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Hydrocarbon accumulation of composite-buried hill reservoirs in the western subsag of Bozhong sag, Bohai Bay Basin
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ScienceDirect Natural Gas Industry B 6 (2019) 546e555 www.keaipublishing.com/en/journals/natural-gas-industry-b/
Research Article
Hydrocarbon accumulation of composite-buried hill reservoirs in the western subsag of Bozhong sag, Bohai Bay Basin*,** Xie Yuhong a, Luo Xiaoping b,c, Wang Deying a, Xu Chunqiang a, Xu Yunlong b,c,*, Hou Mingcai b,d & Chen Anqing b,d b
a China National Offshore Oil Corp., Beijing 100010, China State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation//Chengdu University of Technology, Chengdu, Sichuan 610059, China c College of Energy Resources, Chengdu University of Technology, Chengdu, Sichuan 610059, China d Institute of Sedimentary Geology, Chengdu University of Technology, Chengdu, Sichuan 610059, China
Received 3 April 2019; accepted 25 May 2019 Available online 4 December 2019
Abstract There are abundant hydrocarbon resources in the western subsag of Bozhong sag in the Bohai Bay Basin, where oilegas discoveries have been made in those shallow Neogene and Paleogene reservoirs and deep Mesozoic buried hill reservoirs, but no better understandings have yet been achieved in terms of the process of hydrocarbon accumulation and the relationship between deep buried hill reservoirs and the allocation of shallow reservoirs. Based on the organic geochemical analysis of source rocks and basin modeling of hydrocarbon generation evolution, distribution characteristics of fluid inclusion and homogeneous temperature measurement, combined with the characteristics of oil-source biomarkers, the process of hydrocarbon accumulation in this study area was resumed based upon the regional tectonic background. The following findings were obtained. (1) There are 3 sets of source rocks in the third and first members of Paleogene Shahejie Fm, and the second lower member of Paleogene Dongying Fm; the reservoirs in the peripheral uplift zones include Mesozoic volcanic rocks, Archean metamorphic rocks, and PaleogeneeNeogene deltaefluvial porous sandstones. Hydrocarbon generated in this sag migrated along the fault and the unconformity surface to the slope before accumulated in the peripheral tectonic zones, resulting in 3 sets of sourceereservoirecaprock assemblages formed with the characteristics of reservoir formation in compound oil and gas accumulation zones. (2) The stratum in the third member of Shahejie Fm is the main source rock. (3) The above three assemblages went through four periods of generating process during the geological time of 11e1 Ma. Vertically hydrocarbon sources first filled in the deep Mesozoic and Archean reservoirs, then migrated and accumulated in the shallow Neogene and Paleogene reservoirs, where multiple shore-term rapid filling of high-temperature fluids led to this typical oil and gas pooling mode. © 2019 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Keywords: Bohai Bay Basin; Western subsag of Bozhong sag; Mesozoic; Buried-hill; Composite hydrocarbon reservoir; Oil source correlation; Shallow oil and gas reservoir; Allocation relationship
*
Project supported by the National Major Science and Technology Project “Comprehensive study on hydrocarbon accumulation and favorable exploration targets in buried-hill reservoirs in the Bohai Bay Basin” (No.: 2016ZX05024-003-010) and CNOOC Research Project “Petroleum geology, typical hydrocarbon accumulation mechanisms and exploration prospects in buried-hill reservoirs in the Bohai Sea area” (No.: CCL2014TJXZSS0870). ** This is the English version of the originally published article in Natural Gas Industry (in Chinese), which can be found at https://doi.org/10.3787/j.issn.10000976.2019.05.002. * Corresponding author. State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation//Chengdu University of Technology, Chengdu, Sichuan 610059, China. E-mail address: [email protected] (Xu YL). Peer review under responsibility of Sichuan Petroleum Administration. https://doi.org/10.1016/j.ngib.2019.05.002 2352-8540/© 2019 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
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the western subsag was established, aiming to lay a foundation for the exploration at the periphery of the Bozhong sag.
0. Introduction Buried-hill reservoir refers to the uplifting petroleum accumulation in old strata beneath the regional unconformity surface, with its source of hydrocarbon mainly coming from the overlying and lateral new source rocks, and with the unconformity surface or fault plane serving as the migration path [1]. In the past few years, a series of large- and medium-sized buried-hill oil and gas fields, such as Penglai 9-1 oilfield and Bozhong 28-1 gasfield, were discovered on the uplifts and slopes at the periphery of the Bozhong sag in the Bohai Bay Basin. According to the previous studies, all these discoveries are characterized by “hydrocarbon generation in young strata and preservation in old strata”, “accumulation after rapid charging in the late stage” and “hydrocarbon supply from lateral source in sag, migration through fault and unconformity surface, and compartmental hydrocarbon accumulation” [2e6],which help guide the exploration in buried hills. The composite hydrocarbon accumulation zones dominated by buried hills represent a critical oil/gas enrichment model in the Bohai Bay Basin [7,8]. The buried-hills are different in reservoir and structure features, leading to variable hydrocarbon accumulation models in the structural zones. Based on the previous studies on the sedimentary-structural evolution, this paper discussed the main factors controlling the hydrocarbon accumulation in the western subsag of the Bozhong sag by analyzing the key elements of hydrocarbon accumulation, such as source rocks, oil-source biomarkers, transporting systems and accumulation stages. Furthermore, a hydrocarbon accumulation model of the Mesozoic buried-hill reservoir in
1. Geologic setting The western subsag in the northwestern Bozhong sag is held by the Shaleitian uplift zone and Shijiutuo uplift zone, and faces the major part of the Bozhong sag in the southeast [9] (Fig. 1). It includes several second-order structural zones, such as the northern steep slope zone, the slope zone of northeastern Shaleitian uplift, the Caofeidian 12-6 structural zone, the Bozhong 8 structural zone, and the major part of the western subsag. The western subsag comprises the following strata: the Neogene Minghuazhen Fm. (N2m) mudstone and sandstone and Guantao Fm. (N1g) sandstone, the Paleogene Dongying Fm. (E3d ) and Shahejie Fm. (E2s) dark mudstone with less sandstone band, among which the third member of E2s (E2s3) serves as the major source bed, the Mesozoic (Mz) volcanic rock, and the Archean (Ar) granite buried-hill weathering crust. From top to bottom, there are three sets of plays: the Neogene play in the upper part, the Paleogene play in the middle part, and the Mesozoic buried-hill play in the lower part. Meanwhile, the tectonic evolution can be divided into five stages: ①structural uplifting (Middle Jurassicelate Cretaceous); ② rifting episode I (Paleogene Kongdian Fm.eOligocene E2s3); ③ rifting episode II (Oligocene E2s3eE2s2); ④ rifting episode III (Oligocene E2s2eE3d1) and post-rifting thermal subsidence and depression (Miocene Guantao Fm.ePliocene lower Minghuazhen Fm.);
Fig. 1. Regional location and composite stratigraphic column of the western subsag.
