of reconstructing the basin’s geothermal history.^39,40 Among all the aforementioned components, the paleo-heat flow is one of the most accurate gauges for the basin’s thermal evolution as it was inferred depending on subsidence events.³⁹ Nonetheless, the paleo-heat flow is not an easy estimation as the researchers depend on thermal calibration parameters, i.e., vitrinite reflectance (% VRo) and bottom whole temperature (BHT).⁴¹⁻⁴⁶

In this study, the 1D basin simulation approach was used to estimate the geothermal history using available geological information from the available exploration well together with the calculated VRo from T_max and BHT measurements as additional thermal maturation data (Table 2). In this case, the thermal maturation model was prepared by employing the Easy % Ro method, devised by Sweeny and Burnham.⁴² During the modeling analysis, multiple heat flow scenarios were employed to establish a reasonable fit between Sweeny and Burnham’s maturation (Easy % Ro) and conclude a suitable thermal history model as demonstrated by the good fit between the Easy % Ro and thermal gradient models and calibration parameters, i.e., calculated VRo and BHT measurements (Figure 5). However, the erosion and unconformities were considered while building the models of hydrocarbon generation, thermal history, and timing.⁴⁷ In the Nile Delta, a significant thickness of the sediments, around 800 m, was subjected to prolonged erosion as a result of uplift tectonic events throughout the Miocene.¹⁹ This tentative thickness of the eroded section and the thick overlying strata (Table 2 shows more than 5 km of thickness) are two influential factors in the thermal history of the Tineh source rock system.

In this case, the maturity model implies that the Tineh source rock system in the studied well is presently in the main stage of liquid hydrocarbon generation (i.e., oil to wet gas), as shown in Figure 6A. This finding was also verified by the mature oil window at the beginning of the wet gas generation reflecting Easy % Ro values between 0.55 and 1.38% (Figure 6A). The investigations from the burial and thermal model also reveal the end of the Tineh Formation at a depth of 5760 m, highlighting the high burial temperatures, between 100 and 170 °C, prevailing from the late Miocene to the present day (7–0 Ma; Figure 6B).

Figure 6.

(A) Burial overlap with thermal maturity (colored areas) across all rock units (left), and blue lines are shown exclusively for computed vitrinite reflectance (right) and (B) burial overlap with thermal gradient history (colored areas) across all rock units (left), and red lines are shown exclusively for computed temperatures (right) of the base Tineh Formation in the studied Jh 64-1R well.

The thermal history model in the studied well shows that the base of the Mangahewa Formation went into the early mature oil window (0.55–0.70 Easy % Ro) during the late Miocene (10–7 Ma), as shown in Figure 6A, agreeing to the fluctuation in burial temperatures between 85 and 100 °C (Figure 6B). The peak oil generative window occurred throughout the late Miocene–Pliocene (7–2 Ma), corresponding to an Easy % Ro value between 0.70 and 1.00 (Figure 6A). The temperature during the late Miocene-to-Pliocene transition reached an elevated value between 100 and 150 °C (Figure 6B). This is probably attributed to the high thickness of more than 5 km for the overburdened sediments (Table 2). Subsequently, the base Tineh Formation in the studied well reached the beginning of the wet gas generation during the Pleistocene (less than 1 Ma) and has persisted to the current time (Figure 6A).

5. Discussion

5.1. Shale Source Rock System and Implication of Petroleum Generation Potential

Extensive research into examining source rock characteristics is important for petroleum exploration, including both conventional and unconventional approaches. These characteristics include OM abundance, kerogen classification, thermal maturity, and the potential for hydrocarbon generation, as highlighted by geochemical experts like Jarvie⁴⁸ and Hackley and Ryder.⁴⁹

Regarding OM richness, several researchers indicate that a TOC content of >1% suggests favorable source petroleum potential.⁵⁰ In this context, our study reveals that most of the shale samples from the Oligocene Tineh Formation in the studied well exhibit TOC values exceeding 1 wt %, with some remarkable samples reaching up to 0.99% (Table 1). This finding of the TOC values attests that the Tineh shale source rock system has good source rock characteristics for the hydrocarbon generation potential.

