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Pore size distribution, their geometry and connectivity in deeply buried Paleogene Es1 sandstone reservoir, Nanpu Sag, East China

Pore size distribution, their geometry and connectivity in deeply buried Paleogene Es1 sandstone... The study of pore characteristics is of great importance in reservoir evaluation, especially in deeply buried sandstone. It con- trols the storage mechanism and reservoir fluid properties of the permeable horizons. The first member of Eocene Shahejie Formation (Es1) sandstone is classified as feldspathic litharenite and lithic arkose. The present research investigates the pore characteristics and reservoir features of the deeply buried sandstone reservoir of Es1 member of Shahejie Formation. The techniques including thin-section petrography, mercury injection capillary pressure (MICP), scanning electron microscopy and laser scanning confocal microscope images were used to demarcate the pores including primary intergranular pores and secondary intergranular, intragranular, dissolution and fracture pores. Mercury injection test and routine core analysis were led to demarcate the pore network characteristics of the studied reservoir. Pore size and pore throat size distribution are acquired from mercury injection test. Porosity values range from 0.5% to 30%, and permeability ranges 0.006–7000 mD. Pore radii of coarse-grained sandstone and fine-grained sandstone range from 0.2 to > 4 µm and 1 nm to 1.60 µm, respectively, by MICP analysis. The mineral composition also plays an important role in protecting the pores with pressure from failure. Fractured sandstone and coarse-grained sandstone consist of large and interconnected pores that enhance the reservoir poros- ity and permeability, whereas fine-grained sandstone and siltstone consist of numerous pores but not well interconnected, and so they consist of high porosity with low permeability. Keywords Reservoir rock · Pore characteristics · Pore size distribution · Pore throat · Porosity · Permeability 1 Introduction injection test (Nabawy et al. 2009). Deeply buried sandstone is acting as a good reservoir that is controlled by pore size, The movement of different reservoir fluids via different geo- pore structure and pore size distribution. Sandstone proper- logical systems is mainly controlled by capillary pressure ties (porosity and permeability) are mainly controlled by within the rock unit. The pore volume and pore throat size grain size, grain sorting, shape, mineralogy and sedimentary that relate to displacement pressure are the main components structures as well as their environment of deposition (Saiag that control the reservoir characteristics (mainly permeabil- et al. 2016). Several diagenetic processes (physical, chemical ity) of reservoir rock, and they can be evaluated by mercury and biological) are affecting sediments during lithification, vary with the chemistry of fluid, temperature and pressure and correlate with the burial history of the sedimentary Edited by Hao Jie and Xiu-Qiu Peng basin (Loucks et al. 1984; Bjørlykke 2014). The intercon- nectivity and geometry of the pore system are greatly influ- * Muhammad Kashif enced by the diagenetic overprints (Lai et al. 2018a, b, c; kashifyaqub@yahoo.com Hollis et al. 2010). The intricate diagenetic alteration of the School of Geosciences, China University of Petroleum, sandstone experienced throughout the geological history will Qingdao 266580, China alter the original pore system and exert low control on res- Department of Earth Sciences, University of Sargodha, ervoir quality evolution (Lai et al. 2018a, b, c). Diagenetic Sargodha 40100, Pakistan modification changes the distribution and quantity of pore Institute of Geology, University of the Punjab, Lahore, space, generating smaller and disconnected pore (Lai et al. Pakistan Vol.:(0123456789) 1 3 982 Petroleum Science (2019) 16:981–1000 2018a, b, c; Cook et al. 2011). Different types and various The Es1 sandstone consists of intricate and heterogeneous degrees of diagenesis reshape the pore structures (Lai et al. composition, in which parts comprising pore throat in these 2018a, b, c, 2015). heterogeneous sandstones remain poorly understood and Mechanical compaction, cementation and the authigenic cannot easily be charged by oil and gas (Tian et al. 2015; Xi clay content are the main pore volume-controlling factors; et al. 2016). The studied sandstone consists of interbedded however, fracturing, cement dissolution and framework grain mudstone, and these muddy layers, cement and the muddy are the most significant porosity-improving factors (Lai et al. matrix may have a negative impact on permeability. Mineral 2018a, b, c, 2018b; Nabawy et al. 2009). Well-connected composition, particle size and diagenesis are very significant intergranular pores have large pore throats that contribute controlling factors for the pore throat distribution within the to permeability, whereas the subsequent dissolution pores reservoir sandstone and mainly controlled by hydrodynamic and micropores are only connected by small pore throats condition during sedimentation and diagenesis. Deformed or that contribute less to permeability (Lai et al. 2018a, b, c). ductile mica grains, calcite cement and clay minerals create Primary porosity will be significantly reduced by mechani- a problematic situation to block the pores and narrow the cal and chemical compaction by authigenic minerals (Moz- pore throat that causes to reduce the reservoir quality. ley et al. 2016). Cementation reduced the permeability by High-pressure mercury injection capillary pressure, occluding the pores and pore throats (Lai et al. 2018a, b, c; low-pressure adsorption of N and CO , porosity and per- 2 2 Taghavi et al. 2006). Mercury injection capillary pressure meability data have been used to obtained the quantitative (MICP) analysis was used to characterize the pore struc- pore size, pore volume, pore size distribution, surface area, tures and pore size distribution. Micropores from the matrix porosity and permeability (Howard 1991; Ross and Bus- and authigenic minerals occupy a significant proportion of tin 2009; Chalmers et al. 2012; Schmitt et al. 2013a, b). the total porosity; in addition to the pore size, the perme- Scanning electron microscopy (SEM) photomicrographs ability of reservoir sandstone is much affected by the pore are used to perceive the pore size, morphology and type of throat connectivity, i.e. the pore throat radius, geometry and pores from the nanoscale to the micron scale; quantitative structure (Zou et al. 2012). Quartz overgrowth mostly fills parameters are difficult to obtain. MICP is useful for charac- the primary intergranular pores, reducing it to narrow, flat, terizing micro- to macroporosity (r > 50 nm), low-pressure sheet-like or slot-like pores between adjoining overgrowths N adsorption is used for nanoporosity (d between 2 and face (Lai et al. 2018a, b, c; Soeder and Chowdiah 1990). 50 nm), and CO adsorption for pore is having the smallest The microscopic structure of pore throats is characterized size (d < 2 nm) (Chalmers et al. 2009; Clarkson et al. 2013). by a tortuous pore system, small pore radius, poor connec- High-pressure mercury injection may give rise to the pro- tivity and firm heterogeneity (Zou et al. 2012). Authigenic spective risk of particle degradation, rock compressing and clay minerals play a significant role in decreasing the pore destruction of the pore network (Clarkson and Bustin 1996). volume and concluding the pore apertures (Lai et al. 2018a, The main objectives of this study are to: (1) evaluate the b, c; Yue et al. 2018). Because of their hair-like and hon- pore structure characterization with advance integrated tech- eycomb-like morphology, crystal habit and fibrous nature, niques of the Es1 sandstone of Shahejie Formation of Nanpu they significantly affect the hydraulic and petrophysical Sag; (2) propose the keen understanding of the contribution properties of sandstone, thereby shaping the pore geometry of different pore structures to evaluate the reservoir quality. (Lai et al. 2018a, b, c; Samakinde et al. 2016). Moreover, To achieve these goals, the detailed core observation, thin- pore-bridging or pore-lining clays may decrease the perme- section study of core samples, SEM analysis, laser scan- ability considerably by affecting the pore, pore throat radius ning confocal microscope (LSCM) analysis and MICP were and surface area, and reducing the size of the intergranular used to evaluate the characterization of pore size, pore throat pores and turning them into micropores (Lai et al. 2018a, characteristics and pore distribution. b, c; Schmitt et al. 2013a, b, 2015). Dissolution of detrital grains and cement is the primary process which enhances the porosity and permeability by increasing pores and pore 2 Geological setting throats (Lai et al. 2018a, b, c; Mozley et al. 2016). The Es1 sandstone is classified as feldspathic litharenite, The Bohai Bay Basin is a giant basin and situated in east and lithic arkose of braided river, fluvial channels, distribu- part of China, straddling over the North China Plain, Bohai tary channel and lacustrine delta front facies. Core samples Sea and lower Liaohe Plain, covering an area of about 4 2 of seven exploratory wells are selected to study the petro- 20 × 10  km . Bohai Bay Basin is a complex, petroliferous graphic analysis and sedimentological characteristics of Es1 basin combined by Mesozoic and Cenozoic rifts (Allen sandstone. The present study focuses on pore size, struc- et al. 1997; Ren et al. 2002), with Shahejie Formation and ture and pore throat size characterization of deeply buried Dongying Formation as source rocks (Hao et al. 2011). The high-quality reservoir rock by advanced analytical methods. Nanpu Sag is a sub-unit of Bohai Bay Basin, and it is a 1 3 Bogezhuang Fault Matouying Bulge Np# 4 Fault Structural belt #4 Bogezhuang Bulge Shichang sub-sag Gaoliu Fault Petroleum Science (2019) 16:981–1000 983 small dustpan-shaped faulted sag that is situated in Bohai Xinanzhuang–Baigezhuang (acting as boundary fault) fault Bay Basin towards the north-eastern part of transition to north-east. It further consists of six sub-basins including belt between Huanghua depression, Bozhong depression Jizhong, Huanghua, Jiyang, Liaohe–Liaodong, Bozhong and and Liaodong depression (Xu et al. 2008a, b; Chen et al. Lingqing–Dongpu depression (Gong 1997). 2016; 2018). This sag covers more than 1900 km area, and Drilling data for hydrocarbon exploration are a funda- more than half of the area lies under the Bohai Bay Basin. mental tool to evaluate the stratigraphy of the Nanpu Sag Structurally this sag is acting as a half-graben (Wang et al. rock units. Nanpu Sag consists of thick sediment sequence 2002). Geologically Nanpu Sag is confined towards the of Cenozoic strata about 5000–9000 m (Guo et al. 2016), north by Yanshan Mountain, Shaleitian fault to the south, which consists of the Eocene Shahejie Formation, the Oli- Baigezhuang fault to the north-east, Matouying bulge to the gocene Dongying Formation, the Miocene Minghuazhen west and Xinanzhuang fault to the north-west as shown in Formation, Guantao Formation and Quaternary Pingyuan Fig. 1. Tectonically the Nanpu Sag consists of eight north- Formation (Jiang et al. 2009; Guo et al. 2016) as mentioned east trending structures, including Nanpu 1, Nanpu 2, Nanpu in Fig. 2. The studied Shahejie Formation divided into three 3, Nanpu 4 and Nanpu 5 offshore structures, and Laoyemiao, main members from top to bottom as Es1, Es2 and Es3, Gaoshangpu and Liuzan onshore structures (Wang et al. respectively. The studied Es1 sandstone characterized by 2002) that are shown in Fig. 1. The Nanpu Sag is famous conglomerate sandstone, coarse-grained sandstone, fine- for exploration potential of oil and gas from deeply bur- grained sandstone, with interbedded siltstone, and mudstone ied rock (especially Shahejie Formation > 3500 m). Geo- of a shallow lake, semi-deep lake, meandering river delta graphically Shaleitian fault bounded towards the south and plain and delta plain facies that are shown in Fig. 3. The Es1 Nanpu Sag China Gaoshangpu Laoyemiao Beipu Gaoliu Structural belt Structural belt Beipu Structural belt Linque Getuo Lp1 Nanpu Np2-15 Caofeidian Sub-Sag Pg2 Np306x1 Np288 Np3-19 Np2-60 Np3-80 Legend Shaleitian Fault 10 km FaultWellTown Fig. 1 Location map of the structural belt, associated bulges and structural division of Nanpu Sag, Bohai Bay Basin, China Modified after Chen et al. (2017) 1 3 Xinanzhuang Fault NP# 3 Fault Shaibai Fault Structural belt # 5 Nanpu #1 Fault Laowangzhuang Bulge Structural belt #1 Linque-Liunan sub-sag Xinanzhuang Bulge Structural belt#2 Nanpu # Fault Structural belt #3 984 Petroleum Science (2019) 16:981–1000 Strata Age, Thickness, Sedimentary Tectonic Lithology Form- Sub- Ma m Environment evolution Member ation member Pingyuan 250-310 Flood plain Quaternary (Q) Minghuazhen Meandering 1100-1300 (Nm) stream 5.32 Guantao Braided 300-500 (Ng) stream 23.8 Dongying Deltaic 0-300 (Ed) lacustrine 28.5 Deltaic fan, Es1 200-800 Lacustrine 31.0 Deltaic Fan, Es 2 50-150 Alluvial fan 33.7 Deltaic fan, 150-450 Es3 Lacustrine 38.5 Deltaic fan, 100-300 Es Lacustrine 41.0 Es3 Deltaic fan, 300-600 Es3 Lacustrine 42.0 Es Lacustrine 3 150-300 42.5 Deltaic fan, 150-350 Es3 Lacustrine 45.5 Es Mostly absent in Nanpu Sag Nanpu sag Conglomerate Sandstone Siltstone Mudstone Fig. 2 Generalized Cenozoic–Quaternary stratigraphy of the Nanpu Sag showing the tectonic and sedimentary evolution stages and significant petroleum system elements. Modified after Guo et al. (2013) and Yuan et al. (2015) member is described as shallow lacustrine lithofacies (Dong with mudstone, grey and dark grey sandstone underlain by et al. 2010), and Es2 member consists of mudstone interbed- brownish mudstone interbedded with grey sand and con- ded sandstone and characterized as alluvial sediment (Guo glomerates and characterized as Lacustrine fan delta (Wang et al. 2016). Es3 member consists of brown mudstone with et al. 2002; Guo et al. 2016). The Dongying Formation is a interbedded conglomerate sandstone, mudstone interbedded set of lacustrine deposit, Guantao Formation is characterized with siltstone and sandstone, grey oily shale interbedded as a braided fluvial system, and Minghuazhen Formation 1 3 Paleogene Neogene System Series Paleocene Eocene Oligocene Miocene Pliocene Kongdian Shahejie (Ek) (Es) Source rocks Reservoir rocks Seal Stage I Stage II Stage III Postrift stage Synrift stage Petroleum Science (2019) 16:981–1000 985 LpN1 Np206Np2-29Np2-15Lp1 SP GR SP GR SP GR SP GR SP GR 2200 2500 2300 2600 2600 2600 2700 3200 3200 3100 3300 3200 3400 Meandering Seemi deep Delta plain 3500 river delta front lake WS-NE Shore shallow Turbidite Igneous rock lake Fig. 3 Well connecting line across Np206, Lp1, Np2-15, LpN1 and Np2-29 of the various environments in Nanpu area is a set of low-sinuosity fluvial system (Wang et al. 2002). experienced multistage structural crusade that gave rise to Nowadays the overall burial depth of Shahejie Formation in intricate structures that dip north and derive from west to Nanpu Sag area is more than 4000 m below sea level. The east. The latter established a NW tendency and a sinistral present-day geothermal gradient is 32 °C/km (58 °F), the shear fault, called the Shicun fault, in the south of Caoqiao average surface temperature is 14 °C (57 °F) and, the maxi- area. The Shicun fault is a boundary fault of Guangrao sali- mum temperature is 135 °C (275 °F) at greater than 4000 m ent crossing Lijin Sag, Boxing Sag and Niuzhuang Sag. The depth. The sub-surface temperature of Ed3 and Es1 is almost stratigraphy is consisting of the Paleogene sequence into five 140 °C and 170 °C, respectively, and near to 200 °C for formations, i.e. Kongdian Formation (EK), Shahejie For- Es . The vitrinite reflectance of the shallow Ed3 is 0.8% mation (ES), Dongying Formation (Ed), Guantao Forma- R , and for Es , it could be greater than 2% R (Guo et al. tion (Ng) and Minghuazhen Formation (Nm). The Shahejie o 3 o 2013). The Ed3 source rocks are mature to generate oil. The Formation (Es) consists of source and reservoir members. 