Characteristics and Genesis of Es Productive Sandstone ... · 1 Characteristics and Genesis of Es 1...

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1 Characteristics and Genesis of Es 1 Productive Sandstone Reservoir (Paleogene), Nanpu Sag, East China MUHAMMAD Kashif *¹ʼ², CAO Yingchang*¹, NAVEED Ahsan ᶾ, MUHAMMAD Asif , YUAN Guanghui ¹, XI Kelai¹, ZHANG Shaomin¹, XU Qisong¹, M. Usman TahirORKHAN Isgandarov¹ 1. School of Geosciences, China University of Petroleum, Qingdao 266580, China. 2. Department of Earth sciences, University of Sargodha, Sargodha, 40100, Pakistan. 3. Institute of Geology, University of the Punjab, Lahore 54590, Pakistan. 4. School of Petroleum Engineering, China University of Petroleum, Qingdao 266580, China Abstract: The Shahejie Formation is a fundamental rock unit for hydrocarbon exploration and production in Nanpu Sag, Bohai Bay Basin. The methodology includes thin section, core observation, fluorescence, scanning electron microscope, Cathodoluminescence, fluid inclusion, laser scanning confocal microscope, and geochemical analysis (C & O isotope) to investigate the reservoir characteristics and origin of EsSandstone. Thin section study shows that the reservoir rock consisting of feldspathic litharenite and lithic arkose. The reservoir pores are categorized as intergranular pores, fractures pores, dissolution pores, and intergranular dissolve cement pores. The studied sandstone consisting of good porosity (0.05- 35%) and permeability (0.006-7000mD). The Esreservoir is classified as a fractured reservoir, primary intergranular pores associated reservoir, and dissolution reservoir. Deposition, diagenesis and tectogenesis are the main factors that play an important role in the development of the reservoir. Sedimentation is the foundation and assumption for reservoir development, but the effective reservoir is primarily controlled by primary pores, fractures, lithofacies, tectonic elements and dissolution pores. Moreover, compaction, fracture filling and cementation are the primary sources of reservoir densification. Progressively the reservoir was formed by the influence of different geological and diagenetic events. The present study provides significant information and reference for hydrocarbon exploration and development in Nanpu Sag. Keywords: Characteristics, Es1 reservoir, Nanpu oil field, Genesis, Eocene sandstone, porosity *Corresponding authorMuhammad Kashif, School of Geosciences, China University of Petroleum, Qingdao East China, E-mail: [email protected], [email protected], Cell#+8615610081925 Short Title for the running header: Characteristics & Genesis of Es1 Sandstone 1 Introduction Nanpu sag is a significance sag of the Bohai Bay Basin for hydrocarbon exploration (Tian et al., 2014; Wang et al., 2019). Nanpu oil field was discovered by China national petroleum corporation (CNPC) that made the Nanpu Sag one of oil-rich depression in the whole basin. The Nanpu Sag is a small sag that having significant petroliferous worth within the Bohai Bay Basin comprises 1.18x10tons of oil reserves (Lv et al., 2011; Jiang et al., 2018; Wang et al., 2019). Due to continuous petroleum exploration activities, many investigations have been made regarding reservoir characteristics and genesis ( Cao et al., 2014; Zhang et al., 2014; Zhou et al., 2016), basin formation and evolution (Dong et al., 2010; Zhang & Liu, 2012), sedimentation and stratigraphy (Hua et al., 2009; Wang et al., 2011), fault characteristics and their control on reservoir ( Liu et al., 2010; Zhang et al., 2011; Tao et al., 2012), and organic geochemistry of source rock and hydrocarbon ( Mei et al., 2008 ; Wuguang Li et al., 2011; Zheng et al., 2007). In East China, the reservoir at a depth of ˃ 3500 m, and in west China depth ˃4000 m are considered deep reservoir (Jiayu et al., 2004; Wuguang Li et al., 2011). The Shahejie Formation considered as an excellent potential rock unit for hydrocarbon exploration in Nanpu Sag. The hydrocarbon generation and development from Shahejie Formation are quiet in its embryonic stage, and the degree of consciousness about the stratum remains quite low. For the time being, in the throes of hydrocarbon exploration, revealing the characteristics and origin of the reservoir is not only significant, but they also signify a key factor that directly affects the success of the hydrocarbon exploration ( Han et al., 2012). The previous work has been conducted on Shahejie Formation in the Nanpu Sag area, established an understanding of hydrocarbon geological conditions. In study basin deep horizons are Shahejie Formation, that This article is protected by copyright. All rights reserved. This article has been accepted for publication and undergone full peer review but has not been through the copyediting, typesetting, pagination and proofreading process, which may lead to differences between this version and the Version of Record. Please cite this article as doi: 10.1111/1755-6724.14383.

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Page 1: Characteristics and Genesis of Es Productive Sandstone ... · 1 Characteristics and Genesis of Es 1 Productive Sandstone Reservoir (Paleogene), Nanpu Sag, East China MUHAMMAD Kashif

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Characteristics and Genesis of Es1 Productive Sandstone Reservoir

(Paleogene), Nanpu Sag, East China

MUHAMMAD Kashif *¹ʼ², CAO Yingchang*¹, NAVEED Ahsan ᶾ, MUHAMMAD Asif ᶾ, YUAN

Guanghui ¹, XI Kelai¹, ZHANG Shaomin¹, XU Qisong¹, M. Usman Tahir⁴, ORKHAN Isgandarov¹

1. School of Geosciences, China University of Petroleum, Qingdao 266580, China.

2. Department of Earth sciences, University of Sargodha, Sargodha, 40100, Pakistan.

3. Institute of Geology, University of the Punjab, Lahore 54590, Pakistan.

4. School of Petroleum Engineering, China University of Petroleum, Qingdao 266580, China

Abstract: The Shahejie Formation is a fundamental rock unit for hydrocarbon exploration and production in Nanpu Sag,

Bohai Bay Basin. The methodology includes thin section, core observation, fluorescence, scanning electron microscope,

Cathodoluminescence, fluid inclusion, laser scanning confocal microscope, and geochemical analysis (C & O isotope) to

investigate the reservoir characteristics and origin of Es₁ Sandstone. Thin section study shows that the reservoir rock

consisting of feldspathic litharenite and lithic arkose. The reservoir pores are categorized as intergranular pores, fractures

pores, dissolution pores, and intergranular dissolve cement pores. The studied sandstone consisting of good porosity (0.05-

35%) and permeability (0.006-7000mD). The Es₁ reservoir is classified as a fractured reservoir, primary intergranular pores

associated reservoir, and dissolution reservoir. Deposition, diagenesis and tectogenesis are the main factors that play an

important role in the development of the reservoir. Sedimentation is the foundation and assumption for reservoir

development, but the effective reservoir is primarily controlled by primary pores, fractures, lithofacies, tectonic elements and

dissolution pores. Moreover, compaction, fracture filling and cementation are the primary sources of reservoir densification.

Progressively the reservoir was formed by the influence of different geological and diagenetic events. The present study

provides significant information and reference for hydrocarbon exploration and development in Nanpu Sag.