Furthermore, the bulk kerogen types and petroleum generative potential of the studied Oligocene shales in the studied well were also primarily assessed based on the results of the programmed pyrolysis. The HI and OI pyrolysis parameters are exercised for bulk kerogen type recognition.⁵¹⁻⁵³ The analysis used the categorization of the OM under type I (>600 mg HC/g TOC), type II (300–600 mg HC/g TOC), type II–III (200–300 mg HC/g TOC), and type III (50–200 mg HC/g TOC).⁵⁴⁻⁵⁶ In this case, the HI of the Tineh shale samples under consideration varies between 153 and 348 mg of HC/g of TOC (Table 1). A considerable number of samples in the studied wells exhibit HI < 200 mg of HC/g of TOC (54–198), whereas a lower number of samples showed relatively high HI values between 201 and 240 mg of HC/g of TOC (Table 1). Accordingly, the examined Tineh shale samples in the studied well comprise mixed types II/III and type III kerogens, as revealed from the T_max vs HI van Krevelen diagram (Figure 7A). The extraordinary influence of the type III kerogen with mixed type II/III contributions validates the OI vs HI cross plot (Figure 7B). Moreover, the HI values also reveal that the Tineh shale samples are good oil- and gas-source rock, with high potential of gas generation, as shown by the outputs from TOC and HI cross plots (Figure 8). In addition, this study also assessed the thermal maturity of OM within the Oligocene shale succession in the studied well. This evaluation harnessed a diverse set of thermal indicators encompassing pyrolysis T_max values.

Figure 7.

Characteristics of the kerogen of the Tineh shale samples from the studied Jh 64-1R well based on (A) HI versus T_max and (B) HI versus OI, showing type II/III and III kerogens.

Figure 8.

Geochemical correlation between TOC content and Rock-Eval data (i.e., HI), implying that the analyzed shale samples of the Tineh Formation from the studied Jh 64-1R well are both oil- and gas-prone source rocks.

In this study, the T_max values vary between 437 and 450 °C (Table 1). The majority of the analyzed shale samples display T_max values surpassing 440 °C, signifying a state of mature source rock (Figure 7A). However, the corresponding peak maturity of the oil generation window also aligns with the calculated vitrinite reflectance derived from T_max-based observations, ranging from 0.72 to 0.94 (Table 1).

5.2. Liquid Hydrocarbon Characteristics and Implications for the Origin of Organic Matter Input

The lipid biomarker characteristics of the saturated hydrocarbons together with the heterocyclic aromatic hydrocarbons and their associated parameters and ratios in the examined oil and condensate samples played a crucial role in assessing the type of OM in the probable source rocks and their depositional conditions.⁵⁷⁻⁵⁹ As a result, the examined oil and condensate samples were generated from source rock that was home to mixed OM, with a high contribution of terrestrial OM inputs, as indicated by the CPI vs waxiness cross plot (Figure 9A). This finding also confirms the isoprenoids and their ratios of Pr/n-C₁₇ and Ph/n-C₁₈, indicating the significant input of mixed OM, with high terrestrial OM input (Figure 9B). In addition, the isoprenoid using the Pr/Ph ratio further demonstrates the redox environmental conditions of the source rock.⁶⁰⁻⁶⁴ In this regard, the preliminary investigation of examined oil and condensate samples reveals that their source rock was deposited under oxic (oxidation) environmental conditions with high Pr/Ph ratios of more than 3 (Table 3).

Figure 9.

Geochemical biomarker results of the examined liquid HC (oil and condensate) samples from the studied wells (Jh 64-1R and X-1), including (A) CPI and waxiness degree and (B) pristane/n-C₁₇ versus phytane/n-C₁₈, indicating that the source rock contains mixed OM and was deposited under oxic conditions.

