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The coupling of dynamics and permeability in the hydrocarbon accumulation period controls the oil-bearing potential of low permeability reservoirs: a case study of the low permeability turbidite reservoirs in the middle part of the third member of Shahejie Formation in Dongying Sag

The coupling of dynamics and permeability in the hydrocarbon accumulation period controls the... Pet. Sci. (2016) 13:204–224 DOI 10.1007/s12182-016-0099-0 ORIGINAL PAPER The coupling of dynamics and permeability in the hydrocarbon accumulation period controls the oil-bearing potential of low permeability reservoirs: a case study of the low permeability turbidite reservoirs in the middle part of the third member of Shahejie Formation in Dongying Sag 1,2,3 1,2 1,2 3 • • • • Tian Yang Ying-Chang Cao Yan-Zhong Wang Henrik Friis 4 1,2,4 1,2 • • Beyene Girma Haile Ke-Lai Xi Hui-Na Zhang Received: 24 March 2015 / Published online: 29 April 2016 The Author(s) 2016. This article is published with open access at Springerlink.com Abstract The relationships between permeability and reservoirs except for diagenetic facies A had middle to -3 2 dynamics in hydrocarbon accumulation determine oil- high permeability ranging from 10 9 10 lm to -3 2 bearing potential (the potential oil charge) of low perme- 4207 9 10 lm . In the later accumulation period, the ability reservoirs. The evolution of porosity and perme- reservoirs except for diagenetic facies C had low perme- -3 2 -3 2 ability of low permeability turbidite reservoirs of the ability ranging from 0.015 9 10 lm to 62 9 10 lm . middle part of the third member of the Shahejie Formation In the early accumulation period, the fluid pressure increased in the Dongying Sag has been investigated by detailed core by the hydrocarbon generation was 1.4–11.3 MPa with an descriptions, thin section analyses, fluid inclusion analyses, average value of 5.1 MPa, and a surplus pressure of carbon and oxygen isotope analyses, mercury injection, 1.8–12.6 MPa with an average value of 6.3 MPa. In the later porosity and permeability testing, and basin modeling. The accumulation period, the fluid pressure increased by the cutoff values for the permeability of the reservoirs in the hydrocarbon generation process was 0.7–12.7 MPa with an accumulation period were calculated after detailing the average value of 5.36 MPa and a surplus pressure of accumulation dynamics and reservoir pore structures, then 1.3–16.2 MPa with an average value of 6.5 MPa. Even the distribution pattern of the oil-bearing potential of though different types of reservoirs exist, all can form reservoirs controlled by the matching relationship between hydrocarbon accumulations in the early accumulation per- dynamics and permeability during the accumulation period iod. Such types of reservoirs can form hydrocarbon accu- were summarized. On the basis of the observed diagenetic mulation with high accumulation dynamics; however, features and with regard to the paragenetic sequences, the reservoirs with diagenetic facies A and diagenetic facies B reservoirs can be subdivided into four types of diagenetic do not develop accumulation conditions with low accumu- facies. The reservoirs experienced two periods of hydro- lation dynamics in the late accumulation period for very low carbon accumulation. In the early accumulation period, the permeability. At more than 3000 m burial depth, a larger proportion of turbidite reservoirs are oil charged due to the proximity to the source rock. Also at these depths, lenticular & Ying-Chang Cao sand bodies can accumulate hydrocarbons. At shallower cyc8391680@163.com depths, only the reservoirs with oil-source fault development School of Geosciences, China University of Petroleum, can accumulate hydrocarbons. For flat surfaces, hydrocar- Qingdao 266580, Shandong, China bons have always been accumulated in the reservoirs around Laboratory for Marine Mineral Resources, Qingdao National the oil-source faults and areas near the center of subsags Laboratory for Marine Science and Technology, with high accumulation dynamics. Qingdao 266071, China Department of Geoscience, Aarhus University, Høegh- Keywords Reservoir porosity and permeability Guldbergs Gade 2, 8000 Aarhus C, Denmark evolution  Accumulation dynamics  Cutoff-values of Department of Geosciences, University of Oslo, permeability in the accumulation period  Oil-bearing P.O. Box 1047, Blindern, 0316 Oslo, Norway potential  Low permeability reservoir  The third member of the Shahejie Formation  Dongying Sag Edited by Jie Hao 123 Pet. Sci. (2016) 13:204–224 205 reservoir pore-throat geometries, and finally the distribu- 1 Introduction tion pattern of the oil-bearing potential of the reservoirs is With the increasing interest in oil and gas exploration and determined. This can provide theoretical guidance for the exploration and development of low permeability turbidite development, low permeability clastic rock reservoirs are becoming key exploration target areas (Yang et al. 2010; reservoirs. Cao et al. 2012). The low permeability clastic rock reser- voirs have gone through complex diagenetic events (Yang 2 Geological background et al. 2010; Wang et al. 2011). The distribution of sand- stone porosity is not consistent with the hydrocarbon The Dongying Sag is a sub-tectonic unit lying in the accumulation. The porosity of sandstone during the accu- southeastern part of the Jiyang Depression of the Bohai mulation period is the key factor to determine the oiliness Bay Basin, East China. It is a Mesozoic-Cenozoic half of the reservoirs (Cao et al. 2012; Liu et al. 2014a; Wang graben rift-downwarped basin with lacustrine facies et al. 2014a). Some researchers have attempted to extract data from the porosity of low permeability clastic rock directly deposited on Paleozoic bedrocks (Cao et al. 2014; Wang et al. 2014b). The Dongying Sag is bounded to the reservoirs during the accumulation period (Cao et al. 2011, 2012, 2013; Wang et al. 2013a; Liu et al. 2014a). However, east by the Qingtuozi Salient, to the south by the Luxi Uplift and Guangrao Salient, to the west by the Linfanjia they did not calculate the cutoff values for porosity of the reservoir under the control of accumulation dynamics and Gaoqing salients, and to the north by the Chenji- azhuang-Binxian Salient. The NE-trending sag covers an during the accumulation period (Pan et al. 2011; Wang area of 5850 km (Fig. 1). It is a half graben with a faulted et al. 2014a; Liu et al. 2014a). The distribution of the oil- northern margin and a gentle southern margin. Horizon- bearing potential of reservoirs is still poorly understood. tally, this sag is further subdivided into several secondary The relationships between porosity and the oil-bearing structural units, such as the northern steep slope zone, potential of turbidite reservoirs of the middle part of the middle uplift belt, and the Lijin, Minfeng and Niuzhuang third member of Shahejie Formation (Es ) in Dongying Sag are complex, even though the reservoirs have similar trough zones, Boxing subsag, and the southern gentle zone (Zhang et al. 2014). The sag is filled with Cenozoic sedi- accumulation conditions. The high or low porosity and permeability sandstone reservoirs either contain oil or not. ments, which are formations from the Paleogene, Neogene, and Quaternary periods. The formations from the Paleo- Liu et al. (2014a, b) analyzed the relationship between porosity and the cutoff-values for porosity in the early gene period are the Kongdian (Ek), Shahejie (Es), and Dongying (Ed); the formations from the Neogene period accumulation period of Es turbidite reservoirs in Niuz- huang subsag with the guide of porosity estimation and are the Guantao (Ng) and Minghuazhen (Nm); and the formation from the Quaternary period is the Pingyuan effect-oriented simulation. They concluded that the (Qp). Detailed descriptions of the Paleogene stratigraphy porosity of reservoirs in the early accumulation period was higher than the cutoff-values for porosity of the reservoirs. have been provided by several authors (Zhang et al. 2004, 2010; Guo et al. 2012) (Fig. 2). So the reservoirs could be charged with oil. The perme- ability is the main controlling factor for percolation and the During the deposition of the third member of the Sha- hejie Formation, tectonic movement was strong, and the development of low permeability reservoirs (Meng et al. 2013). There were several stages of accumulation for the basin subsided rapidly reaching its maximum depth. As a result, large amounts of detrital materials were transported Es turbidite reservoirs in the Dongying Sag and the later accumulation period was the most important (Cai 2009). into the basin and formed plentiful source rocks and tur- bidites in deep-water environments in the depressed zone The permeability and the cutoff-values at the later accu- and uplifted zone (Wang et al. 2013b; Yang et al. 2015) mulation period are the most important for the distribution (Fig. 3). The thickness of single sand layers of turbidite of the oil-bearing potential of reservoirs today. reservoirs is 0.1–0.5 m; the accumulation thickness is On the basis of previous studies, taking the Es tur- bidite reservoirs as an example, the permeability of the 10–158 m. Turbidity current deposits with Bouma sequences and debris flow deposits with massive bedding reservoirs in the accumulation period was estimated. The permeability estimation method was based on the para- are most common. The east slope of the Niuzhuang subsag, Liangjialou, and the front of the Dongying delta are places genetic sequence of diagenetic minerals and the reservoir pore-throat geometry. The cutoff-values for permeability where a large volume of turbidites are distributed (Yang et al. 2015). Most turbidite reservoirs are low permeability of reservoirs in the accumulation period are calculated after the estimation of accumulation dynamics and with complex oil-bearing characteristics. 123 Qingtuozi Salient Chenguanzhuang Fault Shicun fault zone 206 Pet. Sci. (2016) 13:204–224 42e (a) N (b) Sag 0 100 km N 0 10 20 km Uplift 40e Beijing Yanshan A’ Chenjiazhuang Salient Č Dalian Bohai Bay 38e Coastline China Northern zone Jinan 36e Beijing steep Minfeng Tanlu Strike-slip Fault Zone Binxian subsag 114e 116e 118e 120e 122e 124e Salient uplift area Middle Lizezheng subsag Qingcheng Boxing subsag Salient Paleogene Paleogene system A system area overlap zone Luxi Uplift Study Major Paleogene system area fault denuded zone Guangrao Lijin Northern Luxi South gentle slope Niuzhuang subsag Uplift Central anticline steep slope subsag Uplift A’ N─Q Es ─Ed Es ─Es 3 2 Ek─Es Mz (c) Fig. 1 a Location map showing the six major sub basins of the Bohai Bay Basin. b Structural map of the Dongying Sag. The area in the green line box is the study area (After Liu et al. 2014a). c N–S cross section (A –A) of the Dongying Sag showing the various tectonic-structural zones and key stratigraphic intervals 3 Materials and methods were tested by a 3020-62 helium porosity analyzer and GDS-9F gas permeability analyzer at common temperature Over 1500 m of representative cores of turbidite in the and humidity. Mercury injection was tested by a 9505 mercury injection analyzer at 22 C and 60 % humidity. target formation have been described. 