3 1 Es1 source rock reached hydrocarbon generation initiation The main source rock members are Es and Es (Zhu and 3 4 at about 23 Ma, being up to high maturity to produce wet Jin 2003). Within the Dongying Sag, the maximum burial gas at that stage. depth of Shahejie Formation is 5000 m (Guo et al. 2012; Dongying Sag is also a small secondary fault–sag depres- Song et al. 2009). The present-day geothermal gradient is sion and situated at the south-eastern side of Bohai Bay 34 °C/km, and the maximum temperature is 180 °C at this Basin. It is a dustpan-like structure with overlapping in the depth (Wang 2010). Total organic carbon content within the south and faults in the north, and it consists of an area of source rocks is 0.5%–18.6% with type I and type II kerogen 5800 km . Tectonically it is a half-graben with gentle south- (Guo et al. 2010). The R % (vitrinite reflectance) varies from ern slope and faulted northern margin. Laterally this sag is 0.35% to 1.5% from 2000 to 5000 m, representing source further subdivided into several secondary structural units, rock is slight mature to mature (Guo et al. 2012). such as the northern steep slope zone, middle uplift belt, the Lijin, Minfeng, Niuzhuang trough zone, Boxing sub-sag and southern gentle zone (Zhang et al. 2014). The significant 3 Materials and methods hydrocarbons generated source rock in Dongying Sag are 3 1 Es (dark shale with 100–400 m) and Es (dark shale with A comprehensive study was a prerequisite including petro- 3 4 mudstone 100–300 m) sub-members of Paleogene Shahejie graphic thin-section observation and petrophysical analy- Formation. These two members are the main aims of shale ses of core cutting samples. Wireline log data, thin-section oil exploration in the Bohai Bay Basin. The sedimentary petrography, SEM analysis, LSCM analysis and MICP anal- succession and regional history of the sag are divided into ysis are the primary methods that are used to evaluate the syn-rift and post-rift stages (Xie et al. 2006). The Es (humid pore characteristics of Es1 sandstone. Core samples are col- lacustrine environment) and Es (saline environment) were lected from seven wells; among them, 120 core plugs were deposited during the syn-rift stage. Dongying Sag area selected for thin sections at a depth interval of 2490–4500 m. 1 3 986 Petroleum Science (2019) 16:981–1000 On the basis of core observation, samples were collected and 4 Results analysed to investigate pore characteristics from core inter- vals. In total, 140 reservoir porosity and permeability data 4.1 Microscopic studies points and well logging data were obtained from Shengli Oilfield Company, China. Petrographic thin sections were The studied Es1 member of Shahejie Formation mostly con- detailedly studied with the help of an optical polarizing sists of fine-grained, coarse-grained and conglomerate sand- microscope to compute and interpret grain size, their type, stone with interbedded mudstone. Thin-section petrographic fabric, compaction, cement type, sedimentary features and study indicates that Es1 member is primarily comprising pore size distribution. Thin sections were partially stained of the detrital component and mainly composed of quartz by Alizarin red S and K-ferricyanide to identify carbonate (10%–70% bulk volume), feldspar, micas and different rock minerals using Dickson’s technique (1966). Thin sections fragments with a mixed fraction. The petrographic thin- are studied under Zeiss Axioscope POL digital transmis- section study indicates that the studied sandstones are clas- sion microscope for rock mineralogy, pore characteristics sified as lithic arkose and feldspathic litharenite as shown and diagenesis. COXEM EM-30 scanning electron micro- in Fig. 4. Mudstone occurs in subordinate forms and clay- scope (SEM) equipped with an energy-dispersive X-ray associated minerals and carbonate minerals are abundant spectrometer (EDX) was used to interpret the clay miner- in fine-grained sandstone, siltstone and mudstone. Sand- als, cement types, various pore spaces and their impact on stone comprises conglomerate sandstone, coarse-grained petrophysical properties, diagenetic features and other mate- sandstone, medium-grained sandstone and fine-grained rial that affect the whole pore network of the reservoir. The sandstone. Sandstone detrital grains are poorly sorted to SEM equipped with a secondary electron, energy-dispersive sorted and angular to sub-angular and sub-rounded grains. X-ray detector and backscatter electron was used to image Moreover, grains shows concavo-convex to line contact and the pore system and compositional variation. For this pur- represents the intensity of the compaction. Feldspar present pose, twenty-four core samples were prudently chosen for in the form of K-feldspar and albite (Na-feldspar) and ranges SEM analysis. MICP measured pore throat size distribution; from 12% to 65% with an average of 38.5%. Albite shows for this purpose, 22 samples were selected to analyse the little variation concerning a depth that K-feldspar disappears mercury injection experiments using a micrometric Auto- with concerning extent. pores apparatus; porosity was assessed by mercury injection Beside quartz and feldspar, the sandstone consists of rock that was used for special core analysis, and inoculation of fragments and mica that has been identified by thin-section helium at 120 kPa pressure by helium pycnometer is used studies. Rock fragments are present 8%–65% with an aver- for routine core analysis. These types of injection test were age of 38.4%. Chert is also observed in the thin section from conducted using a mercury porosimeter. Their diameter 0.5% to 8% with an average of 3.7% and appears as pure measures the number of pores as megapores/supercapillary quartz due to their constant lucidity under a plane polar- (D ≥ 60 µm), macropores/capillary pores (60 µm > D ≥ 8 µm; izing microscope. The bulk XRD data show that samples and mesopores, 8  µm > D ≥ 0.4  µm) and sub-capillar y/ contain quartz, k-feldspar, albite, calcite and dolomite and micropores (D < 0.4 µm) (Nabawy et al. 2009). pyrite existing in a small amount as well as clay minerals Twenty samples were selected for a laser scanning confo- as a whole. Based on XRD data, the kaolinite and mixed- cal microscope (LSCM) to evaluate the pore, pore size and layer illite/smectite are common in the studied sandstone fol- their connectivity. The operating conditions were done in a lowed by illite. Rendering to pore type and pore percentage, Zeiss microscope equipped with AxioCam 506 colour (LSM the studied sandstone samples consist of homogeneous and 700), was maintained at 10 kV beam energy and 250 µA heterogeneous pores. Among them, homogeneous pores are beam current. characterized mainly by vuggy and intergranular macropores All these samples except MICP were prepared, analysed and mesopores. The homogeneous pores are described by and interpreted at different laboratories of the School of pore types, mineralogical texture and distribution, whereas Geosciences, China University of Petroleum, Huangdao heterogeneous pores are distinguished mainly intergranular (Qingdao), whereas MICP was done at Analytical Labo- mesopores, dissolution pores and micropores (matrix). The ratory of the CNN Beijing Research Institute of Uranium heterogeneity in mineralogical texture is due to the presence Geology. of carbonate cement, iron oxide and other constituent, so some of the studied samples are described by heterogeneity in pore size distribution. 1 3 Petroleum Science (2019) 16:981–1000 987 Quartz, % Quartz arenite 10 90 Subfeldsarenite Sublitharenite Np 306x1 30 70 Np 3-19 40 Np 288 Lp1 50 50 Np 280 Np 2-15 60 40 90 10 Feldspathic Arkose Litharenit Lithic arkose litharenite Feldspar, % Rock fragments,% 10 20 30 40 50 60 70 80 90 Fig. 4 Rock composition of Es1 sandstone (ternary plot refer to the sandstone classification standard of Folk 1974) lower pore connectivity have poor reservoir characteristics. 4.2 Capillary pressure test Well 3–80 (coarse-grained sandstone, 4534.7 m) and well Np306x1 (conglomerate sandstone, 4218.7 m) have pore Mercury injection capillary pressure was performed on throat radius of 0.006 to > 63 µm, and they consist of mega- deeply buried high-quality porous and permeable sandstone. pores, macropores, mesopores and micropores. The sample An advanced increment of the applied pressure was escorted comprises of bigger pore throat radius and well connectiv- by an advanced superior increase in the mercury incursion ity of the pores, so the permeability curve shows the high inside the pore. It is concluded that if the pore throats are permeability of these well samples as shown in Fig. 6a, b. smaller, then higher pressure is required to flow. The studied Well Np306x1 (coarse-grained sandstone, 4234.2 m) and Es1 sandstone exhibits good to excellent porosity varying well Np280 (medium-grained sandstone, 3603.95 m) have from 17.9% to 29.5% that is presented in Table 1. pore throat radius of 0.006 to > 3.2 µm, and they consist of On the basis of diameter, the studied formation consists mesopores and micropores. The sample consists of an aver- of supercapillary/megapores, capillary pores (mesopores and age pore throat radius and connectivity of pores is good, so macropores) and sub-capillary/micropores. The studied Es1 the permeability curve shows the moderate to good reser- sandstone is consisting well to moderate pore connectiv- voir characteristics shown in Fig. 6c, d. Well Np2–15 (fine- ity, so that is why permeability of reservoir is also good grained sandstone and siltstone, 3617 m) and well Np3-19 depending upon pore size and pore throat radius. Mostly (fine-grained sandstone, 4232.59 m) have pore throat radius bigger pores with higher pore connectivity have good poros- of 0.006 to < 0.63 µm, and they consist of mesopores with ity and permeability, and smaller pore with moderate to Table 1 Fractions of mercury porosity values of different pore sizes (based on Nabawy et al. 2009) attained from the mercury injection test Sample no. Depth, m Macropores, Macropore Mesopore, % Mesopore Micropores, % Porosity measured % threshold, µm threshold, µm by Hg injection Np3-80-1 4534.7 26 8.4 53 0.42 21 29.5 Np280-5 3503.95 25 8.4 65 0.42 20 28.4 Np288-6 3725.4 30 8.4 49 0.42 21 26.8 Np3-19-7 4232.59 16 8.4 41 0.42 43 17.9 Np2-15-8 3617 24 8.4 41 0.42 35 19.2 Lp1 2934.20 27 8.4 53 0.42 20 23.7 Np306x1-10 4218.70 28 8.4 54 0.42 17 26.8 1 3 988 Petroleum Science (2019) 16:981–1000 abundant micropores. The sample comprising of average reservoir characteristics (Kashif et al. 2019). Figures 5b, pore throat radius and connectivity of pores is fair to good, e and 8a show the dissolution pores created by leaching so the permeability curve shows the moderate to poor reser- of unstable minerals and rock fragments and enhance the voir characteristics that is shown in Fig. 6e, f. interparticle secondary pores. The pores are varied in shape and size depending on the geometrical arrangements of 4.3 Pore system the grains. Pores appear as elongated surrounded by rigid grains/particles. Other pores include triangular primary Types of pores, their shape and their connectivity depend on pores between rigid grains, which are partially filled by compaction, mineral dissolution, precipitation and organic clays and organic matter and authigenic minerals. These matter degradation/maturation and hydrocarbon genera- pores are acting as a pathway due to their large pore size and tion. Mechanical compaction destroys the pore spaces, and pore connectivity. Dissolution pores are diagenetic pores, dissolution promotes the creation of pores in siliciclastic formed within the low-resistance fragments, minerals, par- sandstone (Mondol et al. 2007; Loucks et al. 2012). Further- ticles, feldspar grains and carbonate cement that are com- more, asphaltic filling and carbonate cement precipitation mon in the studied sandstone as shown in Figs. 5b, e; 7b; significantly reduce the pore size and reduce the porosity and 8a, c. Some micro- to nanoscale pores is also observed (Rexer et al. 2014). The studied sandstone is consisting of within clays aggregates due to the transformation of unsta- macropores, mesopores and micropores. Pores are character- ble clay minerals. Some thin section shows microfractures, ized as macropores (d > 50  nm), mesopores (d = 2–50  nm) interpreted as compaction fractures and dehydration cre- and micropores (d < 2 nm) (Rouquerol et al. 1994). Macro- ated shrinkage cracks, hydrocarbon expulsion generated to nanopore system is developed within the studied samples. fractures. Microfractures also formed due to overpressure According to Loucks et al. (2012), pore classification is used and pressure solution (stylolites) and natural brittle fractures to classify the pore spaces into: (a) intergranular pores, (b) (Zhang et al. 2018). matrix pores and secondary intragranular pore among grains and mineral crystal, and (c) fracture pores (Table 2).4.4 Pore structures Various types of pores are identified in conglomerate sandstone, coarse-grained sandstone, medium-grained sand- 4.4.1 Pore size and pore throat distribution stone, fine-grained sandstone as well as siltstone that are presented in Fig. 