Keywords: Characteristics, Es1 reservoir, Nanpu oil field, Genesis, Eocene sandstone, porosity

*Corresponding author:Muhammad Kashif, School of Geosciences, China University of Petroleum, Qingdao East

China, E-mail: [email protected], [email protected], Cell#+8615610081925

Short Title for the running header: Characteristics & Genesis of Es1 Sandstone

1 Introduction Nanpu sag is a significance sag of the Bohai Bay Basin for hydrocarbon exploration (Tian et al., 2014; Wang

et al., 2019). Nanpu oil field was discovered by China national petroleum corporation (CNPC) that made the Nanpu Sag one of oil-rich depression in the whole basin. The Nanpu Sag is a small sag that having significant petroliferous worth within the Bohai Bay Basin comprises 1.18x10⁹ tons of oil reserves (Lv et al., 2011; Jiang et al., 2018; Wang et al., 2019). Due to continuous petroleum exploration activities, many investigations have been made regarding reservoir characteristics and genesis (Cao et al., 2014; Zhang et al., 2014; Zhou et al., 2016), basin formation and evolution (Dong et al., 2010; Zhang & Liu, 2012), sedimentation and stratigraphy (Hua et al., 2009; Wang et al., 2011), fault characteristics and their control on reservoir (Liu et al., 2010; Zhang et al., 2011; Tao et al., 2012), and organic geochemistry of source rock and hydrocarbon (Mei et al., 2008 ; Wuguang Li et al., 2011; Zheng et al., 2007). In East China, the reservoir at a depth of ˃ 3500 m, and in west China depth ˃4000 m are considered deep reservoir (Jiayu et al., 2004; Wuguang Li et al., 2011). The Shahejie Formation considered as an excellent potential rock unit for hydrocarbon exploration in Nanpu Sag. The hydrocarbon generation and development from Shahejie Formation are quiet in its embryonic stage, and the degree of consciousness about the stratum remains quite low. For the time being, in the throes of hydrocarbon exploration, revealing the characteristics and origin of the reservoir is not only significant, but they also signify a key factor that directly affects the success of the hydrocarbon exploration (Han et al., 2012).

The previous work has been conducted on Shahejie Formation in the Nanpu Sag area, established an understanding of hydrocarbon geological conditions. In study basin deep horizons are Shahejie Formation, that

This article is protected by copyright. All rights reserved.

This article has been accepted for publication and undergone full peer review but has not been

through the copyediting, typesetting, pagination and proofreading process, which may lead to

differences between this version and the Version of Record. Please cite this article as doi:

10.1111/1755-6724.14383.

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is buried to a depth ˃3500 m and exploration in the shallow-middle horizon is quite mature, but in the deep horizon over 3500 m remains potential. The deepest horizon is at a depth of ˃4200 m, where the reservoir prediction especially the production of secondary pores development zone is a key to explore at a deep depth. The burial depth of Es1 Member vary widely and experience several diagenesis variations (Xingzhi et al., 1998; Liu et al., 2007), consequently some discussion regarding the characteristics and origin of reservoir leftovers. These discussions /debates have led to ambiguity when developing exploration and exploitation policies. Previous geoscientist suggests that the geological process were useful to enhance reservoir characteristics especially porosity preservation e.g. the shallow development of chlorite coats around the grains and early hydrocarbon emplacement , fluid overpressure as well as porosity improvement process (by mineral/cement dissolution) can also be the significant controlling factors to improve the quality of deeply buried reservoir ( Ehrenberg, 1993; Waren & Pulham, 2001; Zhong et al., 2003; Xiaomin et al., 2004; Zhang et al., 2007; Yu et al., 2008; Peng et al., 2009; Zhang et al., 2008; Taylor et al., 2010; Meng et al., 2010; Wang et al., 2010; Chen et al., 2011; Zhu et al., 2012). But there is quite some debate on pore types and origin of the deeply buried porous reservoir. Previous studies suggest that deeply buried clastic reservoirs consisting of fractures and dissolution pores, which are the key controlling factor to enhance the reservoir characteristics (Zhong et al., 2003; Zhu et al., 2006; Yuan et al., 2007; Jiangand et al., 2008).

Consequently, the present study reservoir characteristics and genesis based on a detailed study of the reservoir’s basic characteristics by using appropriate coring well data from Nanpu Sag. That including inclusive core observation, petrographic thin sections identification, well logging data, SEM study, fluid inclusion analysis, geochemical data (C & O isotope) and other techniques to evaluate the reservoir characteristics and origin of deeply buried reservoir rocks in the studied area. Main aims and object are to ① assess the factors that influence reservoir quality, ② to probe the reservoir characteristics and also to ③ the origin of productive sandstone for hydrocarbon exploration and development in Nanpu Sag.

2 Geological Setting

The Nanpu Sag is a small sag that is situated in the gigantic Bohai Bay Basin, it is situated in the northeast portion of the Huanghua Depression and consisting over 1930 km² area. Nanpu Sag is restricted by the Shaleitian fault to the south and Xinanzhuang-Baigezhuang fault to the north-east and comprises Cenozoic sedimentary and volcanic rock units. It comprises of six foremost sub-basins comprising Linqing-Dongpu, Jizhong, Jiyang, Bozhong, Liaohe-Liaodong, and Huanghua Depressions and comprising of five main uplifted block comprising Shaleitian, Cangxian, Cheng-Ning, Neihuang, and Xing-heng, from the northeast to the southwest (Gong, 1997). Two boundary fractures regulatory the sag as a part of the Zhangjiakou and penlai fracture belt (Dong et al., 2008). Structurally this sag resembles half-graben and Xinanzhuang and Baigezhuang faults acting as steep dip boundary faults in the direction of south and south-west (Wang et al., 2002). There are eight main structures have been recognized that are trending in the northeast, comprising Liuzan, Beipu, Layemiao, Gaoshangpu, onshore structures and Nanpu 1, Nanpu 2, Nanpu 3, Nanpu 4 and Nanpu 5 offshore structures (Figure 1; Wang et al., 2002).

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Fig. 1. Location map of the study area showing the distribution of main structural elements, faults and discovered oil field within the Nanpu Sag, (modified by Dong et al.,2008).

The Bohai Bay Basin is a lacustrine rift basin comprises an area of 200,000 km² area (Deng et al., 2017; Jiang

et al., 2018; Sun et al., 2019; Wang et al., 2019). The tectonic history of the basin is well documented due to its significant role in hydrocarbon accumulation within the basin (Cheng et al., 2018; Jiang et al., 2019). The Bohai Bay Basin is restricted by different faults in a different direction. These faults are Basin boundary fault, fault controlling depression, basement-involved fault controlling sags and highs, a fault developed in sedimentary cover and composite fault as first, second, third, fourth and fifth-order respectively (Li et al., 2012). Within the Bohai Bay Basin, there are three regional scales NNE strike-slip fault belts that are Tan-Lu Fault System, the Lan-Liao Fault system, and the Baxian-Suolu-Handan Fault System from east to west. Within the basin the complicated faulted blocks and fault groups are associated to three key factors during Cenozoic time: that is a pre-existing basement-involved fault, regional stress field, and local strain field (Li et al., 2012). In western part of Bohai Bay Basin the half-graben structures are formed a restricted asymmetrical Basin-Range-type extensional tectonic framework under simple shearing in Cenozoic, however toward the eastern part formed as escape-induced fault depression under pure shearing and compression (Liu et al., 2002; Han et al., 2005; Xu et al., 2008). These faults in Qingdong, Cenozoic north yellow sea, and south yellow sea-Subei Cenozoic basin are ENE-striking showing that the regional tensional stress was NNW-direction in entire East China (Li et al., 2010).