119 typical samples Samples were examined by a JSM-5500LVSEM combined were taken from the core. Thin section examination and with QUANTAX400 energy dispersive X-ray microanaly- porosity and permeability testing of all 119 samples were ser (EDX). The thin sections and fluorescence thin sections undertaken. Mercury injection testing of 90 samples, scanning electron microscopy (SEM) examination of 15 were prepared by the CNPC Key Laboratory of Oil and Gas reservoirs at the China University of Petroleum and samples, cathode luminescence testing of 17 samples, flu- orescence thin section observation of 17 samples, and fluid were examined using an Axioscope A1 APOL digital polarizing microscope produced by the German company inclusion testing of 53 samples were undertaken. The core samples were provided by the Geological Scientific Zeiss. The cathodoluminescence was studied using an Imager D2 m cathode luminescence microscope also pro- Research Institute of the Sinopec Shengli Oilfield Com- pany. Porosity, permeability, and mercury injections were duced by Zeiss. The fluid inclusions were analyzed using a THMSG600 conventional inclusion temperature measure- measured at the Exploration and Development Research ment system produced by the British Company Linkam. Institute of the Sinopec Zhongyuan Oilfield Company as Sandstone composition analysis data of 2314 samples and were the SEM examinations. Porosity and permeability fault slope Boxing fault zone Binnan-Lijin fault zone Chennan Tuo-Sheng-Yong sub-fracture Guangrao Salient Southern slope Chenguanzhuang-wangjiagang fault zone zone Niuzhuang subsag Lijin subsag Chennan Fault Linfanjia Salient Fold Belt Bamianhe fault zone Shicun Fault Liaodong Uplift Cangxian Uplift Luxi Uplift Gaoqing fault zone Jiaodong Uplift Taihangshan Uplift Depth, km Pet. Sci. (2016) 13:204–224 207 Stratigraphy Main Age Thickness Reservoir Seal Tectonic Sedimentary Lithology source System Series Sub- (Ma) (m) environment rocks rocks evolution Formation Member member rocks Quarternary Pingyuan (Qp) 100-230 Floodplain Minghuazhen (Nm) Floodplain 600-900 5.1 Ng Guantao 300-400 Braided stream (Ng) Ng 24.6 Deltaic Ed 0-110 28.1 Deltaic Dongying 0-280 Lacustrine Ed (Ed) Deltaic Ed 0-420 Lacustrine 32.8 Deltaic Es 0-450 Lacustrine Deltaic Es 38.0 0-350 Fluvial Deltaic Es 100-300 Fluvial Es 3 2 Fan deltaic Es 3 200-500 Shahejie Subaqueous fan (Es) Turbidite fan Es 200-600 Lacustrine 42.5 Es 300-700 Subaqueous fan Es Turbidite fan Es 200-800 (Salt) Lacustrine 52.0 Fluvial Ek 0-1300 Salt lake Kongdian Ek Fluvial (Ek) 0-900 Lacustrine Ek 65.0 Conglomerates Sandstones Siltstones Mudstones Carbonates Volcanic rocks Evaporites Uncomformity Fig. 2 Generalized Cenozoic Quaternary stratigraphy of the Dongying Sag, showing tectonic and sedimentary evolution stages and the major petroleum system elements (After Yuan et al. 2015) porosity and permeability testing of 7433 samples of the sandstones. Based on the amount of framework grains, the research area have been collected from the Geological quartz content is 29 %–69.2 % with an average of 43.5 %; Scientific Research Institute of the Sinopec Shengli Oilfield the feldspar content is 14.3 %–47 % with an average of Company. 33.7 %; the content of rock fragments is 2 %–44.2 % with an average of 22.8 %. The mud content is 0.5 %–48 % with an average of 11.0 %, and the cement content is 0.5 %–34.6 % 4 Characteristics and porosity–permeability with an average of 8.2 %. The compositional maturity is evolution of low permeability turbidite 0.41–2.25 with an average of 0.8, and detrital grains are reservoirs moderately sorted, with sub-angular or sub-rounded shapes. 4.1 Characteristics of low permeability turbidite 4.1.2 Reservoir features reservoirs (1) Porosity–permeability 4.1.1 Petrography Based on the porosity–permeability data, the study area is Es turbidite sandstones from the Dongying Sag predomi- characterized by low permeability with an average porosity -3 2 and permeability value of 17.1 % and 38.1 9 10 lm , nantly belong to lithic arkose families based on the sand- stones classification scheme of Folk (1974)(Fig. 4). The respectively. It contains 31 % low porosity reservoirs, 69 % medium to high porosity reservoirs, 88 % low reservoirs are mainly composed of fine to medium grained Neogene Paleogene Paleocene Eocene Oligocene Miocene Pliocene Stage I Stage II Stage III Stage IV Post-rifting stage Syn-rifting stage Arkose 208 Pet. Sci. (2016) 13:204–224 N Chenjiazhuang Salient Chen 33 Chen1 0 8 km WE Yan18 Yan22 Yong79 S Yong920 Li561 Fengshen1 Tuo76 Tuo719 Fengshen2 Qingtuozi Li932 Tuoshen74 Yong88 Ying9 LiShen1 Salient Xin13 Binxian Salient Qing1 Hua8 Ying11 Bin680 Bin333 He184 Lai105 Bin650 He4 Linfanjia Xin176 Bin670 Xin142 Bin658 Lai30 Salient Shi14 Wang58 Lai64 Wang78 Shi10 Lai32 Bin555 Bin53 Lai2 Liang103 Liang107 Jiao10 Wang64 Wang41 Ling209 Lai3 Guan10 Liang47 Liang117 Wanggu1 Guan102 Chun57 Jiao22 Fan120 Guan117 Chun74 Yang2 Guan110 Mian25 Chun96 Guan6 Fan291 Mian106 Tong16 Fan154 Wang112 Bo4 Gao21 Fan138 Qingcheng Tonggu6 Mian121 Salient Cao19 Gao890 Bo17 Cao117 Bo104 Tong23 Bo20 Bo19 Gao8 Guangrao Salient Cao123 Jin21 Bo1 Jin13 Li 9 Nearshore Slump Well location Delta Fan delta Fault subaqueous fans turbidite  Well number Luxi Uplift Shore-shallow Semi-deep lake Flood Erosion Salient Channel lake and deep lake boundary turbidite Fig. 3 Sedimentary facies distribution of Es in Dongying Sag (2) Reservoir space Quartz, % The reservoir space consists of primary pores, mixed pores, Quartzarenite and secondary pores and gaps. Primary pores include the Sublitharenite Subarkose remaining intergranular pores after compaction and cementation and micropores in clay mineral matrices mak- ing up the main pore type (Fig. 6e, f, g). Expansion of pores by dissolution is the main kind of mixed pores (Fig. 6h). There are various kinds of secondary pores and gaps con- taining dissolution pores in particles and cements (Fig. 6k, l), moldic pores (Fig. 6i), intergranular micropores of kaolinite (Fig. 6m, n, o and p), microfractures and diage- netic contraction fractures. As one kind of gravity flow deposits, turbidite is characterized by a large amount of matrix which contains significant amounts of primary micropores. During the process of diagenetic evolution, Lithic Feldspathic arkose litharenite additional intergranular micropores are developed due to the 100 80 60 40 20 0 transformation from feldspar to kaolinite (Bjørlykke 2014; Feldspar, % Rock fragments, % Giles and de Boer 1990) (Fig. 6m, n, o). The large propor- tion of micropores results in much lower permeability of Fig. 4 Triangular plot of sandstones of the low permeability Es reservoirs than that of other reservoirs with the same turbidite reservoirs porosity (Yuan et al. 2013, 2015; Cao et al. 2014). So middle and high porosity low permeability reservoirs are common. permeability reservoirs, and 12 % medium to high per- (3) The characteristics of pore throat structure meability reservoirs. Low permeability reservoirs with middle-high porosity are most common with 59 % of the Using mercury injection data, we classify pore-throat struc- tures according to the parameters of displacement pressure (P ) total reservoirs (Fig. 5). n = Litharenite Legend Pet. Sci. (2016) 13:204–224 209 n=7463 n=7174 0.42% 11.64% 0-5 5-10 10-15 15-25 above 25 Porosity, % 58.98% n=7178 0.1 0.01 28.96% 0.001 above 50 20 0-0.1 0.1-1 1-10 10-50 010 30 40 –3 2 Porosity, % Permeability, 10 μm Fig. 5 Plots illustrating the porosity and permeability distribution of the low permeability Es turbidite reservoirs and median capillary pressure (P ) (Wang et al. 2014a). First, Fig. 6 Typical diagenesis characteristics and reservoir pore types of the low permeability Es turbidite reservoirs. a Wangxie 543, reservoirs are classified into six types according to displace- 3 3177.3 m (–), calcite; b He 140, 2976.6 m (CL), calcite; c Shi 101, ment pressure (P )IA(P B 0.05 MPa), IB (0.05–0.1 MPa d d 3259.5 m (–), quartz overgrowth; d He 135, 3030.87 m (CL), quartz P ), IIA (0.1–0.5 MPa P ), IIB (0.5–2 MPa P ), IIIA d d d overgrowth; e Niu 42, 3258.6 m (–), grain point contact; f He 155, (2–5 MPa P ), and IIIB (P [ 5 MPa). Second, each type is 2987.04 m (–), primary pore; g Shi 101, 3258.6 m (SEM), primary d d pore; h Hao 7, 2961.1 m (–), dissolution expanding pore; i Wangxie further divided into six units according to median capillary 543, 3184.5 m (–), moldic pore; j Wangxie 543, 3180.6 m (SEM), pressure (P ) P B 0.3 MPa, 0.3–1.5 MPa P , 1.5–5 MPa 50 50 50 feldspar dissolution pore; k Dongke 1, 3333.65 m (–), ankerite P ,5–20 MPa P , 20–40 MPa P , P [ 40 MPa. If the P 50 50 50 50 50 dissolution pore; l Dongke 1, 3333.65 m (SEM), ankerite dissolution datum of a sample is not in accordance with the overall char- pore; m Nan 1, 3403.35 m (–), kaolinite replaces feldspar; n He 155, 2987.04 m (SEM), kaolinite replaces feldspar; o Hao 5, 3142.01 m acteristics of a unit, then the sample is assigned to the lower z (SEM), kaolinite filling pore; p Wangxie 543, 3180.6 m (SEM), unit (Wang et al. 2014a). We divide the Es turbidite reservoirs kaolinite part illitization. Q quartz; F feldspar; R rock fragments; in the Dongying Sag into three broad types and six types. Then M matrix; Qa quartz overgrowth; Ka kaolinite; Il illite; Cc carbonate we correlate K/U with K for each type of reservoir (Fig. 7). So, cement; FD feldspar dissolution; CD carbonate dissolution; PP primary pore; (–) plane-polarized light; CL cathodoluminescence; we can determine the ranges of permeability and the ratio of SEM scanning electron microscope permeability to porosity corresponding to various types of reservoirs (Table 1). Reservoirs with different kinds of pore throat structures have the same power function relationship Grains are arranged mainly by point contacts and point- between K/U and K. This reflects that the permeability of low line contacts, reflecting moderate compaction (Fig. 6e). permeability reservoirs is controlled by pore throat structures. The reservoirs are mainly carbonate cemented. The first However, different kinds of reservoirs have different ranges of groups of carbonate cements are calcite and ferroan cal- permeability (Fig. 7). Good pore throat structures are charac- cite. Calcite and ferroan calcite always occur in the form terized by lower P and P ,aswellashigher K/U and K values; of basal cementation (Fig. 6a) or porous cementation d 50 poor pore throat structures are characterized by higher P and (Fig. 6b). The second groups of carbonate cements are P and lower K/U and K values. dolomite, ankerite, and siderite. As revealed from our observations, dolomite, ankerite, and siderite always develop euhedral crystals (Fig. 6k). Quartz overgrowth is 4.1.3 Diagenesis features the main kind of siliceous cementation (Fig. 6c, d). Two phases of quartz overgrowths can be identified by (1) Diagenetic events cathodoluminescence microscopy. The first phase of The major diagenetic events in the research area include quartz overgrowth is dark black and the second phase is compaction, cementation, replacement, and dissolution. brown as also described by Lander et al. (2008) and Frequency, % Frequency, % –3 2 Permeability, 10 μm 210 Pet. Sci. (2016) 13:204–224 123 Pet. Sci. (2016) 13:204–224 211 Fig. 6 continued 123 212 Pet. Sci. (2016) 13:204–224 100 100 100 Type I Type II Type III A A A 10 10 10 0.877 0.6818 0.8897 K/Ф=0.0684K 1 1 1 K/Ф=0.0551K K/Ф=0.0795K 2 R =0.9691 R =0.9265 R =0.9978 0.1 0.1 0.1 0.01 0.01 0.01 0.001 0.001 0.001 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 –3 2 –3 2 –3 2 K, 10 μm K, 10 μm K, 10 μm 100 100 100 Type I Type II Type III B B B 10 10 10 0.6069 K/Ф=0.0403K 0.7008 K/Ф=0.059K 0.8899 K/Ф=0.0748K 2 2 R =0.9068 1 1 R =0.8611 1 R =0.9629 0.1 0.1 0.1 0.01 0.01 0.01 0.001 0.001 0.001 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 –3 2 –3 2 –3 2 K, 10 μm K, 10 μm K, 10 μm Fig. 7 Pore-throat structure types and their porosity–permeability relationships of the low permeability Es turbidite reservoirs Table 1 Ranges of K and K/U -3 2 Type of pore-throat structure K,10 lm K/U P , MPa P , MPa d 50 of different pore structures of the low permeability Es 3 IA [30.6 [1.52 0.02–0.05 0.26–0.61 turbidite reservoirs IB 13.9–183.34 0.68–7.85 0.06–1 0.16–1.26 IIA 0.15–34.3 0.016–1.54 0.15–0.5 0.48–4.41 IIB 0.037–1.95 0.0056–0.12 0.15–2 2.84–22.35 IIIA 0.013–0.96 0.0027–0.058 0.8–4 17.36–74.12 IIIB \0.11 \0.011 3–8 47.8–73.53 Tournier et al. (2010). Kaolinite is the most important inclusions and thermometry analysis of aqueous inclusions kind of clay mineral (Fig. 6m, n, o). Kaolinite mainly which were captured at the same time as hydrocarbon occurs as euhedral booklets and vermicular aggregates inclusions can identify two periods of hydrocarbon accu- with abundant intercrystalline microporosity. The margin mulation. The first period of hydrocarbon accumulation is of kaolinite is fibrous as a result of illitization (Fig. 6p). from 27.5 to 24.6 Ma, and the second period is from The dissolution of feldspar (Fig. 6h, i, j), lithic fragments, 13.8 Ma until now. From observations using cathodolu- carbonate cements, and other minerals which are unsta- minescence and polarizing microscopy, two phases of ble in the acid environment can form honeycomb-shaped quartz overgrowths can be recognized. There are some dissolution expanding pores with curved outlines (Fig. 6k, hydrocarbon inclusions and oil absorption on clay minerals l). Besides