7. The pores are identified under a plane Besides the reliance of capillary pressure on reservoir char- polarizing microscope and SEM. Conglomerate sandstone, acteristics, former scientists deliberated that the shape of the coarse-grained sandstone, medium-grained sandstone and capillary pressure curve is mostly ae ff cted by the pore geom- fine-grained sandstone are mostly consisting of primary etry (Rose and Bruce 1949; Vavra et al. 1992). MICP curves intergranular pores, dissolution pores and fractures pores. show capillary pressure within the reservoir sandstone is Primary intergranular pores are present between detrital appropriate representatives for quantification of pore geom - grains and were preserved after compaction and cementa- etry and integration of dynamic data into reservoir models. tion that are shown in Fig. 7a, b. Carbonate cement, filling MICP experiments on the selected core samples show con- clay minerals and ductile deformation (grain flow) as shown nected pore size distributions from Es1 sandstones. At least in Figs. 5a, c, d, f; 8f reduce the pore space and decree the six out of eight samples show bimodal pore size distribution Table 2 Porosity and pore volume obtained by helium porosimetry Sample no. Depth, m Lithology Helium pycnometry −3 3 Pore volume, 10 cm /g Porosity, % 1—Np3-80 4534.70 Medium-grained sandstone 1.544 13.6 2—Np306X1 4223.35 Coarse-grained sandstone 2.003 16.7 3—Np306X1 4220.76 Coarse-grained sandstone 1.942 15.9 4—Np280 3503.20 Conglomerate sandstone 1.997 21.1 5—Np280 3503.95 Coarse-grained sandstone 1.362 15.2 6—Np3-19 4232.59 Medium-grained sandstone 1.419 10.4 7—Np2-15 3617.00 Siltstone 0.756 6.3 8—Np306X1 4234.20 Fine-grained sandstone 0.741 7.2 9—Np306X1 4218.70 Siltstone 0.602 5.3 1 3 Petroleum Science (2019) 16:981–1000 989 (a) (b) (c) Pr.p Fr D.mica Fd P.kaolinite Fr 100 µm 100 µm 100 µm Np 306x1, 4223.35 m Np 380, 4534.7 m Np 280,3503.95 m (d) (e) (f) Rf Kaolinite Pr.p Cd.p 200 µm 200 µm Np 2-15, 3617 m Np 288, 3745.4 m Fig. 5 Petrographic thin-section and SEM photograph shows the pore characteristics; a ductile mica flow, caused to reduce the pore size; b primary intergranular pores, fractures and partially to complete feldspar dissolution and enhance the rock quality; c clay mineral (kaolinite) fills the primary pores and reduces the reservoir quality; d primary intergranular pores; pores are filled by calcite cement and reduces the reservoir characteristics; e calcite cement is dissolved and creating pores; f SEM image shows the kaolinite filling the pore space and reduces the reservoir quality; Q quartz; D. mica ductile mica; F feldspar, Fd feldspar dissolution; Fr fractures; Pr. p primary pores; P. kaolinite pore filling kaolinite; C calcite, Cd. p calcite dissolution pores; Rf rock fragment 100 100 100 (a) (b) (c) Np 3-80, 4534.7 m Np 306x1, 4218.7 m Np 306x1, 4234.2 m 90 90 90 80 80 80 70 70 70 60 60 60 50 50 50 40 40 40 30 30 30 20 20 20 10 10 10 0 0 0 0.006 0.063 0.630 6.300 63.000 0.006 0.063 0.630 6.300 63.000 0.006 0.063 0.630 6.300 63.000 Pore throat radius, μm Pore throat radius, μm Pore throat radius, μm 100 100 (d) (e) (f) Np 280, 3603.95 m Np 2-15, 3617 m Np 3-19, 4232.59 m 90 90 80 80 70 70 60 60 50 50 40 40 30 30 20 20 10 10 0 0 0.006 0.063 0.630 6.300 63.000 0.006 0.063 0.630 6.300 63.000 0.006 0.063 0.630 6.300 63.000 Pore throat radius, μm Pore throat radius, μm Pore throat radius, μm Fig. 6 Mercury saturation bar chart and permeability contribution value accumulation curve in Nanpu wells Bohai Bay Basin 1 3 Mercury saturation Mercury saturation frequency, % frequency, % Mercury saturation Mercury saturation frequency, % frequency, % Mercury saturation Mercury saturation frequency, % frequency, % 990 Petroleum Science (2019) 16:981–1000 (a) (b) (c) P.throat Pr.p Pr.P Q.O Pr.p D.p P.throat Fr.p Fr.p 100 µm 200 µm 200 µm Np 306x1, 4233.34 m Np 3-80, 4535.38 mNp 2-15,3617 m (a′) (b′) (c′) P.throat P.throat Pr.p Pr.p Pr.p P.throat (d) (e) (f) Pores Pores Pores Fig. 7 Representation of primary pores and secondary pores under a polarizing microscope, a laser scanning microscope, and SEM and BSEM photographs. a Primary intergranular pores, with pore throat and quartz overgrowth; b primary pores, dissolution pores and fractures pores; pore size is smaller than a; c primary pores, fractures and pore throat, size of pore is smaller than a and b; a′–c′ laser scanning confocal microscopic images of a, b and c; d BSEM image showing the larger pores; e BSEM image shows the primary and dissolution pores in feldspar; f SEM and BSEM combined image shows the smaller minerals/intercrystalline minor pores. Pr. p primary pores; Q. o quartz overgrowth; P. throat pore throat; Dp dissolution pores; Fr. p fracture pores comprised of macropores and mesopores. Most of the SEM images are shown in Figs. 7a, d; 8a, g. Their primary macropores (25%–30%) lie between 1 and 10  μm which drainage curves show good reservoir quality especially per- corresponds to intergranular and dissolution pores. Some meability as shown in Figs.  6a, b. Np306x1, 4223.35 m, samples show 20%–25% pore volume with pore throat sizes and Np280, 3503.95 m, have medium to coarse grain and between 0.1 and 1 μm which corresponds to intercrystalline are moderately sorted, and their primary drainage curve pores in clay and carbonate cement. Nearly all samples show indicates good reservoir characteristics (high permeability) a small fraction (20%) of mesopore volume with pore throat (Figs. 6c, d; 7b, e; 8b). Moderate reservoir consists of mod- sizes of < 0.1 μm which corresponds to intercrystalline pores erate to well-sorted grains of heterogeneous nature as shown in clay. Details of pore throat sizes of < 0.006 μm are not in thin section in Figs. 7b; 8b. On the other hand, samples available from MICP experiments. NP2-15, 3617 m, and Np3-19, 4232.59 m, are poorly sorted, Samples Np306x1, 4218.7 m, and Np3-80, 4534.7 m, compacted and mostly consisted of clay matrix and carbon- are consisting of coarse grains and medium to well-sorted ate cement with low porosity (Figs. 5c, d, f; 8f) that causes grains, and well-developed pores in thin-section as well as to clog the pores, due to that most of the pore throats lie 1 3 Petroleum Science (2019) 16:981–1000 991 (a) (b) (c) Fd Pr.P Pr.p Fd Pr.p Fr.p Fr.p Fr.P 200 µm 100 µm 200 µm Np 306x1, 4234.5 m Np 380, 4334.7 mNp 306x1, 4233.4 m (d) (e) (f) Pr.p P.throat Pr.p Pr.p P.throat Pore filled by Kaolinite 100 µm 50 µm 100 µm Np 2-15, 3717.3 m Np 306x1, 4234.6 mNp 380, 4334.7 m (g) (h) (i) Pores Pore Pore Fig. 8 Representation of primary pores, secondary pores, pore interconnectivity, under polarizing microscope and SEM. a Larger primary inter- granular pores, with dissolution pores and fractures pores with pore throat; b primary pores and fractures pores, pore size is smaller than a; c primary intergranular pores; d large primary intergranular pores with regular pore throat; f primary intergranular pores, pore filled by kaolinite clay and pore throat; g large pore under SEM; h intermediate pores under SEM; i smaller pores under SEM;. Pr. p primary pores; P. throat pore throat; Dp dissolution pores; Fr. p fracture pores between 0.1 μm to 1 μm in size (Fig. 11). It shows the lower within the range of 8.4 µm > D ≥ 0.45 µm, and micropores pore size spectrum than other samples. Due to poorly sorted are the pore throat with a diameter < 0.4 µm (Nabawy et al. and heterogeneous nature, the initial drainage curve moves 2009). In MICP analysis, macropores contribute 25.33%, up higher and indicates poor reservoir quality. The ejection mesopores 52.66% and micropores 23% on average of total curves show that mercury fails to recover from samples com- pore volume with variation in different wells. pletely down to 0.80–0.90 MPa mercury pressure. Mercury The specific surface area of the sample is measured by is still trapped in the pores from 22% to 78% as shown in Brunauer, Emmett and Teller (BET) including pore size Fig.  11. The main reason of mercury not recovered may distribution. It measures the surface area and open pores of be due to some chemical or capillary forces that hold mer- macroporous and mesoporous materials, as well as pore vol- cury in pores or due to the destruction of the pore network. ume and area distribution that characterize porosity below MICP is a useful method to evaluate pore size distribution. the effective range of mercury intrusion porosimetry. The Macropores are the parts of the pore throat with Mp thresh- pore throat structure parameters were gained by N adsorp- old > D ≥ 8.4 µm, mesopores are pore throats with a diameter tion analysis, i.e. average pore volume, pore volume and 1 3 992 Petroleum Science (2019) 16:981–1000 BET surface area (Table  3). The SBET (specific surface 4.5 Porosity and permeability area) of selected samples was calculated by BET equation (Brunauer et al. 1938). Pore voids play a significant role in enhancing the reservoir quality. The Es1 sandstone mostly consists of moderate to 1 c − 1  1 high porosity and permeability. On the basis of core obser- = + , (1) v c  v c m o m o vation and thin-section study, it has been revealed that Es1 ∕ − 1 sandstone containing primary intergranular pores along with secondary pores and occasionally microcrystalline pores is where ρ and ρ are the equilibrium and the saturation pres- also present. Some of them are generated genetically after sure of the adsorbates at the temperature of adsorption, deposition as a result of dissolution and fracturing. Second- respectively, υ is the adsorbed gas quantity and υm is the ary pores are produced by different fluids that affect the monolayer adsorbed gas quantity. C is the BET constant. unstable rock fragments and cement that entirely or par- E − E 1 L tially dissolve the grains and pore cement (Figs. 5e; 8a). c = exp , (2) RT Dissolution pores are mostly generated in unstable detrital grains due to their low resistance against the acidic fluid. where E is the heat of adsorption for the first layer and E 1 L Petrophysical Es1 sandstone has an excellent primary poros- is a second higher layer. ity ranging from 0.4% to 32% and permeability ranging from The SBET (specific surface area) values range from 0.005 to 6870 mD (Fig. 9). Secondary porosity caused by 5540.27 to 115.49 m /g. The specific pore volume is reso- dissolution and fracture also enhances the reservoir porosity lute by Barrette–Joyner–Halenda (BJH) theory (Barrett et al. up to 5%. Primary intergranular porosity accounts consist 1951), and it ranges from 2.0 to 0.073 cm /g. of the main reservoir space for 44% of the total reservoir space. Moreover, some feldspar/rock fragment dissolution 4.4.2 Pore connectivity pores (27%), cement dissolution pores (8%) and fractures pores (17%) and fracture–dissolution pores (6%) account Es1 sandstone consists of a different type of pores that are for 57% of the total reservoir space as shown in Fig. 10. mostly connected, which enhances the reservoir character- Similarly, some other microfractures have specific reservoir istics. The pore connectivity of Es1 sandstone in Nanpu Sag characteristics, but they play a most vital role in serving oil was characterized by using SEM and LSCM to qualitatively and gas seepage channels to enhance the permeability of establishing pore space and analysing pore throat distribu- the reservoir. tion and connectivity. Overall experimental results indicate Mineral dissolution occurred mainly during the uplift that pore throat of a reservoir has little isolation due to dif- period, and the initial reburial stage, the uplift and develop- ferent compositions with moderate to small in size, moderate ment of fractures promoted the penetration of freshwater throat and moderate to good connectivity (Figs. 7a, a′; b, b′; to these sandstones and also played an important role in c, c′; 8c, e, f, i). Calculated porosity from different samples enhancing the permeability of reservoir rock for fluid flow. ranges from 5.3% to 21.1% that is shown in Table 3. Table 3 Pore parameter from N adsorption measurement Sample no. Depth, m Lithology Porosity, % Permeability, mD SBET, m²/gVBJH, cm /g Average pore size, µm 1—Np3-80 4534.70 Conglomerate sandstone 13.6 149 403.94 1.54 15.492 2—Np306X1 4223.35 C sandstone 16.7 442 330.30 2.00 14.416 3—Np306X1 4220.76 C sandstone 15.9 340 346.04 1.94 12.170 4—Np280 3503.20 M sandstone 21.1 49.2 1504.41 2.00 4.575 5—Np280 3503.95 F sandstone 15.2 1.30 5240.19 1.36 0.467 6—Np3-19 4232.59 Siltstone 10.4 0.313 5540.27 1.42 0.073 7—Np2-15 3617.00 F sandstone 6.3 0.0908 4658.23 0.76 0.110 8—Np306X1 4234.20 M sandstone 7.2 0.701 2081.61 0.74 0.508 9—Np306X1 4218.70 M sandstone 5.3 124 115.49 0.60 6.591 SBET surface area using Brunauer–Emmett–Teller method (Brunauer et al. 1938), VBJH pore volume using Barrette–Joyner–Halenda (Barrett et al. 1951), C coarse, M medium, F fine 1 3 Petroleum Science (2019) 16:981–1000 993 Porosity, %Permeability, mD 05 10 15 20 25 30 35 40 0.01 0.11 10 100100010000 1000 1000 1500 1500 2000 2000 2500 2500 3000 3000 3500 3500 4000 4000 4500 4500 5000 5000 Fig. 9 Porosity and permeability distribution of different wells in Nanpu Sag Np 3-19, 4232.59 m Np 2-15, 3617 m 44% N=1242 Np 306x1, 4234.20 mNp 306x1,4220.76 m Np 306x1, 4223.35 m Np 306x1, 4218.7 m Np 3-80,4534.7 m 30 100 27% 17% 8% 4% Fracture Cement Primary Fracture Feldspar/ pores dissolve inter-granular dissolve R.fragment pores pores pores dissolution pores 0.1 Reservoir pore space type 0.01 Fig. 10 Development frequency of different reservoir spaces within 100 80 60 40 20 0 Shahejie Formation reservoir sandstone Mercury saturation, % Fig. 11 Mercury saturation versus capillary pressure diagram in Nanpu well. MICP injection–withdrawal capillary curves on selected samples 1 3 Development frequency, % Depth, m Depth, m Capilary pressure, MPa 994 Petroleum Science (2019) 16:981–1000 preserve relatively large pores at the high-stress area (Yang 5 Discussion and Aplin 2007), whereas smaller pores accompany fine- grained rocks. There is a positive and slight negative correla- 5.1 Relationship between sedimentary features tion between grain size and average pore diameter obtained and pore structures from the N adsorption experiment. Fractures influence some grains during various structure experiments. Pore con- The relationship between depositional fabric and reser- nectivity and throat size are higher due to fractures, whereas voir pore structures was evaluated by grain size analysis high surface area is obtained due to the clay matrix (Fig. 11). and sorting coefficient (So) and their correlation with pore structures. The reservoir permeability of Es1 sandstone is 5.2 Mineral composition association with a pore directly/positively related to grain size. This relation