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⑤neotectonic reworking (Pliocene upper Minghuazhen Fm. to present) [10] (Fig. 1). 2. Samples and experiments Core and crude oil samples were taken from the CFD12-6 and BZ8 structural zones in the western subsag. Specifically, source rocks samples were taken from the dark mudstone of E2s and E3d in 5 wells, totally 31 samples from different layers at certain interval in each well; inclusion samples were taken from three sets of plays in 4 wells, totally 39 samples from each well; 8 crude oil samples were selected from oil testing samples for pay zones in each well. The organic carbon content (TOC ), vitrinite reflectance (Ro), kerogen type and rock pyrolysis tests were conducted in accordance with The Determination of Total Organic Carbon in Sedimentary Rock (GB/T 19145-2003), Method of Determining Microscopically the Reflectance of Vitrinite in Sedimentary Rock (SY/T 5124-2012), Method of Identifying Microscopically the Macerals of Kerogen and Dividing the Kerogen Type by Transmitted-light and Fluorescence (SY/T 5125-1996), and Rock Pyrolysis Analysis (GB/T 18602-2012). The experimental devices included the CS-230 3593 carbon and sulfur analyzer, the microspectrophotometer (20100427VA3), and the BX50 biological microscope 7K05748. The extracts from source rocks and the crude oil chromatographyemass spectrometry were tested in accordance with The Standard Test Method for Biomarker in Sediment and Crude Oil by GCeMS (GB/T 18606-2001). The extracts obtained through the Soxhlet extraction were processed with the silica gel/alumina column chromatography to separate the group components, which were eluted with nhexane, dichloromethane/n-hexane (3:1) and dichloromethane/ methanol (2:1); then, the saturated hydrocarbon, aromatic hydrocarbon and non-hydrocarbon components were obtained. The saturated hydrocarbon was processed with urea collateralization to acquire the single hydrocarbon component of normal paraffin, and then analyzed with the GC and GCeMS devices. The fluid inclusions were analyzed for lithofacies through observation with the Leica DMRX HC microscope. The microthermometry was conducted using the LINKAM THMS600 heating/cooling stage with the resolution of about 0.1 C, the temperature measuring range from 196 to 600 C, the heating temperature error of about 1 C, and the cooling temperature error of about 1 C, under the temperature of 20 C and the moisture of 30%.
The TOC, Ro, kerogen type, rock pyrolysis, source rock extracts and the crude oil GCeMS tests were all completed in the Bohai Branch of CNOOC Test Center, while the fluid inclusion lithofacies and microthermometry tests were completed in Beijing Research Institute of Uranium Geology, China National Nuclear Corporation. 3. Hydrocarbon source of buried-hill reservoir 3.1. Geochemistry of source rocks The western subsag of the Bozhong sag, one of the key hydrocarbon-rich sags in the Bohai Bay Basin, contains three sets of source rocks: E2s3, E2s1 and E3d22. According to the results of experiments, the E3d22 source rock TOC is between 0.36% and 2.13% with an average less than 1.00%, S1 þ S2 is 4.05 mg/g on average, and the total hydrocarbon content is 813.7 mg/g on average; the E2s1 source rock TOC is 1.04%, S1 þ S2 is 0.62 mg/g, and the total hydrocarbon content is 164.68 mg/g; the E2s3 source rock TOC is between 0.34% and 4.29% with an average of 2.06%, S1 þ S2 is 9.35 mg/g on average, and the total hydrocarbon content is 604.5 mg/g on average. According to the evaluation standards for organic matter type and abundance of argillaceous rocks in continental basins in China [11], the E2s3 source rocks are assigned as good to excellent, and the E2s2 and E3d2 source rocks are medium to good; all of these source rocks involve sapropelicprone hybrid kerogens, which are highly capable of hydrocarbon generation. Since the source rock samples were taken from wells drilled in the low uplift zone, the Ro is relatively small and thus cannot accurately reflect the maturity (Table 1). In terms of source rock quality, the abundant hydrocarbons in the buried-hill reservoir are believed to have sourced from E2 s 3 . 3.2. Hydrocarbon source Saturated hydrocarbon chromatogram shows that n-alkanes are complete in crude oil and oil sand extract samples from the Paleogene and Mesozoic buried-hill reservoirs, and the samples from the Neogene reservoirs are observed with slight degradation. The carbon number ranges from nC17 to nC35, with nC20 or nC23 as the peak, suggesting a light carbon component predominance in fore peak distribution (Fig. 2aec). This is consistent in all three sets of source rocks. E3d22 presents the peak carbon number as nC22, with a light carbon component predominance in foreemiddle peak
Table 1 Geochemistry of source rocks in the western subsag. Well
Horizon
Lithology
TOC
(S1 þ S2)/(mg g1)
Total hydrocarbon/(mg$g1)
Ro
Kerogen type
CFD12-6-A BZ8-4-A BZ8-4-A BZ8-4-A BZ8-4-B
E3d22 E3d22
Mudstone Mudstone Mudstone Mudstone Mudstone
1.15% 0.6%e2.13%/0.92% 1.04% 0.34%e4.29%/2.06% 0.36%e1.56%/1.14%
1.23 1.53e6.10/2.55 0.62 0.33e24.84/9.35 1.33e5.62/4.05
185.06 283.5e470.7/377.1 164.68 147.8e1032.2/604.5 219.7e1457.6/813.7
0.46% 0.57%e0.76% 0.59% 0.61%e0.72% 0.57%e0.65%
II1、II2 II1、II2 II1、II2 II1 II1、II2
E2s1 E2s3 E3d22
Notes: The data are expressed as maxemin/avg.; II1 refers to sapropelic-prone hybrid kerogen, and II2 refers to humic-prone hybrid kerogen.
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Fig. 2. Chromatographic characteristic diagrams of crude oil, oil sand extracts and source rocks in the western subsag.
distribution; both E2s3 and E2s1 show complete peaks, with a fore peak distribution of light carbon components, while E2s3 is more similar to crude oil and oil sand extract GS (Fig. 2def). Saturated hydrocarbon chromatographic data suggest that the crude oil and oil sand extract examples from the Neogene and Paleogene reservoirs are similar to certain extent: the C 21/ Cþ ranges from 0.6 to 2.0, indicating a dominance of light 22 carbon components, and the oddeeven predominance (OEP) is more than 1.0, indicating an obvious even carbon number predominance; the pristane to phytane ratio (Pr/Ph) ranges from 0.22 to 1.21, and Pr/nC17 is almost consistent with Ph/ nC18, both less than 1, indicating the organic matter from strong reduction environment [12]. In contrast, the Mesozoic buried-hill reservoirs demonstrate a relatively high Pr/Ph (about 1.1 averagely), but have other features similar to shallower reservoirs. The E3d22 source rocks show a nearly þ heavy carbon component predominance, with C 21/C22 about 0.5 and OEP larger than 1.0, obviously indicative of an even carbon number predominance, and with Pr/Ph ranging from 0.57 to 1.41, and slight difference between Pr/nC17 and Ph/ nC18, both less than 1, indicating the organic matter from a weak reduction environment. The E2s1 source rocks show C 21/
Cþ 22 3.3, suggesting an obvious light carbon predominance, and Pr/Ph 1.2, indicating the organic matter from a weak reduction environment. The E2s3 source rocks resemble the E2s1 source rocks, but are more similar to the Mesozoic buried-hill reservoirs in terms of crude oil features. The triangular diagram of Pr/Ph, Pr/nC17 and Ph/nC18 (Fig. 3) shows that the crude oil samples from the Mesozoic buried-hill reservoirs are nearly distributed in a fresh water lacustrine environment, similar to the E2s3 source rocks, while the crude oil samples from the Neogene reservoirs show some but incomplete similarities to the E3d22 source rocks, mainly in a semi-salt water to salt water environment. The terpane (m/z ¼ 191) spectrograms are very similar for the crude oil and oil sand extract samples from the Neogene and Mesozoic buried-hill reservoirs, both Ts > Tm and with relatively low gammacerane content. The sterane (m/z ¼ 217) spectrograms show that the Mesozoic buried-hill reservoirs contain a higher content of diasterane and have a relatively higher maturity than the Neogene reservoirs. Both Neogene and Mesozoic buried-hill reservoirs generally reveal steranes in a “V” shape, with some C27 predominance, and all three plays take on high 4-methyl sterane (Fig. 4aec). On the terpane spectrogram, the E2d22 source rocks show a low content of
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Fig. 3. Triangular diagram of crude oil, oil sand extracts and source rocks in the western subsag.
gammacerane and also a low content of 4-methyl sterane; the E2s1 source rocks show a low content of diasterane, a medium content of 4-methyl sterane, and C29 predominance, indicating an organic matter input of higher terrestrial plant; the E2s3 source rocks, very similar to the sterane spectrogram of crude oil and oil sand extracts, show a high content of 4-methyl sterane and diasterane (Fig. 4def). According to the terpane and sterane data, the E2s3 and E2s1 source rocks have a medium content of gammacerane, with the gammacerane/C30 hopane ranging from 0.04 to 0.29, generally indicating that the salinity of depositional water is not high, possibly sourcing from a slight salt water environment [13e15].