The sedimentary stratigraphy is consisting from Eocene to Pliocene. Well drilling data for hydrocarbon exploration is useful to evaluate the sedimentary succession of Nanpu Sag (Wang et al., 2002; Zhou et al., 2003). The sedimentary rock sequence of Cenozoic strata (5000- 9000 m) includes the Eocene Shahejie Formation; the Oligocene include Dongying Formation, and the Miocene consist of Guantao and Ming huazheng Formations and the Quaternary Pingyuan Formation (Wang et al., 2002; Hua et al., 2009). Volcanic rocks (igneous basalts with minor mafic pyroclastic rock/ basaltic mudstone) are interbedded with sedimentary rocks. The Shahejie Formation comprised the major source rocks as well as sandstone reservoir rock and distributed to three major members as Es₁, Es₂, and Es₃. The lowest Es₃ member is further divided into five sub-members, Es₃¹, Es₃², Es₃ᵌ, Es₃⁴, and Es₃⁵ from top to bottom (Figure 2a). The Es₂ member consists of alluvial sediments mainly comprise reddish mudstone interbedded with thin layers of sandstone. The Es₁ member (top) is categorized by shallow lacustrine lithofacies (Dong et al., 2010) (thickness 200-800m, Figure 2; Stratigraphic

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column). Whereas the Oligocene Dongying Formation consists of three members as Ed₁, Ed₂, and Ed₃. The Dongying Formation consists of a series of 500-600 m onshore lacustrine deposits and 1500-2000 m offshore deposit (Wang et al., 2002). The Neogene Guantao Formation deposited within the fluvial system and Minghuan Formations deposited in the low-sinuosity fluvial system (Wang et al., 2002).

Fig. 2a. Generalized Cenozoic- Quaternary stratigraphy of the Nanpu sag showing the tectonic and sedimentary evolution stages and major petroleum

system elements(modified from Guo et al.,2013 and Yuan et al.,2015). b. Burial history and corresponding thermal and maturity evolution of

Ed₃, Es₁ and Es₃⁴ interval in Nanpu sag area(modified from Guo et al., 2013).

The source rock is grey to black mudstone, calcareous mudstone and kerogene shales in the upper Es₁ and

lower Es₃⁴ Members of Shahejie Formation and Ed₃ Member of Dongying Formation (Oligocene age) (Zheng et al., 2007; Zhu et al., 2011; Guo et al., 2013). The primary reservoir rocks are syn-rifting lacustrine fan-delta sands and subaqueous fans deposits (Eocene-Oligocene) and post-rifting fluvial facies deposits (Miocene-Pliocene) (Dong, 2002). The buried hills, faulted anticlines, anticlines, and fault-stratigraphic trap are the major structures that contain hydrocarbons (Dong, 2002). There are two sets of regional seals including thick and broadly disseminated mudstone and basalts in Miocene rock (Guantao Formation) and mudstone established sturdily in the upper part of Pliocene Minghuazhen Formation (Zhu et al., 2011; Tao et al., 2013). The present studied Es₁ member consisting of grey and light gray mudstone subordinate with interbedded sandstone and sandy conglomerate underlain by dark gray mudstone interbedded with grey sandstone on the top of bioclastic limestone and sandstone (Dong et al., 2010).

The burial history evaluation entails useful information of the lithology’s of formation, porosities, their geological ages, timing, duration and erosion thickness. Estimation of burial history reconstructs by the measured thickness of formation obtained by well-drilled data and formation thickness changes by porosity depended on compaction and erosion that can be assessed by sonic log (acoustic travel time) (Heasler, 1996). Uplifting causes substantial regional unconformity and the erosion thickness is up to 300-600 m in Late Paleogene. Absolute ages of erosional and depositional events are evaluated by a chronostratigraphic background of the basin (Wang et al., 2002). Fortitude of the porosities is very important due to its substantial impact on the thermal conductivity of sediments which has a relation with thermal possessions of a basin and maturation level of source rock. The burial history suggests that a rapid and continued subsidence and deposition was developed during Neogene. The burial and thermal history of the studied sag have been

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established by acquired appropriate data from different exploration and production wells (Fig. 2b) (Wang et al., 2008; Guo et al., 2013). The overall burial depth of Shahejie Formation in the Nanpu Sag area occurs nowadays more than 4000 m BSL (below sea level). The current geothermal gradient is 32°C/Km (58°F) and the normal surface temperature is 14°C (57°F), and the maximum temperature is 135°C (275°F) at greater than 4000 m depth. In the studied part of Nanpu Sag (Surrounding of Caofeidian sub sag), three main source rocks have greater depth (Ed₃ ˃4500 m, Es₁ ˃5400 m, and Es₃⁴ ˃6000 m). The subsurface geo-temperature of Ed₃ and Es₁ is almost 140°C and 170°C respectively and for Es₃⁴ temperature is near to 200°C. The vitrinite reflectance of the Ed₃ (shallow) and Es₃⁴ consisting 0.8 % R˳ and ˃2% R˳ respectively (Guo et al., 2013).

The Es₁ source rock consisting of high temperature and pressure and reached hydrocarbon generation inception at about 23Ma, and due to high maturity, source rock generate wet gas at that stage. At ˃3300 m depth the Es₃ source rock producing oil at 27 Ma, attainment peak hydrocarbon generation (1% R˳) at the depth ˃4200 m at 21 Ma. At the current stage, it enters at the level of mature to over mature to produce dry gas (Guo et al., 2013).

3 Database and Methodology

For the present study core samples were collected from ten selected wells from Nanpu Sag, Bohai Bay Basin. The rock composition data of 720 sandstone core samples, 312 grading analysis data and well logging data of related wells have been collected at the specific depth from two structural belts and ten exploratory wells including Np306x1, Np 3-19, Np3-80, PG2, Np280, Np288, Np2-15, Np206, Np2-6, and Np208 were attained from the research institute of petroleum exploration and development of oilfield company. More than 1000 samples were selected for making the thin sections, among them 200 samples for thin sections study were impregnated with blue or red epoxy to identify the rock composition, mineralogy and diagenetic pore characteristics. Thin sections were stained with Alizarine Red and potassium-hexacyanoferrate (III) to help to identify calcite cement, dolomite, Ferro calcite and Ferro dolomite (Tucker, 1988).

Twenty-five selective descriptive samples were observed under a COXEM EM-30⁺ scanning electron microscope (SEM) equipped with EDX (an energy dispersive X-ray spectrometer) to identified specific minerals, the pores, and pore filled minerals. Among them, 15 samples were prepared and studied for cathode luminescence (CL) analysis to identify the cement by using a microscope equipped with AxioCam 506 color, CITL-Mk5-2 CL instrument. Twenty four core samples were selected for fluid inclusion analysis, microthermometric measurements, and fluorescent color observation. The petrographic microscope equipped with a Zeiss Axiocam 506 color heating and the cooling stage is used to calculate the homogenization temperature of fluid inclusion. Laser scanning confocal microscope is used to evaluate the pore throat, and pore size distribution, for this purpose twenty special samples are prepared that were viewed under LSM 700, AxioCam MRc5.

To investigate the reservoir origin, 10 interbedded mudstone and 30 non-organic samples from different wells were selected for C & O isotope analysis by Thermo- Finnigan MAT 253 isotope spectrometer. To evaluate the reservoir characteristics and their types, several core plug samples (2.5 cm diameter) from Np306X1, Np 3-80, Np 280 and Np2-15 were tested by mercury intrusion methods to evaluate the reservoir characteristics (porosity and permeability). Then the cross-plot of mud logging data, porosity and permeability of the Np306X1, Np 3-80, Np 280 Np 206 and Np2-15 wells were used to evaluate the reservoir types. Consistent with all these results, this research deliberates the association between deposition, reservoir origin, diagenesis and tectogenesis.

All these analyses excluding Carbon and Oxygen stable isotope were done in the reservoir Key Laboratory and diagenetic simulation laboratory of the China University of Petroleum. Whereas Carbon and Oxygen stable isotope analysis was completed in Beijing Research Institute of Uranium Geology.

