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Abstract

The Laizhou Bay Sag, one of the oil-bearing sags with large exploration potential in the South Bohai Sea of China, contains two sets of high-quality hydrocarbon source rocks, i.e. Member 3 and Member 4 of Shahejie Fm (E₂s³ and E₂s⁴). As an important hydrocarbon accumulation zone in the sag, the KL16-1 low bulge is found to have oil reservoirs in the Neogene Guantao Fm (N₁g), the Paleogene Dongying Fm (E₃d), the Paleogene Shahejie Fm (E₂s), and the Mesozoic buried hill formation. It is characterized by distinct features of composite reservoirs. Nonetheless, its hydrocarbon accumulation process and mechanism are unknown yet. In this paper, the hydrocarbon generation modelling of source rocks, combined with the characteristics of oil-source rock biomarker compounds and fluid inclusions, is used to restore the hydrocarbon accumulation process in the KL16-1 low bulge. Crude oil in all three KL16-1 plays is characterized by low Pr/Ph, low gammacerane, high 4-methyl sterane and high dinosterane. In other words, it is oil of low maturity to maturity. As the biomarker index of the oil is very similar to that of the E₂s³ source rocks, it is thought that E₂s³ is the primary source rock layer, while E₂s⁴ is the secondary source rock layer. In addition, episodic oil and gas charging happened in two phases under high pressure in the late period (from 5.0 Ma till now).

Keywords

Composite reservoir oil-source rock correlation thermal evolution modelling fluid inclusion accumulation period Laizhou Bay Sag

Introduction

Composite oil and gas accumulation is typical in faulted basins in China (Hu et al., 1986; Li, 1990). It refers to the overlay (in time) and combination (in space) of multiple oil and gas layers and various reservoirs belonging to different structural formations (Chen, 1988; Zhang, 1989). For the Bohai Bay Basin, the composite oil and gas accumulation belt dominated by the Paleogene buried hill is an important form of hydrocarbon enrichment (Dong and Chen, 2000; Yan et al., 1980). The exploration practices in the Laizhou Bay Sag have proved that oil and gas accumulations are discovered in the Neogene Guantao Fm (N₁g), the Paleogene Dongying Fm (E₃d), the Paleogene Shahejie Fm (E₂s), and the Mesozoic (Mz) buried hill. However, the reservoirs in different formations have different distribution, oil property and biomarker compound characteristics.

Many scholars studied the Neogene formations of Laizhou Bay Sag in respect of history of structural evolution (Guo et al., 2007; Peng et al., 2009), characteristics of hydrocarbon source rocks and history of hydrocarbon generation and expulsion (Jiang, 2011), depositional sequence features (Sun et al., 2006a, 2006b), conducting systems (Wu et al., 2010) and dynamic characteristics of accumulation (Sun et al., 2006a, 2006b, 2009). The Laizhou Bay Sag experienced multiple structural-depositional evolutions after the Himalayan period to form various conducting systems. Furthermore, oil and gas charging occurred in various periods, and the hydrocarbon accumulation was controlled by various factors. Through research, we get preliminary understanding on such aspects as the depositional–structural evolution characteristics of the Laizhou Bay Sag, the primary source rock layers and the hydrocarbon generation and expulsion features in the sag, and the oil and gas conducting systems and the hydrocarbon accumulation features around the sag.

The KL16-1 low bulge is located in the southern margin gentle slope belt of the Laizhou Bay Sag. Oil and gas reservoirs are discovered in the Mz buried hill for the first time. The hydrocarbon accumulation characteristics in the buried hill formation are different from those of the oil and gas reservoirs of N₁g, E₃d and E₂s around the sag. The buried hill reservoir is known to have the features of composite reservoirs. However, its accumulation characteristics and time-space correlations during the accumulation process are still unknown.

In this paper, the basin modelling technique was used to simulate the hydrocarbon generation and expulsion process based on the hydrocarbon source kitchens determined. The hydrocarbon accumulation process and the major factors controlling the accumulation of the KL16-1 composite reservoirs were systematically studied based on the features of crude oil property, oil-source biomarker compounds, fluid inclusions, regional structural evolutions and oil/gas conducting systems. In addition, the accumulation mechanism of the KL16-1 composite reservoirs was also analyzed.

Geologic setting

Located in the Laizhou Bay area in the South Bohai Sea, the Laizhou Bay Sag covers an area of about, 1200 km². It neighbors the Laibei low bulge to the north, the Weibei bulge to the south, the Laixi slope belt to the west and the Ludong uplift to the east. In addition, the sag is held by the two branches of the Tanlu strike-slip belt in its east and west, respectively. The Laizhou Bay Sag can be divided into seven secondary tectonic units, i.e. the eastern margin strike-slip belt, the western margin strike-slip belt, the northern margin steep slope belt, the northern sub-sag, the central tectonic belt, the southern sub-sag and the southern margin gentle slope belt (Sun et al., 2007; Yu et al., 2008) (Figure 1).

Figure 1.

Tectonic unit map of the Laizhou Bay Sag.

The Neogene Guantao Fm (N₁g) in the Laizhou Bay Sag is a set of sand bodies deposited in fluvial-delta environment, where the Neogene reservoirs were developed (Sun et al., 2006a, 2006b). The Member 3 and Member 4 of the Paleogene Shahejie Fm (E₂s³ and E₂s⁴) are hydrocarbon source rock layers where dark mudstones were developed, and the sedimentary sand bodies of delta facies developed in the Dongying Fm (E₃d) and the Shahejie Fm (E₂s) are Paleogene reservoirs (Wang et al., 2009, 2011a, 2015). The weathered crust of Mz volcanic rocks formed the buried hill reservoirs. Either in N₁g, E₃d, E₂S or Mz buried hill, there are oil and gas reservoirs. Three types of plays, i.e. Mz buried hill, Paleogene and Neogene, are classified based on the characteristics of the source–reservoir–cap assemblages (Figure 2).

Figure 2.

Plays in the Laizhou Bay Sag.

It is thought that the Laizhou Bay Sag in the Bohai Bay Basin is of strike-slip-stretch-split genesis (Cai et al., 2001; Gong et al., 2007; Wu et al., 2006). It is a typical rifting lake basin with the east and west Tanlu faults as the east and west boundaries, respectively. The tectonic evolution of the Laizhou Bay Sag can be divided into four stages based on the macro tectonic evolution features of the Bohai Bay Basin and the structural location of the sag: rifting episode 1 (when the Paleogene Kongdian Fm (E₁k) – Member 2 of the Oligocene Shahejie Fm (E₂s²) were deposited), rifting episode 2 (when Member 1 of the Oligocene Shahejie Fm (E₂s¹) – Dongying Fm (E₃d) were deposited), the episode of post-rifting heat settlement and depression (when the Miocene Guantao Fm (N₁g) – the lower section of Pliocene Minghuazhen Fm (N₂m) were deposited), and the remold of neo-tectonic movement (after the upper section of N₂m was deposited).

The reservoir type in the Laizhou Bay Sag was obviously controlled by the Tanlu tectonic movement and the deposition of the Cenozoic strata. The two sets of hydrocarbon source kitchens determined the formation of various oil and gas reservoirs. Generally, the trap types are diversified, and the reservoirs are of composite accumulation genesis. From the bottom to top, high position buried hill traps were developed in the buried hill play (Figure 3). The lifted and exposed volcanic rocks formed high-quality reservoirs during the Yanshan period (Figure 4). With the overlying Paleogene E₂s mudstone as good cap rock, buried hill oil/gas reservoirs were formed. Lithologic traps, lithologic-stratigraphic traps, lithologic-structural traps, fault-block traps and fault-nose traps were developed in the Paleogene and Neogene plays (Figure 3). The fluvial sand bodies, delta front sand bodies and lithologic sand bodies developed on shore were primary reservoirs. As a result, the permeability and porosity of the sand bodies were rather developed. Later, the mudstone layers lying over the Paleogene E₂s, E₃d and the Neogene reservoirs became the primary cap rocks after they were closed by faults or lithology (Figure 2). Laterally, the oil/gas reservoirs are mainly distributed at structural high positions and near faults (Figure 1).