The tricyclic terpane/C30 hopane ranges from 0.15 to 0.44, with a dominance of higher values; the (pregnane þ progesterone)/ C29aaa(20R) ranges from 0.19 to 0.47, and the content of pregnane and progesterone is high; the regular sterane distribution shows aaaC27(20R) > aaaC28(20R) < aaaC29(20R), and the proportion of aaaC27(20R) for E2s3 is over 35%, indicating an organic matter input of lower aquatic organism, and is 32% for E2s1, indicating an organic matter input of higher terrestrial plant [16]. Dramatically different from E2s, the E3d22 source rocks show a lower content of gammacerane; specifically, the gammacerane/C30 hopane ranges from 0.05 to 0.15, indicating a much lower salinity of depositional water; the tricyclic terpane/ C30 hopane ranges from 0.07 to 0.27, with a dominance of lower values; the (pregnane þ progesterone)/C29aaa(20R) ranges from 0.21 to 0.45, and the content of pregnane and progesterone is low; the regular sterane distribution shows aaaC27(20R) > aaaC28(20R) < aaaC29(20R), indicating an organic matter input of lower aquatic organism. According to the analysis of crude oil and oil sand extract samples, the Neogene, Paleogene and Mesozoic buried-hill reservoirs in the western subsag are very similar in chemistry values. For example, the gammacerane content is medium, the gammacerane/C30 hopane is about 0.15, and the salinity of depositional water is not high generally, possibly sourced from a slight salt water environment. The tricyclic terpane/C30 hopane ranges from 0.31 to 3.22, with a dominance of higher values; the (pregnane þ progesterone)/C29aaa(20R) ranges from 0.46 to 1.16, and the content of pregnane and progesterone is high; the regular sterane distribution shows aaaC27(20R) > aaaC28(20R) < aaaC29(20R), and the aaaC27(20R) proportion is over 35%, indicating an organic
Fig. 4. Terpane and sterane mass chromatography of crude oil, oil sand extracts and source rocks in the western subsag.
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matter input of lower aquatic organism. The biomarker parameters related to maturity involve the Ts/(Tm þ Ts) from 0.51 to 0.66, regC27/C27 from 0.24 to 0.30, aaaC2920S/ (20S þ 20R) from 0.38 to 1.00, and C29bb/(aa þ bb) from 0.42 to 0.87, close to the balance point of thermal evolution, indicating a mature state [17,18]. The Mesozoic samples present a higher maturity, while the Neogene samples contain some immature oil. On the triangular diagram of aaaC27(20R), aaaC28(20R) and aaaC29(20R) of regular sterane (Fig. 5), the E2s1 source rocks present a more evident feature of mixed input dominated by terrestrial plant, the E2s3 source rocks mainly involve lower plankton, and the E3d22 source rocks demonstrate a mixed input dominated by lower plankton. Based on the crude oil sample analysis, the E2s3 source rocks are further confirmed as the major source rock. The tricyclic terpane cross-plot (Fig. 6) directly reflects the oil-source correlation and demonstrates a close relation between the deep buried-hill hydrocarbons and the E2s3 source rocks, while the shallower hydrocarbons are prone to involve the mixed input [12]. The crude oil or oil sand extract samples from three plays were correlated with the biomarkers of three sets of source rocks. The crude oil can be classified into two types. One is sourced from E2s3, with Pr/Ph 1.0, light carbon component predominance in fore peak distribution (Fig. 2b, c þ & f), C from 0.6 to 2.0, Ga/C30H <0.15, 21/C22 (pregnane þ progesterone)/C29aaa(20R) 0.3, and high content of 4-methyl sterane and diphyco sterane (Fig. 4a, b, c & f). The other is sourced from E2s3 as well as E3d22, with Pr/ Ph <1.0, light carbon component predominance in þ middleefore peak distribution (Fig. 2a & d), C 21/C22 about 0.5, and Ga/C30H <0.10, showing no significant difference, indicative of an obvious mixed source. Considering the oil biomarkers of three plays, the crude oil in the Mesozoic buried-hill play is mainly the first type, indicating E2s3 as the
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Fig. 6. Cross-plot of tricyclic terpane in crude oil, oil sand extracts and source rocks in the western subsag.
major source rock; the crude oil in the Neogene Guantao and Minghuazhen Fm. and the Paleogene Dongying Fm. is mainly the second type. 4. Hydrocarbon process of buried-hill reservoir 4.1. Fluid inclusion According to the phase features, the inclusions in the western subsag can be classified into oil inclusions and hydrocarbon-bearing brine inclusions. The host minerals of inclusions mainly involve quartz and calcite, and occur in quartz grain micro-fractures, quartz overgrowth edge, and calcite cements, distributed along fractures in a band, isolated, ring or beaded shape (Fig. 7a, b, d, g & h). The gas-fluid twophase brine inclusions are observed in quartz grains of some samples (Fig. 7e), which are colorless, gray or light brown. Under the unipolarized light, the hydrocarbon inclusions take on light yellow, gray and yellowish brown (Fig. 7b, d & f). Under the UV fluorescence excitation, the oil inclusions take on yellow, yellowish green, green and bluish white (Fig. 7a, c, g & i). According to the inclusion observation under the microscope, the hydrocarbon maturity is different, indicative of multistage hydrocarbon charging and a complex accumulation process [19e22]; the rock pores and fractures commonly display fluorescence, and a lot of oil inclusions exist in a band shape along fractures (Fig. 7g & i), which indicates microfractures as the microscopic migration pathway and obvious features of later hydrocarbon accumulation [23]. 4.2. Hydrocarbon charging time and stages
Fig. 5. Triangular diagram of sterane in crude oil, oil sand extracts and source rocks in the western subsag.
According to the homogenization temperature of hydrocarbon-bearing brine inclusions and the thermal evolution history, the hydrocarbon charging stages can be recovered. Take the CFD12-6 structural zone in the western subsag
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Fig. 7. Typical inclusion pictures under microscope in the western subsag. Notes: a. Well CFD12-6-A, TVD 789 m, N2m, oil-bearing fine sandstone, fewer oil inclusions in the crack of quartz grain, light yellow fluorescence, beaded distribution; b. Well BZ8-4-D, TVD 1718.5 m, N2m, fine sandstone, fewer hydrocarbonbearing brine inclusions in some quartz grains, colorless under transmitted light, with “gas cap”; c. Well BZ8-4-C, TVD 1852 m, N2m, fine sandstone, fewer oil inclusions in the crack of quartz grains, bluish white fluorescence; d&e. Well CFD12-6-A, TVD 2637 m, E3d22, fine sandstone, a log of gasefluid two-phase brine inclusions in quartz grains; f. Well BZ8-4-C, TVD 2385 m, N1g, pebbled fine sandstone, fewer oil inclusions in the crack of quartz grains, dark yellow fluorescence; g. Well CFD12-6-A, TVD 3125 m, Mz, sedimentary tuff, multiple cracks observed on thin sections, a lot of yellow fluorescent oil inclusions in cracks as bands, suggesting micro-cracks as microscopic migration pathway and oil inclusions trapped during quartz growth; h. Well CFD12-6-A, TVD 3105.5 m, Mz, sedimentary tuff, a lot of oil inclusions in the crack of quartz grains, transparent under transmitted light; i. Well CFD12-6-A, TVD 3105.5 m, Mz, sedimentary tuff, a lot of oil inclusions in the crack of quartz grains, beaded distribution, bright yellow fluorescence, and cracks filled with asphalt in tuff, suggesting the cracks as the microscopic migration pathways.