this, quartz and quartz overgrowths have been located in the boundaries between quartz grains and over- slightly dissolved. Replacement between carbonate growth rims (Fig. 8i, k) as also described by Girard et al. cements (Fig. 6d), between carbonate cements and detrital (2002) and Higgs et al. (2007). The color of those organic particles (Fig. 6b), between kaolinite and feldspar materials is orange to yellow in fluorescence microscopy (Fig. 6c) all occurred. Replacement between carbonate which reflects the low maturity of hydrocarbon (Liu et al. cements mainly results in dolomite replacing calcite, 2014c; Chen 2014). It can be inferred that the first phase of ferroan calcite replacing calcite, ankerite replacing calcite, quartz overgrowths formed after the early period hydro- and ankerite replacing ferroan calcite. carbon filling. The homogenization temperature of the aqueous inclusions in the first phase of quartz overgrowths ranges from 98 to 118 C with an average of 106 C (2) Paragenesis of diagenetic minerals (Fig. 9). The color of hydrocarbon inclusions in the second On the basis of previous studies (Jiang et al. 2003), the phase of quartz overgrowths is blue and white under the fluorescence microscope which reflects a high hydrocarbon analysis of the fluorescence color of hydrocarbon K/Ф K/Ф K/Ф K/Ф K/Ф K/Ф Pet. Sci. (2016) 13:204–224 213 Fig. 8 Optical microscope micrographs illustrating the texture and nature of the paragenesis of diagenetic minerals of the low permeability Es turbidite reservoirs. a Niu 24, 3175.61 m (–), feldspar dissolution pore filled by ankerite; b Niu 30, 2871.85 m (–), ankerite replaced quartz overgrowth; c Niu 83, 3199.83 m (–), feldspar dissolution pore filled by kaolinite; d Niu 30, 2891.62 m (–), ankerite replaced quartz ferroan calcite; e Liang 49, 2836.13 m (–), siderite growth around a quartz particle; f Niu 128, 3059.55 m (–), pyrite replaced carbonate cements; g Niu 43, 3266.80 m (FL), first period oil filling after feldspar dissolution; h Liang 49, 2838.13 m (FL), blue in cleavage crack and margin of ankerite; i Shi 101, 3263.9 m (FL), orange fluorescence in quartz overgrowth dust trace; j Niu 42, 3261.9 m (FL), blue-white fluorescent organic inclusion in Q2; k Niu 42, 3261.9 m (FL), orange fluorescent organic inclusion in Q1; l Nan 1, 3401.75 m (FL), blue-white fluorescent organic inclusion in ankerite. – plane-polarized light; FL fluorescence; Q1 Quartz overgrowth in the first phase; Q2 Quartz overgrowth in the second phase maturity (Fig. 8j) (Chen 2014). It can be concluded that the ranges from 120 to 146 C with an average of 134 C quartz overgrowths formed after the late period hydrocar- (Fig. 9). Temperatures calculated from the O isotope ratios bon fill. The homogenization temperature of the aqueous in early carbonate cements (dolomite and calcite) range inclusions in the second phase of quartz overgrowths from 66 to 102 C (Guo et al. 2014), and temperatures 123 214 Pet. Sci. (2016) 13:204–224 Quartz overgrowth in the first period, 106.15 °C Quartz overgrowth in the second period, 134.35 °C Quartz overgrowth in the second period Quartz overgrowth in the first period 12 3 4 5 6 Niu 42, 3261.9, fluid inclusion distribution Temperature measurement in the two periods of quartz overgrowth data points Fig. 9 Fluid inclusion homogenization temperatures of the two phases of quartz overgrowths of the low permeability Es turbidite reservoirs calculated from the isotope ratios in late carbonate cements pyrite cementation. Compaction existed throughout the (ferroan calcite and ankerite) range from 110 to 147 C entire burial and evolutional processes. (Zhang 2012). There are some blue and white color According to the burial history and organic evolution hydrocarbon inclusions in the ankerite under fluorescence history analysis for the reservoirs in the research area, microscopy (Fig. 8l), and cleavage cracks and the edges of combined with the diagenetic environment implied by ankerite grains are impregnated by hydrocarbon with blue- authigenic minerals, the reservoir experienced a diagenetic white fluorescence (Fig. 8h) (Wilkinson et al. 2006). We environment evolution from slightly alkaline ? can infer that the ankerite formed at the same time as acid ? alkaline ? slightly acidic now. The early slightly hydrocarbon charging. alkaline diagenetic environment was controlled by the The siderites and some micritic carbonate have grown original sedimentary water from 42 to 38 Ma (Qi et al. 2006). around the quartz particles without quartz overgrowths With the increase of burial depth, a larger amount of organic (Fig. 8e), showing that siderite cements formed earlier than acid was produced from the evolution of organic matter in x s the quartz overgrowths. The feldspar dissolution pores high-quality source rocks in Es and Es (Surdam et al. 3 4 were filled by ankerite (Fig. 8a), so feldspar dissolution 1989). The diagenetic pore-water became acidic, which occurred earlier than ankerite cementation. Ankerite lasted from 38 to 28 Ma, and the temperature of reservoirs cementation occurred later than quartz overgrowth reflec- was from 80 to 120 C. With further increase in burial depth, ted by the replacement relation between ankerite and quartz organic acid decarboxylation and the alkaline fluid from the overgrowth (Fig. 8b). Ankerite replaced ferroan calcite gypsum in Es dominated the diagenetic environment from (Fig. 8d), so ankerite cementation occurred later than fer- 28 to 16.4 Ma (Wang 2010). The strata were uplifted by the roan calcite. The feldspar dissolution pores were filled by Dongying Movement, and organic acid was generated again. kaolinite (Fig. 8c), so feldspar dissolution took place ear- The diagenetic pore water became acid again from 16.4 to lier than kaolinite cementation. Pyrite replaces carbonate 5 Ma. From 5 Ma to now, organic acid was generated from cements (Fig. 8f), so pyrite formed later than carbonate source rock in Es . As a result of this process, the diagenetic cements. pore water is considered to have remained acidic. After the analysis of timing and order of hydrocarbon filling and formation of various authigenic minerals, the 4.2 Porosity–permeability evolution of Es low- paragenesis of authigenic minerals was determined. Siderite/ permeability turbidity reservoirs micritic carbonate ? first dissolution of feldspar ? the beginning of the first hydrocarbon filling ? first quartz Based on the diagenetic features and paragenetic sequen- overgrowth/authigenic kaolinite precipitation ? the first ces, the porosity and permeability estimation method for group of carbonate cementation ? the end of the first the geological history of the reservoirs has been used hydrocarbon filling ? dissolution of quartz/feldspar over- (Wang et al. 2013a; Cao 2010). According to this method, growth ? second dissolution of feldspar and carbonate we can determine the porosity and permeability of the cementation ? the beginning of the second hydrocarbon reservoirs in the accumulation period. First, we take the filling ? second quartz overgrowth/authigenic kaolinite thin sections of reservoir samples as the study object. After precipitation ? the second group of carbonate cementation/ the analysis of the paragenetic sequence and diagenetic Homogenization temperature, °C Pet. Sci. (2016) 13:204–224 215 -3 2 fluid evolution combined with the study of burial history, of 0.31 9 10 lm is close to the actual measured per- -3 2 we determine the geological time and burial depth of dia- meability of 0.307 9 10 lm . genetic events. Second, we fit the function of plane On the basis of diagenetic paragenetic sequences and the type porosity and visual reservoir porosity from the analysis of and strength of diagenetic events, the reservoir can be divided thin sections, and then we can calculate the contributions of into four types of diagenetic facies. These are strong com- different dissolution pores and authigenic minerals to paction—weak dissolution of feldspar—weak cementation of porosity increase or decrease. After the calculation of ini- carbonate: Diagenetic facies (A); weak compaction—weak tial porosity, the evolution of porosity can be estimated dissolution of feldspar—strong cementation of carbonate: Dia- with the principle of inversion and back-stripping con- genetic facies (B); weak compaction—strong dissolution of straint of the diagenetic paragenetic sequences. Third, the feldspar—weak cementation of carbonate: Diagenetic facies evolution history of actual porosity with geological time or (C); and medium compaction—medium dissolution of feld- burial depth with different diagenetic characteristics can be spar—medium cementation of carbonate: Diagenetic facies (D). established quantitatively combined with the chart of Thin sandstones mainly develop diagenetic facies A and dia- mechanical and thermal compaction correction. Fourth, on genetic facies B. Thick sandstones develop diagenetic facies A the basis of characteristics of pore throat structure, and B in the reservoirs adjacent to mudstones, and diagenetic according to the back-stripping constraint result of plane facies C and D in the middle of sandstones (McMahon et al. porosity and the principle of equivalent expanding, the pore 1992). Typical samples of different kinds of diagenetic facies throat structures of reservoirs can be estimated at the were selected and their evolution of porosity–permeability were geological time of the main diagenetic events. Finally, estimated (Fig. 11). The results show that in the early accu- according to the relationship between pore throat structure mulation period, all reservoirs except for reservoirs with dia- and porosity, the evolution of permeability in geological genetic facies A have middle-high permeability ranging from -3 2 -3 2 time can be estimated with the relationships of porosity and 10 9 10 lm to 4207 9 10 lm . In the later accumula- permeability in different kinds of pore throat structures. tion period, all reservoirs except for reservoirs with diagenetic Taking the turbidite reservoir at the Niu107 well at facies C have low permeability ranging from -3 2 -3 2 3025.5 m as example (Fig. 10), the estimated permeability 0.015 9 10 lm to 62 9 10 lm . Type of Palaeo- -3 2 Evolution of Porosity evolution, % Permeability evolution, 10 μm Accum Time, pore Diagenetic burial pore throat –ulation throat events 0.01 1 100 10 Ma depth, m 02 10 0 30 40 50 period structure structure 42.0% (0m) 55873.05 ΔΦ Mechanical compaction: –6.5% Compaction Siderites ΔΦ Thermal compaction: –2.75% After deposition cementation 32.75% (1001.12m) 1000 5857.47 Compaction 38 Ma Feldspar 1200 ΔΦ Mechanical compaction: –7% dissolution ΔΦ Thermal compaction: –2% Quartz ΔΦ Feldspar dissolution: +3.93% ΔΦ Quartz overgrowth: –2.64% I overgrowth Kaolinite 1600 deposition 28 Ma 525.97 27.5 Ma (1837.18m) 28 26.64% Compaction 1.33 Early Carbonate ΔΦ Mechanical compaction:–0.18% cementation 24.6 Ma II Quartz dissolution ΔΦ Carbonate cementation: –13.57% 13.8 Ma 16.4 2200 ΔΦ Compaction Quartz dissolution: +0.25% Carbonate 16.4 Ma dissolution 15.15% (1902.25m) 5 0.93 ΔΦ Mechanical compaction: –1.02% Later Compaction ΔΦ Carbonate dissolution: +0.36% II Pyrite 2800 14.48% (2417.87m) cementation 5 Ma ΔΦ Mechanical compaction: –1.05% 0.31 ΔΦ Pyrite cementation: –0.89% 0 Ma 0.307 (Actual measurement) 12.54% (3032.5m) II Carbonate Kaolinite Pyrite Bitumen Micro-pores Feldspar dissolution Quartz dissolution Quartz overgrowth Quartz Fig. 10 Porosity-permeability evolution history of the low permeability Es turbidite reservoirs (Well Niu107, 3032.5 m) 123 216 Pet. 