shows structure that the porosity is directly connected to rock fabric (grain size, grain shape and orientation). Generally, the compac- Thin-section studies and XRD data represent that carbon- tion effect is adverse on coarse-grained sandstone that may ates, clay minerals (kaolinite, illite–smectite, illite and chlo- lead to more efficient pore preservation and with increas - rite), detrital quartz and feldspar are the most common min- ing stress less effect on porosity reduction. In medium- to erals in the selected, studied samples (Figs. 5a, c, d, e; 8f). coarse-grained sandstone, it will result in the improvement The link between mineral types, their amount and pore struc- of the connectivity of pores/permeability as compared tures as well as the relationship between detrital minerals to fine-grained rocks (Fawad et al. 2010) and pore throat like quartz and feldspar, and other pore structure parameters size is also affected by grain size; the Es1 sandstone with are similar to carbonate minerals. That shows a link between medium-grained sandstone, coarse-grained sandstone and pore structure parameter and carbonate and clay mineral conglomerate sandstone has good pore and pore throat size. contents used to study the mineral/pore structure relation, Coarse-grained rocks are consisting of coarser particles/frag- respectively. There is no negative correlation between car- ments that provide a framework that is sufficiently strong to bonate minerals and clay minerals with permeability that 60 60 60 (a) (b) Clay minerals Quartz 60 Carbonate minerals Feldspar 40 40 40 20 20 20 0 0 0 0.11 10 100 10000 0.11 10 10010000 Permeability, mD Permeability, mD 60 60 60 60 (c) (d) Clay minerals Quartz Carbonate minerals Feldspar 40 40 20 20 0 0 04 8121620 04 8121620 2 2 BET surface area, m /g BET surface area, m /g Fig. 12 Relation between mineral contents and pore structure parameter in Es1 sandstone 1 3 Carbonate minerals, % Carbonate minerals, % Clay minerals, % Clay minerals, % Feldspar, % Feldspar, % Quartz, % Quartz, % Petroleum Science (2019) 16:981–1000 995 is shown in Fig. 12a; rather, carbonate mineral has a very of macroporous and mesoporous material, as well as pore unpredictable effect on permeability; therefore, there is no volume and area distribution that characterize porosity clear correlation, particularly for Fig. 12a. Carbonate min- below the effective range of mercury intrusion. The SBET eral has a very subtle correlation with permeability. It is (specific surface area) of selected samples was calculated neither a positive nor a negative correlation. Carbonate min- by the BET equation, and its values range from 5540.27 to erals have a patchy effect on permeability as data are very 115.49 m /g. The specific pore volume values range from scattered. Generally, it should have a negative effect, but the 2.0 to 0.073 cm /g. Clay contents are present in the studied studied selected sample data do not represent it. Clay min- sandstone as muddy interlayers and also present in siltstone eral has a negative correlation in Fig. 12a with permeability. and mudstone. Higher content of clay/mud increased the Scattering is due to random sampling. Similarly, Fig. 12c measured SBET and total pore volume due to high clay spe- shows the meagre positive correlation between carbonate cific surface area. Micropores developed due to clogging of and clay minerals with BET surface area. It shows a very clay minerals segmenting of primary intergranular pores into poor correlation between the carbonate and BET, either it micropores. Siltstone and fine-grained sandstone association is positive or negative, whereas clay minerals have a subtle with SBET and total pore volume suggest that carbonate positive correlation. minerals like quartz and feldspar are not a major contributor Clastic minerals like quartz and feldspar have a positive to total surface area and micropore volume (Figs. 7d, e, f; effect on reservoir properties as shown in Fig.  12b. Micro- 8g, h, i). In the studied area, carbonate mineral may provide scopic pore images and SEM studies of the pore are related relatively less total pore volume and specific surface area. to carbonate and clay minerals that show variability. After burial various diagenetic processes started on deposited 5.3 The relation between routine core analysis sediments and due to compaction phenomenon, quartz, and pore characteristics feldspar and carbonate minerals play a significant role in preserving the primary pores due to rigid framework and Mercury injection capillary pressure (MICP) test was con- pressure shadow of rigid grain protect primary pores to ducted for routine core analysis in an experiment to relate collapse, whereas the presence of carbonate cement blocks the much costly mercury achieved as a result to routine less the pore voids and blocks the pore throat. Intergranular and expensive, common and valid tests. MICP is a valuable tech- intragranular pores are associated with clay minerals that nique to evaluate the pore throat size distribution as well block the large pores between the grains and applying the as reservoir quality and diagenesis impact (Tavakoli et al. negative effect on reservoir characteristics. However, there 2011). The calculated mean helium porosity (øHe%) of Es1 will be a positive relation between BET surface area and sandstone shows very good porosities (9.3%–27.1%) that clay minerals, whereas quartz, feldspar, carbonate minerals are mentioned in Table 4, and the measured helium (øHe%) and BET surface area show a variable association (Fig. 12c, porosity usually is higher than mercury porosity (øHg%). d). The specific surface area of the sample is measured by Both types of porosities are higher in Es1 sandstone, vary- Brunauer, Emmett and Teller (BET) including pore size ing from base to middle and then top depending on carbon- distribution. It measures the surface area and open pores ate cement and clay contents. The bulk permeability was Table 4 Storage capacity properties of the Es1 sandstone of Shahejie Formation obtained from the routine core analysis and permeability values calculated from the mercury injection test Sample no. Depth, m øHe, % r25, µm Kr25, µm R35, µm Kr35, mD r10, µm Kr10, mD Kb, mD Np3-80 4534.70 16.5 1.02 16.7 3.4 16.4 7.3 123.6 249 Np306X1 4223.35 20.7 6.7 240 9.1 121.2 12.2 376.4 647 Np306X1 4220.76 21.9 7.3 365 10.5 116.5 10.6 330.5 840 Np280 3503.20 27.1 9.4 256 6.4 2.4 8.7 46.7 149.2 Np280 3503.95 20.2 12.2 216 2.1 0.004 0.07 1.5 10.30 Np3-19 4232.59 16.4 7.6 180 5.4 0.0034 0.05 1 6.313 Np2-15 3617.00 10.3 5.8 245 1.003 0.005 0.004 0.98 6.0908 Np306X1 4234.20 12.2 5.1 175 1.5 0.023 0.032 0.76 5.701 Np306X1 4218.70 9.3 6.2 256 8.5 15.7 7.4 132 324 øHe mean porosity measured by helium injection, r25 pore throat size corresponding to the 25th percentile, R35 pore throat size corresponding to the 35th percentile, Kr25 calculated permeability at r25, Kr35 calculated permeability at R35, r10 pore throat size corresponding to the 10th percentile of measured mercury porosity, Kr10 calculated permeability at r10 using mercury porosity, kb average uncorrected measured air per- meability 1 3 996 Petroleum Science (2019) 16:981–1000 measured by air injection. Its values range from 5.70 mD to 840 mD. The uncorrected air permeability was calculated on the basis of the equation of Winland (Kolodzie 1980) and Pittman (1992), where the usage of corrected permeability values, which may be trivial, would produce a deceptively small pore aperture size calculation (Pittman 2001). The incorporation of porosity and permeability data in Megapores terms of reservoir quality index (RQI) data is suitable for use Meso & Macro pores with the routine core analysis data that provide an excellent Micropores improvement in addressing the reservoir quality in different 05 10 15 20 30 scales (Lai et al. 2016; Tavakoli et al. 2011). It is the best Porosity (Ø ) fraction Hg macrophysical factor for an assessable description of reservoir microscopic pore structure. Higher reservoir quality index Fig. 13 Measured mercury porosity volume (%) versus permeability (RQI) values indicate better microscopic pore structures (Lai (k) differentiated into megapore, macropore and micropore throat size et al. 2016). The concept of Amaefule et al. (1993) technique is based on the calculation of RQI, demarcated as follows: effective pore throats, which constitutes the most operative and permeable pore spaces, thus reducing the net perme- RQI = , (3) ability values (Fig. 13). Fine-grained sandstone, siltstone and mudstone consist of sub-capillary pores. The number where RQI is the reservoir quality index, μm; k is the perme- of pores is high, but their connectivity is low due to their ability, mD; and  is the porosity in terms of total volume smaller size volume concerning coarse-grained sandstone. fraction, %. So the permeability of such rocks or part of the rock that Reservoir quality index (RQI) provides an appropriate consists of siltstone, mud presence and carbonate cement starting point to address the differences between core plug has low reservoir characteristics. samples and reservoir zones (Lai et al. 2016). RQI can be used to calculate the flow characteristics of reservoirs and 5.4 Relationship between pore structure parameter provide a functional association between microscopic fea- and physical property tures and macroscopic logs (Lai et  al. 2016). Reservoir heterogeneity concerning the variants in microscopic pore The maximum and average pore throat radii are correlated structure and reservoir macroscopic permeability of the core to some extent with porosity and permeability. The better plug samples can be evaluated by RQI (Lai et al. 2016). The correlation for permeability as compared to porosity plots RQI and permeability values increase as the proportion of relating to pore structure parameters and physical proper- large pores and small pores increases. There is a significant ties is shown in Fig. 14a–d. The average pore throat radius variation in the pores, and the pore structures are complicated signifies the better correlation with physical properties. due to firm heterogeneity (Zhang et al. 2007). Pores and pore It shows that the average pore throat radius distribution throats are affected by sediments, diagenetic interaction and exemplifies the quality of the deeply buried sandstone cementation. RQI is a good representative of porosity and reservoirs. permeability reservoir quality indices, but this index is not The pore throat distribution is directly reflected by the suitable for the size distribution of pore throats (Tavakoli sorting coefficient of the throat (Sc), where smaller Sc is et al. 2011). This type of distribution could disclose the effect indicating the better sorted pore throat. The sorting coeffi - of diagenetic events on these two significant factors. cient shows a positive correlation with porosity and perme- The measured permeability was plotted contrary to the ability as shown in Fig. 14e, f. The studied rock caused this mercury porosity differentiated into supercapillary pores/ positive correlation due to medium to coarse pores and pore megapores, capillary pores/mesopores and macropores and throats; in addition, coarse pore throat, consisting of some sub-capillary pores/micropores (Fig. 6). The supercapillary microfractures, appears in samples with less sorted pores, pores (megapores) establish an insignificant part of the total so the coarser pore throat contributes much more to perme- pore volume and characterize a surface effect that may be ability. This complies with the pore structure characteristics mixed with the conformance volume. That is why, these discussed above, indicating that samples with large sorting should be detached from additional deliberation, i.e. perme- coefficient have coarse pore throats that provide much more ability is mostly contributed by the pores in the mesopores to permeability, whereas samples with smaller sorting coef- and macropores/capillary pores. An increase in the volume ficient have a large amount of more sorted small pores that percentile increment of the sub-capillary micropore frac- account for a large porosity. tion escorts a decrease in the macropore and mesopore 1 3 Permeability, k Petroleum Science (2019) 16:981–1000 997 (a) (b) y=1.1631x+0.1463 0.0075x y=2.8917e R =0.2011 R=0.5951 10 10 5 5 0 0 -5 -5 -10 -10 05 10 15 20 25 0.11 10 1001000 Porosity, % Permeability, mD 20 20.0 (c) (d) 17.5 15.0 0.2009x y=0.1548e 12.5 y=-0.0336x+2.4415 R=0.2716 R =0.673 10.0 7.5 5.0 2.5 -2 05 10 15 20 25 0.11 10 1001000 Porosity, %Permeability, mD 5.5 5.5 (e) (f) 5.0 5.0 4.5 4.5 y=0.0511x+4.2044 y=-0.0047x+4.1247 4.0 2 4.0 R =0.0666 R =4547 3.5 3.5 3.0 3.0 2.5 2.5 2.0 2.0 1.5 1.5 05 10 15 20 25 0.11 10 1001000 Porosity, % Permeability, mD Fig. 14 Relationship between high-pressure mercury intrusion parameter and porosity and permeability clays minerals, mica minerals and carbonate minerals, and 6 Conclusion the rock is classified as feldspathic litharenite and lithic arkose. The Es1 sandstone of Shahejie Formation is mainly lacus- Several types of pores are evaluated including primary trine sandstone with interbedded mudstone. The Es1 sand- intergranular pores, intragranular pores, dissolution pores, stone mostly consists of quartz, feldspar, rock fragments, 1 3 Sorting coefficient Average pore throat radius, μm Max pore throat radius, μm Average pore throat radius, μm Sorting coefficient Max pore throat radius, μm 998 Petroleum Science (2019) 16:981–1000 fractures pores, and it consists of several matrix pores and References mineral pores including intergranular and intragranular Allen MB, Macdonald DIM, Xun Z, Vincent SJ, Brouet-Menzies C. pores. Pore throat system is characterized by MICP and Early Cenozoic two-phase extension and late Cenozoic thermal LSCM, and a pore radius of the studied sandstone is in subsidence and inversion of the Bohai Basin, northern China. 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Variation in micropores capacity and size Acknowledgements I would like to thank China University of Petro- distribution with composition in bituminous coal of the western leum and China Scholarship Council (CSC) for granting a full schol- Canadian sedimentary basin; implications for coalbed methane arship (2015–2018) to carry out the research. This study was funded potential. Fuel. 1996;75(13):1483–98. by the Natural Science Foundation of China Project (No. 41602138), Clarkson CR, Solano N, Bustin A, Chalmers G, He L, Melnichenko National Science and Technology Special Grant (No. 2016ZX05006- YB, et al. Pore structure characterization of North American shale 007), China Postdoctoral Science Foundation-funded Project gas reservoir using USANS/SANS, gas adsorption, and mercury (2015M580617; 2017T100524) and the Fundamental Research Funds intrusion. Fuel. 2013;103:606–16. for the Central Universities (15CX08001A). We would also like to Cook JE, Goodwin LB, Boutt DF. 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Pore size distribution, their geometry and connectivity in deeply buried Paleogene Es1 sandstone reservoir, Nanpu Sag, East China