as an example, the homogenization temperature of hydrocarbon-bearing brine inclusions at different occurrences shows that the three plays are different in hydrocarbon accumulation stages. The N2m reservoir corresponds to two stages of hydrocarbon charging (Fig. 8a): early charging for 50e60 C and late charging for 70e80 C, both are nearsource charging within the subsag. Rapid charging of hightemperature fluids from deep strata within the subsag is believed for 100e120 C, with the trapping temperature higher than the reservoir background temperature, and happened when the deep fault connecting with the subsag opened, following the above-mentioned two stages. The N1g reservoir corresponds to the first stage of hydrocarbon charging (Fig. 8b), with the homogenization temperature from 80 C to 90 C. The Paleogene reservoir also corresponds to the first stage of hydrocarbon charging (Fig. 8c), with the homogenization temperature from 80 C to 90 C, and also contains the hydrocarbon-bearing brine inclusions captured at the temperature higher than the background temperature, so
this is a rapid charging of high-temperature fluid from deep strata within the subsag. The Mesozoic reservoir corresponds to the first stage of hydrocarbon charging (Fig. 8d), with the homogenization temperature from 100 C to 110 C; it is also believed to have experienced a process of less hydrocarbon charging after the principal hydrocarbon charging stage and in the late stage when hydrocarbons were charged in shallower strata. In summary, hydrocarbon charging occurred late in the western subsag. It can be divided into three stages: I 11e9 Ma, when hydrocarbon charged the Mesozoic buried-hill reservoir, II 5e3 Ma, when hydrocarbon charged the shallower reservoirs, and III at 1 Ma, when hydrocarbon charged the N2m reservoirs. At the time when the deep fault connecting the subsag opened, the high-temperature fluid from the deep strata of the subsag charged the reservoirs quickly, resulting in the homogenization temperature of hydrocarbon-bearing fluid inclusions higher than the reservoir background temperature (Fig. 9).
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Fig. 8. Homogenization temperature histogram of inclusions in Well CFD12-6-A in the western subsag.
4.3. Hydrocarbon accumulation mechanism in the western subsag There are three types of hydrocarbon transport pathways in the western subsag: fault, sand and unconformity surface (Fig. 10), which cross and alternate to form a complex transport network [24]. The fault system and unconformity surface constitute a vertical fault-unconformity pathway to communicate the source rocks and shallow traps, while the deep, stable, thick sands contacting source rocks and the shallow thick N1g glutenite act as the “interchange” between primary migration and secondary allocation [25]; both E2s3 sands contacting the
source rocks and N2m1 sands communicating faults are favorable reservoir beds. Many sets of unconformity surface resulted from the early structural rising and outcropping act as the “bridge” communicating the source kitchens and long distance transporting passage for the secondary migration. Based on the hydrocarbon charging time and stages, and the transport system and the hydrocarbon source, the hydrocarbon accumulation process can be classified into four stages: Stage I (11e9 Ma): The E2s3 source rocks stayed in the oil generating window, and the E2d22 source rocks had not begun to generate hydrocarbons massively.In the period of
Fig. 9. Thermal evolution history corresponding to inclusion homogenization temperature in Well CFD12-6-A in the western subsag.
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Fig. 10. Hydrocarbon accumulation pattern of the western subsag.
neotectonics, the fault reaching the basement opened, and the hydrocarbons sourced from E2s3 preferentially charged the Mesozoic and Archean buried-hill reservoirs along faults and unconformity surfaces. Stage II (5e3 Ma): The hydrocarbons sourced from E2s3 continued to charge the Mesozoic and Archean buried-hill reservoirs and migrated upward along faults and unconformity surfaces to charge the Paleogene and Neogene reservoirs. In this stage, the E2s3 source rocks remained as the major source kitchen. Stage III (1 Ma): The hydrocarbons sourced from E2s3 continued to migrate upward along faults, unconformity surfaces and sands to charge the Neogene shallow reservoirs. In this process, the E2s3 hydrocarbons were mixed with the immature hydrocarbons sourced from E3d. Stage Ⅳ: The high-temperature hydrocarbon fluids sourced from E2s3 in the deep strata of the western subsag quickly charged the three plays along faults, unconformity surfaces and sands when the faults were completely open. This stage is featured by intermittent quick charging.
sterane content, and high dinoflagellate sterane content, which are very similar to the biomarkers of the E2s3 source rocks that serve as the major source kitchen in the subsag. The E2s3 source rocks have entered the oil generation window and match well with the oil property and maturity. The E3d22 source rocks show a low maturity, only with a certain similarity to the shallow Paleogene and Neogene reservoirs. In the late stage, the hydrocarbons sourced from E3d22 together with the hydrocarbons from E2s3 charged the shallower reservoirs. 3) The three plays experienced four stages of hydrocarbon accumulation. At 11e1 Ma, the hydrocarbons preferentially charged the deep Mesozoic and Archean buriedhill reservoirs in a vertical direction, and then migrated upward and charged the shallow Paleogene and Neogene reservoirs. In this process, the E2s3 source rocks in the deep strata of the subsag made a significant contribution to all three plays. The hydrocarbon accumulation pattern is featured by repeated short-term quick charging of high-temperature fluids.
The hydrocarbon accumulation pattern of the western subsag is illustrated in Fig. 10. References 5. Conclusions 1) There are three sets of source rocks (E2s3, E2s1 and E3d22) in the western subsag of the Bozhong sag. The reservoirs in the peripheral uplifts comprise the Mesozoic volcanic rocks and Archean metamorphic rocks as well as the PaleogeneeNeogene porous sandstone of delta-fluvial facies. The hydrocarbons sourced from the subsag migrated to the slope along the fault and unconformity surface and accumulated in the peripheral structural zones, giving rise to three plays featured by complex accumulation. 2) The oil biomarkers of three plays are featured by low Pr/Ph, low gammacerane content, high 4-methyl
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Xie YH. et al. / Natural Gas Industry B 6 (2019) 546e555 [5] Jiang Youlu, Liu Pei, Liu Hua, Song Guoqi, Wang Yongshi & Cui Xiaojun. Difference of reservoir forming conditions of different depressions and accumulation models of Neogene hydrocarbon in Bohai Bay Basin. J China Univ Pet (Ed Nat Sci) 2014;38(1):14e21. [6] Xu Guosheng, Chen Fei, Zhou Xinhuai, Wang Xin, Li Jianping, Wang Guozhi, et al. Hydrocarbon accumulation process of large scale oil and gas field of granite buried hill in Penglai 9-1 structure, Bohai, China. J Chengdu Univ Technol (Sci Technol Ed) 2016;43(2):153e62. [7] Yan Dunshi, Wang Shangwen & Tang Zhi. Block faulting and formation of oil and gas fields associated with buried hills in Bohai Bay Basin. Acta Pet Sin 1980;1(2):1e10. [8] Dong Dong & Chen Jie. The distribution and exploration of buried-hillreservoir in the faulted basin, eastern China: taking Jiyang depression as an example. Pet Explor Dev 2000;27(6):26e7. [9] Mi Lijun & Duan Jili. Characteristics of middle and shallow strata oilegas reservoirs and oilegas accumulation rule in the middle area of Bohai. Acta Pet Sin 2001;22(2):32e7. [10] Yao Jia, Chen Baozhu, Zhang Xintao, Xu Chunqiang & Guo Rui. Preliminary discussion on late stage rapid petroleum accumulation pattern in the western subsag of Bozhong depression, Bohai Bay, China. J Chengdu Univ Technol (Sci Technol Ed) 2017;44(2):149e57. [11] Hu Jianyi & Huang Difan. The bases of nonmarine petroleum geology in China. Beijing: Petroleum Industry Press; 1991. [12] Peters KE, Walters CC & Moldowan JM. The biomarker guide: interpreting molecular fossils in petroleum and ancient sediments. 2nd ed. Upper Saddle River: Prentice Hall; 2005. [13] Zhu Yangming, Weng Huaxin, Su Aiguo, Liang Digang & Peng Dehua. Geochemical characteristics of tertiary saline lacustrine oils in the Western Qaidam Basin, Northwest China. Appl Geochem 2005;20(10):1875e89. [14] Chen Jianyu, Bi Yanpong, Zhang Jiguo & Li Shuafu. Oil-source correlation in the Fulin Basin, Shengli petroleum province, East China. Org Geochem 1996;24(8/9):931e40.