4 Results 4.1 Reservoir Characteristics 4.1.1 Sandstone Composition

Consistent with thin section study, Es₁ member mostly consists of quartz as an abundant detrital mineral in the sandstone unit, usually consisting of 45-75% of bulk volume. Throughout the study, it has been observing a lot of discrepancies observed, including sorting to well sorting, some single uniform crystal, some stressed grain and rock fragments with undulate extinction, and several fused grains.

The second abundant mineral is feldspar ranges 15-65%, and rock fragment content is 10-60%. The entire feldspar content decreases from 30-35% of the whole rock volume; the feldspar concentration is high, moderate and low in different samples that have been observed under the thin section and SEM analysis. The overall proportion of the K-feldspar to total feldspar is variable, the concentration of K-feldspar decreasing with increasing depth, at shallow depth; the percentage of feldspar is high round about 5-65% and reduced with the increasing depth. Overall Na-feldspar has a little variation concerning depth, indicating that K-feldspar disappear concerning depth, and plagioclase feldspar content remain constant.

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Other abundant lithic fragments identified by thin section is chert, consisting of 2% to 8% of whole-rock volume and averaging is 4.1%. Mostly chert grains appear as pure quartz that is recognized under plane-polarized light on the basis of their uniform clarity. In few samples chert having slight inclusions of clay and few contain carbonates, and some chert appears as dark to speckle in the plane-polarized light.

Further lithic constituents comprise metamorphic, sedimentary and volcanic rock fragments. Alteration and dissolution of the matrix in volcanic rock fragments might be contributing a minor element to pore fluids. Volcanic rock fragments are the main detrital component to disintegrate during transporting and weathering (Kashiwagi et al., 2008). Consequently, the occurrence of a similar volume of volcanic rock fragments all over the section proposes that the origin and transport distant did not change throughout the deposition of sandstone. The sandstone of Es1 member of Shahejie Formation is categorized as lithic arkose, arkose, and feldspathic litharenite established on petrographic composition study (Figure 3) (Folk 1974). Overall shallow sandstones are categorized as lithic arkose field while deeper sandstone is having minor k-feldspar, so they are classified as a feldspathic litharenite field (Stroker, 2013).

Fig. 3. Rock composition of Es₁ member of Oligocene sandstone in Nanpu Sag. Ternary plot refers to the sandstone classification standard of Folk et

al. (1970).

4.1.2 Pore Space Pore space plays an important role to enhance the reservoir characteristics. Core observation and thin sections

study reveal that reservoir sandstone containing primary as well as secondary pores, and at some intervals, microcrystalline pores are also present. Some pores are generated after deposition due to dissolution and fracturing. Various fluids affect the unstable grains/rock fragments & cement that entirely or partially dissolve the grains and pores cement and creates secondary pores (Figure 4b, g, h). Dissolution pores are generally developed in unstable detrital grains due to their low resistance against the acidic fluid. Reservoir sandstone is having a good primary porosity (0.5% up to 35%) and permeability (0.006 mD-up to 7000 mD) (Figure 5). The dissolution and fracture also improve the reservoir porosity by 4-5%. Primary intergranular porosity accounts consist of the main reservoir space for 44% of the total reservoir space. Moreover, some feldspar/rock fragment dissolution pores (27%), cement dissolve pores (8%), and fractures pores (17%), fractures dissolve pores (6%) accounts for 57% of the entire reservoir pore space (Figure 6). Similarly, some other microfractures that having definite reservoir characteristics, but they play a most important role to serve hydrocarbon (oil/gas) outflow channels to enhance the reservoir characteristics (especially permeability).

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Fig. 4. Core samples and microphotograph showing the different reservoir pore spaces and reservoir types. a. core samples showing the irregular

fractures that enhance reservoir permeability and rock is a fractured reservoir. b. photomicrograph is showing the primary intergranular pore and

feldspar dissolution pores. c. core sample showing the fractures and fractures are filled with bitumens. d. photomicrograph is showing the calcite and

dolomite cement. e. Core sample showing the pebbles and visible pores. f. thin section microphotograph showing the fracture and that fractures are

filled by ferrocalcite, ferrocalcite developed later stage of diagenesis after fracturing. g. microphotograph is showing the calcite cement

dissolution/replacement. h. thin section microphotograph is showing the primary intergranular pores and feldspar dissolution pores. i Micro thin

section showing the fractures which enhance the permeability of the rock. j. Micrograph thin section is showing the feldspar dissolution secondary

pores as well as primary intergranular pores. k. microphotograph is showing the ductile deformation of mica due to compaction. l. microphotograph

of a thin section showing the effective permeability with some oil. Fr- fractures; Ca.d- calcite dissolution; Ch-chert ; Do-dolomite ; Pr.p-Primary

pores; Fd-feldspar dissolution; Ca-calcite; Fe.ca-Ferro- calcite; Dd-ductile deformation; per-permeability.

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Fig. 5. The correlation between the porosity and permeability of Shahejie Formation reservoir rock in Nanpu Sag

Fig. 6. Development frequency of different reservoir space within Shahejie formation reservoir sandstone.

4.2 Reservoir Characteristics

Porosity and permeability data (petrophysical) of 704 samples from the Es1 member of Shahejie Formation have been summarized (Figure 7 A, B). The average porosity 18.6%, and mainly consisting of 15% to 20%, accounting for 30% of all the samples. Whereas the porosity ranging from 0-5% accounting for 4% of all samples, 5% to 10% accounting for 7% of all samples, 10% to 15% accounting for 18% of all samples, 20% to 25% accounting for 14% of all samples, 25% to 30% accounting for 17% of all samples and 30% to 35% accounting for 10% of all samples. The permeability is mainly100-1000 mD, accounting for 42%, and 1-10 mD, 10-100 mD and 1000-10000 mD is 13%, 20% and 15% respectively. Porosity type, pore structure/shape, pore connectivity, pore radii and micro matrix can be evaluated by thin sections study and laser scanning confocal microscope (Figure 8). That showing the structure of the pore and connectivity of the pores, and results also indicate that the pores of study reservoir having moderate to good radii, matrix pores are intergranular dissolution pores, intragranular dissolution pores, and intergranular pore cemented with clay. On the basis of these results, it has been concluded that the Es₁ member (Shahejie Formation) of deeply buried sandstone reservoir has good characteristics of porosity and permeability that make it more economic significance.

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Pore throat radius and pore surface area frequency also play an important role to evaluate the reservoir characteristics. Smaller the pores size of throat having high capillary pressure required to inject mercury and bigger pore/pore throats requires smaller the capillary pressure required to inject mercury, samples Np 2-15 (3617 m) and Np 3-19(4232.59 m) having smaller pore throat radius <1 µm. So they are having smaller pore throat and consist of low porosity and low permeability (Figure 9) indicating poor reservoir characteristics. Whereas samples Np 306x1 (4220.76 m), and Np3-80 (4534.7 m) having high porosity and pore throat radius ˃1 µm indicating low capillary pressure requires injecting mercury. Mercury saturation is high due to the excellent interconnectivity of pores and having a good permeability (Figure 9) representing good reservoir characteristics. Whereas samples Np280 (3503.95 m) and Np 306x1 (4234.2 m) having moderate porosity and permeability (moderate pore throat and moderate reservoir characteristics)

Fig. 7. The frequency distribution of porosity (A) and permeability of (B) reservoir rock of the Shahejie formation in Nanpu sag, Bohai Bay Basin.

Fig. 8. Showing the pore, pore structure and pore connectivity. (a, b, c). Thin section images of excellent to good pores pore structure and

connectivity, (a’, b’, c’). 2D images from a laser scanning confocal microscope showing the pore structure connectivity, and pores intensities.