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Springer Journals
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Copyright © 2019 by The Author(s)
Subject
Earth Sciences; Mineral Resources; Industrial Chemistry/Chemical Engineering; Industrial and Production Engineering; Energy Policy, Economics and Management
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1672-5107
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1995-8226
DOI
10.1007/s12182-019-00375-3
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Abstract

The study of pore characteristics is of great importance in reservoir evaluation, especially in deeply buried sandstone. It con- trols the storage mechanism and reservoir fluid properties of the permeable horizons. The first member of Eocene Shahejie Formation (Es1) sandstone is classified as feldspathic litharenite and lithic arkose. The present research investigates the pore characteristics and reservoir features of the deeply buried sandstone reservoir of Es1 member of Shahejie Formation. The techniques including thin-section petrography, mercury injection capillary pressure (MICP), scanning electron microscopy and laser scanning confocal microscope images were used to demarcate the pores including primary intergranular pores and secondary intergranular, intragranular, dissolution and fracture pores. Mercury injection test and routine core analysis were led to demarcate the pore network characteristics of the studied reservoir. Pore size and pore throat size distribution are acquired from mercury injection test. Porosity values range from 0.5% to 30%, and permeability ranges 0.006–7000 mD. Pore radii of coarse-grained sandstone and fine-grained sandstone range from 0.2 to > 4 µm and 1 nm to 1.60 µm, respectively, by MICP analysis. The mineral composition also plays an important role in protecting the pores with pressure from failure. Fractured sandstone and coarse-grained sandstone consist of large and interconnected pores that enhance the reservoir poros- ity and permeability, whereas fine-grained sandstone and siltstone consist of numerous pores but not well interconnected, and so they consist of high porosity with low permeability. Keywords Reservoir rock · Pore characteristics · Pore size distribution · Pore throat · Porosity · Permeability 1 Introduction injection test (Nabawy et al. 2009). Deeply buried sandstone is acting as a good reservoir that is controlled by pore size, The movement of different reservoir fluids via different geo- pore structure and pore size distribution. Sandstone proper- logical systems is mainly controlled by capillary pressure ties (porosity and permeability) are mainly controlled by within the rock unit. The pore volume and pore throat size grain size, grain sorting, shape, mineralogy and sedimentary that relate to displacement pressure are the main components structures as well as their environment of deposition (Saiag that control the reservoir characteristics (mainly permeabil- et al. 2016). Several diagenetic processes (physical, chemical ity) of reservoir rock, and they can be evaluated by mercury and biological) are affecting sediments during lithification, vary with the chemistry of fluid, temperature and pressure and correlate with the burial history of the sedimentary Edited by Hao Jie and Xiu-Qiu Peng basin (Loucks et al. 1984; Bjørlykke 2014). The intercon- nectivity and geometry of the pore system are greatly influ- * Muhammad Kashif enced by the diagenetic overprints (Lai et al. 2018a, b, c; kashifyaqub@yahoo.com Hollis et al. 2010). The intricate diagenetic alteration of the School of Geosciences, China University of Petroleum, sandstone experienced throughout the geological history will Qingdao 266580, China alter the original pore system and exert low control on res- Department of Earth Sciences, University of Sargodha, ervoir quality evolution (Lai et al. 2018a, b, c). Diagenetic Sargodha 40100, Pakistan modification changes the distribution and quantity of pore Institute of Geology, University of the Punjab, Lahore, space, generating smaller and disconnected pore (Lai et al. Pakistan Vol.:(0123456789) 1 3 982 Petroleum Science (2019) 16:981–1000 2018a, b, c; Cook et al. 2011). Different types and various The Es1 sandstone consists of intricate and heterogeneous degrees of diagenesis reshape the pore structures (Lai et al. composition, in which parts comprising pore throat in these 2018a, b, c, 2015). heterogeneous sandstones remain poorly understood and Mechanical compaction, cementation and the authigenic cannot easily be charged by oil and gas (Tian et al. 2015; Xi clay content are the main pore volume-controlling factors; et al. 2016). The studied sandstone consists of interbedded however, fracturing, cement dissolution and framework grain mudstone, and these muddy layers, cement and the muddy are the most significant porosity-improving factors (Lai et al. matrix may have a negative impact on permeability. Mineral 2018a, b, c, 2018b; Nabawy et al. 2009). Well-connected composition, particle size and diagenesis are very significant intergranular pores have large pore throats that contribute controlling factors for the pore throat distribution within the to permeability, whereas the subsequent dissolution pores reservoir sandstone and mainly controlled by hydrodynamic and micropores are only connected by small pore throats condition during sedimentation and diagenesis. Deformed or that contribute less to permeability (Lai et al. 2018a, b, c). ductile mica grains, calcite cement and clay minerals create Primary porosity will be significantly reduced by mechani- a problematic situation to block the pores and narrow the cal and chemical compaction by authigenic minerals (Moz- pore throat that causes to reduce the reservoir quality. ley et al. 2016). Cementation reduced the permeability by High-pressure mercury injection capillary pressure, occluding the pores and pore throats (Lai et al. 2018a, b, c; low-pressure adsorption of N and CO , porosity and per- 2 2 Taghavi et al. 2006). Mercury injection capillary pressure meability data have been used to obtained the quantitative (MICP) analysis was used to characterize the pore struc- pore size, pore volume, pore size distribution, surface area, tures and pore size distribution. Micropores from the matrix porosity and permeability (Howard 1991; Ross and Bus- and authigenic minerals occupy a significant proportion of tin 2009; Chalmers et al. 2012; Schmitt et al. 2013a, b). the total porosity; in addition to the pore size, the perme- Scanning electron microscopy (SEM) photomicrographs ability of reservoir sandstone is much affected by the pore are used to perceive the pore size, morphology and type of throat connectivity, i.e. the pore throat radius, geometry and pores from the nanoscale to the micron scale; quantitative structure (Zou et al. 2012). Quartz overgrowth mostly fills parameters are difficult to obtain. MICP is useful for charac- the primary intergranular pores, reducing it to narrow, flat, terizing micro- to macroporosity (r > 50 nm), low-pressure sheet-like or slot-like pores between adjoining overgrowths N adsorption is used for nanoporosity (d between 2 and face (Lai et al. 2018a, b, c; Soeder and Chowdiah 1990). 50 nm), and CO adsorption for pore is having the smallest The microscopic structure of pore throats is characterized size (d < 2 nm) (Chalmers et al. 2009; Clarkson et al. 2013). by a tortuous pore system, small pore radius, poor connec- High-pressure mercury injection may give rise to the pro- tivity and firm heterogeneity (Zou et al. 2012). Authigenic spective risk of particle degradation, rock compressing and clay minerals play a significant role in decreasing the pore destruction of the pore network (Clarkson and Bustin 1996). volume and concluding the pore apertures (Lai et al. 2018a, The main objectives of this study are to: (1) evaluate the b, c; Yue et al. 2018). Because of their hair-like and hon- pore structure characterization with advance integrated tech- eycomb-like morphology, crystal habit and fibrous nature, niques of the Es1 sandstone of Shahejie Formation of Nanpu they significantly affect the hydraulic and petrophysical Sag; (2) propose the keen understanding of the contribution properties of sandstone, thereby shaping the pore geometry of different pore structures to evaluate the reservoir quality. (Lai et al. 2018a, b, c; Samakinde et al. 2016). Moreover, To achieve these goals, the detailed core observation, thin- pore-bridging or pore-lining clays may decrease the perme- section study of core samples, SEM analysis, laser scan- ability considerably by affecting the pore, pore throat radius ning confocal microscope (LSCM) analysis and MICP were and surface area, and reducing the size of the intergranular used to evaluate the characterization of pore size, pore throat pores and turning them into micropores (Lai et al. 2018a, characteristics and pore distribution. b, c; Schmitt et al. 2013a, b, 2015). Dissolution of detrital grains and cement is the primary process which enhances the porosity and permeability by increasing pores and pore 2 Geological setting throats (Lai et al. 2018a, b, c; Mozley et al. 2016). The Es1 sandstone is classified as feldspathic litharenite, The Bohai Bay Basin is a giant basin and situated in east and lithic arkose of braided river, fluvial channels, distribu- part of China, straddling over the North China Plain, Bohai tary channel and lacustrine delta front facies. Core samples Sea and lower Liaohe Plain, covering an area of about 4 2 of seven exploratory wells are selected to study the petro- 20 × 10  km . Bohai Bay Basin is a complex, petroliferous graphic analysis and sedimentological characteristics of Es1 basin combined by Mesozoic and Cenozoic rifts (Allen sandstone. The present study focuses on pore size, struc- et al. 1997; Ren et al. 2002), with Shahejie Formation and ture and pore throat size characterization of deeply buried Dongying Formation as source rocks (Hao et al. 2011). The high-quality reservoir rock by advanced analytical methods. Nanpu Sag is a sub-unit of Bohai Bay Basin, and it is a 1 3 Bogezhuang Fault Matouying Bulge Np# 4 Fault Structural belt #4 Bogezhuang Bulge Shichang sub-sag Gaoliu Fault Petroleum Science (2019) 16:981–1000 983 small dustpan-shaped faulted sag that is situated in Bohai Xinanzhuang–Baigezhuang (acting as boundary fault) fault Bay Basin towards the north-eastern part of transition to north-east. It further consists of six sub-basins including belt between Huanghua depression, Bozhong depression Jizhong, Huanghua, Jiyang, Liaohe–Liaodong, Bozhong and and Liaodong depression (Xu et al. 2008a, b; Chen et al. Lingqing–Dongpu depression (Gong 1997). 2016; 2018). This sag covers more than 1900 km area, and Drilling data for hydrocarbon exploration are a funda- more than half of the area lies under the Bohai Bay Basin. mental tool to evaluate the stratigraphy of the Nanpu Sag Structurally this sag is acting as a half-graben (Wang et al. rock units. Nanpu Sag consists of thick sediment sequence 2002). Geologically Nanpu Sag is confined towards the of Cenozoic strata about 5000–9000 m (Guo et al. 2016), north by Yanshan Mountain, Shaleitian fault to the south, which consists of the Eocene Shahejie Formation, the Oli- Baigezhuang fault to the north-east, Matouying bulge to the gocene Dongying Formation, the Miocene Minghuazhen west and Xinanzhuang fault to the north-west as shown in Formation, Guantao Formation and Quaternary Pingyuan Fig. 1. Tectonically the Nanpu Sag consists of eight north- Formation (Jiang et al. 2009; Guo et al. 2016) as mentioned east trending structures, including Nanpu 1, Nanpu 2, Nanpu in Fig. 2. The studied Shahejie Formation divided into three 3, Nanpu 4 and Nanpu 5 offshore structures, and Laoyemiao, main members from top to bottom as Es1, Es2 and Es3, Gaoshangpu and Liuzan onshore structures (Wang et al. respectively. The studied Es1 sandstone characterized by 2002) that are shown in Fig. 1. The Nanpu Sag is famous conglomerate sandstone, coarse-grained sandstone, fine- for exploration potential of oil and gas from deeply bur- grained sandstone, with interbedded siltstone, and mudstone ied rock (especially Shahejie Formation > 3500 m). Geo- of a shallow lake, semi-deep lake, meandering river delta graphically Shaleitian fault bounded towards the south and plain and delta plain facies that are shown in Fig. 3. The Es1 Nanpu Sag China Gaoshangpu Laoyemiao Beipu Gaoliu Structural belt Structural belt Beipu Structural belt Linque Getuo Lp1 Nanpu Np2-15 Caofeidian Sub-Sag Pg2 Np306x1 Np288 Np3-19 Np2-60 Np3-80 Legend Shaleitian Fault 10 km FaultWellTown Fig. 1 Location map of the structural belt, associated bulges and structural division of Nanpu Sag, Bohai Bay Basin, China Modified after Chen et al. (2017) 1 3 Xinanzhuang Fault NP# 3 Fault Shaibai Fault Structural belt # 5 Nanpu #1 Fault Laowangzhuang Bulge Structural belt #1 Linque-Liunan sub-sag Xinanzhuang Bulge Structural belt#2 Nanpu # Fault Structural belt #3 984 Petroleum Science (2019) 16:981–1000 Strata Age, Thickness, Sedimentary Tectonic Lithology Form- Sub- Ma m Environment evolution Member ation member Pingyuan 250-310 Flood plain Quaternary (Q) Minghuazhen Meandering 1100-1300 (Nm) stream 5.32 Guantao Braided 300-500 (Ng) stream 23.8 Dongying Deltaic 0-300 (Ed) lacustrine 28.5 Deltaic fan, Es1 200-800 Lacustrine 31.0 Deltaic Fan, Es 2 50-150 Alluvial fan 33.7 Deltaic fan, 150-450 Es3 Lacustrine 38.5 Deltaic fan, 100-300 Es Lacustrine 41.0 Es3 Deltaic fan, 300-600 Es3 Lacustrine 42.0 Es Lacustrine 3 150-300 42.5 Deltaic fan, 150-350 Es3 Lacustrine 45.5 Es Mostly absent in Nanpu Sag Nanpu sag Conglomerate Sandstone Siltstone Mudstone Fig. 2 Generalized Cenozoic–Quaternary stratigraphy of the Nanpu Sag showing the tectonic and sedimentary evolution stages and significant petroleum system elements. Modified after Guo et al. (2013) and Yuan et al. (2015) member is described as shallow lacustrine lithofacies (Dong with mudstone, grey and dark grey sandstone underlain by et al. 2010), and Es2 member consists of mudstone interbed- brownish mudstone interbedded with grey sand and con- ded sandstone and characterized as alluvial sediment (Guo glomerates and characterized as Lacustrine fan delta (Wang et al. 2016). Es3 member consists of brown mudstone with et al. 2002; Guo et al. 2016). The Dongying Formation is a interbedded conglomerate sandstone, mudstone interbedded set of lacustrine deposit, Guantao Formation is characterized with siltstone and sandstone, grey oily shale interbedded as a braided fluvial system, and Minghuazhen Formation 1 3 Paleogene Neogene System Series Paleocene Eocene Oligocene Miocene Pliocene Kongdian Shahejie (Ek) (Es) Source rocks Reservoir rocks Seal Stage I Stage II Stage III Postrift stage Synrift stage Petroleum Science (2019) 16:981–1000 985 LpN1 Np206Np2-29Np2-15Lp1 SP GR SP GR SP GR SP GR SP GR 2200 2500 2300 2600 2600 2600 2700 3200 3200 3100 3300 3200 3400 Meandering Seemi deep Delta plain 3500 river delta front lake WS-NE Shore shallow Turbidite Igneous rock lake Fig. 3 Well connecting line across Np206, Lp1, Np2-15, LpN1 and Np2-29 of the various environments in Nanpu area is a set of low-sinuosity fluvial system (Wang et al. 2002). experienced multistage structural crusade that gave rise to Nowadays the overall burial depth of Shahejie Formation in intricate structures that dip north and derive from west to Nanpu Sag area is more than 4000 m below sea level. The east. The latter established a NW tendency and a sinistral present-day geothermal gradient is 32 °C/km (58 °F), the shear fault, called the Shicun fault, in the south of Caoqiao average surface temperature is 14 °C (57 °F) and, the maxi- area. The Shicun fault is a boundary fault of Guangrao sali- mum temperature is 135 °C (275 °F) at greater than 4000 m ent crossing Lijin Sag, Boxing Sag and Niuzhuang Sag. The depth. The sub-surface temperature of Ed3 and Es1 is almost stratigraphy is consisting of the Paleogene sequence into five 140 °C and 170 °C, respectively, and near to 200 °C for formations, i.e. Kongdian Formation (EK), Shahejie For- Es . The vitrinite reflectance of the shallow Ed3 is 0.8% mation (ES), Dongying Formation (Ed), Guantao Forma- R , and for Es , it could be greater than 2% R (Guo et al. tion (Ng) and Minghuazhen Formation (Nm). The Shahejie o 3 o 2013). The Ed3 source rocks are mature to generate oil. The Formation (Es) consists of source and reservoir members. 