Figure 3.

Structures and reservoir types in the Laizhou Bay Sag (compiled and modified after Peng et al., 2009) (the location of A’-A section shown in Figure 1).

Figure 4.

Rock types and porosity features of the Mesozoic volcanic rock reservoirs in KL16-1. (a, b) Well KL161-1-A, 1210 m, cast section of Mesozoic tuff, fractures and dissolved pores (plane polarized light); (c) Well KL16-1-D, 1610 m, Mesozoic tuff, diameter of dissolved pores about 135 µm (SEM); (d, e) Well KL16-1-F, 1588 m, Mesozoic tuff and volcanic breccia (cores from borehole wall); (f) Well KL16-1-F, 1648.5 m, Mesozoic volcanic breccia (UV fluorescence).

Faults and unconformity surfaces were abundantly developed in the sag. During the major tectonic movement periods, faults acted as the primary conducting system of the composite reservoirs, while unconformity surfaces and sand bodies acted as the secondary hydrocarbon migration channels (Wang et al., 2011b; Wu et al., 2010) (Figure 3).

Experimental method

Samples and tests

All the samples used in our research were taken from the actual drilling cores and crude oil in the KL16-1 low bulge. The hydrocarbon source rock samples were taken from the dark mudstone of E₂s³ and E₂s⁴ in six wells – 84 samples were acquired in total, and the sampling was done from every two intervals in each well. The reservoir inclusion samples were taken from three plays in six wells – 32 samples were collected, and the sampling was done from every two intervals in each well. The crude oil samples were taken from the oil producing layers in each well, totally 15 oil samples obtained.

Tests of TOC, vitrinite reflectance, kerogen type and rock pyrolysis were conducted by using the carbon-sulfur analyzer (CS-230 3593), microscopic spectrophotometer (20100427VA3), BX50 biological microscope 7K05748 and BX50 biological microscope 7K05748, according to the China national or industrial standards such as Test of TOC in Sedimentary Rocks (GB/T19145-2003), Methodology for Testing Vitrinite Reflectance in Sedimentary Rocks (SY/T 5124-2012), Methodology for Determining and Categorizing the Transmission Light – Fluorescent Kerogen Micro-particles (SY/T5125-1996) and Rock Pyrolysis Analysis (GB/T18602-2012).

Tests of crude oil property were carried out by using the SVM3000 kinematic viscometer/densimeter according to Determination of the Dynamic Viscosity and Density of Petroleum Products and Calculation of Their Kinematic Viscosity – Stabinger Viscometer Method (NB/SH/T 0870-2013).

Chromatography and mass spectroscopy tests of source rock and crude oil samples were conducted according to Determination of Biomarkers in Sediments and Crude Oil by Gas Chromatography – Mass Spectrometry (GB/T 18606-2001). The samples were first extracted by Soxhlet extraction. The group compositions were then separated by the silica gel/alumina column chromatography, and eluted with hexane, dichloromethane/n-hexane (volume ratio 3:1) and dichloromethane/methanol (volume ratio 2:1), respectively, to obtain the saturated hydrocarbons, aromatics and non-hydrocarbons. The monomer hydrocarbon components of n-alkanes were finally obtained by using the urea complexing method and analyzed by chromatography (GC) and chromatographic–mass spectrometry (GC–MS).

The fluid inclusions were analyzed via microscopic observation and microscopic temperature measurement. The lithofacies analysis was performed using a Leica D MRX HC microscope. The microscopic temperature measurement was done using a LINKAM THMS 600 cooling-heating stage, which features the resolution of about 0.1°C, the temperature testing range from −196°C to 600°C, and the heating temperature error and cooling temperature measurement error of about 0.1°C, at the test conditions of 20°C temperature and 30% humidity.

Tests and analysis of TOC, rock pyrolysis, vitrinite reflectance, kerogen microscopy, crude oil property, source rock and oil sand extracts, as well as crude oil chromatography and color-mass spectrometry were done in the CNOOC Bohai Experimental Center. Lithofacies analysis of fluid inclusions and micro-temperature measurement were performed in the Beijing Geology Institute of China National Nuclear Corporation.

Basin modelling

The burial, thermal evolution and hydrocarbon generation/generation histories of the Laizhou Bay Sag were simulated using Schlumberger’s PetroMod. The model was built by using the 2D seismic profile and virtual points within the sag (Figure 1) and was corrected with actual Ro data.

Parameters of burial history, thermal history and hydrocarbon history were selected. The burial history parameters include denudation recovery data and compaction correction data. The denudation recovery data were taken from previous study results (Li et al., 2012; Wang et al., 2011b). The compaction correction was realized with the back-stripping method which is based on constant deposition skeleton volume (Yang and Qi, 2003). The initial sandstone porosity and mudstone porosity were 40% and 60%, respectively. The compaction factors of sandstone and mudstone were 0.0012 and 0.0010165, respectively. The paleo-thermal current and paleo-geothermal data of the Bohai Sea Basin recovered with the paleo-thermal current method were used as the thermal history parameters (Hu et al., 1999), and the specific values were 70 mW/m² for the rifting–fault depression period (55–24.6 Ma), 60–63 mW/m² for the late fault–depression period (24.6 Ma), and 50–58 mW/m² for the late fault depression–late depression period (24.6 Ma – now). The globally unified sedimentary water interface temperature – time template (SWIT) provided by PetroMod was used as the sedimentary water interface temperature. Since there are no laboratory data of high temperature thermal modelling of actual geologic samples in the area, the Easy%R_o method (Sweeney and Burnham, 1990) was used, based on the actual abundance of organic matter and type, to set the kinetic parameters of hydrocarbon generation, and the TI (GRS) kinetic model of hydrocarbon generation (Behar et al., 1992, 1997) was applied to simulate the hydrocarbon generation history of the wells and 2D seismic profile of the Laizhou Bay Sag.

Results

Geochemical features of the hydrocarbon source rocks

The E₂s³ and E₂s⁴ dark mudstones of deep lake – semi deep lake facies are the primary hydrocarbon source rocks in the Laizhou Bay Sag (Wang and Guo, 2011). Laboratory data indicate that the 52 E₂s³ dark mudstone samples have the residual organic carbon content ranging from 0.52% to 7.00% (averagely 1.36%), and the average content of chloroform bitumen “A”, total hydrocarbon and S₁+S₂ reaching 0.139%, 0.064 and 4.59 mg·g⁻¹, respectively; the 32 E₂s⁴ dark mudstone samples have the residual organic carbon content ranging from 0.50% to 2.26% (averagely 1.22%) and the average content of chloroform bitumen “A”, total hydrocarbon and S₁+S₂ reaching 0.134%, 0.076 and 3.38 mg·g⁻¹, respectively. According to the China evaluation criteria for the type and abundance of the organic matters of the mudstones in continental basins (Hu and Huang, 1991), the E₂s³ and E₂s⁴ hydrocarbon source rocks are good – very good. Specifically, the E₂s³ dark mudstones are a little better than the E₂s⁴ dark mudstones (Table 1). Optical identification result of kerogen shows the average values of maceral in the E₂s³ and E₂s⁴ mudstone individually: sapropelinite contents are 4.47% and 2.48%, exinite contents are 85.61% and 88.52%, vitrinite contents are 8.08% and 6.84%, inertinite contents are 1.71% and 2.04%, and average type index values are 39.68% and 39.64%; the maceral is the exinite from terrestrial organic matter, with better organic matter type (mainly being type II₁ organic matter and oil type organic matter) (Table 2). As the wells from which source rock samples were taken are located in the low bulge area, the vitrinite reflectance (Ro) is rather low – the E₂s³ source rocks are in immature – low mature period, and the E₂s⁴ source rocks are in immature – mature period (Table 1).