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(2016) 13:204–224 Well He146, 3095.8, Diagenetic facies (A) Niu42, 3264.7, Diagenetic facies (B) Accum -3 2 -3 2 -ulation Porosity evolution, % Permeability evolution, 10 μm Porosity evolution, % Permeability evolution, 10 μm Time, period 0 10 20 3040 50 0.01 1 100 10 1020 3040 50 0.01 1 100 10 Ma (0m) (0m) 41.5% 36.5% 50124.19 15651.65 ΔΦ Mechanical compaction: –11.7% ΔΦ Mechanical compaction: –11.5% ΔΦ Thermal compaction: –2.75% ΔΦ Thermal compaction: –2.75% (1212.27m) (1216.85m) 27.05% 22.25% 1034.71 176.06 38 ΔΦ Mechanical compaction: –6.1% ΔΦ Mechanical compaction: –4.3% ΔΦ Thermal compaction: –2% ΔΦ Thermal compaction: –2% ΔΦ Feldspar dissolution: +3.03% ΔΦ Feldspar dissolution: +3.68% ΔΦ Quartz overgrowth: –2.02% ΔΦ Quartz overgrowth: –2.02% (2053.84m) 22.34% (1924.09m) 27.5 20.36% 106.24 28 45.59 ΔΦ Mechanical compaction: –0% Early ΔΦ Mechanical compaction: –0.01% ΔΦ Carbonate cementation: –17.75% 24.6 ΔΦ Carbonate cementation:–11.51% ΔΦ Quartz dissolution: +0.15% ΔΦ Quartz dissolution:+0.34% 0.11 4.74% (2149.02m) 0.015 13.8 16.4 (2064.49m) 11.17% ΔΦ Mechanical compaction: –0% ΔΦ Mechanical compaction: –0.02% ΔΦ Carbonate dissolution: +0% ΔΦ Carbonate dissolution: +0% Later (2644.94m) 4.74% (2496.11m) 11.15% 5 0.11 0.015 ΔΦ Mechanical compaction: –0.02% ΔΦ Mechanical compaction: –0% ΔΦ Pyrite cementation: –0% ΔΦ Pyrite cementation:+0% 11.13% (3095.8m) 4.74% (3264.7m) 0.11 0.015 Well Hao7, 2973.69, Diagenetic facies (C) Shi3, 3348.4, Diagenetic facies (D) Accum -3 2 -3 2 -ulation Porosity evolution, % Permeability evolution, 10 μm Porosity evolution, % Permeability evolution, 10 μm Time, period 0 10 20 30 40 50 0.01 1 100 10 0 10 20 30 40 50 0.01 1 100 10 Ma 44% (0m) 41.5% (0m) 85186.34 50124.19 ΔΦ Mechanical compaction: –11.5% ΔΦ Mechanical compaction: –9% ΔΦ Thermal compaction: –2.75% ΔΦ Thermal compaction: –2.75% (1168.86m) (1216.85m) 29.75% 29.75% 2451.49 2451.49 38 ΔΦ Mechanical compaction: –5% ΔΦ Mechanical compaction: –7.6% ΔΦ Thermal compaction: –2% ΔΦ Thermal compaction: –2% ΔΦ Feldspar dissolution: +12.57% ΔΦ Feldspar dissolution: +5.54% ΔΦ Quartz overgrowth: –3.0% ΔΦ Quartz overgrowth: –0.37% (1924.09m) 31.58% (1848.19m) 25.57% 27.5 361.94 4207.3 ΔΦ Mechanical compaction: –0.2% ΔΦ Mechanical compaction: –1.76% Early ΔΦ Carbonate cementation: –12.64% 24.6 ΔΦ Carbonate cementation: –8.7% ΔΦ Quartz dissolution: +0.34% ΔΦ Quartz dissolution: +0% 3.62 21.08% (1983.06m) 17.13% (2064.49m) 13.8 16.4 62.56 ΔΦ Mechanical compaction: –0.75% ΔΦ Mechanical compaction: –1.82% ΔΦ Carbonate dissolution: +0% ΔΦ Carbonate dissolution: +0% Later (2397.65m) (2496.11m) 20.33% 15.31% 0.711 5 44.95 ΔΦ Mechanical compaction: –0.92% ΔΦ Mechanical compaction: –1.82% Pyrite cementation: –0.34% ΔΦ ΔΦ Pyrite cementation: –0.34% (3095.8m) 19.06% (2973.69m) 13.14% 28.9 0.095 Fig. 11 Porosity-permeability evolution history of different diagenetic facies low permeability Es turbidite reservoirs and permeability in the accumulation period under the 5 Cutoff-values for porosity and permeability constraint of accumulation dynamics and pore throat of turbidite reservoirs in the accumulation period structure (Wang et al. 2014a). The method procedure includes: (1) establishing a functional relationship between Capillary pressure (Pc) is the most important resistance oil–water interfacial tension and formation temperature; (2) calculating lower limiting values of maximum connected force in hydrophilic reservoir rocks. Only when the dynamic force surpasses the resistance force, can petro- pore-throat radius according to formation temperature and dynamic forces of each reservoir interval; (3) correlating leum seep into rocks and form petroleum reservoirs (Hao permeability with maximum connected pore-throat radius et al. 2010). We calculated the cutoff-values for porosity 123 Pet. Sci. (2016) 13:204–224 217 and then obtaining cutoff-values for permeability in the 6 Control on the oil-bearing potential accumulation period; and (4) calculating cutoff-values for of a reservoir by the relationship porosity on the basis of cutoff-values for permeability between permeability and dynamics according to specific correlations suitable for the type of in the accumulation period pore-throat structure (Wang et al. 2014a). According to the test data of oil–water interfacial ten- 6.1 Accumulation dynamics estimation sion (d) for different formation temperature (T) in the Es and Es reservoirs in the Dongying Sag, the functional The turbidite reservoirs are located in overpressured for- relationship can be written as (Wang et al. 2014a): mations of the Dongying Sag. Overpressure is the main 0:149 2 dynamic controlling hydrocarbon accumulation (Zhuo d ¼ 40:5  T ; R ¼ 0:65 ð1Þ et al. 2006; Sui et al. 2008; Gao et al. 2010). Disequilib- This equation could be used to calculate the oil–water rium stresses under a high subsidence rate or rapid burial interfacial tension at any given formation temperature. For and hydrocarbon generation are the two possible over- example, for a formation temperature of 125 C which is pressure generating mechanisms in sedimentary basins close to the actual formation temperature of Es in the 3 (Bao et al. 2007; Bloch et al. 2002; Taylor et al. 2010). By research area, the calculated oil–water interfacial tension is means of fluid inclusion PVT simulation, the minimum 19.7 mN/m. For a fixed critical accumulation dynamic fluid pressure in the hydrocarbon accumulation period can value P , we can get cutoffs of maximum connected pore f be obtained. According to basin modeling techniques, fluid throat radius using equation r = 2dcosh/P when the 0 f pressure resulting from disequilibrium compaction can be wetting contact angle of oil–water is 0 and interfacial determined (the balance pressure between sandstones and tension at 125 C is 19.7 mN/m (Table 2). mudstones). The differences between those two pressures Establishing a correlation between permeability and are the increased minimum fluid pressure of hydrocarbon maximum connected pore-throat radius using mercury generation. For an isolated lenticular sand body without injection data (Fig. 12), we find that there is a good faults, fluid pressures generated by disequilibrium com- exponential relationship between permeability and the paction would transfer from mudstones to sandstones to maximum connected pore-throat radius as: reach a balance of fluid pressure (Cai et al. 2009). So the 1:7992 2 fluid pressure generated by hydrocarbon generation is the K ¼ 0:3927  r ; R ¼ 0:8275; ð2Þ main accumulation dynamic. For a sand body with faults -3 2 where K is the permeability, 10 lm ; r is the maximum 0 developed, the surplus pressure which is the difference connected pore-throat radius, lm. between fluid pressure and hydrostatic pressure will result Substituting the limiting value of the maximum con- in fluid migration through the faults which is the main nected pore-throat radius under different critical accumu- accumulation dynamic (Zhuo et al. 2006; Cai et al. 2009). lation dynamics into Eq. (2), a series of cutoff-values for According to the estimations of the accumulation dynamics permeability in the accumulation period can be obtained at of reservoirs in the research area (Table 3), in the early 125 C (Table 2). accumulation period the fluid pressure increase by hydro- On the basis of the classification of pore-throat struc- carbon generation is 1.4–11.3 MPa with an average of tures, according to the functional relationships between 5.14 MPa, and the surplus pressure is 1.8–12.6 MPa with K and K/U of different pore-throat structures as well as an average of 6.3 MPa. In the late accumulation period the their variation ranges (Fig. 4, Table 1), we calculated fluid pressure increased by hydrocarbon generation is cutoff-values for porosity according to variation ranges of 0.7–12.7 MPa with an average of 5.4 MPa, and the surplus permeability in Table 1 and regarded those values as cut- pressure is 1.3–16.2 MPa with an average of 6.6 MPa. The off-values for porosity in the accumulation period for the accumulation dynamics in the later accumulation period corresponding type of pore-throat structures under different are stronger than those in the early accumulation period. critical accumulation dynamics. With the same method, we can calculate the cutoff-values for porosity and perme- 6.2 Coupling of dynamics and permeability ability in the accumulation period for the corresponding in the hydrocarbon accumulation period type of pore-throat structures under different critical accumulation dynamics at different formation temperatures The estimation of the permeability of reservoirs with dif- (Fig. 13). ferent diagenetic facies indicated that the permeability of the 123 218 Pet. Sci. (2016) 13:204–224 Table 2 Cutoff-values for porosity and permeability of the low permeability Es turbidite reservoirs under the constraint of the accumulation dynamics and pore throat structure and at 125 C formation temperature -3 2 Accumulation Maximum connected pore-throat K ,10 lm U ,% cutoff cutoff dynamics P , MPa radius r , lm f 0 U U U U U U IA IB IIA IIB IIIA IIIB 0.01 48.45 422.82 24.04 – – – – – 0.02 24.22 121.49 21.62 22.68 – – – – 0.024 20.19 87.51 21.02 21.87 – – – – 0.026 18.63 75.78 20.77 21.53 – – – – 0.03 16.15 58.58 20.32 20.93 – – – – 0.04 12.11 34.91 19.44 19.77 22.63 – – – 0.05 9.69 23.37 – 18.91 21.54 – – – 0.055 8.81 19.68 – 18.56 21.09 – – – 0.06 8.07 16.83 – 18.24 20.69 – – – 0.065 7.45 14.57 – 17.96 20.33 – – – 0.07 6.92 12.75 – – 20.0 – – – 0.075 6.46 11.27 – – 19.69 – – – 0.08 6.06 10.03 – – 19.41 – – – 0.09 5.38 8.12 – – 18.91 – – – 0.1 4.84 6.71 – – 18.48 – – – 0.2 2.42 1.93 – – 15.85 20.63 – – 0.3 1.62 0.93 – – 14.49 16.59 17.74 – 0.32 1.51 0.83 – – 14.29 16.02 17.09 – 0.4 1.21 0.55 – – 13.60 14.21 15.04 – 0.49 1 0.39 – – 13.0 12.74 13.39 – 0.5 0.97 0.37 – – 12.94 12.60 13.24 – 0.7 0.69 0.2 – – 12.01 10.51 10.92 – 0.9 0.54 0.13 – – – 9.18 9.46 – 1 0.48 0.11 – – – 8.68 8.90 10.29 1.2 0.4 0.077 – – – 7.86 8.02 9.05 1.4 0.35 0.058 – – – 7.24 7.34 8.11 1.5 0.32 0.051 – – – 6.97 7.06 7.73 1.6 0.3 0.046 – – – 6.74 6.80 7.38 2 0.24 0.031 – – – – 5.99 6.30 2.2 0.22 0.026 – – – – 5.67 5.89 2.4 0.2 0.022 – – – – 5.39 5.54 2.5 0.19 0.021 – – – – 5.27 5.38 3 0.16 0.015 – – – – 4.75 4.73 3.2 0.15 0.013 – – – – 4.57 4.52 3.4 0.14 0.012 – – – – – 4.33 3.6 0.14 0.011 – – – – – 4.16 4 0.12 0.009 – – – – – 3.86 6 0.08 0.004 – – – – – 2. 90 8 0.06 0.003 – – – – – 2.37 10 0.05 0.002 – – – – – 2.02 -3 2 reservoir ranged from 10 9 10 lm to 4207 9 generation is 1.4–11.3 MPa with an average value of -3 2 10 lm in the early accumulation period. When there is no 5.1 MPa. Using the minimum accumulation dynamics of fault development in the sand body, the fluid pressure 1.4 MPa, the maximum cutoff-value for permeability in the increased by hydrocarbon generation is the main accumu- accumulation period at a formation temperature of 125 C -3 2 lation dynamic. The fluid pressure increased by hydrocarbon was calculated to be 0.058 9 10 lm . The permeability of 123 Pet. Sci. (2016) 13:204–224 219 maximum cutoff-value for permeability in the accumula- 1.7992 K=0.3927r tion period at a formation temperature of 125 C was cal- R²= 0.8275 -3 2 culated to be 0.203 9 10 lm . Using the maximum accumulation dynamics of 12.7 MPa, the minimum cutoff- value for permeability in the accumulation period at a formation temperature of 125 C is calculated to be -3 2 0.001 9 10 lm . So, at the high level of accumulation 0.1 dynamics hydrocarbon can accumulate in all studied 0.01 reservoirs. Reservoirs with diagenetic facies A and diage- netic facies B do not develop accumulation conditions at 0.001 the low level of accumulation dynamics, because the per- 0.01 0.1 1 10 100 Maximum connected pore-throat radius, μm meability of reservoirs with diagenetic facies A and dia- genetic facies B is lower than the maximum cutoff value. Fig. 12 The relationship between permeability and maximum con- z The surplus pressure is 1.3–16.2 MPa with an average of nected pore-throat radius of the low permeability Es turbidite 6.6 MPa. Using the minimum accumulation dynamics reservoirs 1.3 MPa, the maximum cutoff-value for permeability in the accumulation period at a formation temperature of 125 C the reservoir in the early accumulation period was much -3 2 higher than this cutoff-value, so all the studied reservoirs was calculated to be 0.066 9 10 lm . Using the maxi- mum accumulation dynamics 16.2 MPa, the minimum could accumulate hydrocarbon. When there is fault devel- cutoff-value for permeability in the accumulation period at opment in the sand body, the surplus pressure is the main a formation temperature of 125 C was calculated to be accumulation dynamic. The surplus pressure is -3 2 0.0007 9 10 lm . So, different kinds of reservoirs can 1.8–12.6 MPa with an average of 6.3 MPa. Using the min- all accumulate hydrocarbon with high accumulation imum accumulation dynamics of 1.8 MPa, the maximum dynamics. Reservoirs with diagenetic facies A and diage- cutoff-value for permeability in the accumulation period at a netic facies B do not develop accumulation conditions at formation temperature of 125 C was calculated to be -3 2 the low level of accumulation dynamics. 