This interpretation is corroborated by the association between the hopane and terpane biomarkers and their ratios. Most of the oil and condensate samples have a C₃₁R/C₃₀ hopane ratio of less than 1 (Table 4), indicating that these oil samples were generated from clay-rich source rock deposited in fluvial to fluvial-deltaic environments as low values of less than 0.25 are indicative of a nonmarine depositional environment.⁶⁵

The association between the Pr/Ph isoprenoid and C₃₁R/C₃₀ hopane together with the DPT/P ratio also alludes to the fluvial to fluvial-deltaic source rocks deposited under oxic environmental conditions (Figure 10A,B). The nonmarine shale source rock for the oil and condensate samples under investigation is also indicated by the distribution of tricyclic terpane and their ratios (Table 4). The association between the low C₃₁R/C₃₀ hopane ratio and the high C_26tri/C_25tri ratio of more than 1 is also inferred from the nonmarine clay-rich source rock (Figure 10C).

Figure 10.

Geochemical biomarker results of the examined liquid HC (oil and condensate) samples in the studied wells (Jh 64-1R and X-1), showing (A) Pr/Ph versus C₃₁ regular homohopane/C₃₀hopane (HCR₃₁/HC₃₀), (B) Pr/Ph versus DBT/P, and (C) C₃₁R/C₃₀-hopane versus C₂₆/C₂₅ tricyclic terpane ratios, indicating nonmarine source rock (i.e., fluvial–fluvial-deltaic) under oxic conditions.

This interpretation also is supported by the distribution of the monoaromatic steroids (Table 4), which corresponds to nonmarine shale source rock, as indicated by the ternary diagram of the monoaromatic steroids (Figure 11A).

Figure 11.

Geochemical biomarker ternary diagrams of the examined liquid HC (oil and condensate) samples in the studied wells (Jh 64-1R and X-1), showing (A) C₂₇, C₂₈, and C₂₉ monoaromatic steroids (MAS) and (B) C₂₇, C₂₈, and C₂₉ regular steranes, showing the source of the OM.

In addition, the richness of the C₂₉ and C₂₈ regular steranes compared to the C₂₇ regular sterane of all examined oil and condensate samples (Table 4) supports the inference of primarily OM derived from plants, with little input of aquatic OM, based on the adapted ternary diagram of Huang and Meinschein,⁶⁶ as shown in Figure 11B.

One of the prominent features is the presence of oleanane in the m/z 191 mass fragmentogram (Figure 4B), whereby the analyzed oil and condensate samples display a variable oleanane index (oleanane/C₃₀ hopane) in the range of 0.15–0.66 (Table 4). Applying the oleanane parameter to indicate terrestrial OM input shows that the examined oil and condensate samples with measurable amounts of oleanane (Figure 4B) are a strong indicator of terrestrial angiosperm plants in the source rock from the late Cretaceous or after.⁶⁷ The association between the oleanane index of more than 0.2 and relatively low C₂₈/C₂₉ regular sterane also inferred the Tertiary age (Figure 12).

Figure 12.

Cross plot of the oleanane index vs C28ββS/C29ββS sterane ratio of the examined liquid HC (oil and condensate) samples, showing the Tertiary age of the probable source rock.

5.3. Origin and Source of Natural Gases

The molecular composition and isotopes of carbon and hydrogen have been applied to investigate the origin of the natural gases in the Oligocene gas-bearing reservoirs in the studied wells using the most widely diagrams from several published works.^32,68−74

Most of the natural gases in the studied wells have δ¹³C₁ values lighter than −30‰ to up to −51.9‰ (Table 5), reflecting that these gases are typically biogenic gases rather than abiogenic (hydrothermal origin), according to the classification of Dai et al.³² However, Dai et al.³² and Whiticar⁷² classified the biogenic gases into two types, including bacteriogenic and thermogenic gases. They indicated that bacteriogenic gases are characterized by a high methane content and a high dryness index of more than 99%, with δ¹³C₁ values lighter than −55‰, while the thermogenic gases have δ¹³C₁ values heavier than −50‰ (less negative). In this regard, most of the studied natural gases are classified as more thermogenic gases, as indicated by their relatively low dryness index between 77.90 and 95.85%, with less negative values of δ¹³C₁ (Table 5). This interpretation is corroborated by the association between the molecular composition (C₁/C₂ + C₃) and δ¹³C–CH₄ values as most of the gases are plotted in the zone of thermogenic gases (Figure 13).