Table 1.

Geochemical characteristics of E₂s³ and E₂s⁴ hydrocarbon source rocks of KL16-1 in Laizhou Bay Sag.

Strata	Lithology	TOC (%)	“A” (%)	HC (ppm)	S₁+S₂ (mg/g)	T_max (°C)	R_O (%)	OM type
E₂s³	Mudstone	0.52–7.00	0.038–0.424	182.42–2892.81	0.27–21.91	327–459	0.35–0.73	II₁
E₂s³	Mudstone	1.36 (52)	0.139 (29)	644.85 (29)	4.59 (52)
E₂s⁴	Mudstone	0.50–2.62	0.024–0.247	122.53–5107.25	0.09–11.69	428–447	0.36–0.85	II₁
E₂s⁴	Mudstone	1.22 (32)	0.134 (17)	760.36 (17)	3.38 (32)

Note: minimum − maximum/average (sample number).

Table 2.

Maceral feature of kerogen in E₂s³ and E₂s⁴ hydrocarbon source rocks of KL16-1 in Laizhou Bay Sag.

Strata	Lithology	Sapropelinite (%)	Exinite (%)	Vitrinite (%)	Inertinite (%)	TI (%)
E₂s³	Mudstone	0–194.47 (38)	21–9785.61 (38)	1–678.08 (38)	0–81.71 (38)	−39 to 5739.68 (38)
E₂s⁴	Mudstone	0–72.48 (25)	61–9688.52 (25)	0–296.84 (25)	0–92.04 (25)	1–5039.64 (25)

Note: minimum − maximum/average (sample number).

Physical property of crude oil

The properties of crude oil, especially density, viscosity and maturity, differ depending on plays in the Laizhou Bay Sag. Density and viscosity are key physical property parameters of crude oil. As indicated below, reservoirs in the Laizhou Bay Sag show rather different oil viscosity and density.

The N₁g oil shows the density of 0.91–0.92 g/cm³, averaged at 0.92 g/cm³, and the viscosity of 72.54–79.44 mPa·s, averaged at 74.95 mPa·s. The N₂m oil demonstrates the density of 0.94–0.95 g/cm³, averaged at 0.95 g/cm³, and the viscosity of 388.40–410.10 mPa·s, averaged at 399.70 mPa·s. The Paleogene oil is found with the density of 0.88–0.96 g/cm³, averaged at 0.92 g/cm³, and the viscosity of 18.57–353.00 mPa·s, averaged at 111.19 mPa·s. The Mz buried hill oil has the density of 0.878 g/cm³ and the viscosity of 17.46 mPa·s on average. According to Geochemical Evaluation Method of Hydrocarbon Source Rocks of Continental Facies, China (SY/T5735-1995), part crude oil in Neogene and Paleogene oil reserves is heavy oil, while the buried hill reservoirs contain normal oil (Figure 5).

Figure 5.

Density-viscosity plot of KL16-1 in the Laizhou Bay Sag.

Characteristics of biomarker compounds of oil and oil sand extracts

Biomarker compounds are also referred to as molecular fossils. The biochemical substances in the once alive biological bodies kept the fundamental compound structures. They can be detected in the oil and source rock extracts (Table 3), and are often used to identify the oil-source relations (Peters et al., 2005).

Table 3.

Group component feature of oil, oil sand and source rock extracts of KL16-1 in the Laizhou Bay Sag.

Strata	Sample	T.S.E. (%wt)	PN (%wt)	Ar. (%wt)	n-Pn (%wt)	Asphaltene (%wt)
N₁g	Crude oil/oil sand	1.24–7.724.00 (19)	10.44–40.3029.37 (23)	10.55–40.9626.80 (23)	17.27–32.1224.83 (23)	6.67–31.4412.51 (23)
E₂s³	Crude oil/oil sand	0–10.333.31 (20)	12.53–65.0036.30 (26)	9.90–33.8122.68 (26)	9.18–34.4519.03 (26)	0.71–49.2811.43 (26)
E₂s⁴	Crude oil/oil sand	0.08–4.171.61 (17)	7.69–57.2437.49 (25)	11.77–36.9623.55 (25)	10.41–46.6725.80 (25)	2.03–25.0010.46 (25)
K	Crude oil/oil sand	0.11–1.630.69 (3)	26.23–52.2436.35 (3)	17.06–26.2320.76 (3)	16.47–24.5920.44 (3)	4.90–9.417.50 (3)
E₂s³	Source rock	0.04–0.870.17 (23)	23.24–53.0534.17 (23)	10.69–34.9820.06 (23)	20.19–38.3827.80 (23)	1.64–20.819.27 (23)
E₂s⁴	Source rock	0.02–1.010.17 (12)	18.94–47.3733.89 (12)	9.93–28.5717.75 (12)	16.40–37.3325.05 (12)	3.72–18.309.32 (12)

Note: minimum − maximum/average (sample number).

The experiment data of group components in crude oil and oil sand extracts show that: (1) the average content of paraffin hydrocarbons in 23 samples from Neogene Guantao Formation is 29.37%wt, the average content of aromatic hydrocarbons is 26.8%wt, that of nonhydrocarbons is 24.83%wt, and that of bituminous matter is the lowest (averaging 12.51%wt). (2) The average content of paraffin hydrocarbons in 26 samples from Paleogene E₂s³ is 36.3%wt, the average content of aromatic hydrocarbons is 22.68%wt, that of nonhydrocarbons is 19.03%wt, and that of bituminous matter is 11.43%wt. (3) The average content of paraffin hydrocarbons in 25 samples from Paleogene E₂s⁴ is 37.49%wt, the average content of aromatic hydrocarbons is 23.55%wt, that of nonhydrocarbons is 25.80%wt, and that of bituminous matter is the lowest (averaging 10.46%wt). (4) The average content of paraffin hydrocarbons in three samples from Mz Erathem is 36.35%wt, the average content of aromatic hydrocarbons is 20.76%wt, that of nonhydrocarbons is 20.44%wt, and that of bituminous matter is 7.5%wt. The extracts of crude oil and reservoir oil sand are featured with lower saturated hydrocarbon content, higher contents of aromatic hydrocarbons, nonhydrocarbons and bituminous matter. Moreover, from deep section to shallow section, the saturated hydrocarbon content decreases, while bituminous matter content increases (Table 3).