0.037 9 10 lm . The permeability of the reservoirs in the early accumulation period was much higher than this cutoff- 6.3 Distribution of hydrocarbon resources value, so all the studied reservoirs could accumulate hydrocarbon. The Es source rocks are not fully mature, because the In the later accumulation period the permeability had -3 2 z been reduced and was in the range of 0.015 9 10 lm to burial depth of the Es turbidite reservoirs ranges from -3 2 62 9 10 lm . The fluid pressure increased by hydro- 2500 to 3500 m. Oil–source correlation analysis indicated carbon generation was 0.7 MPa to 12.7 MPa with an that the oil of the low permeability turbidite reservoirs in average of 5.4 MPa in the late accumulation period. Using the early accumulation period comes from source rocks in x s the minimum accumulation dynamics of 0.7 MPa, the Es and Es (Cai 2009). The source rocks are overlain by 3 4 Porosity and permeability cutoffs Porosity and permeability cutoffs Porosity and permeability cutoffs in accumulation time at 75 °C in accumulation time at 100 °C in accumulation time at 125 °C -3 2 -3 2 -3 2 Permeability cutoff, 10 μm Po ro sit y cu t o ff , % Permeability cutoff, 10 μm Po ro sity cu to ff , % Permeability cutoff, 10 μm Po ro sity cu to ff , % 0.001 0.01 0.1 1 10 100 1000 0 5 10 15 20 25 0.001 0.01 0.1 1 10 100 1000 05 10 15 20 25 0.001 0.01 0.1 1 10 100 1000 05 10 15 20 25 0.01 0.01 0.01 0.01 0.01 0.01C I I A A I B 0.1 0.1 0.1 0.1 0.1 0.1 II II A II II II II III 1 1 1 1 1 1 III III III III III B B 10 10 10 10 10 10 Fig. 13 Cutoff-values for porosity and permeability under different formation temperatures of the low permeability Es turbidite reservoirs Accumulation dynamic force, MPa -3 2 Permeability, 10 μm Accumulation dynamic force, MPa Accumulation dynamic force, MPa Accumulation dynamic force, MPa Accumulation dynamic force, MPa Accumulation dynamic force, MPa 220 Pet. 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(2016) 13:204–224 Table 3 Estimates of accumulation dynamics of the low permeability Es turbidite reservoirs (Zhang 2014) Well Depth, m Paleo-fluid Paleopressure after Geological Palaeo-burial Hydrostatic Pressure generated by Surplus pressure, Pressure Accumulation pressure, MPa disequilibrium time, Ma depth, m pressure, MPa hydrocarbon, MPa MPa coefficient period compaction, MPa Xin 154 2936 31.9 31.2 2.3 2800 28 0.7 3.9 1.14 Late Xin 154 2939 22 19.5 27.5 1950 19.5 2.5 2.5 1.13 Early Xin 154 2939 26.8 23.7 7.5 2350 23.5 3.1 3.3 1.14 Late Xin 154 2942.8 29.6 31.2 2.3 2800 28 – 1.6 1.06 Late Niu 108 3146.5 23.8 22.4 25.3 2200 22 1.4 1.8 1.08 Early Niu 108 3146.5 33.2 21.6 11 2000 20 11.6 13.2 1.66 Late Niu 108 3146.5 18.6 21.6 11 2000 20 – – 0.93 Late Niu 35 2991.7 22.3 21.4 9.8 2100 21 0.9 1.3 1.06 Late Niu 107 3272.5 34.6 23.9 9.5 2290 22.9 10.7 11.7 1.51 Late Shi128 3099 33.3 32.2 2.6 2850 28.5 1.1 4.8 1.17 Late Shi 128 3099 27.8 22 9.3 2140 21.4 5.8 6.4 1.30 Late Niu 20 3073 43 30.3 3 2680 26.8 12.7 16.2 1.60 Late Niu 20 3073 28.3 22.5 9.1 2150 21.5 5.8 6.8 1.32 Late Niu 24 3159.2 27.9 24.3 25.9 2150 21.5 3.6 6.4 1.30 Early Niu 24 3159.2 29.1 25.4 6 2450 24.5 3.7 4.6 1.19 Late Niu 24 3159.2 32.9 31.2 3.6 2710 27.1 1.7 5.8 1.21 Late Niu 24 3175.6 38.6 27.3 4.7 2630 26.3 11.3 12.3 1.47 Late Niu 24 3175.6 32.2 25.3 24.8 2400 24 6.9 8.2 1.34 Early Niu 24 3175.6 36.6 25.3 24.8 2400 24 11.3 12.6 1.53 Early Niu 24 3175.6 27 23.7 9.8 2350 23.5 3.3 3.5 1.15 Late Niu 24 3175.6 26.4 23.7 9.8 2350 23.5 2.7 2.9 1.12 Late 4145000 4140000 4135000 4145000 4140000 4135000 1.1 1.1 1.7 1.4 1.3 1.1 1.3 1.4 1.2 1.4 1.1 1.1 Pet. 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(2016) 13:204–224 221 z z Immature source rock in Es Immature source rock in Es 3 3 Lowly mature source rock in Es Fluid pressure decrease Later accumulation period (13.8–0 Ma) Early accumulation period (34–24.8 Ma) Legend Low permeability Overpressure High permeability Early Later Oil-source Carbonate Early hydrocarbon Later hydrocarbon sandstone sandstone hydrocarbons hydrocarbons fault cement migration migration fracture Fig. 14 The hydrocarbon accumulation patterns of low permeability Es turbidite reservoirs 20620000 20625000 20630000 20635000 20640000 20645000 20650000 01 2km Niuxie 879 Niuxie 113 Niuxie 878 He 127 Niuxie 109 Niuxie 874 Niuxie114 He 129 He 45 Wangxie 583 Niuxie 44 Wangxie 582 Wang 60 Wang 588–10 Wangxie 115 Shixie 137 Wang 545 Wang 27 Wang 57–2 Wangxie 543 Wang 127 Wang 542 C Xinwang 50 Wangxie 544 Wang 72 Wangxie 118 Wangxie 114 Wang 102-202 Wang 2 Shixie 132 F3 Niu1–Wang52 Fault Niu 12 Niu 93 Niu 100 Niuxie 302 Niu 100 C Niu35 Pressure Fault Well Oilfields coefficient 20620000 20625000 20630000 20635000 20640000 20645000 20650000 Fig. 15 The hydrocarbon distribution of the low permeability Es turbidite reservoirs the reservoir rocks, and the generated oil migrates from the and Es accumulate hydrocarbon easily. Duo to hetero- lower part to the upper part (the reservoir). Faults in source geneity caused by diagenetic processes (Liu et al. 2014a), rocks controlled the accumulation of reservoirs. The oil of hydrocarbon accumulation mostly occurred in the reser- the low permeability turbidite reservoirs in the late accu- voirs with high permeability under the control of oil-source x s mulation period comes from source rock in Es ,Es , and faults (Fig. 14). The fluid pressure increased by hydrocar- 3 4 bon generation is the main accumulation dynamic for iso- Es (Li et al. 2007). The source rocks are either below the reservoirs or both the source rocks and reservoir rocks are lated lenticular sand bodies without faults in the later accumulation period. All types of reservoirs with high from the same formation. Surplus pressure is the main accumulation dynamic in accumulation dynamics can accumulate hydrocarbon. Reservoirs with diagenetic facies A and diagenetic facies B the early accumulation period. In the early accumulation period, the permeability of all reservoirs is higher than the do not develop accumulation conditions at the low level of accumulation dynamics in the later accumulation period cutoff-values for permeability. So, the sand bodies with fault development and connected with source rock in Es because the permeability of reservoir with diagenetic facies 1.4 1.2 1.4 1.3 1.2 1.3 1.2 1.2 1.5 F1 Xianhe Fault 1.5 1.3 1.3 F2 Niu27–He122 Fault 1.5 1.5 1.4 1.3 Legend 1.2 222 Pet. Sci. (2016) 13:204–224 A and diagenetic facies B is lower than the maximum second hydrocarbon filling ? second quartz over- cutoff value. Surplus pressure is the main accumulation growth/authigenic kaolinite precipitation ? the dynamic for sand bodies with fault development. All types second group of carbonate cementation/pyrite of reservoirs with high accumulation dynamics can accu- cementation. Compaction existed throughout the entire burial and evolutional processes. mulate hydrocarbon. Reservoirs with diagenetic facies A and diagenetic facies B do not develop accumulation (2) In the early accumulation period, the reservoirs except for diagenetic facies A had middle to high conditions at the low level of accumulation dynamics. -3 2 Hydrocarbon always accumulated in reservoirs with high permeability ranging from 10 9 10 lm to -3 2 4207.3 9 10 lm , all the studied reservoirs can accumulation dynamics and oil-source faults development. Source rocks of the lower part of Es have a high maturity accumulate hydrocarbon. In the later accumulation period the reservoirs except for diagenetic facies C when the burial depth of turbidite reservoir is more than 3000 m (Hao et al. 2006). The oil in the reservoirs came have low permeability ranging from -3 2 -3 2 0.015 9 10 lm to 62 9 10 lm , all the stud- from the source rocks both at the same burial depth as the reservoirs and from a deeper burial depth than the reser- ied reservoirs can accumulate hydrocarbon at the high level of accumulation dynamics. Reservoirs voirs. The closer to the source rocks, the higher accumu- with diagenetic facies A and diagenetic facies B do lation dynamics and the higher the hydrocarbon-filling not develop accumulation conditions at the low level degree. So isolated lenticular sand bodies can accumulate of accumulation dynamics. hydrocarbon. As the distances from source rocks to reser- voirs increases, the accumulation dynamics for the reser- (3) The hydrocarbon-filling degree is higher when the burial depth of turbidite reservoirs is more than voirs decrease and the hydrocarbon-filling degree decreases as well. The distance limit for an isolated lenticular sand 3000 m. Isolated lenticular sand bodies can accu- mulate hydrocarbon. When the burial depth of body to accumulate hydrocarbon is about 225 m from the lower part of source rocks (Song et al. 2014) (Fig. 14). turbidite reservoirs is less than 3000 m, isolated lenticular sand bodies cannot accumulate hydrocar- When the burial depth of turbidite reservoir is less than 3000 m, the oil in the reservoirs came from the source bon. Hydrocarbons always accumulate in reservoirs around the oil-source faults and areas near the center rocks at deeper burial depth than the reservoirs. The oil- of subsags with high accumulation dynamics. source faults controlled the accumulation of reservoirs. Taking the Niuzhuang subsag as an example, hydrocarbon always accumulated in reservoirs around the oil-source Acknowledgments This work is supported by the National Natural faults and areas near the center of subsag with high accu- Science Foundation of China (Grant No. U1262203), the National Science and Technology Special Grant (No. 2011ZX05006-003), the mulation dynamics (Fig. 15). Fundamental Research Funds for the Central Universities (Grant No. 14CX06070A), and the Chinese Scholarship Council (No. 201506450029). The Shengli Oilfield Company of SINOPEC pro- vided all the related core samples and some geological data. The 7 Conclusions authors wish to thank editors and reviewers for their thorough and very constructive review that greatly improved the manuscript. (1) Es turbidite sandstones in the Dongying Sag are Open Access This article is distributed under the terms of the mostly lithic arkoses, and composed of mainly fine Creative Commons Attribution 4.0 International License (http://crea to medium sized grains. Low permeability reservoirs tivecommons.org/licenses/by/4.0/), which permits unrestricted use, distribution, and reproduction in any medium, provided you give with middle to high porosity are most common, and appropriate credit to the original author(s) and the source, provide a the reservoir space is mainly primary pores. There link to the Creative Commons license, and indicate if changes were are three broad types of pore throat structures which made. are subdivided into six sub-types. The major diage- netic events are mechanical compaction, cementa- tion, replacement, and dissolution. 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The coupling of dynamics and permeability in the hydrocarbon accumulation period controls the oil-bearing potential of low permeability reservoirs: a case study of the low permeability turbidite reservoirs in the middle part of the third member of Shahejie Formation in Dongying Sag

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Earth Sciences; Mineral Resources; Industrial Chemistry/Chemical Engineering; Industrial and Production Engineering; Energy Economics