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[15] Hao Fang, Zhou Xinhuai, Zhu Yangming & Yang Yuanyuan. Mechanisms for oil depletion and enrichment on the Shijiutuo uplift, Bohai Bay Basin, China. AAPG Bull 2009;93(8):1015e37. [16] Huang WY & Meinschein WG. Sterols as ecological indicators. Geochim Cosmochim Acta 1979;43(5):739e45. [17] Mackenzie AS. Application of biological markers in petroleum geochemistry. London: Academic Press; 1984. [18] Seifert WK, Moldowan JM & Demaison GJ. Source correlation of biodegraded oils. Org Geochem 1984;6:633e43. [19] Sellwood BW, Wilkes M & James B. Hydrocarbon inclusions in late calcite cements: migration indicators in the Great Oolite Group, Weald Basin, S. England. Sediment Geol 1993;84(1/4):51e5. [20] Stasiuk LD & Snowdon LR. Fluorescence micro-spectrometry of synthetic and natural hydrocarbon fluid inclusions: crude oil chemistry, density and application to petroleum migration. Appl Geochem 1997;12(3):229e41. [21] Parnell J, Carey P & Duncan W. History of hydrocarbon charge on the Atlantic Margin: evidence from fluid-inclusion studies, west of Shetland. Geology 1998;26(9):807e10. [22] Lin Hongmei, Cheng Fuqi, Wang Yongshi & Song Guoqi. Fluid inclusion evidence for multi-period oil charge in Shahejie Member 4, Bonan Subsag, Bohai Bay Basin. Oil Gas Geol 2017;38(2):209e18. [23] Liu Qingshun, Yang Bo, Yang Haifeng, Guo Tao, Wu Jingchao & Wang Liliang. Application of quantitative fluorescence techniques in oil zone identification and hydrocarbon charging process research in Bohai Oilfield. China Offshore Oil Gas 2017;29(2):27e35. [24] Wang Liang, Zhou Xinhuai, Niu Chengmin & Yang Bo. The effect of structure evolution on hydrocarbon accumulation in Laizhouwan Depression, Bohai Bay. Chin J Geol 2011;43(3):838e46. [25] Deng Yunhua & Li Jianping. The formation mechanism of shallow reservoir: a case from oil and gas areas in Bohai Sea. Beijing: Petroleum Industry Press; 2009.
ScienceDirect Natural Gas Industry B 6 (2019) 546e555 www.keaipublishing.com/en/journals/natural-gas-industry-b/
Research Article
Hydrocarbon accumulation of composite-buried hill reservoirs in the western subsag of Bozhong sag, Bohai Bay Basin*,** Xie Yuhong a, Luo Xiaoping b,c, Wang Deying a, Xu Chunqiang a, Xu Yunlong b,c,*, Hou Mingcai b,d & Chen Anqing b,d b
a China National Offshore Oil Corp., Beijing 100010, China State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation//Chengdu University of Technology, Chengdu, Sichuan 610059, China c College of Energy Resources, Chengdu University of Technology, Chengdu, Sichuan 610059, China d Institute of Sedimentary Geology, Chengdu University of Technology, Chengdu, Sichuan 610059, China
Received 3 April 2019; accepted 25 May 2019 Available online 4 December 2019
Abstract There are abundant hydrocarbon resources in the western subsag of Bozhong sag in the Bohai Bay Basin, where oilegas discoveries have been made in those shallow Neogene and Paleogene reservoirs and deep Mesozoic buried hill reservoirs, but no better understandings have yet been achieved in terms of the process of hydrocarbon accumulation and the relationship between deep buried hill reservoirs and the allocation of shallow reservoirs. Based on the organic geochemical analysis of source rocks and basin modeling of hydrocarbon generation evolution, distribution characteristics of fluid inclusion and homogeneous temperature measurement, combined with the characteristics of oil-source biomarkers, the process of hydrocarbon accumulation in this study area was resumed based upon the regional tectonic background. The following findings were obtained. (1) There are 3 sets of source rocks in the third and first members of Paleogene Shahejie Fm, and the second lower member of Paleogene Dongying Fm; the reservoirs in the peripheral uplift zones include Mesozoic volcanic rocks, Archean metamorphic rocks, and PaleogeneeNeogene deltaefluvial porous sandstones. Hydrocarbon generated in this sag migrated along the fault and the unconformity surface to the slope before accumulated in the peripheral tectonic zones, resulting in 3 sets of sourceereservoirecaprock assemblages formed with the characteristics of reservoir formation in compound oil and gas accumulation zones. (2) The stratum in the third member of Shahejie Fm is the main source rock. (3) The above three assemblages went through four periods of generating process during the geological time of 11e1 Ma. Vertically hydrocarbon sources first filled in the deep Mesozoic and Archean reservoirs, then migrated and accumulated in the shallow Neogene and Paleogene reservoirs, where multiple shore-term rapid filling of high-temperature fluids led to this typical oil and gas pooling mode. © 2019 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Keywords: Bohai Bay Basin; Western subsag of Bozhong sag; Mesozoic; Buried-hill; Composite hydrocarbon reservoir; Oil source correlation; Shallow oil and gas reservoir; Allocation relationship
*
Project supported by the National Major Science and Technology Project “Comprehensive study on hydrocarbon accumulation and favorable exploration targets in buried-hill reservoirs in the Bohai Bay Basin” (No.: 2016ZX05024-003-010) and CNOOC Research Project “Petroleum geology, typical hydrocarbon accumulation mechanisms and exploration prospects in buried-hill reservoirs in the Bohai Sea area” (No.: CCL2014TJXZSS0870). ** This is the English version of the originally published article in Natural Gas Industry (in Chinese), which can be found at https://doi.org/10.3787/j.issn.10000976.2019.05.002. * Corresponding author. State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation//Chengdu University of Technology, Chengdu, Sichuan 610059, China. E-mail address: [email protected] (Xu YL). Peer review under responsibility of Sichuan Petroleum Administration. https://doi.org/10.1016/j.ngib.2019.05.002 2352-8540/© 2019 Sichuan Petroleum Administration. Production and hosting by Elsevier B.V. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
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the western subsag was established, aiming to lay a foundation for the exploration at the periphery of the Bozhong sag.
0. Introduction Buried-hill reservoir refers to the uplifting petroleum accumulation in old strata beneath the regional unconformity surface, with its source of hydrocarbon mainly coming from the overlying and lateral new source rocks, and with the unconformity surface or fault plane serving as the migration path [1]. In the past few years, a series of large- and medium-sized buried-hill oil and gas fields, such as Penglai 9-1 oilfield and Bozhong 28-1 gasfield, were discovered on the uplifts and slopes at the periphery of the Bozhong sag in the Bohai Bay Basin. According to the previous studies, all these discoveries are characterized by “hydrocarbon generation in young strata and preservation in old strata”, “accumulation after rapid charging in the late stage” and “hydrocarbon supply from lateral source in sag, migration through fault and unconformity surface, and compartmental hydrocarbon accumulation” [2e6],which help guide the exploration in buried hills. The composite hydrocarbon accumulation zones dominated by buried hills represent a critical oil/gas enrichment model in the Bohai Bay Basin [7,8]. The buried-hills are different in reservoir and structure features, leading to variable hydrocarbon accumulation models in the structural zones. Based on the previous studies on the sedimentary-structural evolution, this paper discussed the main factors controlling the hydrocarbon accumulation in the western subsag of the Bozhong sag by analyzing the key elements of hydrocarbon accumulation, such as source rocks, oil-source biomarkers, transporting systems and accumulation stages. Furthermore, a hydrocarbon accumulation model of the Mesozoic buried-hill reservoir in
1. Geologic setting The western subsag in the northwestern Bozhong sag is held by the Shaleitian uplift zone and Shijiutuo uplift zone, and faces the major part of the Bozhong sag in the southeast [9] (Fig. 1). It includes several second-order structural zones, such as the northern steep slope zone, the slope zone of northeastern Shaleitian uplift, the Caofeidian 12-6 structural zone, the Bozhong 8 structural zone, and the major part of the western subsag. The western subsag comprises the following strata: the Neogene Minghuazhen Fm. (N2m) mudstone and sandstone and Guantao Fm. (N1g) sandstone, the Paleogene Dongying Fm. (E3d ) and Shahejie Fm. (E2s) dark mudstone with less sandstone band, among which the third member of E2s (E2s3) serves as the major source bed, the Mesozoic (Mz) volcanic rock, and the Archean (Ar) granite buried-hill weathering crust. From top to bottom, there are three sets of plays: the Neogene play in the upper part, the Paleogene play in the middle part, and the Mesozoic buried-hill play in the lower part. Meanwhile, the tectonic evolution can be divided into five stages: ①structural uplifting (Middle Jurassicelate Cretaceous); ② rifting episode I (Paleogene Kongdian Fm.eOligocene E2s3); ③ rifting episode II (Oligocene E2s3eE2s2); ④ rifting episode III (Oligocene E2s2eE3d1) and post-rifting thermal subsidence and depression (Miocene Guantao Fm.ePliocene lower Minghuazhen Fm.);
Fig. 1. Regional location and composite stratigraphic column of the western subsag.