The GC and GC–MS parameters of the saturated hydrocarbons of the extracts obtained from the oil and oil sands of the three KL16-1 plays are similar to some extent. The saturated hydrocarbons of the N₂m and N₁g oil sand samples from Well KL16-1-A and Well KL16-1-E experienced biodegradation, and the n-alkanes were totally consumed (Figure 6(a) and (b)). The n-alkanes of other oil and oil sand extracts are dominated by low C number – the peak carbon is below nC₂₅, the OEP value is around 1 (without odd or even advantage), the Pr/Ph is around 0.48–1.74, and mostly within 0.5–0.8 (Table 4). The Pr/nC₁₇ and the Ph/nC₁₈ differ greatly; the three sand oil samples from Well KL16-1-D have the ratios greater than 1, while other samples normally have the ratios no larger than 1, indicating that the crude oil came from the organic matter deposited in strong reducing environment (Peters et al., 2005). The content of gammacerane is rather high in sterane and terpane – the Gam/C₃₀hop ranges from 0.11 to 0.29, and the 4-methyl sterane (C₃₀)/C₂₉ sterane is from 0.3 to 0.4, showing that the organic water generating oil has high salinity, and was probably deposited in slightly salt – salt water environment (Chen et al., 1996; Hao et al., 2009; Zhu et al., 2005). The regular sterane αααC₂₇ (20R)>αααC₂₈(20R)<αααC₂₉(20R); the proportion of αααC₂₉ (20R) is greater than 40%, demonstrating that the higher plants of continental origin account for a large proportion in the input organic substance (Huang and Meinschein, 1979). The biomarker compound parameter related to the maturity, Ts/(Tm + Ts), is from 0.5 to 0.6, the Dia.sC₂₇/C₂₇ is less than 0.2 on average, the αααC₂₉ 20S/(20S + 20R) is 0.3–0.41, the C₂₉ββ/(αα + ββ) is 0.40–0.58, not reaching or approaching the thermal equilibrium point, and the Rc calculated with the methylphenanthrene index (Radke et al., 1982) is 0.6–0.8%, indicating that all the crude oil is already in mature stage, but the maturity is not high (Mackenzie, 1984; Seifert et al., 1984). The three oil sand samples taken from N₂m and N₁g of Well KL16-1-E and E₂s⁴ of Well KL16-1-C contain 25-norhopanes, suggesting degradation. 25-Norhopane/C₃₀hop＜0.1, between 0.03 and 0.06, with degradation of the fifth level (Peter and Molowan, 1993; Rullkotter and Wendisch, 1982) (Table 4, Figure 6(a), (b) and (e)). The extracts of the oil and oil sands from the three plays have similar biomarker compound characteristics, suggesting that the three plays have similar genesis and accumulation process.

Table 4.

Biomarker compound parameters of the extracts of the crude oil and oil sands from KL16-1, the Laizhou Bay Sag.

Well	Strata	Depth (m)	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16	17
KL16-1-E	N₂m	960	–	–	–	–	–	0.29	0.25	0.51	0.13	0.36	0.48	0.34	0.33	0.23	0.44	0.03	0.64
KL16-1-E	N₁g	1046.5	–	–	1.27	1.35	–	1.74	0.27	0.51	0.14	0.29	0.58	0.41	0.34	0.23	0.43	0.06	0.69
KL16-1-D	E₂s³	1302.5	19	1.06	2.2	3.48	1.03	0.63	0.26	0.50	0.10	0.32	0.40	0.33	0.33	0.21	0.46	–	0.71
KL16-1-D	E₂s³	1319.7	19	0.99	2.92	4.9	0.51	0.51	0.29	0.51	0.11	0.34	0.41	0.32	0.33	0.21	0.46	–	0.71
KL16-1-D	E₂s³	1317.5	19	1	2.79	4.71	0.52	0.52	0.28	0.50	0.10	0.31	0.41	0.32	0.33	0.21	0.46	–	0.71
KL16-1-B	E₂s³	1105.7	17	1.04	0.58	0.76	0.92	0.82	0.11	0.59	0.14	0.33	0.43	0.31	0.37	0.20	0.44	–	0.77
KL16-1-B	E₂s³	1078	19	1.07	0.77	0.98	0.76	0.79	0.10	0.61	0.13	0.31	0.46	0.33	0.35	0.20	0.44	–	0.73
KL16-1-B	E₂s³	1079	19	1.07	0.77	1.01	0.71	0.79	0.13	0.58	0.13	0.37	0.42	0.35	0.34	0.19	0.47	–	0.72
KL16-1-B	E₂s³	1107	19	1.05	0.55	0.74	0.66	0.73	0.13	0.57	0.12	0.36	0.42	0.32	0.34	0.18	0.48	–	0.72
KL16-1-F	E₂s⁴	1444	23	1.04	0.68	1.04	0.64	0.6	0.20	0.55	0.11	0.32	0.44	0.30	0.35	0.19	0.46	–	0.72
KL16-1-F	E₂s⁴	1443	19	1.03	0.67	1.04	0.59	0.63	0.18	0.55	0.11	0.32	0.45	0.31	0.36	0.19	0.45	–	0.69
KL16-1-F	E₂s⁴	1473	23	1.02	0.72	1.11	0.59	0.6	0.24	0.53	0.09	0.32	0.42	0.32	0.36	0.20	0.44	–	0.71
KL16-1-F	E₂s⁴	1429	23	1.05	0.69	1.05	0.5	0.48	0.19	0.54	0.11	0.35	0.42	0.30	0.35	0.20	0.44	–	0.77
KL16-1-C	E₂s⁴	1278	21	1.02	0.44	0.38	0.42	0.51	0.17	0.58	0.34	0.27	0.43	0.33	0.37	0.18	0.45	0.06	0.68
KL16-1-D	K	1546	25	1.05	0.64	0.94	0.5	0.59	0.18	0.53	0.10	0.30	0.42	0.32	0.35	0.19	0.46	–	0.71
KL16-1-D	K	1567	25	1.04	0.69	1.06	0.51	0.6	0.19	0.53	0.11	0.32	0.43	0.33	0.35	0.19	0.46	–	0.71
KL16-1-D	K	1543.5	25	1.05	0.6	0.9	0.55	0.66	0.18	0.55	0.09	0.21	0.43	0.32	0.34	0.18	0.47	–	0.70

Note: (1) main peak carbon, (2) OEP, (3) Pr/nC₁₇, (4) Ph/nC₁₈, (5) C₂₁-/C₂₂+, (6) Pr/Ph, (7) Gam/C₃₀hop, (8) Ts/（Ts + Tm), (9) Dia.sC₂₇/C₂₇, (10) 4-methylsterane（C₃₀）/C₂₉Regular sterane, (11) C₂₉ββ/(αα + ββ), (12) αα C₂₉ 20S/(20S + 20R), (13) C₂₇reg/%, (14) C₂₈reg/%, (15) C₂₉reg/%, (16) 25-Drop hopane/C₃₀Hopane and (17) R_c.

Figure 6.

Crude oil chromatogram characteristics of KL16-1 low bulge, the Laizhou Bay Sag.

The chromatographic characteristics of the saturated hydrocarbons indicate that the crude oil of N₁g (Figure 6(a)) and N₂m (Figure 6(b)) experienced degradation, but the degradation is not so strong. Only few samples occur the fifth level degradation. As a result, some n-alkanes remained. The crude oil samples from E₂s³ and E₂s⁴ did not suffer degradation (Figure 6(c) and (d)), and their chromatogram shows as front peak type. The crude oil from E₂s⁴ in Well KL16-1-C also occurs the fifth level degradation. The n-alkanes have completely remained in the crude oil samples from Mz buried hill reservoir (Figure 6(f)), and there is no distinct peak on the chromatogram.

The spectrogram characteristics of terpane and sterane display that the N₁g crude oil has moderate rearranged sterane content, rather high 4-methyl sterane and dinosterane content, and moderate gammacerane content (Figure 7(c)). The E₂s³ crude oil has relatively high rearranged sterane content, rather high 4-methyl sterane and dinosterane content, and relatively low gammacerane content (Figure 7(d)). The crude oil from Mz buried hill reservoir has moderate rearranged sterane content, moderate 4-methyl sterane and dinosterane content, and relatively low gammacerane content (Figure 7(e)).

Figure 7.

Sterane and terpane chromatogram characteristics of the E₂s³ and E₂s⁴ source rocks and crude oil from KL16-1, the Laizhou Bay Sag.