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Pet. Sci. (2016) 13:204–224 DOI 10.1007/s12182-016-0099-0 ORIGINAL PAPER The coupling of dynamics and permeability in the hydrocarbon accumulation period controls the oil-bearing potential of low permeability reservoirs: a case study of the low permeability turbidite reservoirs in the middle part of the third member of Shahejie Formation in Dongying Sag 1,2,3 1,2 1,2 3 • • • • Tian Yang Ying-Chang Cao Yan-Zhong Wang Henrik Friis 4 1,2,4 1,2 • • Beyene Girma Haile Ke-Lai Xi Hui-Na Zhang Received: 24 March 2015 / Published online: 29 April 2016 The Author(s) 2016. This article is published with open access at Springerlink.com Abstract The relationships between permeability and reservoirs except for diagenetic facies A had middle to -3 2 dynamics in hydrocarbon accumulation determine oil- high permeability ranging from 10 9 10 lm to -3 2 bearing potential (the potential oil charge) of low perme- 4207 9 10 lm . In the later accumulation period, the ability reservoirs. The evolution of porosity and perme- reservoirs except for diagenetic facies C had low perme- -3 2 -3 2 ability of low permeability turbidite reservoirs of the ability ranging from 0.015 9 10 lm to 62 9 10 lm . middle part of the third member of the Shahejie Formation In the early accumulation period, the fluid pressure increased in the Dongying Sag has been investigated by detailed core by the hydrocarbon generation was 1.4–11.3 MPa with an descriptions, thin section analyses, fluid inclusion analyses, average value of 5.1 MPa, and a surplus pressure of carbon and oxygen isotope analyses, mercury injection, 1.8–12.6 MPa with an average value of 6.3 MPa. In the later porosity and permeability testing, and basin modeling. The accumulation period, the fluid pressure increased by the cutoff values for the permeability of the reservoirs in the hydrocarbon generation process was 0.7–12.7 MPa with an accumulation period were calculated after detailing the average value of 5.36 MPa and a surplus pressure of accumulation dynamics and reservoir pore structures, then 1.3–16.2 MPa with an average value of 6.5 MPa. Even the distribution pattern of the oil-bearing potential of though different types of reservoirs exist, all can form reservoirs controlled by the matching relationship between hydrocarbon accumulations in the early accumulation per- dynamics and permeability during the accumulation period iod. Such types of reservoirs can form hydrocarbon accu- were summarized. On the basis of the observed diagenetic mulation with high accumulation dynamics; however, features and with regard to the paragenetic sequences, the reservoirs with diagenetic facies A and diagenetic facies B reservoirs can be subdivided into four types of diagenetic do not develop accumulation conditions with low accumu- facies. The reservoirs experienced two periods of hydro- lation dynamics in the late accumulation period for very low carbon accumulation. In the early accumulation period, the permeability. At more than 3000 m burial depth, a larger proportion of turbidite reservoirs are oil charged due to the proximity to the source rock. Also at these depths, lenticular & Ying-Chang Cao sand bodies can accumulate hydrocarbons. At shallower cyc8391680@163.com depths, only the reservoirs with oil-source fault development School of Geosciences, China University of Petroleum, can accumulate hydrocarbons. For flat surfaces, hydrocar- Qingdao 266580, Shandong, China bons have always been accumulated in the reservoirs around Laboratory for Marine Mineral Resources, Qingdao National the oil-source faults and areas near the center of subsags Laboratory for Marine Science and Technology, with high accumulation dynamics. Qingdao 266071, China Department of Geoscience, Aarhus University, Høegh- Keywords Reservoir porosity and permeability Guldbergs Gade 2, 8000 Aarhus C, Denmark evolution  Accumulation dynamics  Cutoff-values of Department of Geosciences, University of Oslo, permeability in the accumulation period  Oil-bearing P.O. Box 1047, Blindern, 0316 Oslo, Norway potential  Low permeability reservoir  The third member of the Shahejie Formation  Dongying Sag Edited by Jie Hao 123 Pet. Sci. (2016) 13:204–224 205 reservoir pore-throat geometries, and finally the distribu- 1 Introduction tion pattern of the oil-bearing potential of the reservoirs is With the increasing interest in oil and gas exploration and determined. This can provide theoretical guidance for the exploration and development of low permeability turbidite development, low permeability clastic rock reservoirs are becoming key exploration target areas (Yang et al. 2010; reservoirs. Cao et al. 2012). The low permeability clastic rock reser- voirs have gone through complex diagenetic events (Yang 2 Geological background et al. 2010; Wang et al. 2011). The distribution of sand- stone porosity is not consistent with the hydrocarbon The Dongying Sag is a sub-tectonic unit lying in the accumulation. The porosity of sandstone during the accu- southeastern part of the Jiyang Depression of the Bohai mulation period is the key factor to determine the oiliness Bay Basin, East China. It is a Mesozoic-Cenozoic half of the reservoirs (Cao et al. 2012; Liu et al. 2014a; Wang graben rift-downwarped basin with lacustrine facies et al. 2014a). Some researchers have attempted to extract data from the porosity of low permeability clastic rock directly deposited on Paleozoic bedrocks (Cao et al. 2014; Wang et al. 2014b). The Dongying Sag is bounded to the reservoirs during the accumulation period (Cao et al. 2011, 2012, 2013; Wang et al. 2013a; Liu et al. 2014a). However, east by the Qingtuozi Salient, to the south by the Luxi Uplift and Guangrao Salient, to the west by the Linfanjia they did not calculate the cutoff values for porosity of the reservoir under the control of accumulation dynamics and Gaoqing salients, and to the north by the Chenji- azhuang-Binxian Salient. The NE-trending sag covers an during the accumulation period (Pan et al. 2011; Wang area of 5850 km (Fig. 1). It is a half graben with a faulted et al. 2014a; Liu et al. 2014a). The distribution of the oil- northern margin and a gentle southern margin. Horizon- bearing potential of reservoirs is still poorly understood. tally, this sag is further subdivided into several secondary The relationships between porosity and the oil-bearing structural units, such as the northern steep slope zone, potential of turbidite reservoirs of the middle part of the middle uplift belt, and the Lijin, Minfeng and Niuzhuang third member of Shahejie Formation (Es ) in Dongying Sag are complex, even though the reservoirs have similar trough zones, Boxing subsag, and the southern gentle zone (Zhang et al. 2014). The sag is filled with Cenozoic sedi- accumulation conditions. The high or low porosity and permeability sandstone reservoirs either contain oil or not. ments, which are formations from the Paleogene, Neogene, and Quaternary periods. The formations from the Paleo- Liu et al. (2014a, b) analyzed the relationship between porosity and the cutoff-values for porosity in the early gene period are the Kongdian (Ek), Shahejie (Es), and Dongying (Ed); the formations from the Neogene period accumulation period of Es turbidite reservoirs in Niuz- huang subsag with the guide of porosity estimation and are the Guantao (Ng) and Minghuazhen (Nm); and the formation from the Quaternary period is the Pingyuan effect-oriented simulation. They concluded that the (Qp). Detailed descriptions of the Paleogene stratigraphy porosity of reservoirs in the early accumulation period was higher than the cutoff-values for porosity of the reservoirs. have been provided by several authors (Zhang et al. 2004, 2010; Guo et al. 2012) (Fig. 2). So the reservoirs could be charged with oil. The perme- ability is the main controlling factor for percolation and the During the deposition of the third member of the Sha- hejie Formation, tectonic movement was strong, and the development of low permeability reservoirs (Meng et al. 2013). There were several stages of accumulation for the basin subsided rapidly reaching its maximum depth. As a result, large amounts of detrital materials were transported Es turbidite reservoirs in the Dongying Sag and the later accumulation period was the most important (Cai 2009). into the basin and formed plentiful source rocks and tur- bidites in deep-water environments in the depressed zone The permeability and the cutoff-values at the later accu- and uplifted zone (Wang et al. 2013b; Yang et al. 2015) mulation period are the most important for the distribution (Fig. 3). The thickness of single sand layers of turbidite of the oil-bearing potential of reservoirs today. reservoirs is 0.1–0.5 m; the accumulation thickness is On the basis of previous studies, taking the Es tur- bidite reservoirs as an example, the permeability of the 10–158 m. Turbidity current deposits with Bouma sequences and debris flow deposits with massive bedding reservoirs in the accumulation period was estimated. The permeability estimation method was based on the para- are most common. The east slope of the Niuzhuang subsag, Liangjialou, and the front of the Dongying delta are places genetic sequence of diagenetic minerals and the reservoir pore-throat geometry. The cutoff-values for permeability where a large volume of turbidites are distributed (Yang et al. 2015). Most turbidite reservoirs are low permeability of reservoirs in the accumulation period are calculated after the estimation of accumulation dynamics and with complex oil-bearing characteristics. 123 Qingtuozi Salient Chenguanzhuang Fault Shicun fault zone 206 Pet. Sci. (2016) 13:204–224 42e (a) N (b) Sag 0 100 km N 0 10 20 km Uplift 40e Beijing Yanshan A’ Chenjiazhuang Salient Č Dalian Bohai Bay 38e Coastline China Northern zone Jinan 36e Beijing steep Minfeng Tanlu Strike-slip Fault Zone Binxian subsag 114e 116e 118e 120e 122e 124e Salient uplift area Middle Lizezheng subsag Qingcheng Boxing subsag Salient Paleogene Paleogene system A system area overlap zone Luxi Uplift Study Major Paleogene system area fault denuded zone Guangrao Lijin Northern Luxi South gentle slope Niuzhuang subsag Uplift Central anticline steep slope subsag Uplift A’ N─Q Es ─Ed Es ─Es 3 2 Ek─Es Mz (c) Fig. 1 a Location map showing the six major sub basins of the Bohai Bay Basin. b Structural map of the Dongying Sag. The area in the green line box is the study area (After Liu et al. 2014a). c N–S cross section (A –A) of the Dongying Sag showing the various tectonic-structural zones and key stratigraphic intervals 3 Materials and methods were tested by a 3020-62 helium porosity analyzer and GDS-9F gas permeability analyzer at common temperature Over 1500 m of representative cores of turbidite in the and humidity. Mercury injection was tested by a 9505 mercury injection analyzer at 22 C and 60 % humidity. target formation have been described. 119 typical samples Samples were examined by a JSM-5500LVSEM combined were taken from the core. Thin section examination and with QUANTAX400 energy dispersive X-ray microanaly- porosity and permeability testing of all 119 samples were ser (EDX). The thin sections and fluorescence thin sections undertaken. Mercury injection testing of 90 samples, scanning electron microscopy (SEM) examination of 15 were prepared by the CNPC Key Laboratory of Oil and Gas reservoirs at the China University of Petroleum and samples, cathode luminescence testing of 17 samples, flu- orescence thin section observation of 17 samples, and fluid were examined using an Axioscope A1 APOL digital polarizing microscope produced by the German company inclusion testing of 53 samples were undertaken. The core samples were provided by the Geological Scientific Zeiss. The cathodoluminescence was studied using an Imager D2 m cathode luminescence microscope also pro- Research Institute of the Sinopec Shengli Oilfield Com- pany. Porosity, permeability, and mercury injections were duced by Zeiss. The fluid inclusions were analyzed using a THMSG600 conventional inclusion temperature measure- measured at the Exploration and Development Research ment system produced by the British Company Linkam. Institute of the Sinopec Zhongyuan Oilfield Company as Sandstone composition analysis data of 2314 samples and were the SEM examinations. Porosity and permeability fault slope Boxing fault zone Binnan-Lijin fault zone Chennan Tuo-Sheng-Yong sub-fracture Guangrao Salient Southern slope Chenguanzhuang-wangjiagang fault zone zone Niuzhuang subsag Lijin subsag Chennan Fault Linfanjia Salient Fold Belt Bamianhe fault zone Shicun Fault Liaodong Uplift Cangxian Uplift Luxi Uplift Gaoqing fault zone Jiaodong Uplift Taihangshan Uplift Depth, km Pet. Sci. (2016) 13:204–224 207 Stratigraphy Main Age Thickness Reservoir Seal Tectonic Sedimentary Lithology source System Series Sub- (Ma) (m) environment rocks rocks evolution Formation Member member rocks Quarternary Pingyuan (Qp) 100-230 Floodplain Minghuazhen (Nm) Floodplain 600-900 5.1 Ng Guantao 300-400 Braided stream (Ng) Ng 24.6 Deltaic Ed 0-110 28.1 Deltaic Dongying 0-280 Lacustrine Ed (Ed) Deltaic Ed 0-420 Lacustrine 32.8 Deltaic Es 0-450 Lacustrine Deltaic Es 38.0 0-350 Fluvial Deltaic Es 100-300 Fluvial Es 3 2 Fan deltaic Es 3 200-500 Shahejie Subaqueous fan (Es) Turbidite fan Es 200-600 Lacustrine 42.5 Es 300-700 Subaqueous fan Es Turbidite fan Es 200-800 (Salt) Lacustrine 52.0 Fluvial Ek 0-1300 Salt lake Kongdian Ek Fluvial (Ek) 0-900 Lacustrine Ek 65.0 Conglomerates Sandstones Siltstones Mudstones Carbonates Volcanic rocks Evaporites Uncomformity Fig. 2 Generalized Cenozoic Quaternary stratigraphy of the Dongying Sag, showing tectonic and sedimentary evolution stages and the major petroleum system elements (After Yuan et al. 2015) porosity and permeability testing of 7433 samples of the sandstones. Based on the amount of framework grains, the research area have been collected from the Geological quartz content is 29 %–69.2 % with an average of 43.5 %; Scientific Research Institute of the Sinopec Shengli Oilfield the feldspar content is 14.3 %–47 % with an average of Company. 