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Fig. 9. Mercury saturation bar chart and permeability contribution value accumulation curve in Nanpu wells, Bohai Bay Basin.

4.3 Reservoir Types

On the basis of experimental data, it has been suggested that the porosity and permeability have a direct correlation, there is a very good association between them. However porosity of fracture reservoir is low, and permeability of fractured reservoir is high, there is no association between them (Shi et al., 2010; Zhou et al., 2014). Consequently, the qualitative study of the reservoir types rendering to the correlation characteristics between the porosity and permeability (Shi et al., 2010; Dai et al., 2007; Qiang, 2007).

Porosity and permeability distribution mainly consist of 2 regions: Region A and Region B (Figure 10). Among them, the region “A” having a positive correlation, the porosity distributed is 8.4% to 18.5%. With high permeability 54 mD to 1015 mD, indicating the existence of primary intergranular pores, dissolution, and fractures in the reservoir, and said to fracture reservoir due to low porosity but high permeability, as well as the presence of fractures, also enhance the reservoir permeability relative to porosity. The core sample observation and thin sections analysis indicate that the reservoir pores are categorized as intergranular pores, unstable rock fragments and skeleton fragments dissolution pores, cement dissolves pores, and intergranular dissolution pores and at some intervals containing microfractures creating pores. The region “B” also represent direct positive relation, emphasized by the coeval change of porosity (0.5% to 35%) and permeability (0.006 mD to 7000 mD). The thin section analysis shows that the reservoir space is mainly primary intergranular pores, feldspar dissolution pores, cement-dissolve pores and evenly distributed intergranular dissolve pores that were generated by dissolution. Hence, both region (A & B) may show various types of the reservoir, revealing of the primary intergranular porous reservoir, fractured reservoirs and dissolution porous reservoir (A) and Primary intergranular porous reservoir and dissolution porous reservoir (B) respectively.

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Fig. 10. The relationship between porosity and permeability of Shahejie formation (Es₁ member) reservoir rock in Nanpu Sag with different zones.

Actually, dissolution pores reservoir consisting of feldspar dissolution pores, and dissolve cement pores in

Es1 member (Shahejie formation). In the progress of core observation and the thin section, it has been found that there are some big voids and dissolves cement voids (Figure 4g & Figure 11b, f, g), that enhance the reservoir characteristics. Similarly, during the drilling process, the loss of circulation or loss of mud fluid and drill pipe venting occurred representing that drill formation is highly porous, highly fractured or less compacted. From all these analyses it has been evaluating that pore space structures in the Shahejie Formation are relatively intricate and reservoir origin was affected by several factors. Within the Shahejie Formation there are three main types of reservoir occurs in Shahejie formation, included primary intergranular porous reservoir, fractured porous reservoir, and dissolution porous reservoir rocks (Figure 4a, c, f, h, i & Figure 11a), (Figure 4b, h, j, & Figure 11j, k, l) and (Figure 4b, h, j and Figure 11f) respectively.

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Fig. 11. Photomicrograph showing the diagenetic types of the Shahejie formation in Nanpu Sag. a. Showing fractures that create interconnectivity for

reservoir fluid migration. b. Feldspar dissolution pores as well as primary pores. c. presence of oil in pores. d. quartz overgrowth. e. pressure

solution/stylolites formed at a later diagenetic stage. f. feldspar dissolution and calcite cement dissolution creating secondary pores. g. grains come

close to one another, primary pore filled with calcite that is removed or replaced at a later stage of diagenesis and creating pores. h. CL micrograph

showing the presence of calcite cement dull (older) and bright orange (younger). i. Micrograph of a thin section showing grains overlap one another

as well as quartz overgrowth. j-lMicrograph of a thin section showing the primary intergranular pores; Fr- fractures; Cd- calcite dissolution; QO-

quartz overgrowth; PR.S- pressure solution; Pr.p-Primary pores; Fd-feldspar dissolution; Ca-II younger calcite; Ca-I older calcite.

5 Discussion

The porosity is acting as fluid storage space as well as migration pathway for hydrocarbon (oil/gas), consequently, the creation and distribution of pores is one of the significant tasks to evaluate the reservoir (Zhu et al., 2015). Secondary pores are mostly developed due to the dissolution of different organic matters and fracturing. Surdam et al., (1984) proposed the theory of organic acid dissolution of aluminosilicates and carbonate minerals. Clastic rocks in China are generally lithic, and arkose sandstone, and mostly pore spaces are generated by dissolution of feldspar, unstable rock fragments and carbonate cement (Zhu et al., 2015). The sedimentation, tectonic activity and diagenesis play an important role in the formation of a reservoir that is discussed below.

5.1 Depositional effect on reservoir formation

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The sedimentation of Shahejie Formation (Es1 member) occurred on a deltaic fan, lacustrine environment. It divided into numerous sub-facies that having a deltaic fan, shallow to the deep lacustrine environment. On the basis of core observation and thin sections study, the different sedimentary microfacies having different reservoirs (Yongsheng et al., 2006). Samples that were taken from shallow depth consisting of cross-bedding and other sedimentary structures and consisting high porosity and permeability due to less compaction effect. The mudstone microfacies have organic matter and contain micropores that are important to late dissolution, simply creating various size dissolution pores, and forming source to the reservoir. Other microfacies (Table 1) have contained many primary, dissolution, fracture and minor crystal pores. The diameter of the organic pore may be slightly increased due to dissolution thereby forming porous reservoir dissolution, so forming the high porosity reservoir due to dissolution in unstable detrital grains. Dissolution pores are mostly generated in the sandstone portion, and the porosity is reduced at the contact/interface surface due to high carbonate/clay cementation. Similarly, in mudstone microfacies, it is very problematic for pores to generate through dissolution phenomenon, so that’s why mudstone microfacies have very low hydrocarbon (oil/gas) storage porosity.

According to petrophysical data analysis, porosity and permeability are distinctly different in many deposits within microfacies (Table 1). Porosity and permeability data of different facies in Nanpu Sag are representing in porosity histogram (Figure 12). It shows that the maximum porosity of siltstone microfacies deposit is 14.3% and the minimum porosity is 0.8%, with an average 7.3%. Whereas the maximum permeability of siltstone microfacies deposits is 887 mD, and the minimum is 0.016 mD with an average of 399.44 mD.

Fig. 12. The porosity histogram of different sedimentary microfacies in Es₁ reservoir of Shahejie formation. Table 1. Physical parameters of Es1 member of Shahejie formation

Sedimentary

microfacies

Porosity,% Permeability, mD

Maximum Minimum Average Quantity Maximum Minimum Average Quantity

Conglomerate

sandstone

33.5 4.3 18.7 27 6280 6.2 3200.16 27

Coarse sandstone 30.5 3.4 17.5 81 5770 4.8 2940.14 81

Medium sandstone 28.7 2.1 15.4 73 4573.32 3.7 2500.02 73

Fine sandstone 20.2 1.1 10.6 51 1248.23 2.6 631.24 51

Siltstone 14.3 0.8 7.3 31 887 0.016 398.44 31

Similarly, the maximum porosity of fine sandstone microfacies deposit is 20.2%, and the minimum is 1.1%,

with an average of 10.6%. The maximum permeability of fine sandstone microfacies deposits 1248.23 mD and the minimum is 2.6 mD. The maximum porosity of the medium sandstone microfacies deposit is 28.7%, and the minimum is 2.1% with an average of 15.4%. Whereas the permeability of medium sandstone microfacies deposit is 4573.32 mD and the minimum is 3.7 mD with an average is 2500.02 mD. The maximum porosity of the coarse sandstone microfacies deposit 30.5% and the minimum is 3.4% with an average 17.5%. Whereas the maximum permeability of coarse sandstone microfacies deposit is 5770 mD and the minimum is 4.8 mD with an average is 2940.14 mD. The maximum porosity of the conglomerate sandstone microfacies deposit 33.5% and the minimum is 4.3% with an average 18.7%. Whereas the maximum permeability of conglomerate sandstone microfacies deposit is 6280 mD and the minimum is 6.2 mD with an average is 3200.16 mD. Instantaneously the reservoir thickness and ranges are different in different sedimentary facies.