Characteristics of biomarker compounds of E₂s³ and E₂s⁴ mudstone extracts

The E₂s³ and E₂s⁴ hydrocarbon source rocks are buried shallow in the KL16-1 zone, with R_o of 0.32–0.44%, indicating that both sets of source rocks are immature.

The experiment data of group components in source rock extracts show that: (1) the average content of paraffin hydrocarbons in 23 samples from E₂s³ source rock is 34.17%wt, the average content of aromatic hydrocarbons is 20.06%wt, that of nonhydrocarbons is 27.8%wt, and that of bituminous matter is 9.27%wt. (2) The average content of paraffin hydrocarbons in 12 samples from E₂s⁴ source rock is 33.89%wt, the average content of aromatic hydrocarbons is 17.75%wt, that of nonhydrocarbons is 25.05%wt, and that of bituminous matter is 9.32%wt (Table 3).

The main peak on the chromatogram of the saturated hydrocarbons of the E₂s³ source rock extracts lies in the later section. The n-alkanes of large C number dominate. The OEP is greater than 1, indicating the odd–even carbon advantage. The Pr/Ph is 0.50–1.83, showing that the hydrocarbon source rocks were deposited in weak reducing – reducing environment. The Gam/C₃₀hop is 0.07–0.35, and mostly less than 0.3. The 4-methyl sterane/C₂₉ sterane is 0.2–0.4, and mostly greater than 0.32. The Dia.sC₂₇/C₂₇ is less than 0.2. The regular sterane αααC₂₇ (20R)>αααC₂₈(20R)<αααC₂₉(20R); the proportion of αααC₂₉ (20R) is 0.41–0.52, with some advantage; moreover, the exinite and vitrinite contents in kerogen maceral are relatively abundant (Table 2), demonstrating that the higher plants of continental origin account for a large proportion in the input organic substance. The Ts/(Tm + Ts) is 0.2–0.6, the αααC₂₉ 20S/(20S + 20R) is 0.10–0.35, and the C₂₉ββ/(αα + ββ) is 0.25–0.56, indicating that the E₂s³ source rocks have low maturity (Table 5).

Table 5.

Chromatographic parameters of the saturated hydrocarbons of the source rock extracts in the Laizhou Bay Sag.

Well	Strata	Depth (m)	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16
KL16-1-A	E₂s³	1079	25	1.14	0.6	0.87	0.42	0.5	0.17	0.55	0.09	0.34	0.45	0.35	0.35	0.22	0.42	0.35
KL16-1-C	E₂s³	1100	17	2.72	0.61	0.8	0.72	0.87	0.25	0.48	0.13	0.35	0.56	0.32	0.34	0.22	0.44	0.32
KL16-1-B	E₂s³	1110	16	1.06	0.71	1.36	2.05	0.79	0.26	0.51	0.09	0.33	0.43	0.31	0.34	0.20	0.46	\
KL16-1-C	E₂s³	1190	27	3.94	0.62	0.75	0.28	0.93	0.27	0.48	0.13	0.38	0.51	0.33	0.36	0.21	0.43	0.35
KL16-1-F	E₂s³	1230	17	1.71	0.91	1.04	0.57	1.39	0.35	0.42	0.10	0.30	0.40	0.35	0.37	0.21	0.41	0.33
KL16-1-C	E₂s³	1260	29	2.5	0.56	0.79	0.51	0.71	0.25	0.40	0.13	\	0.39	0.18	0.30	0.17	0.52	0.36
KL16-1-F	E₂s³	1320	27	3.67	1.14	1.34	0.46	1.45	0.20	0.32	0.03	0.18	0.29	0.10	0.42	0.15	0.43	0.4
KL16-1-D	E₂s³	1480	27	1.7	1.34	0.66	0.49	1.83	0.07	0.25	0.15	0.19	0.23	0.19	0.43	0.12	0.45	0.36
KL16-1-B	E₂s⁴	1255	16	1.04	0.63	1.87	2.38	0.85	0.98	0.31	0.04	0.31	0.38	0.28	0.36	0.20	0.44	0.43
KL16-1-B	E₂s⁴	1300	16	0.59	0.76	3.71	5.17	0.52	1.21	0.26	0.03	0.32	0.36	0.29	0.36	0.21	0.43	0.44
KL16-1-C	E₂s⁴	1330	29	2.96	0.77	1.05	0.7	0.57	0.30	0.45	0.07	\	0.34	0.15	0.30	0.28	0.42	0.39
KL16-1-C	E₂s⁴	1400	19	1.52	0.59	0.74	1.1	0.43	0.21	0.50	0.13	0.29	0.51	0.31	0.36	0.22	0.42	0.38
KL16-1-F	E₂s⁴	1460	19	1.06	0.71	1.08	0.7	0.6	0.29	0.52	0.10	\	0.39	0.32	0.38	0.18	0.44	0.37

Note: (1) main peak carbon, (2) OEP, (3) Pr/nC₁₇, (4) Ph/nC₁₈, (5) C₂₁-/C₂₂+, (6) Pr/Ph, (7) Gam/C₃₀hop, (8) Ts/（Ts + Tm), (9) Dia.sC₂₇/C₂₇, (10) 4-methylsterane（C₃₀）/C₂₉ Regular sterane, (11) C₂₉ββ/(αα + ββ), (12) αα C₂₉ 20S/(20S + 20R), (13) C₂₇reg/%, (14) C₂₈reg/%, (15) C₂₉reg/% and (16) R_o.

Most of the main peak carbons on the chromatogram of the saturated hydrocarbons of the E₂s⁴ source rock extracts are lower than nC₂₀. The n-alkanes of small C number dominate. The OEP is between 1.0 and 3.0. Only a small part shows the odd–even carbon advantage. The Pr/Ph is 0.40–0.85, inferring that the hydrocarbon source rocks were deposited in reducing environment. The Gam/C₃₀hop is 0.21–1.30, and most is less than 0.3. The 4-methyl sterane/C₂₉ sterane is 0.29–0.32, less than 0.32. The Dia.sC₂₇/C₂₇ is less than 0.2. The regular sterane αααC₂₇(20R)>αααC₂₈(20R)<αααC₂₉(20R), and the proportion of αααC₂₉ (20R) is 0.42–0.44; moreover, the exinite and vitrinite contents in kerogen maceral from terrestrial organic matter are relatively abundant (Table 2), demonstrating that the input of organic matter of continental origin accounts for a large proportion. The Ts/(Tm + Ts) is 0.2–0.6, the Dia.sC₂₇/C₂₇ is less than 0.2, the αααC₂₉ 20S/(20S + 20R) is 0.15–0.32, and the C₂₉ββ/(αα + ββ) is 0.38–0.51, indicating that the E₂s⁴ source rocks are still in the immature stage (Table 5).

The feature of the chromatogram of the saturated hydrocarbons shows that the chromatogram of the E₂s³ (Figure 6(g)) has bulges, but its peaking is more complete, performing as double-peak type; the E₂s⁴ source rock (Figure 6(h)) has complete peaking, performing as front-peak type.

The spectrogram characteristics of terpane and sterane display that the E₂s³ hydrocarbon source rocks have high rearranged sterane content, rather high 4-methyl sterane and dinosterane content (Figure 7(a)). The E₂s⁴ hydrocarbon source rocks have relatively low rearranged sterane content, rather low 4-methyl sterane and dinosterane content, and high gammacerane (Figure 7(b)).

The characteristics of the biomarker compounds of oil and oil sand extracts from three plays show that the crude oil of all the three plays demonstrates some mixed source characteristics.

Thermal evolution characteristics of hydrocarbon source rocks

There is better correction between measured Ro values and the simulated Ro curve in the Laizhou Bay Sag, and the modeling results have higher accuracy (Figure 8).