33.7 %; the content of rock fragments is 2 %–44.2 % with an average of 22.8 %. The mud content is 0.5 %–48 % with an average of 11.0 %, and the cement content is 0.5 %–34.6 % 4 Characteristics and porosity–permeability with an average of 8.2 %. The compositional maturity is evolution of low permeability turbidite 0.41–2.25 with an average of 0.8, and detrital grains are reservoirs moderately sorted, with sub-angular or sub-rounded shapes. 4.1 Characteristics of low permeability turbidite 4.1.2 Reservoir features reservoirs (1) Porosity–permeability 4.1.1 Petrography Based on the porosity–permeability data, the study area is Es turbidite sandstones from the Dongying Sag predomi- characterized by low permeability with an average porosity -3 2 and permeability value of 17.1 % and 38.1 9 10 lm , nantly belong to lithic arkose families based on the sand- stones classification scheme of Folk (1974)(Fig. 4). The respectively. It contains 31 % low porosity reservoirs, 69 % medium to high porosity reservoirs, 88 % low reservoirs are mainly composed of fine to medium grained Neogene Paleogene Paleocene Eocene Oligocene Miocene Pliocene Stage I Stage II Stage III Stage IV Post-rifting stage Syn-rifting stage Arkose 208 Pet. Sci. (2016) 13:204–224 N Chenjiazhuang Salient Chen 33 Chen1 0 8 km WE Yan18 Yan22 Yong79 S Yong920 Li561 Fengshen1 Tuo76 Tuo719 Fengshen2 Qingtuozi Li932 Tuoshen74 Yong88 Ying9 LiShen1 Salient Xin13 Binxian Salient Qing1 Hua8 Ying11 Bin680 Bin333 He184 Lai105 Bin650 He4 Linfanjia Xin176 Bin670 Xin142 Bin658 Lai30 Salient Shi14 Wang58 Lai64 Wang78 Shi10 Lai32 Bin555 Bin53 Lai2 Liang103 Liang107 Jiao10 Wang64 Wang41 Ling209 Lai3 Guan10 Liang47 Liang117 Wanggu1 Guan102 Chun57 Jiao22 Fan120 Guan117 Chun74 Yang2 Guan110 Mian25 Chun96 Guan6 Fan291 Mian106 Tong16 Fan154 Wang112 Bo4 Gao21 Fan138 Qingcheng Tonggu6 Mian121 Salient Cao19 Gao890 Bo17 Cao117 Bo104 Tong23 Bo20 Bo19 Gao8 Guangrao Salient Cao123 Jin21 Bo1 Jin13 Li 9 Nearshore Slump Well location Delta Fan delta Fault subaqueous fans turbidite  Well number Luxi Uplift Shore-shallow Semi-deep lake Flood Erosion Salient Channel lake and deep lake boundary turbidite Fig. 3 Sedimentary facies distribution of Es in Dongying Sag (2) Reservoir space Quartz, % The reservoir space consists of primary pores, mixed pores, Quartzarenite and secondary pores and gaps. Primary pores include the Sublitharenite Subarkose remaining intergranular pores after compaction and cementation and micropores in clay mineral matrices mak- ing up the main pore type (Fig. 6e, f, g). Expansion of pores by dissolution is the main kind of mixed pores (Fig. 6h). There are various kinds of secondary pores and gaps con- taining dissolution pores in particles and cements (Fig. 6k, l), moldic pores (Fig. 6i), intergranular micropores of kaolinite (Fig. 6m, n, o and p), microfractures and diage- netic contraction fractures. As one kind of gravity flow deposits, turbidite is characterized by a large amount of matrix which contains significant amounts of primary micropores. During the process of diagenetic evolution, Lithic Feldspathic arkose litharenite additional intergranular micropores are developed due to the 100 80 60 40 20 0 transformation from feldspar to kaolinite (Bjørlykke 2014; Feldspar, % Rock fragments, % Giles and de Boer 1990) (Fig. 6m, n, o). The large propor- tion of micropores results in much lower permeability of Fig. 4 Triangular plot of sandstones of the low permeability Es reservoirs than that of other reservoirs with the same turbidite reservoirs porosity (Yuan et al. 2013, 2015; Cao et al. 2014). So middle and high porosity low permeability reservoirs are common. permeability reservoirs, and 12 % medium to high per- (3) The characteristics of pore throat structure meability reservoirs. Low permeability reservoirs with middle-high porosity are most common with 59 % of the Using mercury injection data, we classify pore-throat struc- tures according to the parameters of displacement pressure (P ) total reservoirs (Fig. 5). n = Litharenite Legend Pet. Sci. (2016) 13:204–224 209 n=7463 n=7174 0.42% 11.64% 0-5 5-10 10-15 15-25 above 25 Porosity, % 58.98% n=7178 0.1 0.01 28.96% 0.001 above 50 20 0-0.1 0.1-1 1-10 10-50 010 30 40 –3 2 Porosity, % Permeability, 10 μm Fig. 5 Plots illustrating the porosity and permeability distribution of the low permeability Es turbidite reservoirs and median capillary pressure (P ) (Wang et al. 2014a). First, Fig. 6 Typical diagenesis characteristics and reservoir pore types of the low permeability Es turbidite reservoirs. a Wangxie 543, reservoirs are classified into six types according to displace- 3 3177.3 m (–), calcite; b He 140, 2976.6 m (CL), calcite; c Shi 101, ment pressure (P )IA(P B 0.05 MPa), IB (0.05–0.1 MPa d d 3259.5 m (–), quartz overgrowth; d He 135, 3030.87 m (CL), quartz P ), IIA (0.1–0.5 MPa P ), IIB (0.5–2 MPa P ), IIIA d d d overgrowth; e Niu 42, 3258.6 m (–), grain point contact; f He 155, (2–5 MPa P ), and IIIB (P [ 5 MPa). Second, each type is 2987.04 m (–), primary pore; g Shi 101, 3258.6 m (SEM), primary d d pore; h Hao 7, 2961.1 m (–), dissolution expanding pore; i Wangxie further divided into six units according to median capillary 543, 3184.5 m (–), moldic pore; j Wangxie 543, 3180.6 m (SEM), pressure (P ) P B 0.3 MPa, 0.3–1.5 MPa P , 1.5–5 MPa 50 50 50 feldspar dissolution pore; k Dongke 1, 3333.65 m (–), ankerite P ,5–20 MPa P , 20–40 MPa P , P [ 40 MPa. If the P 50 50 50 50 50 dissolution pore; l Dongke 1, 3333.65 m (SEM), ankerite dissolution datum of a sample is not in accordance with the overall char- pore; m Nan 1, 3403.35 m (–), kaolinite replaces feldspar; n He 155, 2987.04 m (SEM), kaolinite replaces feldspar; o Hao 5, 3142.01 m acteristics of a unit, then the sample is assigned to the lower z (SEM), kaolinite filling pore; p Wangxie 543, 3180.6 m (SEM), unit (Wang et al. 2014a). We divide the Es turbidite reservoirs kaolinite part illitization. Q quartz; F feldspar; R rock fragments; in the Dongying Sag into three broad types and six types. Then M matrix; Qa quartz overgrowth; Ka kaolinite; Il illite; Cc carbonate we correlate K/U with K for each type of reservoir (Fig. 7). So, cement; FD feldspar dissolution; CD carbonate dissolution; PP primary pore; (–) plane-polarized light; CL cathodoluminescence; we can determine the ranges of permeability and the ratio of SEM scanning electron microscope permeability to porosity corresponding to various types of reservoirs (Table 1). Reservoirs with different kinds of pore throat structures have the same power function relationship Grains are arranged mainly by point contacts and point- between K/U and K. This reflects that the permeability of low line contacts, reflecting moderate compaction (Fig. 6e). permeability reservoirs is controlled by pore throat structures. The reservoirs are mainly carbonate cemented. The first However, different kinds of reservoirs have different ranges of groups of carbonate cements are calcite and ferroan cal- permeability (Fig. 7). Good pore throat structures are charac- cite. Calcite and ferroan calcite always occur in the form terized by lower P and P ,aswellashigher K/U and K values; of basal cementation (Fig. 6a) or porous cementation d 50 poor pore throat structures are characterized by higher P and (Fig. 6b). The second groups of carbonate cements are P and lower K/U and K values. dolomite, ankerite, and siderite. As revealed from our observations, dolomite, ankerite, and siderite always develop euhedral crystals (Fig. 6k). Quartz overgrowth is 4.1.3 Diagenesis features the main kind of siliceous cementation (Fig. 6c, d). Two phases of quartz overgrowths can be identified by (1) Diagenetic events cathodoluminescence microscopy. The first phase of The major diagenetic events in the research area include quartz overgrowth is dark black and the second phase is compaction, cementation, replacement, and dissolution. brown as also described by Lander et al. (2008) and Frequency, % Frequency, % –3 2 Permeability, 10 μm 210 Pet. Sci. (2016) 13:204–224 123 Pet. Sci. (2016) 13:204–224 211 Fig. 6 continued 123 212 Pet. Sci. (2016) 13:204–224 100 100 100 Type I Type II Type III A A A 10 10 10 0.877 0.6818 0.8897 K/Ф=0.0684K 1 1 1 K/Ф=0.0551K K/Ф=0.0795K 2 R =0.9691 R =0.9265 R =0.9978 0.1 0.1 0.1 0.01 0.01 0.01 0.001 0.001 0.001 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 –3 2 –3 2 –3 2 K, 10 μm K, 10 μm K, 10 μm 100 100 100 Type I Type II Type III B B B 10 10 10 0.6069 K/Ф=0.0403K 0.7008 K/Ф=0.059K 0.8899 K/Ф=0.0748K 2 2 R =0.9068 1 1 R =0.8611 1 R =0.9629 0.1 0.1 0.1 0.01 0.01 0.01 0.001 0.001 0.001 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 0.001 0.01 0.1 1 10 100 1000 –3 2 –3 2 –3 2 K, 10 μm K, 10 μm K, 10 μm Fig. 7 Pore-throat structure types and their porosity–permeability relationships of the low permeability Es turbidite reservoirs Table 1 Ranges of K and K/U -3 2 Type of pore-throat structure K,10 lm K/U P , MPa P , MPa d 50 of different pore structures of the low permeability Es 3 IA [30.6 [1.52 0.02–0.05 0.26–0.61 turbidite reservoirs IB 13.9–183.34 0.68–7.85 0.06–1 0.16–1.26 IIA 0.15–34.3 0.016–1.54 0.15–0.5 0.48–4.41 IIB 0.037–1.95 0.0056–0.12 0.15–2 2.84–22.35 IIIA 0.013–0.96 0.0027–0.058 0.8–4 17.36–74.12 IIIB \0.11 \0.011 3–8 47.8–73.53 Tournier et al. (2010). Kaolinite is the most important inclusions and thermometry analysis of aqueous inclusions kind of clay mineral (Fig. 6m, n, o). Kaolinite mainly which were captured at the same time as hydrocarbon occurs as euhedral booklets and vermicular aggregates inclusions can identify two periods of hydrocarbon accu- with abundant intercrystalline microporosity. The margin mulation. The first period of hydrocarbon accumulation is of kaolinite is fibrous as a result of illitization (Fig. 6p). from 27.5 to 24.6 Ma, and the second period is from The dissolution of feldspar (Fig. 6h, i, j), lithic fragments, 13.8 Ma until now. From observations using cathodolu- carbonate cements, and other minerals which are unsta- minescence and polarizing microscopy, two phases of ble in the acid environment can form honeycomb-shaped quartz overgrowths can be recognized. There are some dissolution expanding pores with curved outlines (Fig. 6k, hydrocarbon inclusions and oil absorption on clay minerals l). Besides this, quartz and quartz overgrowths have been located in the boundaries between quartz grains and over- slightly dissolved. Replacement between carbonate growth rims (Fig. 8i, k) as also described by Girard et al. cements (Fig. 6d), between carbonate cements and detrital (2002) and Higgs et al. (2007). The color of those organic particles (Fig. 6b), between kaolinite and feldspar materials is orange to yellow in fluorescence microscopy (Fig. 6c) all occurred. Replacement between carbonate which reflects the low maturity of hydrocarbon (Liu et al. cements mainly results in dolomite replacing calcite, 2014c; Chen 2014). It can be inferred that the first phase of ferroan calcite replacing calcite, ankerite replacing calcite, quartz overgrowths formed after the early period hydro- and ankerite replacing ferroan calcite. carbon filling. The homogenization temperature of the aqueous inclusions in the first phase of quartz overgrowths ranges from 98 to 118 C with an average of 106 C (2) Paragenesis of diagenetic minerals (Fig. 9). The color of hydrocarbon inclusions in the second On the basis of previous studies (Jiang et al. 2003), the phase of quartz overgrowths is blue and white under the fluorescence microscope which reflects a high hydrocarbon analysis of the fluorescence color of hydrocarbon K/Ф K/Ф K/Ф K/Ф K/Ф K/Ф Pet. Sci. (2016) 13:204–224 