On behalf of all analysis, it is suggested that the porosity and permeability of coarse sandstone microfacies and medium to coarse microfacies deposit are very well developed. Similarly, the medium, silty sandstone and

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medium sandstone microfacies also having good porosity as well as permeability, only interface zone contains minor porosity and permeability due to mud infiltration that is high near the contact/interface surface. Over-all the effective reservoir of Shahejie Formation is mostly controlled by conglomerate sandstone, coarse sandstone and medium to coarse sandstone microfacies.

5.2 Impact of compaction and cementation on reservoir formation

Reservoir characteristics especially porosity and permeability are severely affected by compaction, cementation and pore-filling (Dixon et al., 1989; Yang et al., 2014; Xu et al., 2008; Shi et al., 2010; Zhou et al., 2014). The Shahejie Formation has been buried more than 3500 m depth. Due to high compaction and pre-solution, the primary intergranular porosity of the reservoir decreases sharply. While the pressure solution seam (Figure 11e) was formed during positive burial influences were made to the reservoir. Usually, due to compaction the primary intergranular pores are reduced or vanish and causes significant contributors for the densification of the reservoir. Cementation is a chemical diagenetic process that consolidates loose sediments. Most probably there are two stages of cementation in the studied reservoir. At the early stage (C=I), the calcite and other cement were deposited in intergranular pores, and such type of early-stage carbonate cement shows dull red appearance under Cathodoluminescence microscope (Figure 11d, h). The second stage occurs at a later time/messogenesis stage (C=II), at that stage, cement was generated inside the primary residual pores and fractures that were occupied by the early cement of fine minerals (Figure 11d). Later stage calcite appears as bright yellow or bright orange color under Cathodoluminescence (Figure 11d, C=II). Ferrocalcite, ankerite, authigenic quartz cement are formed at a later stage and filled the intergranular pores, fractures, and quartz overgrowth or over cemented at a later stage (Figure 4d, f, g and Figure 11b, g, h). The part of the reservoir near to mud/sand interface having low reservoir characteristics due to infiltration of clay or calcite cement. That’s why near the interface porosity and permeability is low and part of formation away from an interface having good porosity. Kaolinite occurs as euhedral aggregate filling in primary pores and mixed-layer I/S occurs as a honeycomb structure that filling the primary pores and rosette shape chlorite occurred along grain surface or within the secondary pores after feldspar dissolution (Figure 13a, b, c, d), that affect the reservoir quality. The carbonate cement and pore blocking clays reducing the reservoir pore spaces, mired fluid flow into pores and restricted the progress of dissolution, so the cementation contributes the reservoir densification. Many dissolution pores and fractures were filled by clay, calcite, ferrocalcite, quartz, and some minor rock fragments from overlying strata in the studied reservoir that impact on reservoir space, that narrows the pore space or pore throat to reduce reservoir characteristics. Consequently, the secondary pores filled by cement are hard to find and also the prominent cause of reservoir densification.

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Fig. 13. Clay mineral characteristics in Es₁ sandstone reservoir member of Shahejie formation: A and A', Micrograph of SEM and EDX of mark site

showing the vermicular aggregates Kaolinite. B and B'. Micrograph of SEM and EDX of mark site showing the honeycomb-shaped mixed –layer I/S

between the pores. C and C'. Micrograph of SEM and EDX of mark site showing the rosette and needle shape chlorite. D and D'. Micrograph of SEM

and EDX of mark site showing flaky crystal illite in pores.QA-authigenic quartz; K- kaolinite; I/S-mixed layer illite/smectite; I- illite; Ch- chlorite;

Fd- feldspar dissolution.

5.3 Replacement Effect on Reservoir Formation In the studied reservoir, it consists of carbonate cement, i.e. calcite, ferrocalcite, ankerite and minor dolomite.

Calcite cement replacement and unstable mineral dissolution are common in studied sandstone (Figure 4g, Figure 11b, g), for replacement of carbonate minerals, it has been used oxygen and carbon isotope data (Table 2). Due to the lack of homogenization temperature data of carbonate cement, theδ¹⁸O values are used to measure the precipitation temperature of carbonate cement. The best perception between the marine and freshwater carbonate is assumed by the equation 1 of Keithe & Weber, (1964) and later on (Chen, 1994; Wang & Xiang, 1996; Xi, 2015; and Zhou, 2016).

Z= a (δ¹ᵌC+50) +b (δ¹⁸O+50). (1) Here a and b are 2.048 and 0.498 respectively,

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On the basis of Z-values, the carbonate cement origin has been evaluated. If the Z-value is >120 then the carbonate having a marine origin, fresh water having Z-values <120 and intermediate or mixed origin with Z-values near 120 (Keith & Weber, 1964). The calculated result of the studied sandstone indicates that mostly Z-value ranges from 109.20 to 121.4, most of them are less than 120 (Table 2), (Figure 14) which shows that the source of pore water and is the atmospheric freshwater environment with minor mixed water (<120 Z value). The replacement, dissolve cement process not only change the rock structural component as well as make the calcite and dolomite crystal coarse and euhedral, with increasing pore diameter and pore throat becoming smooth and straight (Ferm et al., 1993). In later diagenesis, the pores are favorable for acidic flow, which promotes carbonate cement dissolution and the formation of dissolved pores (Figure 4g, Figure 11b, g) which are effective in restoring oil and gas. Consequently, replacement, dissolution, and recrystallization of cement are also a significant factor for the development of a porous reservoir.

Fig. 14. Carbon isotopic and Z values for the carbonate rocks from distinctive environments; from Chen (1994), Wang and Xiang (1996) and Zheng

Zhou et al. (2016).

Table 2 Geochemical characteristics of Es1 member of Shahejie Formation in Nanpu Sag. FC- ferrocalcite; ANK-

ankerite; DO-dolomite

No Well# Lithology Depth, m Carbonate

mineral/cement

δ¹ᵌ C

(‰PDB)