Figure 8.

Typical characteristics of hydrocarbon generation modelling of the Laizhou Bay Sag (see Figure 1 for the virtual point).

The basin modeling results show that the E₂s⁴ source rocks in the Laizhou Bay Sag started to enter the peak hydrocarbon generation stage at the end of the E₂s deposition period (38 Ma), and the Ro is greater than 1%; the E₂s³ source rocks started to enter the peak hydrocarbon generation stage in the late period of the N₂m deposition (5.1 Ma), and the Ro is greater than 1% (Figure 8). The thermal evolution history modelling of the 2D seismic profile of the basin shows that when the E₂s⁴ source rocks entered the peak hydrocarbon generation period (Ro > 1%), the E₂s³ source rocks were not mature yet (38 Ma) (Figure 9(a)); when the E₂s³ source rocks became mature during the middle period of the N₁g deposition (18.6 Ma) (Ro > 0.7%), the E₂s⁴ source rocks had already reached the oil generation window (1.3%>Ro > 1%) (Figure 9(b)); all of the E₂s⁴ source rocks entered the peak hydrocarbon generation period in the early period of N₂m deposition (12 Ma) (Ro > 1%) (Figure 9(c)); by now, all the E₂s³ source rocks have got mature, and the E₂s⁴ source rocks have entered the over-mature period already (Figure 9(d)).

Figure 9.

Profile of source rock maturity evolution modeling of the Laizhou Bay Sag (see Figure 1 for the A’-A section).

Characteristics of fluid inclusions

The inclusions of the Laizhou Bay Sag can be categorized as oil-gas inclusions and hydrocarbon-bearing brine inclusions based on the inclusion components. The inclusion host minerals are mainly quartz and calcite, and the inclusions primarily exist in the micro-cracks of quartz particles, secondary quartz enlargement edges and calcite cement. Most of the brine inclusions are transparent colorless, gray or light brown. The hydrocarbon inclusions look light yellow, yellow or yellowish-brown under plane-polarized light. When activated by UV, the fluorescence of hydrocarbon inclusions may appear yellow, yellowish green (Figure 10(g) and (d)), green or blue (Figure 10(c), (d) and (h)). Observation of the inclusion fluorescence indicates that there are at least two periods of oil and gas charging (Lin et al., 2017; Parnell et al., 1998; Sellwood et al., 1993; Stasiuk and Snowdon, 1997). Both the reservoir pores and the fractures display green fluorescence (Figure 10(h)), a feature of oil and gas charging in the late period (Liu et al., 2017).

(a) Well KL16-1-B, 975.55 m, N₁g fine sandstone, isolated light brown hydrocarbon-bearing brine inclusions in tight calcite cement among sandstone particles (orthogonal polarized light); (b) Well KL16-1-B, 975.35 m, N₁g fine sandstone, isolated light brown hydrocarbon-bearing brine inclusions in calcite cement among sandstone particles (plane-polarized light); (c) Well KL16-1-B, 975.35 m, N₁g fine sandstone, isolated light oil-gas inclusions in calcite cement among sandstone particles, glowing blue, green, or yellowish green fluorescence (UV fluorescence); (d, e) Well KL16-1-D, 1319.53 m, E₂s³ fine sandstone, light yellow – gray light oil-gas inclusions generated by dissolution and distributed in groups in feldspar particles, glowing yellowish green fluorescence (UV fluorescence and plane-polarized light); (f) Well KL16-1-F, 1517.00 m, E₂s³ sandy conglomerate, light brown hydrocarbon-bearing brine inclusions generated by dissolution and distributed in groups in feldspar particles (plane-polarized light); (g) Well KL16-1-F, 1400 m, E₂s⁴ fine sandstone, light oil-gas inclusions distributed along the micro-cracks of quartz particles, glowing yellow fluorescence (UV fluorescence); (h) Well KL16-1-F, 1517 m, E₂s⁴ sandy conglomerate, transparent colorless light oil inclusions generated by dissolution and distributed in groups in feldspar particles, glowing green fluorescence (UV fluorescence); (k) Well KL16-1-D, 1620 m, Mz volcaniclastic rock, light brown hydrocarbon-bearing brine inclusions generated by dissolution and distributed in groups in feldspar crystal fragments (plane-polarized light).

Figure 10.

Microscopic features of the typical inclusions in the Laizhou Bay Sag.

The homogenization temperature of the hydrocarbon-bearing brine inclusions from the three plays indicate that the homogenization temperature of the hydrocarbon-bearing brine inclusions from N₁g and N₂m reservoirs is in two intervals, which are 50–80°C and 90–130°C, respectively (Figure 11(a)), and their salinity ranges from 0.35 wt% to 23.11 wt% (Table 6); the homogenization temperature of the hydrocarbon-bearing brine inclusions from Paleogene reservoir ranges from 60°C to 90°C (Figure 11(b)), and their salinity is 1.50–24.00 wt% (Table 6); the homogenization temperature of the hydrocarbon-bearing brine inclusions from Mz buried hill reservoir is also in two intervals, which are 60–80°C and 90–110°C, respectively (Figure 11(c)), and their salinity is 2.00–23.00 wt% (Table 6). The above data show that the Neogene reservoirs and the Mz buried hill reservoirs have experienced at least two periods of oil-gas charging.

Figure 11.

Homogenization temperature distribution of the inclusions in KL16-1, the Laizhou Bay Sag.

Table 6.

Homogenization temperature and salinity of hydrocarbon-bearing brine inclusions in the Laizhou Bay Sag.

Well	Strata	Depth (m)	Host mineral	Homogenization temperature (°C)		Salinity (wt%NaCl eq.)
Well	Strata	Depth (m)	Host mineral	Range/number of measurements	Mean	Range/number of measurements	Mean
KL16-1-A	N₁g	934	Micro-cracks of quartz particles	60–72/5	66.40	12.96–17.96/5	16.92
	N₁g	980	Micro-cracks of quartz particles	62–74/9	68.30	0.35–22.44/8	14.22
	N₁g	1013	Micro-cracks of quartz particles	66–74/5	69.00	2.41–8.95/5	4.92
	N₁g	1024	Micro-cracks of quartz particles	62–76/10	68.10	4.96–23.11/10	13.93
	E₂s³	1141	Micro-cracks of quartz particles	68–72/5	69.40	1.57–5.86/5	4.11
	E₂s⁴	1152	Micro-cracks of quartz particles	69–77/4	72.00	2.41–3.71/4	3.02
KL16-1-B	N₁g	936	Micro-cracks of quartz particles	56–73/8	65.50	8.28–23.05/6	15.68
	N₁g	974.15	Micro-cracks of quartz particles	63–73/9	69.22	0.35–4.96/9	2.91
	N₁g	975.35	Calcite cement	98–108/11	103.82	0.71–13.69/11	8.67
	N₁g	1017.5	Micro-cracks of quartz particles	55–78/6	63.00	3.87–9.6/6	6.85
	E₂s³	1075	Micro-cracks of quartz particles	63–80/7	69.00	4.18–10.11/7	6.76
	E₂s³	1202	Micro-cracks of quartz particles	70–75/3	72.00	4.18–19.37/3	9.24
	Mz	1303	Micro-cracks of quartz particles	67–80/5	74.60	2.57–22.38/5	7.79
KL16-1-C	N₂m	975	Micro-cracks of quartz particles	58–69/10	63.40	4.96–17.79/8	9.78
	N₁g	1085	Micro-cracks of quartz particles	62–72/9	67.33	1.57–13.29/9	7.24
	E₂s³	1137	Micro-cracks of quartz particles	62–71/10	66.60	11.7–23.11/8	17.55
KL16-1-D	E₂s³	1318	Micro-cracks of quartz particles	64–72/8	67.50	2.07–14.04/8	6.82
	E₂s³	1522	Micro-cracks of quartz particles	68–74/9	71.22	5.56–14.77/9	9.6
	Mz	1620	In feldspar crystal fragments	89–106/7	96.86	7.31–13.82/7	11.21
KL16-1-F	N₁g	980	Micro-cracks of quartz particles	63–71/10	67.40	3.87–13.18/10	9.28
	E₃s¹	1129	Micro-cracks of quartz particles	62–72/8	68.63	10.49–23.11/8	15.08
	E₂s⁴	1517	Calcite cement	70–84/10	76.90	4.96–12.42/10	8.1
	Mz	1560	Micro-cracks of quartz crystal fragments	73–88/8	79.00	2.74–5.26/8	3.77