Figure 13.

(A) Genetic plot of δ¹³C₁ versus the Bernard diagram of the C₁/(C₂ + C₃) ratio and (B) revised genetic fields of this plot, showing that most of the natural gas samples from the studied wells (Jh 64-1R, X-1, and X-2) are mainly thermogenic gases.

The association between the δ¹³C and δD1 of methane (CH₄) also alludes to thermogenic gas formation (Figure 14). However, most of the natural gases in the studied wells mainly belong to the oil-associated gas field and away from the field of secondary biodegradation, as shown in Figures 13B and 14.

Figure 14.

Genetic plot of δ¹³C₁ versus δ¹³H–C₁ of the natural gases from the studied wells (X-1 and X-2), showing mainly thermogenic gas generation.

The thermogenic gases result from either the initial cracking of type III kerogen or oil cracking due to the high thermal maturity. The differentiation between oil cracking gas and kerogen cracking gas for the origin of the natural gases has been performed using the molecular composition of the methane (C₁), ethane (C₂), and propane (C₃) and their ratios.^69,75,76 The C₂/C₃ of the oil cracking gas increases rapidly with thermal evolution, whereas that of the kerogen-cracking gas remains nearly constant. Contrarily, the C₁/C₂ ratio of the oil cracking gas decreases, while that of the kerogen cracking gas grows and remains essential.^69,75 Accordingly, the studied natural gas samples tend to generate gases formed from both primary and secondary cracking, as shown by Behar et al.’s⁷⁶ diagram of Ln C₁/C₂ and Ln C₂/ C₃ (Figure 15A). Most of the gas samples in the studied wells exhibit a wide range of Ln C₂/C₃ values of more than 1 and follow the pattern of cracking oil rather than the primary cracking of kerogen, with the exception of one sample from the X1 well, which trends toward gases formed from primary cracking of kerogen, with a low Ln C₂/C₃ value of less than 0.4 (Figure 15A). The high abundance of thermogenic gas from the secondary oil and oil/gas cracking was further demonstrated by the C₂/C₃ and δ¹³C₂–δ¹³C₃ relationship (Figure 15B). This relationship also aided in understanding the level of thermal maturity, revealing that most thermogenic gases were formed during the high-maturity stages.

Figure 15.

Cross plots of (A) Ln C₁/C₂ versus Ln C₂/C₃ and (B) C₂/C₃ versus δ¹³C₂–δ¹³C₃ of the natural gases from the studied wells (Jh 64-1R, X-1, and X-2), showing the mechanism of gases formed mainly from secondary cracking of oil and/or gas, with small contributions from primary cracking of kerogen.

Furthermore, the origin and source of the OM of the thermogenic gases can be separated into two groups: those produced from coal-type kerogen (type III) and those that are broken from oil of saprophytic OM.⁷⁷ Gases with a coal-type kerogen (type III) source have δ¹³C₂ and δ¹³C₃ values greater than −27.5 and −25.5, respectively, while the gases with a saprophytic source have δ¹³C₂ and δ¹³C₃ values lower than –29.0 and −27.0, respectively.^78,79 In this case, most of the natural gases from the studied wells exhibit the characteristics of combining coal- and saprophytic-type OM, with values between −25.8 and −33.1‰ for δ¹³C₂ and between 24.9 and −33.1‰ for δ¹³C₃ (Table 5). The interpretation of the mixing source of the studied natural gas samples is also demonstrated by the combination of the carbon and hydrogen isotopic compositions of methane (CH₄) and ethane (C₂H₆) gases, as shown in Figure 16.

Figure 16.