δ¹⁸ O (‰PDB) Z values

1 Np 306x1 Medium-coarse Sandstone 4218.4 100%CA 0.1 -14.9 119.6

2 Np 306x1 Medium-coarse Sandstone 4218.7 100%FC -3.4 -10.9 114.90

3 Np 306x1 Medium-coarse Sandstone 4220.76 100%CA -0.2 -13.9 119.2

4 Np 306x1 Coarse Sandstone 4221.9 60% CA+ 40% ANK -2 -9.1 118

5 Np 306x1 Coarse Sandstone 4223.35 100%FC -1.1 -7.3 121.4

6 Np 306x1 Medium Sandstone 4240.32 70% FC+ 30% ANK -4.2 -7.6 114.91

7 Np 306x1 Medium-coarse Sandstone 4243.15 100%FC -1.5 -14.3 117.10

8 Np 3-19 Medium, silty Sandstone 4132.59 100%FC -3.6 -12.9 111.44

9 Np 3-80 Medium- coarse Sandstone 4534.9 90% FC+10%DO -3 -11.1 115.62

10 Np 3-80 Medium- coarse Sandstone 4538.23 100%FC -4.2 -10.9 113.27

11 PG2 Medium- coarse Sandstone 4252.39 60% CA+ 40% ANK -2.4 -12.9 115.96

12 PG2 Coarse Sandstone 4257.34 100%FC -2.1 -9.9 118.55

13 Np 2-6 Medium- coarse Sandstone 3617.42 100%FC -3.7 -14.9 112.29

14 Np 2-6 Medium Sandstone 3622.2 100%FC -2.8 -9.2 116.97

15 Np 2-15 Medium- coarse Sandstone 3525.4 70% FC+ 30% ANK -4.7 -9.9 112.73

16 Np 2-15 Medium Sandstone 3626.13 100%FC -3.7 -11.1 114.20

17 Np 280 Medium- coarse Sandstone 3503.2 100%FC -5.6 -13.3 109.20

18 Np 280 Coarse Sandstone 3505.7 100%FC -5.3 -6.2 113.35

19 Np 206 Medium Sandstone 3625.32 90% FC+10%ANK -3.6 -10.2 114.84

20 Np 206 Coarse Sandstone 3628.14 100%FC -4.3 -5.5 115.75

5.4 Tectogenesis Fractures Effect on Reservoir Formation

Nanpu sag is a complex area due to its tectonic events. The Nanpu Sag experienced two stages of structural evolution; the Paleogene faulted depression and Neogene depression. The deposition of Shahejie Formation is at an early stage of faulted depression when the extension force is stronger in NW-SE direction, due to that a series of NE-SW oriented faults and fractures were generated in the Sag. The Nanpu Sag in Bohai Bay basin is a lie in Zhangjiakou-Penglai fracture belt, with 220 km length and 50-100 km width, that consisting a series of NW to nearly EW fractures (Dong et al., 2008). These fractures are generally the boundaries of the Paleogene rift basin. The Es₁ member (Shahejie Formation) in Nanpu Sag of Bohai Bay Basin has experienced several main tectonic events and major sub-basin and uplifted block (Gong, 1997) that has been affected by strong tension, squeezed

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slip tectonic and strong uplift, due to that fracturing produced within the rock with good connectivity. Though, unfilled and partial filled fracture plays an essential role to enhance the reservoir quality.

According to core observation and thin section studies, it has been estimated that there is a lot of 767 branch angle fractures in studied reservoir (Table 4)(Figure 4a, c, f, h, i and Fig. 11a), that are related to major wells (Np306x1, PG2, Np3-19, Np 3-80, Np 2-6, Np 206, Np 280, Np288, Np2-15). The calculated unfilled fractures are characterized by 119 branches and comprise of 15.51% of all area. The partially filled fractures are described by 105 branches and consists of 13.68% of the whole area. The fully filled fractures are characterized by 553 branches and comprise of 70.79% of the total area. Hence, the unfilled and partially filled fractures efficiently consist of 224 branches, comprising 29.19% of the entire area representing that the effective fracture ratio is smaller (Table 4). It concluded that fractures increase the permeability of the reservoir rock but most of the fractures are partially or fully filled by other material so their contribution to reservoir formation is limited. Though the actual fractures can hold hydrocarbon (oil/gas as filtration space with a width of ˃2 mm (Qiang, 2007) and a fraction of 21.22%, the effective fracture can be useful for hydrocarbon percolation space with a width of ˂ 2 mm and a proportion of 78.88%. Along with micro-fractures, fluid inclusions are also present in quartz grain or quartz overgrowth. Fluid inclusions can calculate the authigenic mineral forming temperature or measured by oxygen isotope data, that provide precise relative timing of diagenetic reactions. The homogenization temperature of fluid inclusion in quartz and quartz overgrowth appears in two diagenetic stages, ranges from 90-170°C (90 °C to 130 °C and 140°C to 170°C) (Table 3)(Kashif et al., 2018). Fluid inclusions are mostly developed along fracture or quartz overgrowth (Fig.15A (a & b)) or within the calcite cement (Fig. 15A (c)), consequently, it indicates that the inclusions are formed at the later diagenetic stage. So, the fractures generated by tectogenesis considerably enhance the reservoir permeability, but their contribution to overall reservoir porosity is limited.

Fig. 15. Showing the fluid inclusions. A. Showing the fractures healed and showing fluid inclusions in quartz as well as in fractures, quartz

overgrowth (b) and calcite (c). B. Schematic diagram showing the fluid inclusion in different diagenetic events like fractures, quartz overgrowth

cement, calcite cement and matrix (A, B, C, D, E, F, G etc.)

Table 3. Microthermometric data of aqueous fluid inclusion in Es₁ sandstone in Nanpu Sag. Th: homogenization

temperature

Well # Strata Depth, Aqueous inclusion in healed

microfractures in quartz

grains

Aqueous inclusion in healed

in quartz overgrowth

Aqueous inclusion in

carbonate cement

Size

µm

Th C°(Number) Size

µm

Th C°(Number) Size

µm

Th C°(Number)

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Np 306x1 Es1 4109.14-4140.71 2.5-8 90-130 (18),

140- 170 (13)

3-8 90-130 (4),

140-170 (3)

3.7 110 (4)

Np 3-19 Es1 4250-4404.96 2-7 90-130 (20),

140- 170 (4)

4-8 90-130 (4) 4.3 123 (3)

Np 3-80 Es1 4470-4540.40 3-8 90-130 (22),

140- 170 (4)

3-8 9-130 (3) 4.6 118 (5)

Np3-10 Es1 3953-4210.14 3-7 90-130 (13),

140- 170 (3)

3-8 9-130 (3),

140-170 (2)

- -

Np 280 Es1 3503.2-3696.72 3-8.5 90-130 (12),

140- 170 (2)

2.5-7 90-140 (5) 5 126 (4)

Np 2-15 Es1 2907.78-3505.24 2-8 90-130 (16),

140- 170 (3)

3-8 90-150 (6) - -

Np 2-6 Es1 3617.42-2864.24 3-8 90-130 (9),

140- 170 (1)

2.7-8 90-130 (4),

140-170 (1)

- -

Np 206 Es1 3338.01-3383.9 2-8.5 90-130 (15),

140- 170 (3)

3-8 90-130 (6) 4.8 123 (4)

Table 4. Fracture statistics of Shahejie Formation core in the Nanpu Sag, Bohai Bay Basin/Branch

Type Classification according to filling condition Classification according to effective fracture width

Well # (Es1

member)

Unfilled Partial - filled Full-filled Total ˃ 2mm 0.2 – 2 mm ˂ 2 mm Total

Np 306x1 15 15 85 115 12 8 9 29

Np3-19 18 20 72 110 9 11 13 33

Np 3-80 15 17 53 85 6 24 25 55

PG2 13 13 79 105 12 16 34 62

Np 2-15 13 - 67 80 14 18 50 82

Np 2-6 - 14 46 60 20 9 54 83

Np 280 15 15 47 77 24 16 36 76

Np 288 16 11 48 75 10 20 42 72

Np- 206 14 - 46 60 14 24 40 78

Total 119 105 543 767 121 146 303 570

Percent % 15.51 13.68 70.79 100 21.22 25.61 53.15 100

5.5 Impact of dissolution on reservoir formation

Dissolution is a common diagenetic process in Shahejie formation. Mostly feldspar dissolution occurs in porous sandstone and non-porous sandstone with extensive early calcite cement, contains limited feldspar pores that suggesting extensive feldspar dissolution occurs after Eo-diagenetic calcite cement (Yuan et al., 2017) and timing of detrital feldspar dissolution and new growth of minerals can be evaluated proportionate to compaction features (Molenaar et al., 2015). Dissolution of feldspar and precipitation of clay are significant diagenetic reactions that are affecting reservoir quality evolution in sandstone with detrital feldspar. Studied sandstone is lithic arkose, arkose and feldspathic litharenite having secondary pores that developed due to the dissolution of feldspar and unstable rock fragments (Figure. 4b, h, Figure 11f, and Figure 13b). In studied sandstone, the amount of authigenic clay and quartz cement is low as compare to leached feldspar. Small authigenic clays and quartz cement, as well as low pore water salinity, predict that most of K⁺, AL⁺, and SiO2 release from K-feldspar leaching exported from studied sandstone. The abundant feldspar dissolution improved porosity and permeability. The organic CO2 and organic acid are not sufficient for the creation of feldspar pores (Lundegard et al., 1984; Giles & Marshall, 1986) because meteoric water can deliver inorganic CO2, feldspar dissolution in sandstone possibly occurred in the existence of acids from organic matter and the meteoric water.