3 1 Es1 source rock reached hydrocarbon generation initiation The main source rock members are Es and Es (Zhu and 3 4 at about 23 Ma, being up to high maturity to produce wet Jin 2003). Within the Dongying Sag, the maximum burial gas at that stage. depth of Shahejie Formation is 5000 m (Guo et al. 2012; Dongying Sag is also a small secondary fault–sag depres- Song et al. 2009). The present-day geothermal gradient is sion and situated at the south-eastern side of Bohai Bay 34 °C/km, and the maximum temperature is 180 °C at this Basin. It is a dustpan-like structure with overlapping in the depth (Wang 2010). Total organic carbon content within the south and faults in the north, and it consists of an area of source rocks is 0.5%–18.6% with type I and type II kerogen 5800 km . Tectonically it is a half-graben with gentle south- (Guo et al. 2010). The R % (vitrinite reflectance) varies from ern slope and faulted northern margin. Laterally this sag is 0.35% to 1.5% from 2000 to 5000 m, representing source further subdivided into several secondary structural units, rock is slight mature to mature (Guo et al. 2012). such as the northern steep slope zone, middle uplift belt, the Lijin, Minfeng, Niuzhuang trough zone, Boxing sub-sag and southern gentle zone (Zhang et al. 2014). The significant 3 Materials and methods hydrocarbons generated source rock in Dongying Sag are 3 1 Es (dark shale with 100–400 m) and Es (dark shale with A comprehensive study was a prerequisite including petro- 3 4 mudstone 100–300 m) sub-members of Paleogene Shahejie graphic thin-section observation and petrophysical analy- Formation. These two members are the main aims of shale ses of core cutting samples. Wireline log data, thin-section oil exploration in the Bohai Bay Basin. The sedimentary petrography, SEM analysis, LSCM analysis and MICP anal- succession and regional history of the sag are divided into ysis are the primary methods that are used to evaluate the syn-rift and post-rift stages (Xie et al. 2006). The Es (humid pore characteristics of Es1 sandstone. Core samples are col- lacustrine environment) and Es (saline environment) were lected from seven wells; among them, 120 core plugs were deposited during the syn-rift stage. Dongying Sag area selected for thin sections at a depth interval of 2490–4500 m. 1 3 986 Petroleum Science (2019) 16:981–1000 On the basis of core observation, samples were collected and 4 Results analysed to investigate pore characteristics from core inter- vals. In total, 140 reservoir porosity and permeability data 4.1 Microscopic studies points and well logging data were obtained from Shengli Oilfield Company, China. Petrographic thin sections were The studied Es1 member of Shahejie Formation mostly con- detailedly studied with the help of an optical polarizing sists of fine-grained, coarse-grained and conglomerate sand- microscope to compute and interpret grain size, their type, stone with interbedded mudstone. Thin-section petrographic fabric, compaction, cement type, sedimentary features and study indicates that Es1 member is primarily comprising pore size distribution. Thin sections were partially stained of the detrital component and mainly composed of quartz by Alizarin red S and K-ferricyanide to identify carbonate (10%–70% bulk volume), feldspar, micas and different rock minerals using Dickson’s technique (1966). Thin sections fragments with a mixed fraction. The petrographic thin- are studied under Zeiss Axioscope POL digital transmis- section study indicates that the studied sandstones are clas- sion microscope for rock mineralogy, pore characteristics sified as lithic arkose and feldspathic litharenite as shown and diagenesis. COXEM EM-30 scanning electron micro- in Fig. 4. Mudstone occurs in subordinate forms and clay- scope (SEM) equipped with an energy-dispersive X-ray associated minerals and carbonate minerals are abundant spectrometer (EDX) was used to interpret the clay miner- in fine-grained sandstone, siltstone and mudstone. Sand- als, cement types, various pore spaces and their impact on stone comprises conglomerate sandstone, coarse-grained petrophysical properties, diagenetic features and other mate- sandstone, medium-grained sandstone and fine-grained rial that affect the whole pore network of the reservoir. The sandstone. Sandstone detrital grains are poorly sorted to SEM equipped with a secondary electron, energy-dispersive sorted and angular to sub-angular and sub-rounded grains. X-ray detector and backscatter electron was used to image Moreover, grains shows concavo-convex to line contact and the pore system and compositional variation. For this pur- represents the intensity of the compaction. Feldspar present pose, twenty-four core samples were prudently chosen for in the form of K-feldspar and albite (Na-feldspar) and ranges SEM analysis. MICP measured pore throat size distribution; from 12% to 65% with an average of 38.5%. Albite shows for this purpose, 22 samples were selected to analyse the little variation concerning a depth that K-feldspar disappears mercury injection experiments using a micrometric Auto- with concerning extent. pores apparatus; porosity was assessed by mercury injection Beside quartz and feldspar, the sandstone consists of rock that was used for special core analysis, and inoculation of fragments and mica that has been identified by thin-section helium at 120 kPa pressure by helium pycnometer is used studies. Rock fragments are present 8%–65% with an aver- for routine core analysis. These types of injection test were age of 38.4%. Chert is also observed in the thin section from conducted using a mercury porosimeter. Their diameter 0.5% to 8% with an average of 3.7% and appears as pure measures the number of pores as megapores/supercapillary quartz due to their constant lucidity under a plane polar- (D ≥ 60 µm), macropores/capillary pores (60 µm > D ≥ 8 µm; izing microscope. The bulk XRD data show that samples and mesopores, 8  µm > D ≥ 0.4  µm) and sub-capillar y/ contain quartz, k-feldspar, albite, calcite and dolomite and micropores (D < 0.4 µm) (Nabawy et al. 2009). pyrite existing in a small amount as well as clay minerals Twenty samples were selected for a laser scanning confo- as a whole. Based on XRD data, the kaolinite and mixed- cal microscope (LSCM) to evaluate the pore, pore size and layer illite/smectite are common in the studied sandstone fol- their connectivity. The operating conditions were done in a lowed by illite. Rendering to pore type and pore percentage, Zeiss microscope equipped with AxioCam 506 colour (LSM the studied sandstone samples consist of homogeneous and 700), was maintained at 10 kV beam energy and 250 µA heterogeneous pores. Among them, homogeneous pores are beam current. characterized mainly by vuggy and intergranular macropores All these samples except MICP were prepared, analysed and mesopores. The homogeneous pores are described by and interpreted at different laboratories of the School of pore types, mineralogical texture and distribution, whereas Geosciences, China University of Petroleum, Huangdao heterogeneous pores are distinguished mainly intergranular (Qingdao), whereas MICP was done at Analytical Labo- mesopores, dissolution pores and micropores (matrix). The ratory of the CNN Beijing Research Institute of Uranium heterogeneity in mineralogical texture is due to the presence Geology. of carbonate cement, iron oxide and other constituent, so some of the studied samples are described by heterogeneity in pore size distribution. 1 3 Petroleum Science (2019) 16:981–1000 987 Quartz, % Quartz arenite 10 90 Subfeldsarenite Sublitharenite Np 306x1 30 70 Np 3-19 40 Np 288 Lp1 50 50 Np 280 Np 2-15 60 40 90 10 Feldspathic Arkose Litharenit Lithic arkose litharenite Feldspar, % Rock fragments,% 10 20 30 40 50 60 70 80 90 Fig. 4 Rock composition of Es1 sandstone (ternary plot refer to the sandstone classification standard of Folk 1974) lower pore connectivity have poor reservoir characteristics. 4.2 Capillary pressure test Well 3–80 (coarse-grained sandstone, 4534.7 m) and well Np306x1 (conglomerate sandstone, 4218.7 m) have pore Mercury injection capillary pressure was performed on throat radius of 0.006 to > 63 µm, and they consist of mega- deeply buried high-quality porous and permeable sandstone. pores, macropores, mesopores and micropores. The sample An advanced increment of the applied pressure was escorted comprises of bigger pore throat radius and well connectiv- by an advanced superior increase in the mercury incursion ity of the pores, so the permeability curve shows the high inside the pore. It is concluded that if the pore throats are permeability of these well samples as shown in Fig. 6a, b. smaller, then higher pressure is required to flow. The studied Well Np306x1 (coarse-grained sandstone, 4234.2 m) and Es1 sandstone exhibits good to excellent porosity varying well Np280 (medium-grained sandstone, 3603.95 m) have from 17.9% to 29.5% that is presented in Table 1. pore throat radius of 0.006 to > 3.2 µm, and they consist of On the basis of diameter, the studied formation consists mesopores and micropores. The sample consists of an aver- of supercapillary/megapores, capillary pores (mesopores and age pore throat radius and connectivity of pores is good, so macropores) and sub-capillary/micropores. The studied Es1 the permeability curve shows the moderate to good reser- sandstone is consisting well to moderate pore connectiv- voir characteristics shown in Fig. 6c, d. Well Np2–15 (fine- ity, so that is why permeability of reservoir is also good grained sandstone and siltstone, 3617 m) and well Np3-19 depending upon pore size and pore throat radius. Mostly (fine-grained sandstone, 4232.59 m) have pore throat radius bigger pores with higher pore connectivity have good poros- of 0.006 to < 0.63 µm, and they consist of mesopores with ity and permeability, and smaller pore with moderate to Table 1 Fractions of mercury porosity values of different pore sizes (based on Nabawy et al. 2009) attained from the mercury injection test Sample no. Depth, m Macropores, Macropore Mesopore, % Mesopore Micropores, % Porosity measured % threshold, µm threshold, µm by Hg injection Np3-80-1 4534.7 26 8.4 53 0.42 21 29.5 Np280-5 3503.95 25 8.4 65 0.42 20 28.4 Np288-6 3725.4 30 8.4 49 0.42 21 26.8 Np3-19-7 4232.59 16 8.4 41 0.42 43 17.9 Np2-15-8 3617 24 8.4 41 0.42 35 19.2 Lp1 2934.20 27 8.4 53 0.42 20 23.7 Np306x1-10 4218.70 28 8.4 54 0.42 17 26.8 1 3 988 Petroleum Science (2019) 16:981–1000 abundant micropores. The sample comprising of average reservoir characteristics (Kashif et al. 2019). Figures 5b, pore throat radius and connectivity of pores is fair to good, e and 8a show the dissolution pores created by leaching so the permeability curve shows the moderate to poor reser- of unstable minerals and rock fragments and enhance the voir characteristics that is shown in Fig. 6e, f. interparticle secondary pores. The pores are varied in shape and size depending on the geometrical arrangements of 4.3 Pore system the grains. Pores appear as elongated surrounded by rigid grains/particles. Other pores include triangular primary Types of pores, their shape and their connectivity depend on pores between rigid grains, which are partially filled by compaction, mineral dissolution, precipitation and organic clays and organic matter and authigenic minerals. These matter degradation/maturation and hydrocarbon genera- pores are acting as a pathway due to their large pore size and tion. Mechanical compaction destroys the pore spaces, and pore connectivity. Dissolution pores are diagenetic pores, dissolution promotes the creation of pores in siliciclastic formed within the low-resistance fragments, minerals, par- sandstone (Mondol et al. 2007; Loucks et al. 2012). Further- ticles, feldspar grains and carbonate cement that are com- more, asphaltic filling and carbonate cement precipitation mon in the studied sandstone as shown in Figs. 5b, e; 7b; significantly reduce the pore size and reduce the porosity and 8a, c. Some micro- to nanoscale pores is also observed (Rexer et al. 2014). The studied sandstone is consisting of within clays aggregates due to the transformation of unsta- macropores, mesopores and micropores. Pores are character- ble clay minerals. Some thin section shows microfractures, ized as macropores (d > 50  nm), mesopores (d = 2–50  nm) interpreted as compaction fractures and dehydration cre- and micropores (d < 2 nm) (Rouquerol et al. 1994). Macro- ated shrinkage cracks, hydrocarbon expulsion generated to nanopore system is developed