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⑤neotectonic reworking (Pliocene upper Minghuazhen Fm. to present) [10] (Fig. 1). 2. Samples and experiments Core and crude oil samples were taken from the CFD12-6 and BZ8 structural zones in the western subsag. Specifically, source rocks samples were taken from the dark mudstone of E2s and E3d in 5 wells, totally 31 samples from different layers at certain interval in each well; inclusion samples were taken from three sets of plays in 4 wells, totally 39 samples from each well; 8 crude oil samples were selected from oil testing samples for pay zones in each well. The organic carbon content (TOC ), vitrinite reflectance (Ro), kerogen type and rock pyrolysis tests were conducted in accordance with The Determination of Total Organic Carbon in Sedimentary Rock (GB/T 19145-2003), Method of Determining Microscopically the Reflectance of Vitrinite in Sedimentary Rock (SY/T 5124-2012), Method of Identifying Microscopically the Macerals of Kerogen and Dividing the Kerogen Type by Transmitted-light and Fluorescence (SY/T 5125-1996), and Rock Pyrolysis Analysis (GB/T 18602-2012). The experimental devices included the CS-230 3593 carbon and sulfur analyzer, the microspectrophotometer (20100427VA3), and the BX50 biological microscope 7K05748. The extracts from source rocks and the crude oil chromatographyemass spectrometry were tested in accordance with The Standard Test Method for Biomarker in Sediment and Crude Oil by GCeMS (GB/T 18606-2001). The extracts obtained through the Soxhlet extraction were processed with the silica gel/alumina column chromatography to separate the group components, which were eluted with nhexane, dichloromethane/n-hexane (3:1) and dichloromethane/ methanol (2:1); then, the saturated hydrocarbon, aromatic hydrocarbon and non-hydrocarbon components were obtained. The saturated hydrocarbon was processed with urea collateralization to acquire the single hydrocarbon component of normal paraffin, and then analyzed with the GC and GCeMS devices. The fluid inclusions were analyzed for lithofacies through observation with the Leica DMRX HC microscope. The microthermometry was conducted using the LINKAM THMS600 heating/cooling stage with the resolution of about 0.1 C, the temperature measuring range from 196 to 600 C, the heating temperature error of about 1 C, and the cooling temperature error of about 1 C, under the temperature of 20 C and the moisture of 30%.
The TOC, Ro, kerogen type, rock pyrolysis, source rock extracts and the crude oil GCeMS tests were all completed in the Bohai Branch of CNOOC Test Center, while the fluid inclusion lithofacies and microthermometry tests were completed in Beijing Research Institute of Uranium Geology, China National Nuclear Corporation. 3. Hydrocarbon source of buried-hill reservoir 3.1. Geochemistry of source rocks The western subsag of the Bozhong sag, one of the key hydrocarbon-rich sags in the Bohai Bay Basin, contains three sets of source rocks: E2s3, E2s1 and E3d22. According to the results of experiments, the E3d22 source rock TOC is between 0.36% and 2.13% with an average less than 1.00%, S1 þ S2 is 4.05 mg/g on average, and the total hydrocarbon content is 813.7 mg/g on average; the E2s1 source rock TOC is 1.04%, S1 þ S2 is 0.62 mg/g, and the total hydrocarbon content is 164.68 mg/g; the E2s3 source rock TOC is between 0.34% and 4.29% with an average of 2.06%, S1 þ S2 is 9.35 mg/g on average, and the total hydrocarbon content is 604.5 mg/g on average. According to the evaluation standards for organic matter type and abundance of argillaceous rocks in continental basins in China [11], the E2s3 source rocks are assigned as good to excellent, and the E2s2 and E3d2 source rocks are medium to good; all of these source rocks involve sapropelicprone hybrid kerogens, which are highly capable of hydrocarbon generation. Since the source rock samples were taken from wells drilled in the low uplift zone, the Ro is relatively small and thus cannot accurately reflect the maturity (Table 1). In terms of source rock quality, the abundant hydrocarbons in the buried-hill reservoir are believed to have sourced from E2 s 3 . 3.2. Hydrocarbon source Saturated hydrocarbon chromatogram shows that n-alkanes are complete in crude oil and oil sand extract samples from the Paleogene and Mesozoic buried-hill reservoirs, and the samples from the Neogene reservoirs are observed with slight degradation. The carbon number ranges from nC17 to nC35, with nC20 or nC23 as the peak, suggesting a light carbon component predominance in fore peak distribution (Fig. 2aec). This is consistent in all three sets of source rocks. E3d22 presents the peak carbon number as nC22, with a light carbon component predominance in foreemiddle peak
Table 1 Geochemistry of source rocks in the western subsag. Well
Horizon
Lithology
TOC
(S1 þ S2)/(mg g1)
Total hydrocarbon/(mg$g1)
Ro
Kerogen type
CFD12-6-A BZ8-4-A BZ8-4-A BZ8-4-A BZ8-4-B
E3d22 E3d22
Mudstone Mudstone Mudstone Mudstone Mudstone
1.15% 0.6%e2.13%/0.92% 1.04% 0.34%e4.29%/2.06% 0.36%e1.56%/1.14%
1.23 1.53e6.10/2.55 0.62 0.33e24.84/9.35 1.33e5.62/4.05
185.06 283.5e470.7/377.1 164.68 147.8e1032.2/604.5 219.7e1457.6/813.7
0.46% 0.57%e0.76% 0.59% 0.61%e0.72% 0.57%e0.65%
II1、II2 II1、II2 II1、II2 II1 II1、II2
E2s1 E2s3 E3d22
Notes: The data are expressed as maxemin/avg.; II1 refers to sapropelic-prone hybrid kerogen, and II2 refers to humic-prone hybrid kerogen.