Discussion

Analysis of oil and gas sources

The Paleogene E₂s³ and E₂s⁴ source rocks are both good-best source rocks; among them, the quality of E₂s³ dark mudstone is slightly better than that of E₂s⁴ dark mudstone (Table 1); the two sets of source rocks are both type II₁ kerogen (Table 2). In the southern gentle slope belt and center of the Laizhou Bay Sag, they both have arrived hydrocarbon generation threshold and entered hydrocarbon generation peak (Figure 9). They both have better hydrocarbon supply capacity, but they have different contributions to oil and gas in three plays.

The group components of the crude oil and oil sand extracts in the three plays have similar contents of paraffin hydrocarbons, aromatic hydrocarbons, nonhydrocarbons and bituminous matter, also are similar to that of two sets of source rocks (E₂s³ and E₂s⁴), showing mixed source input characteristics (Table 3).

Similarity analysis of the extracts of the crude oil or oil sands from the three plays and the biomarker compound characteristics of the two primary sets of hydrocarbon source rocks show that the oil sources can be classified into two categories. In the first category, oil mostly comes from the E₂s³ source rocks, and a little from the E₂s⁴ source rocks, demonstrating such features as Pr/Ph ≥ 0.6, Gam/C₃₀hop < 0.3, high 4-methyl sterane and dinosterane content (Figure 7(c) and (d)). In the second category, oil mostly comes from the E₂s⁴ source rocks, showing such features as Pr/Ph < 0.6, Gam/C₃₀hop ≥ 0.3, low 4-methyl sterane and dinosterane content (Figure 7(e)). Integrated investigation of the biomarker compound characteristics of the crude oil from the three plays indicates that the first category dominates the oil compositions, inferring that E₂s³ acts as the primary source rocks, while E₂s⁴ serves as the secondary source rocks to adjust and transform the charging (Tables 4 and 5). The cross-plot relations of the 4-methyl sterane/C₂₉ regular sterane and the Gammacerane/C₃₀ hopane of the crude oil from the three plays and the crude oil and source rocks from the two source rock layers also prove the above conclusion (Zan et al., 2012) (Figure 12).

Figure 12.

Cross plot of the 4-methyl sterane (C₃₀)/C₂₉ regular sterane and the gammacerane/C₃₀ hopane of the crude oil and source rocks from KL16-1.

The crude oil in Neogene and part Paleogene oil reservoirs is heavy oil, and the crude oil in buried hills is normal crude oil (Figure 5). The heavy oil was mainly generated by the overlying mudstone caprock thickness and diagenesis difference. Because of overlying caprock, the crude oil in Neogene N₁g and part E₂s³ suffered mildly biodegradation; some samples have 25-norhopane, with 25-norhopane/C₃₀ hopane <0.1, and fifth level of degradation (Peter and Molowan, 1993; Rullkotter and Wendisch, 1982) (Table 4, Figure 6(a), (b) and (e)). Its overlying caprock is thinner and at shallower burial depth (＜1300 m) (Figure 3). We inferred that hydrocarbons charged during later period and suffered short-term biodegradation (Peng et al., 2013).

The isomerization parameters of steroid terpene in biomarker compound is widely used to determine the maturity of crude oil (Wang et al., 1995). The steroid terpene isomerization parameters of KL16-1 satisfy the following inequalities: C₂₉ααα20S/(20S＋20R)<0.42, and C₂₉ββ/(αα＋ββ)<0.43. These two parameters have good correlation, and most of the samples have not reached the equilibrium point (Niu et al., 2016; Wang et al., 2012), indicating that the crude oil is mature but the maturity is not high (Figure 13) (Peters et al., 1999).

Figure 13.

Maturity of crude oil and oil sand extract samples of KL16-1.

The oil maturity, Rc, calculated based on the aromatic methylphenol index of oil and oil sand extracts shows that the oil maturity of N₁g, N₂m, Paleogene and Mz buried hill reservoirs ranges from 0.64 to 0.77, which is not high, indicating that the crude oil was generated during the peak oil generation period. In addition, the maturity of the crude oil from the three plays is similar (Table 4).

Periods and time of oil and gas charging in KL16-1

As the KL16-1 low bulge is located in structural high position, the plays are buried rather shallow (<2000 m), and the actual homogenization temperature of the hydrocarbon-bearing brine inclusions is higher than the reservoir background temperature (Figure 14(c)). It is generally believed to attribute to two aspects. First, there was invasion of high temperature fluid during the oil-gas charging process, which made the reservoir temperature increase as a whole (Liu et al., 2010). Second, the episodic expulsion of the over-pressured fluid in deep formations and the fast charging of such over-pressured fluid in shallow formations generated transient temperature effect, which made the reservoir temperature increase quickly. As the charging of the over-pressured fluid ceased, the reservoir temperature decreased gradually and approached the background temperature. Responding to the episodic expulsion of the over-pressured fluid, the temperature of the reservoirs being charged displayed transient and periodic features (Hao et al., 2003).

Figure 14.

Reservoir temperature and pressure characteristics of the Laizhou Bay Sag and the homogenization temperature of the inclusions in the thermal evolution history of Well KL16-1-B.

High temperature systems are widely developed in the E₂s³ and E₂s⁴ hydrocarbon source rock layers of the Laizhou Bay Sag, but the shallow formations have normal pressure system (Figure 14(b) and (c)). The boundary of the two pressure systems is at about 2680–2720 m. The high pressure deep zones and the low pressure shallow zones constitute the drive for the vertical oil and gas migration (Sun et al., 2010). The high temperature and high pressure fluid in the deep formations quickly migrated upward along the active faults and unconformity surfaces and charged the traps in the shallow formations. In addition, the area of the sag is rather small, the distance between the hydrocarbon source kitchen and the traps is short, and the fluid migration path is also short. These factors helped to maintain the high temperature of oil and gas during the trap charging process, and the temperature captured by the inclusions was higher than the reservoir background temperature.

The salinity features of the hydrocarbon-bearing brine inclusions coexisting with the organic inclusions reflect the characteristics of the formation water trapped in different periods. Therefore, the salinity of inclusions can be used as one of the important factors classifying the oil and gas migration periods (Chen et al., 2017; Li et al., 2003). The E₂s⁴ hydrocarbon source rocks have high salinity, while the E₂s³ source rocks have low salinity. The different salinities also reflect the different fluid sources (Table 6).