There are two types of dissolution in the studied reservoir, syngenetic-penecontemporaneous dissolution, and burial dissolution. In syngenetic-penecontemporaneous dissolution the freshwater or atmospheric water affecting the exposed part of deposit (due to tectonic uplift and erosion) and mainly take place in selective dissolution, creating limited inter-granular dissolved pores, that are sometimes disappearing by late compaction, cementing and other diagenetic processes that had no direct impact on any existing reservoir. Due to tectonic uplift, the effect of atmospheric fresh water, strong supergene dissolution occurred and formed weathered residual material. At some places many dissolve pores and seam/veins were formed due to strong supergene dissolution, most of these pores were retained and may act as effective hydrocarbon (oil/gas) migration channel, and some dissolution pores may be filled or deform during later diagenesis stage. During drilling in the highly porous and fractured zone, the loss of circulation of fluid and many drill pipe venting is a clue of such zone. Supergene dissolution plays a significant role in reservoir formation.

Burial dissolution also plays a significant role in reservoir formation, dissolution occurs due to excessive acidic fluids generated by the maturation of organic matter when the source rock was buried at 3-4 km depth, the temperature is high and organic matter expelled a considerable amount of acidic fluid, and that acidic fluid dissolved the adjacent rock units. Another possibility is liquid hydrocarbon degradation, which is also producing an acidic fluid that dissolves the adjacent rock units. This type of dissolution is nonselective, so it cannot

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enhance the total porosity, but it improving the early pore structures (Zhou et al., 2014), significantly reforming the interconnectivity of pores of the reservoir and stimulating the development of the high-quality reservoir.

5.6 Pore Space Effect on Reservoir Formation

The diagenesis has a great impact on reservoir formation; it has been evaluated on the basis of the above analysis, the reservoir formation process of the studied reservoir can be divided into different stages (Figure 16). The process of deposition create primary pores, due to the passage of time, compaction of overlying sediment and cementation has been reduced the porosity. Throughout cementation, the pore spaces of the reservoir decrease 8 to 15% because of authigenic clay occluded the intergranular pores. In the interim, the loose sediments continued weak and semi-consolidated. Similarly, sediments occasionally exposed to the atmosphere and were dissolved by freshwater (penecontemporaneous stage), so the atmospheric water and mix water producing dissolve pores and large intergranular pores and may increase the reservoir porosity 4 to 10%.

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Fig. 16. Schematic diagram of reservoir space evolution and diagenesis of the Shahejie formation in Nanpu Sag, Bohai Bay Basin.

In shallow burial process, numerous primary intergranular pores were developed at the time of deposition,

excluding the discriminating intergranular dissolved pores that were created by atmospheric fresh water through the penecontemporaneous time, due to compaction and cementation, the pore spaces were abundantly damage and reduce to ˂ 5%. Due to compaction and pressure solution collapse with matter and led to early formed pores to disappear. On another hand, weak recrystallization is also generating crystal pores within the reservoir pores and effective porosity was decreased up to 7 to 10%. By dissolution, it can cause to produce dissolution pores and dissolution seams/veins, more space was preserved and instantaneously became an important reservoir and improved the overall reservoir pore spaces up to 15 to 20%.

The present study was carried out at the depth range of 3000-4500 m depth at medium to deep burial diagenetic stage (Mesodiagenesis and catagenesis stage). Wherever the compaction and cementation clog the pore space and destroy the reservoir characteristics. Though the rock had a specific resistance against compaction, however dissolution and replacement generated secondary pores, so that’s why there volume of reservoir space is increasing and obliteration of pore space volume was approximately equivalent; therefore the changes in total effective pore space were not clear. At deeper depth, at some intervals, the effective porosity decreased up to 5 %. The acidic fluid (formed by maturation and degradation of organic matter) dissolved adjacent strata and improvements the early formed pore structures, absolute porosity did not enhance, but the interconnected (effective) porosity increases up to 4.5 %. Due to tectonic events, many fractures were developed in the reservoir rock. These fractures play minor contribution to reservoir porosity, but the permeability of the reservoir has been enhanced.

6 Conclusions

Es₁ member of Shahejie formation in a studied area consisting of feldspathic litharenite, arkose, and lithic arkose. The reservoir space is primary preserve pore as well as pore spaces conquered by the dissolution of unstable lithic fragments. On the basis of reservoir characteristics, the reservoir is divided as a primary porous reservoir, fractured porous reservoir, and dissolution porous reservoir rocks.

Reservoir pores occur as intergranular pores, fractures pores, intra-granular dissolution pores, primary, intergranular cement dissolution pores, feldspar/rock fragment dissolution pores and micropores. Among them, the interconnected pores (effective) comprises of intergranular pores, fractures pores, micropores, and some nano-scale throat. The general matrix pore radius is 4-120 µm, and the matrix throat radius is 10-600 nm, and fracture opening degree ranges from 100-400 µm.

Es1 sandstone is acting as a good reservoir that was generated by the actions of sediment deposition, tectonic activity and diagenesis. Sedimentation assumption for reservoir improvement, but the effective reservoir is mainly controlled by primary pores, fractures and dissolution pores. Whereas the compaction fractures and pore-filling and cementation play a significant role in reservoir densification. Acidic fluid dissolves intergranular pore cement, and replacement are the main factor for forming the porous reservoir. High dissolution endorses the reservoir characteristics. Fracture plays a significant role in improving the reservoir pore interconnectivity or permeability and has less effect on reservoir porosity. Overall the studied reservoir is progressively developed and formed by numerous geological and diagenetic processes.

Acknowledgments Muhammad Kashif like to thanks, China scholarship council (CSC) China for granting me a full scholarship (2015-2018) to carry out the research. This study was funded by the Natural Science Foundation of China Project (No. 41602138), National Science and Technology Special Grant (No. 2016ZX05006-007), China Postdoctoral Science Foundation-funded project (2015M580617; 2017T100524), and the Fundamental Research Funds for the Central Universities (15CX08001A). We would also like to thanks the Jidong oil field company for their cooperation to provide the research data and help to complete the research without loss of time. The reviewers are sincerely acknowledged for their helpful comments and suggestions on an earlier version of this manuscript. The authors are very thankful to the Dr. Zengqian hou (Editor-in-Chief) for his excellent advice and cooperation on a previous version of this manuscript. References

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About the First Author

MUHAMMAD Kashif (male) born in Sargodha, Punjab Province Pakistan. He received his Bachelor and Master degree

from University of the Punjab, Pakistan. Recently he received his Ph.D degree from School of Geosciences, China

University of Petroleum (East China). Main research interest includes diagenesis, reservoir characteristics and genesis of the

deeply buried reservoir. E-mail: [email protected]

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