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Fig. 2. Chromatographic characteristic diagrams of crude oil, oil sand extracts and source rocks in the western subsag.
distribution; both E2s3 and E2s1 show complete peaks, with a fore peak distribution of light carbon components, while E2s3 is more similar to crude oil and oil sand extract GS (Fig. 2def). Saturated hydrocarbon chromatographic data suggest that the crude oil and oil sand extract examples from the Neogene and Paleogene reservoirs are similar to certain extent: the C 21/ Cþ ranges from 0.6 to 2.0, indicating a dominance of light 22 carbon components, and the oddeeven predominance (OEP) is more than 1.0, indicating an obvious even carbon number predominance; the pristane to phytane ratio (Pr/Ph) ranges from 0.22 to 1.21, and Pr/nC17 is almost consistent with Ph/ nC18, both less than 1, indicating the organic matter from strong reduction environment [12]. In contrast, the Mesozoic buried-hill reservoirs demonstrate a relatively high Pr/Ph (about 1.1 averagely), but have other features similar to shallower reservoirs. The E3d22 source rocks show a nearly þ heavy carbon component predominance, with C 21/C22 about 0.5 and OEP larger than 1.0, obviously indicative of an even carbon number predominance, and with Pr/Ph ranging from 0.57 to 1.41, and slight difference between Pr/nC17 and Ph/ nC18, both less than 1, indicating the organic matter from a weak reduction environment. The E2s1 source rocks show C 21/
Cþ 22 3.3, suggesting an obvious light carbon predominance, and Pr/Ph 1.2, indicating the organic matter from a weak reduction environment. The E2s3 source rocks resemble the E2s1 source rocks, but are more similar to the Mesozoic buried-hill reservoirs in terms of crude oil features. The triangular diagram of Pr/Ph, Pr/nC17 and Ph/nC18 (Fig. 3) shows that the crude oil samples from the Mesozoic buried-hill reservoirs are nearly distributed in a fresh water lacustrine environment, similar to the E2s3 source rocks, while the crude oil samples from the Neogene reservoirs show some but incomplete similarities to the E3d22 source rocks, mainly in a semi-salt water to salt water environment. The terpane (m/z ¼ 191) spectrograms are very similar for the crude oil and oil sand extract samples from the Neogene and Mesozoic buried-hill reservoirs, both Ts > Tm and with relatively low gammacerane content. The sterane (m/z ¼ 217) spectrograms show that the Mesozoic buried-hill reservoirs contain a higher content of diasterane and have a relatively higher maturity than the Neogene reservoirs. Both Neogene and Mesozoic buried-hill reservoirs generally reveal steranes in a “V” shape, with some C27 predominance, and all three plays take on high 4-methyl sterane (Fig. 4aec). On the terpane spectrogram, the E2d22 source rocks show a low content of
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Fig. 3. Triangular diagram of crude oil, oil sand extracts and source rocks in the western subsag.
gammacerane and also a low content of 4-methyl sterane; the E2s1 source rocks show a low content of diasterane, a medium content of 4-methyl sterane, and C29 predominance, indicating an organic matter input of higher terrestrial plant; the E2s3 source rocks, very similar to the sterane spectrogram of crude oil and oil sand extracts, show a high content of 4-methyl sterane and diasterane (Fig. 4def). According to the terpane and sterane data, the E2s3 and E2s1 source rocks have a medium content of gammacerane, with the gammacerane/C30 hopane ranging from 0.04 to 0.29, generally indicating that the salinity of depositional water is not high, possibly sourcing from a slight salt water environment [13e15].
The tricyclic terpane/C30 hopane ranges from 0.15 to 0.44, with a dominance of higher values; the (pregnane þ progesterone)/ C29aaa(20R) ranges from 0.19 to 0.47, and the content of pregnane and progesterone is high; the regular sterane distribution shows aaaC27(20R) > aaaC28(20R) < aaaC29(20R), and the proportion of aaaC27(20R) for E2s3 is over 35%, indicating an organic matter input of lower aquatic organism, and is 32% for E2s1, indicating an organic matter input of higher terrestrial plant [16]. Dramatically different from E2s, the E3d22 source rocks show a lower content of gammacerane; specifically, the gammacerane/C30 hopane ranges from 0.05 to 0.15, indicating a much lower salinity of depositional water; the tricyclic terpane/ C30 hopane ranges from 0.07 to 0.27, with a dominance of lower values; the (pregnane þ progesterone)/C29aaa(20R) ranges from 0.21 to 0.45, and the content of pregnane and progesterone is low; the regular sterane distribution shows aaaC27(20R) > aaaC28(20R) < aaaC29(20R), indicating an organic matter input of lower aquatic organism. According to the analysis of crude oil and oil sand extract samples, the Neogene, Paleogene and Mesozoic buried-hill reservoirs in the western subsag are very similar in chemistry values. For example, the gammacerane content is medium, the gammacerane/C30 hopane is about 0.15, and the salinity of depositional water is not high generally, possibly sourced from a slight salt water environment. The tricyclic terpane/C30 hopane ranges from 0.31 to 3.22, with a dominance of higher values; the (pregnane þ progesterone)/C29aaa(20R) ranges from 0.46 to 1.16, and the content of pregnane and progesterone is high; the regular sterane distribution shows aaaC27(20R) > aaaC28(20R) < aaaC29(20R), and the aaaC27(20R) proportion is over 35%, indicating an organic
Fig. 4. Terpane and sterane mass chromatography of crude oil, oil sand extracts and source rocks in the western subsag.
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matter input of lower aquatic organism. The biomarker parameters related to maturity involve the Ts/(Tm þ Ts) from 0.51 to 0.66, regC27/C27 from 0.24 to 0.30, aaaC2920S/ (20S þ 20R) from 0.38 to 1.00, and C29bb/(aa þ bb) from 0.42 to 0.87, close to the balance point of thermal evolution, indicating a mature state [17,18]. The Mesozoic samples present a higher maturity, while the Neogene samples contain some immature oil. On the triangular diagram of aaaC27(20R), aaaC28(20R) and aaaC29(20R) of regular sterane (Fig. 5), the E2s1 source rocks present a more evident feature of mixed input dominated by terrestrial plant, the E2s3 source rocks mainly involve lower plankton, and the E3d22 source rocks demonstrate a mixed input dominated by lower plankton. Based on the crude oil sample analysis, the E2s3 source rocks are further confirmed as the major source rock. The tricyclic terpane cross-plot (Fig. 6) directly reflects the oil-source correlation and demonstrates a close relation between the deep buried-hill hydrocarbons and the E2s3 source rocks, while the shallower hydrocarbons are prone to involve the mixed input [12]. The crude oil or oil sand extract samples from three plays were correlated with the biomarkers of three sets of source rocks. The crude oil can be classified into two types. One is sourced from E2s3, with Pr/Ph 1.0, light carbon component predominance in fore peak distribution (Fig. 2b, c þ & f), C from 0.6 to 2.0, Ga/C30H <0.15, 21/C22 (pregnane þ progesterone)/C29aaa(20R) 0.3, and high content of 4-methyl sterane and diphyco sterane (Fig. 4a, b, c & f). The other is sourced from E2s3 as well as E3d22, with Pr/ Ph <1.0, light carbon component predominance in þ middleefore peak distribution (Fig. 2a & d), C 21/C22 about 0.5, and Ga/C30H <0.10, showing no significant difference, indicative of an obvious mixed source. Considering the oil biomarkers of three plays, the crude oil in the Mesozoic buried-hill play is mainly the first type, indicating E2s3 as the
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Fig. 6. Cross-plot of tricyclic terpane in crude oil, oil sand extracts and source rocks in the western subsag.
major source rock; the crude oil in the Neogene Guantao and Minghuazhen Fm. and the Paleogene Dongying Fm. is mainly the second type. 4. Hydrocarbon process of buried-hill reservoir 4.1. Fluid inclusion According to the phase features, the inclusions in the western subsag can be classified into oil inclusions and hydrocarbon-bearing brine inclusions. The host minerals of inclusions mainly involve quartz and calcite, and occur in quartz grain micro-fractures, quartz overgrowth edge, and calcite cements, distributed along fractures in a band, isolated, ring or beaded shape (Fig. 7a, b, d, g & h). The gas-fluid twophase brine inclusions are observed in quartz grains of some samples (Fig. 7e), which are colorless, gray or light brown. Under the unipolarized light, the hydrocarbon inclusions take on light yellow, gray and yellowish brown (Fig. 7b, d & f). Under the UV fluorescence excitation, the oil inclusions take on yellow, yellowish green, green and bluish white (Fig. 7a, c, g & i). According to the inclusion observation under the microscope, the hydrocarbon maturity is different, indicative of multistage hydrocarbon charging and a complex accumulation process [19e22]; the rock pores and fractures commonly display fluorescence, and a lot of oil inclusions exist in a band shape along fractures (Fig. 7g & i), which indicates microfractures as the microscopic migration pathway and obvious features of later hydrocarbon accumulation [23]. 4.2. Hydrocarbon charging time and stages
Fig. 5. Triangular diagram of sterane in crude oil, oil sand extracts and source rocks in the western subsag.