within the studied samples. fractures. Microfractures also formed due to overpressure According to Loucks et al. (2012), pore classification is used and pressure solution (stylolites) and natural brittle fractures to classify the pore spaces into: (a) intergranular pores, (b) (Zhang et al. 2018). matrix pores and secondary intragranular pore among grains and mineral crystal, and (c) fracture pores (Table 2).4.4 Pore structures Various types of pores are identified in conglomerate sandstone, coarse-grained sandstone, medium-grained sand- 4.4.1 Pore size and pore throat distribution stone, fine-grained sandstone as well as siltstone that are presented in Fig. 7. The pores are identified under a plane Besides the reliance of capillary pressure on reservoir char- polarizing microscope and SEM. Conglomerate sandstone, acteristics, former scientists deliberated that the shape of the coarse-grained sandstone, medium-grained sandstone and capillary pressure curve is mostly ae ff cted by the pore geom- fine-grained sandstone are mostly consisting of primary etry (Rose and Bruce 1949; Vavra et al. 1992). MICP curves intergranular pores, dissolution pores and fractures pores. show capillary pressure within the reservoir sandstone is Primary intergranular pores are present between detrital appropriate representatives for quantification of pore geom - grains and were preserved after compaction and cementa- etry and integration of dynamic data into reservoir models. tion that are shown in Fig. 7a, b. Carbonate cement, filling MICP experiments on the selected core samples show con- clay minerals and ductile deformation (grain flow) as shown nected pore size distributions from Es1 sandstones. At least in Figs. 5a, c, d, f; 8f reduce the pore space and decree the six out of eight samples show bimodal pore size distribution Table 2 Porosity and pore volume obtained by helium porosimetry Sample no. Depth, m Lithology Helium pycnometry −3 3 Pore volume, 10 cm /g Porosity, % 1—Np3-80 4534.70 Medium-grained sandstone 1.544 13.6 2—Np306X1 4223.35 Coarse-grained sandstone 2.003 16.7 3—Np306X1 4220.76 Coarse-grained sandstone 1.942 15.9 4—Np280 3503.20 Conglomerate sandstone 1.997 21.1 5—Np280 3503.95 Coarse-grained sandstone 1.362 15.2 6—Np3-19 4232.59 Medium-grained sandstone 1.419 10.4 7—Np2-15 3617.00 Siltstone 0.756 6.3 8—Np306X1 4234.20 Fine-grained sandstone 0.741 7.2 9—Np306X1 4218.70 Siltstone 0.602 5.3 1 3 Petroleum Science (2019) 16:981–1000 989 (a) (b) (c) Pr.p Fr D.mica Fd P.kaolinite Fr 100 µm 100 µm 100 µm Np 306x1, 4223.35 m Np 380, 4534.7 m Np 280,3503.95 m (d) (e) (f) Rf Kaolinite Pr.p Cd.p 200 µm 200 µm Np 2-15, 3617 m Np 288, 3745.4 m Fig. 5 Petrographic thin-section and SEM photograph shows the pore characteristics; a ductile mica flow, caused to reduce the pore size; b primary intergranular pores, fractures and partially to complete feldspar dissolution and enhance the rock quality; c clay mineral (kaolinite) fills the primary pores and reduces the reservoir quality; d primary intergranular pores; pores are filled by calcite cement and reduces the reservoir characteristics; e calcite cement is dissolved and creating pores; f SEM image shows the kaolinite filling the pore space and reduces the reservoir quality; Q quartz; D. mica ductile mica; F feldspar, Fd feldspar dissolution; Fr fractures; Pr. p primary pores; P. kaolinite pore filling kaolinite; C calcite, Cd. p calcite dissolution pores; Rf rock fragment 100 100 100 (a) (b) (c) Np 3-80, 4534.7 m Np 306x1, 4218.7 m Np 306x1, 4234.2 m 90 90 90 80 80 80 70 70 70 60 60 60 50 50 50 40 40 40 30 30 30 20 20 20 10 10 10 0 0 0 0.006 0.063 0.630 6.300 63.000 0.006 0.063 0.630 6.300 63.000 0.006 0.063 0.630 6.300 63.000 Pore throat radius, μm Pore throat radius, μm Pore throat radius, μm 100 100 (d) (e) (f) Np 280, 3603.95 m Np 2-15, 3617 m Np 3-19, 4232.59 m 90 90 80 80 70 70 60 60 50 50 40 40 30 30 20 20 10 10 0 0 0.006 0.063 0.630 6.300 63.000 0.006 0.063 0.630 6.300 63.000 0.006 0.063 0.630 6.300 63.000 Pore throat radius, μm Pore throat radius, μm Pore throat radius, μm Fig. 6 Mercury saturation bar chart and permeability contribution value accumulation curve in Nanpu wells Bohai Bay Basin 1 3 Mercury saturation Mercury saturation frequency, % frequency, % Mercury saturation Mercury saturation frequency, % frequency, % Mercury saturation Mercury saturation frequency, % frequency, % 990 Petroleum Science (2019) 16:981–1000 (a) (b) (c) P.throat Pr.p Pr.P Q.O Pr.p D.p P.throat Fr.p Fr.p 100 µm 200 µm 200 µm Np 306x1, 4233.34 m Np 3-80, 4535.38 mNp 2-15,3617 m (a′) (b′) (c′) P.throat P.throat Pr.p Pr.p Pr.p P.throat (d) (e) (f) Pores Pores Pores Fig. 7 Representation of primary pores and secondary pores under a polarizing microscope, a laser scanning microscope, and SEM and BSEM photographs. a Primary intergranular pores, with pore throat and quartz overgrowth; b primary pores, dissolution pores and fractures pores; pore size is smaller than a; c primary pores, fractures and pore throat, size of pore is smaller than a and b; a′–c′ laser scanning confocal microscopic images of a, b and c; d BSEM image showing the larger pores; e BSEM image shows the primary and dissolution pores in feldspar; f SEM and BSEM combined image shows the smaller minerals/intercrystalline minor pores. Pr. p primary pores; Q. o quartz overgrowth; P. throat pore throat; Dp dissolution pores; Fr. p fracture pores comprised of macropores and mesopores. Most of the SEM images are shown in Figs. 7a, d; 8a, g. Their primary macropores (25%–30%) lie between 1 and 10  μm which drainage curves show good reservoir quality especially per- corresponds to intergranular and dissolution pores. Some meability as shown in Figs.  6a, b. Np306x1, 4223.35 m, samples show 20%–25% pore volume with pore throat sizes and Np280, 3503.95 m, have medium to coarse grain and between 0.1 and 1 μm which corresponds to intercrystalline are moderately sorted, and their primary drainage curve pores in clay and carbonate cement. Nearly all samples show indicates good reservoir characteristics (high permeability) a small fraction (20%) of mesopore volume with pore throat (Figs. 6c, d; 7b, e; 8b). Moderate reservoir consists of mod- sizes of < 0.1 μm which corresponds to intercrystalline pores erate to well-sorted grains of heterogeneous nature as shown in clay. Details of pore throat sizes of < 0.006 μm are not in thin section in Figs. 7b; 8b. On the other hand, samples available from MICP experiments. NP2-15, 3617 m, and Np3-19, 4232.59 m, are poorly sorted, Samples Np306x1, 4218.7 m, and Np3-80, 4534.7 m, compacted and mostly consisted of clay matrix and carbon- are consisting of coarse grains and medium to well-sorted ate cement with low porosity (Figs. 5c, d, f; 8f) that causes grains, and well-developed pores in thin-section as well as to clog the pores, due to that most of the pore throats lie 1 3 Petroleum Science (2019) 16:981–1000 991 (a) (b) (c) Fd Pr.P Pr.p Fd Pr.p Fr.p Fr.p Fr.P 200 µm 100 µm 200 µm Np 306x1, 4234.5 m Np 380, 4334.7 mNp 306x1, 4233.4 m (d) (e) (f) Pr.p P.throat Pr.p Pr.p P.throat Pore filled by Kaolinite 100 µm 50 µm 100 µm Np 2-15, 3717.3 m Np 306x1, 4234.6 mNp 380, 4334.7 m (g) (h) (i) Pores Pore Pore Fig. 8 Representation of primary pores, secondary pores, pore interconnectivity, under polarizing microscope and SEM. a Larger primary inter- granular pores, with dissolution pores and fractures pores with pore throat; b primary pores and fractures pores, pore size is smaller than a; c primary intergranular pores; d large primary intergranular pores with regular pore throat; f primary intergranular pores, pore filled by kaolinite clay and pore throat; g large pore under SEM; h intermediate pores under SEM; i smaller pores under SEM;. Pr. p primary pores; P. throat pore throat; Dp dissolution pores; Fr. p fracture pores between 0.1 μm to 1 μm in size (Fig. 11). It shows the lower within the range of 8.4 µm > D ≥ 0.45 µm, and micropores pore size spectrum than other samples. Due to poorly sorted are the pore throat with a diameter < 0.4 µm (Nabawy et al. and heterogeneous nature, the initial drainage curve moves 2009). In MICP analysis, macropores contribute 25.33%, up higher and indicates poor reservoir quality. The ejection mesopores 52.66% and micropores 23% on average of total curves show that mercury fails to recover from samples com- pore volume with variation in different wells. pletely down to 0.80–0.90 MPa mercury pressure. Mercury The specific surface area of the sample is measured by is still trapped in the pores from 22% to 78% as shown in Brunauer, Emmett and Teller (BET) including pore size Fig.  11. The main reason of mercury not recovered may distribution. It measures the surface area and open pores of be due to some chemical or capillary forces that hold mer- macroporous and mesoporous materials, as well as pore vol- cury in pores or due to the destruction of the pore network. ume and area distribution that characterize porosity below MICP is a useful method to evaluate pore size distribution. the effective range of mercury intrusion porosimetry. The Macropores are the parts of the pore throat with Mp thresh- pore throat structure parameters were gained by N adsorp- old > D ≥ 8.4 µm, mesopores are pore throats with a diameter tion analysis, i.e. average pore volume, pore volume and 1 3 992 Petroleum Science (2019) 16:981–1000 BET surface area (Table  3). The SBET (specific surface 4.5 Porosity and permeability area) of selected samples was calculated by BET equation (Brunauer et al. 1938). Pore voids play a significant role in enhancing the reservoir quality. The Es1 sandstone mostly consists of moderate to 1 c − 1  1 high porosity and permeability. On the basis of core obser- = + , (1) v c  v c m o m o vation and thin-section study, it has been revealed that Es1 ∕ − 1 sandstone containing primary intergranular pores along with secondary pores and occasionally microcrystalline pores is where ρ and ρ are the equilibrium and the saturation pres- also present. Some of them are generated genetically after sure of the adsorbates at the temperature of adsorption, deposition as a result of dissolution and fracturing. Second- respectively, υ is the adsorbed gas quantity and υm is the ary pores are produced by different fluids that affect the monolayer adsorbed gas quantity. C is the BET constant. unstable rock fragments and cement that entirely or par- E − E 1 L tially dissolve the grains and pore cement (Figs. 5e; 8a). c = exp , (2) RT Dissolution pores are mostly generated in unstable detrital grains due to their low resistance against the acidic fluid. where E is the heat of adsorption for the first layer and E 1 L Petrophysical Es1 sandstone has an excellent primary poros- is a second higher layer. ity ranging from 0.4% to 32% and permeability ranging from The SBET (specific surface area) values range from 0.005 to 6870 mD (Fig. 9). Secondary porosity caused by 5540.27 to 115.49 m /g. The specific pore volume is reso- dissolution and fracture also enhances the reservoir porosity lute by Barrette–Joyner–Halenda (BJH) theory (Barrett et al. up to 5%. Primary intergranular porosity accounts consist 1951), and it ranges from 2.0 to 0.073 cm /g. of the main reservoir space for 44% of the total reservoir space. Moreover, some feldspar/rock fragment dissolution 4.4.2 Pore connectivity pores (27%), cement dissolution pores (8%) and fractures pores (17%) and fracture–dissolution pores (6%) account Es1 sandstone consists of a different type of pores that are for 57% of the total reservoir space as shown in Fig. 10. mostly connected, which enhances the reservoir character- Similarly, some other microfractures have specific reservoir istics. The pore connectivity of Es1 sandstone in Nanpu Sag characteristics, but they play a most vital role in serving oil was characterized by using SEM and LSCM to qualitatively and gas seepage channels to enhance the permeability of establishing pore space and analysing pore throat distribu- the reservoir. tion and connectivity. Overall experimental results indicate Mineral dissolution occurred mainly during the uplift that pore throat of a reservoir has little isolation due to dif- period, and the initial reburial stage, the uplift and develop- ferent compositions with moderate to small in size, moderate ment of fractures promoted the penetration of freshwater throat and moderate to good connectivity (Figs. 7a, a′; b, b′; to these sandstones and also played an important role in c, c′; 8c, e, f, i). Calculated porosity from different samples enhancing the permeability of reservoir rock for fluid flow. ranges from 5.3% to 21.1% that is shown in Table 3. Table 3 Pore parameter from N adsorption measurement Sample no. Depth, m Lithology Porosity, % Permeability, mD SBET, m²/gVBJH, cm /g Average pore size, µm 1—Np3-80 4534.70 Conglomerate sandstone 13.6 149 403.94 1.54 15.492 2—Np306X1 4223.35 C sandstone 16.7 442 330.30 2.00 14.416 3—Np306X1 4220.76 C sandstone 15.9 340 346.04 1.94 12.170 4—Np280 3503.20 M sandstone 21.1 49.2 1504.41 2.00 4.575 5—Np280 3503.95 F sandstone 15.2 1.30 5240.19 1.36 0.467 6—Np3-19 4232.59 Siltstone 10.4 0.313 5540.27 1.42 0.073 7—Np2-15 3617.00 F sandstone 6.3 0.0908 4658.23 0.76 0.110 8—Np306X1 4234.20 M sandstone 7.2 0.701 2081.61 0.74 0.508 9—Np306X1 4218.70 M sandstone 5.3 124 115.49 0.60 6.591 SBET surface area using Brunauer–Emmett–Teller method (Brunauer et al. 1938), VBJH pore volume using Barrette–Joyner–Halenda (Barrett et al. 1951), C coarse, M medium, F fine 1 3 Petroleum Science (2019) 16:981–1000 993 Porosity, %Permeability, mD 05 10 15 20 25 30 35 40 0.01 0.11 10 100100010000 1000 1000 1500 1500 2000 2000 2500 2500 3000 3000 3500 3500 4000 4000 4500 4500 5000 5000 Fig. 9 Porosity and permeability distribution of different wells in Nanpu Sag Np 3-19, 4232.59 m Np 2-15, 3617 m 44% N=1242 Np 306x1, 4234.20 mNp 306x1,4220.76 m Np 306x1, 4223.35 m Np 306x1, 4218.7 m Np 3-80,4534.7 m 30 100 27% 17% 8% 4% Fracture Cement Primary Fracture Feldspar/ pores dissolve inter-granular dissolve R.fragment pores pores pores dissolution pores 0.1 Reservoir pore space type 0.01 Fig. 10 Development frequency of different reservoir spaces within 100 80 60 40 20 0 Shahejie Formation reservoir sandstone Mercury saturation, % Fig. 11 Mercury saturation versus capillary pressure diagram in Nanpu well. MICP injection–withdrawal capillary curves on selected samples 1 3 Development frequency, % Depth, m Depth, m Capilary pressure, MPa 994 Petroleum Science (2019) 16:981–1000 preserve relatively large pores at the high-stress area (Yang 5 Discussion and Aplin 2007), whereas smaller pores accompany fine- grained rocks. There is a positive and slight negative correla- 5.1 Relationship between sedimentary