Correlation diagram of δ¹³H–C₁ vs δ¹³C₁ and δ¹³C₂ of the natural gases from the studied wells (X-1 and X-2), showing mainly mixed OM.

5.4. Estimated Maturity Levels of Liquid Hydrocarbons and Natural Gases

The bulk composition of the liquid hydrocarbons shows that the examined oil and condensate samples are thermally mature, ranging from mature to very mature, with a high abundance of the saturated HC fraction, as indicated by the ternary diagram (Figure 17) established by Tissot and Welte.⁸⁰

Figure 17.

Ternary plot of saturated and aromatic hydrocarbon fractions with polar components obtained from the examined liquid HC (oil and condensate) samples, showing a highly mature source rock.

This finding of the maturation degree of the examined oil and condensate samples is also clearly demonstrated by the direct proportionality between the API and the saturated HC fraction and the inverse proportionality between the API and the polar content (Figure 18) because the API value and saturated HC fraction increased with an increase in the degree of thermal maturity. However, the condensate sample is more mature than the oil samples, with a high saturated HC fraction and API values of up to 97.83% and 46.0, respectively (Table 3).

Figure 18.

Relationship between (A) API gravity versus saturated HC and (B) API gravity versus polar fractions, showing good correlations and indicating that the high API value is due to the high thermal maturity of the examined liquid HC (oil and condensate) samples.

Moreover, the bulk composition is in compatibility with the hopanes and sterane maturity biomarkers in the m/z 191 and 217 mass fragmentograms, specifically 22S/(22S + 22R) in C₃₂ homohopanes, Ts/Tm, and C₂₉ sterane ratios of the 20S/(20S + 20R) and ββ/(ββ + αα).⁸¹⁻⁸⁴ C₃₂ homohopanes in the examined oil and condensate samples are dominated by S-isomers rather than R-isomers (Figure 4B), suggesting that these samples have attained maturity.⁸² However, the distributions of C₃₂-homohopane are used to determine the [22S/(22S 22R)] isomerization ratio. As thermal maturity grows, this ratio reaches a maximum of 0.70.⁸³ The source rock is considered immature if the C₃₂ ratio falls below 0.50. The source rocks with an early mature-to-peak mature oil window have C₃₂ ratios of 0.50–0.57, while an equilibrium point larger than 0.58 indicates further maturation.⁸³ Following this scale, the examined oil and condensate samples were generated from mature source rock, entering a highly mature generation phase, as demonstrated by the high C₃₂ hopane ratios between 0.56 and 0.58 (Table 4). It is also important to note that the ratio of the C₂₉ sterane’s 20S/(20S + 20R) and ββ/(ββ + αα) shows the thermal maturity of the crude oil samples.⁸¹⁻⁸³ The oil window has been reached if these ratios are more than 0.40.^85,86 Samples of oil and condensate analyzed in this study had ββ/(ββ + αα) C₂₉ 20S/(20S + 20R) and ββ/(ββ + αα) sterane ratios of 0.44–0.51 and 0.47–0.58 (Table 4), which further suggested mature source rock, with high maturity of the condensate sample (Figure 19A). The association between the C₃₂-homohopane and C₂₉-ββ/(ββ + αα) sterane ratios also supports the highly mature phase of the source rocks for the examined oil and condensate samples, as shown in Figure 19B. The high Ts/Tm ratio obtained from the mass fragmentograms of the m/z 191 (more than 0.8) is consistent with this maturation interpretation. As maturity increases, the Ts/Tm ratio increases from approximately 0.4 in immature source rock to more than 0.5 in mature source rocks, according to Roushdy et al.⁸⁷

Figure 19.

Geochemical cross plot of the biomarker maturity indicators of the examined liquid HC (oil and condensate) samples, including (A) C₂₉-sterane 20S/(20S + 20R) versus ββ/(ββ + αα) and (B) C₃₂-hopane 22S/(22S + 22R) versus C₂₉ sterane ββ/(ββ + αα), showing the high thermal maturation of the probable source rock.