According to the homogenization temperature of hydrocarbon-bearing brine inclusions and the thermal evolution history, the hydrocarbon charging stages can be recovered. Take the CFD12-6 structural zone in the western subsag
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Fig. 7. Typical inclusion pictures under microscope in the western subsag. Notes: a. Well CFD12-6-A, TVD 789 m, N2m, oil-bearing fine sandstone, fewer oil inclusions in the crack of quartz grain, light yellow fluorescence, beaded distribution; b. Well BZ8-4-D, TVD 1718.5 m, N2m, fine sandstone, fewer hydrocarbonbearing brine inclusions in some quartz grains, colorless under transmitted light, with “gas cap”; c. Well BZ8-4-C, TVD 1852 m, N2m, fine sandstone, fewer oil inclusions in the crack of quartz grains, bluish white fluorescence; d&e. Well CFD12-6-A, TVD 2637 m, E3d22, fine sandstone, a log of gasefluid two-phase brine inclusions in quartz grains; f. Well BZ8-4-C, TVD 2385 m, N1g, pebbled fine sandstone, fewer oil inclusions in the crack of quartz grains, dark yellow fluorescence; g. Well CFD12-6-A, TVD 3125 m, Mz, sedimentary tuff, multiple cracks observed on thin sections, a lot of yellow fluorescent oil inclusions in cracks as bands, suggesting micro-cracks as microscopic migration pathway and oil inclusions trapped during quartz growth; h. Well CFD12-6-A, TVD 3105.5 m, Mz, sedimentary tuff, a lot of oil inclusions in the crack of quartz grains, transparent under transmitted light; i. Well CFD12-6-A, TVD 3105.5 m, Mz, sedimentary tuff, a lot of oil inclusions in the crack of quartz grains, beaded distribution, bright yellow fluorescence, and cracks filled with asphalt in tuff, suggesting the cracks as the microscopic migration pathways.
as an example, the homogenization temperature of hydrocarbon-bearing brine inclusions at different occurrences shows that the three plays are different in hydrocarbon accumulation stages. The N2m reservoir corresponds to two stages of hydrocarbon charging (Fig. 8a): early charging for 50e60 C and late charging for 70e80 C, both are nearsource charging within the subsag. Rapid charging of hightemperature fluids from deep strata within the subsag is believed for 100e120 C, with the trapping temperature higher than the reservoir background temperature, and happened when the deep fault connecting with the subsag opened, following the above-mentioned two stages. The N1g reservoir corresponds to the first stage of hydrocarbon charging (Fig. 8b), with the homogenization temperature from 80 C to 90 C. The Paleogene reservoir also corresponds to the first stage of hydrocarbon charging (Fig. 8c), with the homogenization temperature from 80 C to 90 C, and also contains the hydrocarbon-bearing brine inclusions captured at the temperature higher than the background temperature, so
this is a rapid charging of high-temperature fluid from deep strata within the subsag. The Mesozoic reservoir corresponds to the first stage of hydrocarbon charging (Fig. 8d), with the homogenization temperature from 100 C to 110 C; it is also believed to have experienced a process of less hydrocarbon charging after the principal hydrocarbon charging stage and in the late stage when hydrocarbons were charged in shallower strata. In summary, hydrocarbon charging occurred late in the western subsag. It can be divided into three stages: I 11e9 Ma, when hydrocarbon charged the Mesozoic buried-hill reservoir, II 5e3 Ma, when hydrocarbon charged the shallower reservoirs, and III at 1 Ma, when hydrocarbon charged the N2m reservoirs. At the time when the deep fault connecting the subsag opened, the high-temperature fluid from the deep strata of the subsag charged the reservoirs quickly, resulting in the homogenization temperature of hydrocarbon-bearing fluid inclusions higher than the reservoir background temperature (Fig. 9).
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Fig. 8. Homogenization temperature histogram of inclusions in Well CFD12-6-A in the western subsag.
4.3. Hydrocarbon accumulation mechanism in the western subsag There are three types of hydrocarbon transport pathways in the western subsag: fault, sand and unconformity surface (Fig. 10), which cross and alternate to form a complex transport network [24]. The fault system and unconformity surface constitute a vertical fault-unconformity pathway to communicate the source rocks and shallow traps, while the deep, stable, thick sands contacting source rocks and the shallow thick N1g glutenite act as the “interchange” between primary migration and secondary allocation [25]; both E2s3 sands contacting the
source rocks and N2m1 sands communicating faults are favorable reservoir beds. Many sets of unconformity surface resulted from the early structural rising and outcropping act as the “bridge” communicating the source kitchens and long distance transporting passage for the secondary migration. Based on the hydrocarbon charging time and stages, and the transport system and the hydrocarbon source, the hydrocarbon accumulation process can be classified into four stages: Stage I (11e9 Ma): The E2s3 source rocks stayed in the oil generating window, and the E2d22 source rocks had not begun to generate hydrocarbons massively.In the period of
Fig. 9. Thermal evolution history corresponding to inclusion homogenization temperature in Well CFD12-6-A in the western subsag.
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Fig. 10. Hydrocarbon accumulation pattern of the western subsag.
neotectonics, the fault reaching the basement opened, and the hydrocarbons sourced from E2s3 preferentially charged the Mesozoic and Archean buried-hill reservoirs along faults and unconformity surfaces. Stage II (5e3 Ma): The hydrocarbons sourced from E2s3 continued to charge the Mesozoic and Archean buried-hill reservoirs and migrated upward along faults and unconformity surfaces to charge the Paleogene and Neogene reservoirs. In this stage, the E2s3 source rocks remained as the major source kitchen. Stage III (1 Ma): The hydrocarbons sourced from E2s3 continued to migrate upward along faults, unconformity surfaces and sands to charge the Neogene shallow reservoirs. In this process, the E2s3 hydrocarbons were mixed with the immature hydrocarbons sourced from E3d. Stage Ⅳ: The high-temperature hydrocarbon fluids sourced from E2s3 in the deep strata of the western subsag quickly charged the three plays along faults, unconformity surfaces and sands when the faults were completely open. This stage is featured by intermittent quick charging.
sterane content, and high dinoflagellate sterane content, which are very similar to the biomarkers of the E2s3 source rocks that serve as the major source kitchen in the subsag. The E2s3 source rocks have entered the oil generation window and match well with the oil property and maturity. The E3d22 source rocks show a low maturity, only with a certain similarity to the shallow Paleogene and Neogene reservoirs. In the late stage, the hydrocarbons sourced from E3d22 together with the hydrocarbons from E2s3 charged the shallower reservoirs. 3) The three plays experienced four stages of hydrocarbon accumulation. At 11e1 Ma, the hydrocarbons preferentially charged the deep Mesozoic and Archean buriedhill reservoirs in a vertical direction, and then migrated upward and charged the shallow Paleogene and Neogene reservoirs. In this process, the E2s3 source rocks in the deep strata of the subsag made a significant contribution to all three plays. The hydrocarbon accumulation pattern is featured by repeated short-term quick charging of high-temperature fluids.
The hydrocarbon accumulation pattern of the western subsag is illustrated in Fig. 10. References 5. Conclusions 1) There are three sets of source rocks (E2s3, E2s1 and E3d22) in the western subsag of the Bozhong sag. The reservoirs in the peripheral uplifts comprise the Mesozoic volcanic rocks and Archean metamorphic rocks as well as the PaleogeneeNeogene porous sandstone of delta-fluvial facies. The hydrocarbons sourced from the subsag migrated to the slope along the fault and unconformity surface and accumulated in the peripheral structural zones, giving rise to three plays featured by complex accumulation. 2) The oil biomarkers of three plays are featured by low Pr/Ph, low gammacerane content, high 4-methyl
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