The hydrocarbon-bearing brine inclusions with different sources reserved in the KL16-1 low bulge demonstrate different salinity-homogenization temperature features (Figure 15). The homogenization temperature and salinity characteristics indicate that there are two peaks on the homogenization temperature plots of the hydrocarbon-bearing brine inclusions in the Neogene reservoirs and the Mz buried hill reservoirs, suggesting that there were two oil and gas charging phases (Burruss et al., 1983; Karlsen et al., 1993). In contrast, the homogenization temperature features of the hydrocarbon-bearing brine inclusions in the Paleogene reservoirs indicate that there was only one oil-gas charging phase. The 50–80°C inclusions were those charged in the early period, and the 90–130°C inclusions were those charged in the late period. Phase 1 oil and gas charging is characterized by scattered salinity distribution. In Phase 1, the E₂s³ and E₂s⁴ source rocks generated various types of fluid and they charged the reservoirs intermittently and swiftly. Phase 2 oil and gas charging is characterized by two types of salinity. Type I corresponds to the charging of high salinity fluid from E₂s⁴ sources rocks, while Type II corresponds to the charging of low salinity fluid from E₂s³ source rocks. The fluid of these two sets of source rocks charged the reservoirs in different phases – when the Mz buried hill reservoir was charged by the fluid from E₂s⁴ source rocks, the Neogene reservoirs were charged by the fluid from both E₂s³ and E₂s⁴ source rocks.

Figure 15.

Distribution of homogenization temperature-salinity in KL16-1, the Laizhou Bay Sag.

To sum up, the oil and gas charging in Phase 1 and Phase 2 both happened in the late period, from around 5.0 Ma till now (Figure 14(a)). There are differences between the two oil and gas charging phases – Phase 1 is the primary oil and gas charging period, while Phase 2 is the adjustment and transformation period of reservoirs charged in Phase 1. In both phases, oil and gas charging was done episodically under high pressure, and the charging happened in the late period.

Hydrocarbon accumulation mechanism of KL16-1 composite reservoirs

Conducting systems. There are three oil and gas conducting systems in the Laizhou Bay Sag, i.e. sand bodies, faults and unconformity surfaces (Figure 16). The sand bodies, faults and unconformity surfaces combine effectively to form composite conducting systems. The faults and the unconformity surfaces constitute the hydrocarbon conducting system of the Mz buried hill traps, while the sand bodies developed in E₂s³ and E₂s⁴ layers and the faults combination provide the conducting system for the Paleogene and Neogene reservoirs. These conducting systems helped to form the composite reservoirs in the three plays in the KL16-1 low bulge.

Figure 16.

Accumulation modes of the composite oil and gas reservoirs in KL16-1, the Laizhou Bay Sag.

Accumulation mechanism. Based on the oil and gas sources, charging time and phases identified, together with the conducting systems and the major trap types, the hydrocarbon accumulation process in KL16-1 can be divided into two phases.

Accumulation in Stage 1: around 5.0 Ma

The E₂s⁴ source rocks entered the hydrocarbon generation window, and most of E₂s³ source rocks got mature and entered the peak hydrocarbon generation period. The active faults connecting the two hydrocarbon source kitchens were open during the new tectonic movement period, and the oil and gas generated by the two sets of source rocks episodically charged the three sets of reservoirs driven by high pressure (Hao et al., 2005). Particularly, the E₂s³ source rocks were the primary hydrocarbon source kitchen. The crude oil that was charged in middle-shallow tectonic belts during this period (mainly being the crude oil in part Neogene and Paleogene oil reservoirs) became heavy oil reservoirs as the result of biodegradation during later period (Figure 5).

2. Accumulation in Stage 2: from 5.0 Ma till now

The E₂s⁴ source rocks were in the oil generation window period, and most of the E₂s³ source rocks reached the mature period and entered the peak hydrocarbon generation period. In this stage, the new tectonic movement only made the active faults connecting the two sets of hydrocarbon source rocks partially open, and the oil and gas generated by the two sets of source rocks, driven by high pressure, charged episodically and adjusted, in two phases. As mudstone is well developed in the Paleogene (Figure 2), with higher mudstone/formation ratio, the first phase of hydrocarbon charging had almost saturated the oil reservoirs; the cap rock has strong sealing capacity, thus there was less dissipation of the formed oil and gas reservoirs. The second phase of hydrocarbon adjustment charging had no apparent influence on the Paleogene reservoir framework. As the Neogene has poor caprock condition, the early charged oil and gas in Neogene reservoirs was dissipated and degraded by biology action, thus the oil-bearing rate in its reservoir is reduced. Hence, the second phase of hydrocarbons only charged the Neogene and the Mz buried hill reservoirs.

The E₂s⁴ source rocks were the primary hydrocarbon source kitchen in this stage. The charged crude oil in the reservoirs during this phase suffered no degradation (Figures 5 and 17).

Figure 17.

Accumulation events in the Laizhou Bay Sag.

Conclusions

Two sets of hydrocarbon sources, E₂s³ and E₂s⁴, are developed in the Laizhou Bay Sag. The reservoirs in the KL16-1 low bulge include the Mz volcanic buried hill dissolved reservoirs and the Paleogene–Neogene sandstone porous reservoirs of delta-fluvial facies. The oil and gas generated in the sag migrated to the KL16-1 structural zone along the faults and unconformity surfaces to accumulate and form three plays, i.e. the Mz buried hill, Paleogene and Neogene, all of which have the features of composite reservoirs.

The Biomarker compounds of the crude oil from the three plays in the Laizhou Bay Sag are characterized by low Pr/Ph, rather low gammacerane, high 4-methyl sterane and high dinosterane, which are very similar to the biomarker compounds of the E₂s³ source rocks. E₂s³ is the primary hydrocarbon source rock layer. The E₂s³ source rocks entered the oil generation window 5.0 Ma ago, demonstrating the features of accumulation in the late period, and the oil property matches the maturity well in the reservoirs.

The three plays in KL16-1 experienced two phases of accumulation. Phase 1 happened about 5.0 Ma, when the E₂s³ source rocks dominated, the high pressure fluid episodically charged the reservoirs quickly and all of the three plays were charged. Phase 2 happened from 5.0 Ma till now, when the E₂s⁴ source rocks dominated, the high pressure fluid episodically charged the Neogene reservoir and Mz buried hill reservoir quickly and adjusted these reservoirs formed in Phase 1.

Footnotes

Acknowledgements

We sincerely thank two anonymous reviewers and editors for supportive and helpful comments. We also thank Prof. Guosheng Xu,Dr. Xiaoxing Gong,Dr. Wenjie Li and Dr. Tengjiao Sun from the Chengdu University of Technology for helpful suggestions and discussions about the manuscript. We are particularly grateful to Prof. Guosheng Xu and his team for their assistance in the project research (The National Major Science and Technology Project of the Thirteenth Five Year Plan,number 2016ZX05024-002-007).

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research,authorship,and/or publication of this article.

Funding

The author(s) disclosed receipt of the following financial support for the research,authorship,and/or publication of this article: This work was funded by the National Major Science and Technology Project of the Thirteenth Five Year Plan (2016ZX05024-003-010).

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Hydrocarbon accumulation and formation of composite reservoirs in KL16-1 of Laizhou Bay Sag,Bohai Sea,China

Abstract

Keywords

Introduction

Geologic setting

Experimental method

Samples and tests

Basin modelling

Results

Geochemical features of the hydrocarbon source rocks

Physical property of crude oil

Characteristics of biomarker compounds of oil and oil sand extracts

Characteristics of biomarker compounds of E2s3 and E2s4 mudstone extracts

Thermal evolution characteristics of hydrocarbon source rocks

Characteristics of fluid inclusions

Discussion

Analysis of oil and gas sources

Periods and time of oil and gas charging in KL16-1

Hydrocarbon accumulation mechanism of KL16-1 composite reservoirs

Conclusions

Footnotes

Acknowledgements

Declaration of conflicting interests

Funding

References

Characteristics of biomarker compounds of E₂s³ and E₂s⁴ mudstone extracts