In addition, the maturity index of the methylphenanthrene (MPI) in the aromatic hydrocarbon fraction of the examined oil and condensate samples (Table 4) was also employed to assess the thermal maturity of the source rock’s studied oil and condensate samples. In the current study, the examined oil and condensate samples have high MPI-1 values in the range of 0.64–1.01 (Table 4), indicating mature source rock for these samples. In this case, the condensate sample is more mature than the oil samples; as the maturity increases, the MPI was increased.⁸⁸ However, the equivalent vitrinite reflectance from the MPI parameter (% Rc MPI) was estimated and ranged from 0.75 to 1.01 (Table 4), further suggesting mature source rock in the peak mature-to-late mature oil generation stage.

Beside the evaluation of thermal maturity of the liquid hydrocarbons, the maturity of the natural gas in the Oligocene reservoir rock was also estimated using the δ¹³C compositions of the methane (CH₄), ethane (C₂H₄), and propane (C₃H₆) gases.^70,89,90

In this study, most of the natural gases from the Oligocene reservoir rock in the studied wells are mainly formed from a mixed source of OM as highlighted in the previous subsections (see Figures 9B and 16). Therefore, the diagnostic cross plots of carbon isotope data of the mentioned gases were used and provided valuable information about the maturity of mixed gases and the related source rock maturities. The carbon isotopic composition of heavy hydrocarbon gases (C₂H₄ and C₃H₆) is inextricably linked to the source rocks and better allows for prediction of gas maturity and their sources.^32,76,90 The isotopic composition of ethane and propane in most of the natural gases already clarifies their derivation from mixed kerogen of type II/III at maturity degrees ranging between 0.68 and 1.37% (Figure 20). This model reveals that most of the thermogenic gases in the Jh 64-1R and X2 wells were formed by secondary cracking of oil and gas, with maturity values (Ro) ranging from 1.00 to 1.37% (Figure 20). On the other hand, the natural gases from the X1 well were primarily generated from a secondary cracking of oil, with relative Ro values between 0.68 and 0.72% (Figure 20).

Figure 20.

Isotopic maturity models of the δ¹³C₂ and δ¹³C₃ based on δ¹³C_kerogen, showing that the natural gases from the studied wells (Jh-64-1R, X-1, and X-2), were formed from secondary cracking of oil and gas, with Ro values between 0.69 and 1.39%.

5.5. Geochemical Correlations and Their Implications for Petroleum Exploration Opportunities

In order to investigate geochemical correlation variables, this study used source OM and maturity-related biomarkers of the saturated and aromatic HCs for the examined oil and condensate samples together with the isotopic signatures of natural gases in the Oligocene reservoir from the studied wells. Consequently, both the natural gases and associated oil and condensate originate from source rock containing mixed OM (i.e., type II/III kerogen) and were generated at different thermal maturity levels. In this case, the molecular and isotope compositions of natural gases show that most of the gas samples are mainly thermogenic methane gases (Figures 13 and 14) and were generated from mixed OM, as described in the preceding subsection and cross plots between these natural gases (Figure 16). These thermogenic methane gases were formed as results of secondary cracking of oil or/and gas (Figure 15) based on the maturity-related metrics (Figure 20). These features are closely related to the probable source rock of the associated oil and condensate samples, as evidenced by OM input and maturity-related parameters (Figures 9–11, 17 and 19). However, the probable source rock of both oil and condensate samples in the Oligocene reservoir rock was dated to the Tertiary period, evidenced by age-dating biomarker results of the oleanane index and C₂₈/C₂₉ββS sterane ratio (Figure 12). These age-dating biomarker results of the oil and condensate samples in the Oligocene reservoir rock from the studied wells correspond to the source rock potential of the Cenozoic (Oligocene–Miocene) sedimentary successions in the Nile Delta reported by previous works.^11,91 These source rocks are mainly clay-rich facies and have types III and II/III kerogen.^11,91 However, the Oligocene units, including the Tineh Formation, are buried approximately up to 6000 m deeper than the Miocene and Pliocene formations in the studied Jh 64-1R well and reached a main oil and gas generation window (Figure 6), indicating that the Oligocene Tineh Formation is more mature and genetically linked enough to be the oil and gas source rock in the offshore Nile Delta.