features tion between grain size and average pore diameter obtained and pore structures from the N adsorption experiment. Fractures influence some grains during various structure experiments. Pore con- The relationship between depositional fabric and reser- nectivity and throat size are higher due to fractures, whereas voir pore structures was evaluated by grain size analysis high surface area is obtained due to the clay matrix (Fig. 11). and sorting coefficient (So) and their correlation with pore structures. The reservoir permeability of Es1 sandstone is 5.2 Mineral composition association with a pore directly/positively related to grain size. This relation shows structure that the porosity is directly connected to rock fabric (grain size, grain shape and orientation). Generally, the compac- Thin-section studies and XRD data represent that carbon- tion effect is adverse on coarse-grained sandstone that may ates, clay minerals (kaolinite, illite–smectite, illite and chlo- lead to more efficient pore preservation and with increas - rite), detrital quartz and feldspar are the most common min- ing stress less effect on porosity reduction. In medium- to erals in the selected, studied samples (Figs. 5a, c, d, e; 8f). coarse-grained sandstone, it will result in the improvement The link between mineral types, their amount and pore struc- of the connectivity of pores/permeability as compared tures as well as the relationship between detrital minerals to fine-grained rocks (Fawad et al. 2010) and pore throat like quartz and feldspar, and other pore structure parameters size is also affected by grain size; the Es1 sandstone with are similar to carbonate minerals. That shows a link between medium-grained sandstone, coarse-grained sandstone and pore structure parameter and carbonate and clay mineral conglomerate sandstone has good pore and pore throat size. contents used to study the mineral/pore structure relation, Coarse-grained rocks are consisting of coarser particles/frag- respectively. There is no negative correlation between car- ments that provide a framework that is sufficiently strong to bonate minerals and clay minerals with permeability that 60 60 60 (a) (b) Clay minerals Quartz 60 Carbonate minerals Feldspar 40 40 40 20 20 20 0 0 0 0.11 10 100 10000 0.11 10 10010000 Permeability, mD Permeability, mD 60 60 60 60 (c) (d) Clay minerals Quartz Carbonate minerals Feldspar 40 40 20 20 0 0 04 8121620 04 8121620 2 2 BET surface area, m /g BET surface area, m /g Fig. 12 Relation between mineral contents and pore structure parameter in Es1 sandstone 1 3 Carbonate minerals, % Carbonate minerals, % Clay minerals, % Clay minerals, % Feldspar, % Feldspar, % Quartz, % Quartz, % Petroleum Science (2019) 16:981–1000 995 is shown in Fig. 12a; rather, carbonate mineral has a very of macroporous and mesoporous material, as well as pore unpredictable effect on permeability; therefore, there is no volume and area distribution that characterize porosity clear correlation, particularly for Fig. 12a. Carbonate min- below the effective range of mercury intrusion. The SBET eral has a very subtle correlation with permeability. It is (specific surface area) of selected samples was calculated neither a positive nor a negative correlation. Carbonate min- by the BET equation, and its values range from 5540.27 to erals have a patchy effect on permeability as data are very 115.49 m /g. The specific pore volume values range from scattered. Generally, it should have a negative effect, but the 2.0 to 0.073 cm /g. Clay contents are present in the studied studied selected sample data do not represent it. Clay min- sandstone as muddy interlayers and also present in siltstone eral has a negative correlation in Fig. 12a with permeability. and mudstone. Higher content of clay/mud increased the Scattering is due to random sampling. Similarly, Fig. 12c measured SBET and total pore volume due to high clay spe- shows the meagre positive correlation between carbonate cific surface area. Micropores developed due to clogging of and clay minerals with BET surface area. It shows a very clay minerals segmenting of primary intergranular pores into poor correlation between the carbonate and BET, either it micropores. Siltstone and fine-grained sandstone association is positive or negative, whereas clay minerals have a subtle with SBET and total pore volume suggest that carbonate positive correlation. minerals like quartz and feldspar are not a major contributor Clastic minerals like quartz and feldspar have a positive to total surface area and micropore volume (Figs. 7d, e, f; effect on reservoir properties as shown in Fig.  12b. Micro- 8g, h, i). In the studied area, carbonate mineral may provide scopic pore images and SEM studies of the pore are related relatively less total pore volume and specific surface area. to carbonate and clay minerals that show variability. After burial various diagenetic processes started on deposited 5.3 The relation between routine core analysis sediments and due to compaction phenomenon, quartz, and pore characteristics feldspar and carbonate minerals play a significant role in preserving the primary pores due to rigid framework and Mercury injection capillary pressure (MICP) test was con- pressure shadow of rigid grain protect primary pores to ducted for routine core analysis in an experiment to relate collapse, whereas the presence of carbonate cement blocks the much costly mercury achieved as a result to routine less the pore voids and blocks the pore throat. Intergranular and expensive, common and valid tests. MICP is a valuable tech- intragranular pores are associated with clay minerals that nique to evaluate the pore throat size distribution as well block the large pores between the grains and applying the as reservoir quality and diagenesis impact (Tavakoli et al. negative effect on reservoir characteristics. However, there 2011). The calculated mean helium porosity (øHe%) of Es1 will be a positive relation between BET surface area and sandstone shows very good porosities (9.3%–27.1%) that clay minerals, whereas quartz, feldspar, carbonate minerals are mentioned in Table 4, and the measured helium (øHe%) and BET surface area show a variable association (Fig. 12c, porosity usually is higher than mercury porosity (øHg%). d). The specific surface area of the sample is measured by Both types of porosities are higher in Es1 sandstone, vary- Brunauer, Emmett and Teller (BET) including pore size ing from base to middle and then top depending on carbon- distribution. It measures the surface area and open pores ate cement and clay contents. The bulk permeability was Table 4 Storage capacity properties of the Es1 sandstone of Shahejie Formation obtained from the routine core analysis and permeability values calculated from the mercury injection test Sample no. Depth, m øHe, % r25, µm Kr25, µm R35, µm Kr35, mD r10, µm Kr10, mD Kb, mD Np3-80 4534.70 16.5 1.02 16.7 3.4 16.4 7.3 123.6 249 Np306X1 4223.35 20.7 6.7 240 9.1 121.2 12.2 376.4 647 Np306X1 4220.76 21.9 7.3 365 10.5 116.5 10.6 330.5 840 Np280 3503.20 27.1 9.4 256 6.4 2.4 8.7 46.7 149.2 Np280 3503.95 20.2 12.2 216 2.1 0.004 0.07 1.5 10.30 Np3-19 4232.59 16.4 7.6 180 5.4 0.0034 0.05 1 6.313 Np2-15 3617.00 10.3 5.8 245 1.003 0.005 0.004 0.98 6.0908 Np306X1 4234.20 12.2 5.1 175 1.5 0.023 0.032 0.76 5.701 Np306X1 4218.70 9.3 6.2 256 8.5 15.7 7.4 132 324 øHe mean porosity measured by helium injection, r25 pore throat size corresponding to the 25th percentile, R35 pore throat size corresponding to the 35th percentile, Kr25 calculated permeability at r25, Kr35 calculated permeability at R35, r10 pore throat size corresponding to the 10th percentile of measured mercury porosity, Kr10 calculated permeability at r10 using mercury porosity, kb average uncorrected measured air per- meability 1 3 996 Petroleum Science (2019) 16:981–1000 measured by air injection. Its values range from 5.70 mD to 840 mD. The uncorrected air permeability was calculated on the basis of the equation of Winland (Kolodzie 1980) and Pittman (1992), where the usage of corrected permeability values, which may be trivial, would produce a deceptively small pore aperture size calculation (Pittman 2001). The incorporation of porosity and permeability data in Megapores terms of reservoir quality index (RQI) data is suitable for use Meso & Macro pores with the routine core analysis data that provide an excellent Micropores improvement in addressing the reservoir quality in different 05 10 15 20 30 scales (Lai et al. 2016; Tavakoli et al. 2011). It is the best Porosity (Ø ) fraction Hg macrophysical factor for an assessable description of reservoir microscopic pore structure. Higher reservoir quality index Fig. 13 Measured mercury porosity volume (%) versus permeability (RQI) values indicate better microscopic pore structures (Lai (k) differentiated into megapore, macropore and micropore throat size et al. 2016). The concept of Amaefule et al. (1993) technique is based on the calculation of RQI, demarcated as follows: effective pore throats, which constitutes the most operative and permeable pore spaces, thus reducing the net perme- RQI = , (3) ability values (Fig. 13). Fine-grained sandstone, siltstone and mudstone consist of sub-capillary pores. The number where RQI is the reservoir quality index, μm; k is the perme- of pores is high, but their connectivity is low due to their ability, mD; and  is the porosity in terms of total volume smaller size volume concerning coarse-grained sandstone. fraction, %. So the permeability of such rocks or part of the rock that Reservoir quality index (RQI) provides an appropriate consists of siltstone, mud presence and carbonate cement starting point to address the differences between core plug has low reservoir characteristics. samples and reservoir zones (Lai et al. 2016). RQI can be used to calculate the flow characteristics of reservoirs and 5.4 Relationship between pore structure parameter provide a functional association between microscopic fea- and physical property tures and macroscopic logs (Lai et  al. 2016). Reservoir heterogeneity concerning the variants in microscopic pore The maximum and average pore throat radii are correlated structure and reservoir macroscopic permeability of the core to some extent with porosity and permeability. The better plug samples can be evaluated by RQI (Lai et al. 2016). The correlation for permeability as compared to porosity plots RQI and permeability values increase as the proportion of relating to pore structure parameters and physical proper- large pores and small pores increases. There is a significant ties is shown in Fig. 14a–d. The average pore throat radius variation in the pores, and the pore structures are complicated signifies the better correlation with physical properties. due to firm heterogeneity (Zhang et al. 2007). Pores and pore It shows that the average pore throat radius distribution throats are affected by sediments, diagenetic interaction and exemplifies the quality of the deeply buried sandstone cementation. RQI is a good representative of porosity and reservoirs. permeability reservoir quality indices, but this index is not The pore throat distribution is directly reflected by the suitable for the size distribution of pore throats (Tavakoli sorting coefficient of the throat (Sc), where smaller Sc is et al. 2011). This type of distribution could disclose the effect indicating the better sorted pore throat. The sorting coeffi - of diagenetic events on these two significant factors. cient shows a positive correlation with porosity and perme- The measured permeability was plotted contrary to the ability as shown in Fig. 14e, f. The studied rock caused this mercury porosity differentiated into supercapillary pores/ positive correlation due to medium to coarse pores and pore megapores, capillary pores/mesopores and macropores and throats; in addition, coarse pore throat, consisting of some sub-capillary pores/micropores (Fig. 6). The supercapillary microfractures, appears in samples with less sorted pores, pores (megapores) establish an insignificant part of the total so the coarser pore throat contributes much more to perme- pore volume and characterize a surface effect that may be ability. This complies with the pore structure characteristics mixed with the conformance volume. That is why, these discussed above, indicating that samples with large sorting should be detached from additional deliberation, i.e. perme- coefficient have coarse pore throats that provide much more ability is mostly contributed by the pores in the mesopores to permeability, whereas samples with smaller sorting coef- and macropores/capillary pores. An increase in the volume ficient have a large amount of more sorted small pores that percentile increment of the sub-capillary micropore frac- account for a large porosity. tion escorts a decrease in the macropore and mesopore 1 3 Permeability, k Petroleum Science (2019) 16:981–1000 997 (a) (b) y=1.1631x+0.1463 0.0075x y=2.8917e R =0.2011 R=0.5951 10 10 5 5 0 0 -5 -5 -10 -10 05 10 15 20 25 0.11 10 1001000 Porosity, % Permeability, mD 20 20.0 (c) (d) 17.5 15.0 0.2009x y=0.1548e 12.5 y=-0.0336x+2.4415 R=0.2716 R =0.673 10.0 7.5 5.0 2.5 -2 05 10 15 20 25 0.11 10 1001000 Porosity, %Permeability, mD 5.5 5.5 (e) (f) 5.0 5.0 4.5 4.5 y=0.0511x+4.2044 y=-0.0047x+4.1247 4.0 2 4.0 R =0.0666 R =4547 3.5 3.5 3.0 3.0 2.5 2.5 2.0 2.0 1.5 1.5 05 10 15 20 25 0.11 10 1001000 Porosity, % Permeability, mD Fig. 14 Relationship between high-pressure mercury intrusion parameter and porosity and permeability clays minerals, mica minerals and carbonate minerals, and 6 Conclusion the rock is classified as feldspathic litharenite and lithic arkose. The Es1 sandstone of Shahejie Formation is mainly lacus- Several types of pores are evaluated including primary trine sandstone with interbedded mudstone. The Es1 sand- intergranular pores, intragranular pores, dissolution pores, stone mostly consists of quartz, feldspar, rock fragments, 1 3 Sorting coefficient Average pore throat radius, μm Max pore throat radius, μm Average pore throat radius, μm Sorting coefficient Max pore throat radius, μm 998 Petroleum Science (2019) 16:981–1000 fractures pores, and it consists of several matrix pores and References mineral pores including intergranular and intragranular Allen MB, Macdonald DIM, Xun Z, Vincent SJ, Brouet-Menzies C. pores. Pore throat system is characterized by MICP and Early Cenozoic two-phase extension and late Cenozoic thermal LSCM, and a pore radius of the studied sandstone is in subsidence and inversion of the Bohai Basin, northern China. 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Published: Sep 25, 2019

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