The basin-scale model in this study helped also in setting a plan for further scientific investigations in the offshore Nile Delta. It shows that the Tineh source rock system in the studied Jh 64-1R well reached a transformation ratio (TR) between 10 and 71% (Figure 21). This is attributed to the thermal maturity, with corresponding VRo values between 0.70 and 1.38% throughout the studied well (Figure 6A). The Jh 64-1R well-based model suggests that the TRs reached maximum values of up to 50% during the late Miocene–early Pliocene period (5–2 Ma) and had increased with increasing thermal maturation (up to 1%; Figure 6A); hence, the substantial oil volumes may have been generated during this time (Figure 21). These amounts of generated oil were then expelled from the shale source rock system of the Oligocene Tineh Formation as a result of the greatest values of more than 50% (up to 65%) for its kerogen conversion and then trapped in its reservoir sandstone rock during the early Pliocene–Pleistocene period (Figure 21). Therefore, the Oligocene Tineh Formation can be considered as self-source and self-reservoir rock. In addition, the trapped amounts of oil in the reservoir sandstone rock were subsequently converted to thermogenic gases during the period of time between the Pleistocene and the present day (Figure 21), with increasing thermal maturation (up to 1.38%; Figure 6A). The result of the current basin modeling study is confirmed from the existence of the natural gases and associated oil and condensate samples within the sandstone intervals of the Oligocene Tineh Formation in the studied wells, as mentioned in the preceding subsection.

Figure 21.

(A) Model of cumulative hydrocarbon generation and (B) evolution of the TR and computed vitrinite reflectance (Easy % VRo) with age for the base Tineh Formation in the studied Jh 64-1R well.

Considering the results of this study, a correlation of the source rock characteristics of the Oligocene Tineh Formation across the eastern and western flanks of the offshore Nile Delta is one of the significant tasks that could add value in any further conventional or unconventional exploration activity. But, due to data limitations and constraints created by the owner oil companies, currently, this task was not achieved in this work, but it opens the floor for another good point of research to be covered in a future work.

6. Conclusions

Sixty-five shale samples of the Oligocene Tineh Formation, together with 15 natural gas samples and three liquid hydrocarbon (2 oils and 1 condensate) samples from the reservoir rock of the Tineh Formation in different well locations in the East Mediterranean Sea, were geochemically investigated and integrated with a 1D basin modeling study to predict the timing of petroleum generation and explosion. The follwoing are the most concluded points:

• Organic geochemical results show excessive OM content (TOC reaching more that 1 wt %) and mainly type III and type II/III kerogens from the Tineh shale samples, indicating good source rock for both oil and gas generation potential.

• The basin model results advocate that the Tineh shale source rock reached the main oil- and wet gas-generating phase, with a kerogen conversion ratio between 10 and 72 TR %, during the period of time between the late Miocene and the present day.

• Substantial oil volumes may have been generated and expelled into the Tineh sandstone reservoir during this time and then converted into thermogenic gases with increasing thermal maturation of up to 1.39%.

• The study of the physical and geochemical characteristics reveals that both the oil and condensate accumulations in the Oligocene reservoir originated from clay-rich source rock, containing mixed OM, with large amounts of terrestrial OM deposited in fluvial to fluvial-deltaic environments under oxic conditions.

• According to the molecular composition and isotopes of carbon and hydrogen, most of the natural gases in the Oligocene reservoir are mainly thermogenic methane gases, which were generated from the mixed OM due to mainly secondary cracking of oil and/or gas in different thermal maturity stages.

• The above geochemical properties together with basin modeling results suggest that most of the natural gases and associated oil and condensate in the Oligocene reservoir rock are sourced from the mature Oligocene Tineh shale source rock system and formed by primary kerogen cracking and secondary oil and oil/gas cracking at the oil and gas generation window

The authors declare no competing financial interest.