213 Fig. 8 Optical microscope micrographs illustrating the texture and nature of the paragenesis of diagenetic minerals of the low permeability Es turbidite reservoirs. a Niu 24, 3175.61 m (–), feldspar dissolution pore filled by ankerite; b Niu 30, 2871.85 m (–), ankerite replaced quartz overgrowth; c Niu 83, 3199.83 m (–), feldspar dissolution pore filled by kaolinite; d Niu 30, 2891.62 m (–), ankerite replaced quartz ferroan calcite; e Liang 49, 2836.13 m (–), siderite growth around a quartz particle; f Niu 128, 3059.55 m (–), pyrite replaced carbonate cements; g Niu 43, 3266.80 m (FL), first period oil filling after feldspar dissolution; h Liang 49, 2838.13 m (FL), blue in cleavage crack and margin of ankerite; i Shi 101, 3263.9 m (FL), orange fluorescence in quartz overgrowth dust trace; j Niu 42, 3261.9 m (FL), blue-white fluorescent organic inclusion in Q2; k Niu 42, 3261.9 m (FL), orange fluorescent organic inclusion in Q1; l Nan 1, 3401.75 m (FL), blue-white fluorescent organic inclusion in ankerite. – plane-polarized light; FL fluorescence; Q1 Quartz overgrowth in the first phase; Q2 Quartz overgrowth in the second phase maturity (Fig. 8j) (Chen 2014). It can be concluded that the ranges from 120 to 146 C with an average of 134 C quartz overgrowths formed after the late period hydrocar- (Fig. 9). Temperatures calculated from the O isotope ratios bon fill. The homogenization temperature of the aqueous in early carbonate cements (dolomite and calcite) range inclusions in the second phase of quartz overgrowths from 66 to 102 C (Guo et al. 2014), and temperatures 123 214 Pet. Sci. (2016) 13:204–224 Quartz overgrowth in the first period, 106.15 °C Quartz overgrowth in the second period, 134.35 °C Quartz overgrowth in the second period Quartz overgrowth in the first period 12 3 4 5 6 Niu 42, 3261.9, fluid inclusion distribution Temperature measurement in the two periods of quartz overgrowth data points Fig. 9 Fluid inclusion homogenization temperatures of the two phases of quartz overgrowths of the low permeability Es turbidite reservoirs calculated from the isotope ratios in late carbonate cements pyrite cementation. Compaction existed throughout the (ferroan calcite and ankerite) range from 110 to 147 C entire burial and evolutional processes. (Zhang 2012). There are some blue and white color According to the burial history and organic evolution hydrocarbon inclusions in the ankerite under fluorescence history analysis for the reservoirs in the research area, microscopy (Fig. 8l), and cleavage cracks and the edges of combined with the diagenetic environment implied by ankerite grains are impregnated by hydrocarbon with blue- authigenic minerals, the reservoir experienced a diagenetic white fluorescence (Fig. 8h) (Wilkinson et al. 2006). We environment evolution from slightly alkaline ? can infer that the ankerite formed at the same time as acid ? alkaline ? slightly acidic now. The early slightly hydrocarbon charging. alkaline diagenetic environment was controlled by the The siderites and some micritic carbonate have grown original sedimentary water from 42 to 38 Ma (Qi et al. 2006). around the quartz particles without quartz overgrowths With the increase of burial depth, a larger amount of organic (Fig. 8e), showing that siderite cements formed earlier than acid was produced from the evolution of organic matter in x s the quartz overgrowths. The feldspar dissolution pores high-quality source rocks in Es and Es (Surdam et al. 3 4 were filled by ankerite (Fig. 8a), so feldspar dissolution 1989). The diagenetic pore-water became acidic, which occurred earlier than ankerite cementation. Ankerite lasted from 38 to 28 Ma, and the temperature of reservoirs cementation occurred later than quartz overgrowth reflec- was from 80 to 120 C. With further increase in burial depth, ted by the replacement relation between ankerite and quartz organic acid decarboxylation and the alkaline fluid from the overgrowth (Fig. 8b). Ankerite replaced ferroan calcite gypsum in Es dominated the diagenetic environment from (Fig. 8d), so ankerite cementation occurred later than fer- 28 to 16.4 Ma (Wang 2010). The strata were uplifted by the roan calcite. The feldspar dissolution pores were filled by Dongying Movement, and organic acid was generated again. kaolinite (Fig. 8c), so feldspar dissolution took place ear- The diagenetic pore water became acid again from 16.4 to lier than kaolinite cementation. Pyrite replaces carbonate 5 Ma. From 5 Ma to now, organic acid was generated from cements (Fig. 8f), so pyrite formed later than carbonate source rock in Es . As a result of this process, the diagenetic cements. pore water is considered to have remained acidic. After the analysis of timing and order of hydrocarbon filling and formation of various authigenic minerals, the 4.2 Porosity–permeability evolution of Es low- paragenesis of authigenic minerals was determined. Siderite/ permeability turbidity reservoirs micritic carbonate ? first dissolution of feldspar ? the beginning of the first hydrocarbon filling ? first quartz Based on the diagenetic features and paragenetic sequen- overgrowth/authigenic kaolinite precipitation ? the first ces, the porosity and permeability estimation method for group of carbonate cementation ? the end of the first the geological history of the reservoirs has been used hydrocarbon filling ? dissolution of quartz/feldspar over- (Wang et al. 2013a; Cao 2010). According to this method, growth ? second dissolution of feldspar and carbonate we can determine the porosity and permeability of the cementation ? the beginning of the second hydrocarbon reservoirs in the accumulation period. First, we take the filling ? second quartz overgrowth/authigenic kaolinite thin sections of reservoir samples as the study object. After precipitation ? the second group of carbonate cementation/ the analysis of the paragenetic sequence and diagenetic Homogenization temperature, °C Pet. Sci. (2016) 13:204–224 215 -3 2 fluid evolution combined with the study of burial history, of 0.31 9 10 lm is close to the actual measured per- -3 2 we determine the geological time and burial depth of dia- meability of 0.307 9 10 lm . genetic events. Second, we fit the function of plane On the basis of diagenetic paragenetic sequences and the type porosity and visual reservoir porosity from the analysis of and strength of diagenetic events, the reservoir can be divided thin sections, and then we can calculate the contributions of into four types of diagenetic facies. These are strong com- different dissolution pores and authigenic minerals to paction—weak dissolution of feldspar—weak cementation of porosity increase or decrease. After the calculation of ini- carbonate: Diagenetic facies (A); weak compaction—weak tial porosity, the evolution of porosity can be estimated dissolution of feldspar—strong cementation of carbonate: Dia- with the principle of inversion and back-stripping con- genetic facies (B); weak compaction—strong dissolution of straint of the diagenetic paragenetic sequences. Third, the feldspar—weak cementation of carbonate: Diagenetic facies evolution history of actual porosity with geological time or (C); and medium compaction—medium dissolution of feld- burial depth with different diagenetic characteristics can be spar—medium cementation of carbonate: Diagenetic facies (D). established quantitatively combined with the chart of Thin sandstones mainly develop diagenetic facies A and dia- mechanical and thermal compaction correction. Fourth, on genetic facies B. Thick sandstones develop diagenetic facies A the basis of characteristics of pore throat structure, and B in the reservoirs adjacent to mudstones, and diagenetic according to the back-stripping constraint result of plane facies C and D in the middle of sandstones (McMahon et al. porosity and the principle of equivalent expanding, the pore 1992). Typical samples of different kinds of diagenetic facies throat structures of reservoirs can be estimated at the were selected and their evolution of porosity–permeability were geological time of the main diagenetic events. Finally, estimated (Fig. 11). The results show that in the early accu- according to the relationship between pore throat structure mulation period, all reservoirs except for reservoirs with dia- and porosity, the evolution of permeability in geological genetic facies A have middle-high permeability ranging from -3 2 -3 2 time can be estimated with the relationships of porosity and 10 9 10 lm to 4207 9 10 lm . In the later accumula- permeability in different kinds of pore throat structures. tion period, all reservoirs except for reservoirs with diagenetic Taking the turbidite reservoir at the Niu107 well at facies C have low permeability ranging from -3 2 -3 2 3025.5 m as example (Fig. 10), the estimated permeability 0.015 9 10 lm to 62 9 10 lm . Type of Palaeo- -3 2 Evolution of Porosity evolution, % Permeability evolution, 10 μm Accum Time, pore Diagenetic burial pore throat –ulation throat events 0.01 1 100 10 Ma depth, m 02 10 0 30 40 50 period structure structure 42.0% (0m) 55873.05 ΔΦ Mechanical compaction: –6.5% Compaction Siderites ΔΦ Thermal compaction: –2.75% After deposition cementation 32.75% (1001.12m) 1000 5857.47 Compaction 38 Ma Feldspar 1200 ΔΦ Mechanical compaction: –7% dissolution ΔΦ Thermal compaction: –2% Quartz ΔΦ Feldspar dissolution: +3.93% ΔΦ Quartz overgrowth: –2.64% I overgrowth Kaolinite 1600 deposition 28 Ma 525.97 27.5 Ma (1837.18m) 28 26.64% Compaction 1.33 Early Carbonate ΔΦ Mechanical compaction:–0.18% cementation 24.6 Ma II Quartz dissolution ΔΦ Carbonate cementation: –13.57% 13.8 Ma 16.4 2200 ΔΦ Compaction Quartz dissolution: +0.25% Carbonate 16.4 Ma dissolution 15.15% (1902.25m) 5 0.93 ΔΦ Mechanical compaction: –1.02% Later Compaction ΔΦ Carbonate dissolution: +0.36% II Pyrite 2800 14.48% (2417.87m) cementation 5 Ma ΔΦ Mechanical compaction: –1.05% 0.31 ΔΦ Pyrite cementation: –0.89% 0 Ma 0.307 (Actual measurement) 12.54% (3032.5m) II Carbonate Kaolinite Pyrite Bitumen Micro-pores Feldspar dissolution Quartz dissolution Quartz overgrowth Quartz Fig. 10 Porosity-permeability evolution history of the low permeability Es turbidite reservoirs (Well Niu107, 3032.5 m) 123 216 Pet. Sci. (2016) 13:204–224 Well He146, 3095.8, Diagenetic facies (A) Niu42, 3264.7, Diagenetic facies (B) Accum -3 2 -3 2 -ulation Porosity evolution, % Permeability evolution, 10 μm Porosity evolution, % Permeability evolution, 10 μm Time, period 0 10 20 3040 50 0.01 1 100 10 1020 3040 50 0.01 1 100 10 Ma (0m) (0m) 41.5% 36.5% 50124.19 15651.65 ΔΦ Mechanical compaction: –11.7% ΔΦ Mechanical compaction: –11.5% ΔΦ Thermal compaction: –2.75% ΔΦ Thermal compaction: –2.75% (1212.27m) (1216.85m) 27.05% 22.25% 1034.71 176.06 38 ΔΦ Mechanical compaction: –6.1% ΔΦ Mechanical compaction: –4.3% ΔΦ Thermal compaction: –2% ΔΦ Thermal compaction: –2% ΔΦ Feldspar dissolution: +3.03% ΔΦ Feldspar dissolution: +3.68% ΔΦ Quartz overgrowth: –2.02% ΔΦ Quartz overgrowth: –2.02% (2053.84m) 22.34% (1924.09m) 27.5 20.36% 106.24 28 45.59 ΔΦ Mechanical compaction: –0% Early ΔΦ Mechanical compaction: –0.01% ΔΦ Carbonate cementation: –17.75% 24.6 ΔΦ Carbonate cementation:–11.51% ΔΦ Quartz dissolution: +0.15% ΔΦ Quartz dissolution:+0.34% 0.11 4.74% (2149.02m) 0.015 13.8 16.4 (2064.49m) 11.17% ΔΦ Mechanical compaction: –0% ΔΦ Mechanical compaction: –0.02% ΔΦ Carbonate dissolution: +0% ΔΦ Carbonate dissolution: +0% Later (2644.94m) 4.74% (2496.11m) 11.15% 5 0.11 0.015 ΔΦ Mechanical compaction: –0.02% ΔΦ Mechanical compaction: –0% ΔΦ Pyrite cementation: –0% ΔΦ Pyrite cementation:+0% 11.13% (3095.8m) 4.74% (3264.7m) 0.11 0.015 Well Hao7, 2973.69, Diagenetic facies (C) Shi3, 3348.4, Diagenetic facies (D) Accum -3 2 -3 2 -ulation Porosity evolution, % Permeability evolution, 10 μm Porosity evolution, % Permeability evolution, 10 μm Time, period 0 10 20 30 40 50 0.01 1 100 10 0 10 20 30 40 50 0.01 1 100 10 Ma 44% (0m) 41.5% (0m) 85186.34 50124.19 ΔΦ Mechanical compaction: –11.5% ΔΦ Mechanical compaction: –9% ΔΦ Thermal compaction: –2.75% ΔΦ Thermal compaction: –2.75% (1168.86m) (1216.85m) 29.75% 29.75% 2451.49 2451.49 38 ΔΦ Mechanical compaction: –5% ΔΦ Mechanical compaction: –7.6% ΔΦ Thermal compaction: –2% ΔΦ Thermal compaction: –2% ΔΦ Feldspar dissolution: +12.57% ΔΦ Feldspar dissolution: +5.54% ΔΦ Quartz overgrowth: –3.0% ΔΦ Quartz overgrowth: –0.37% (1924.09m) 31.58% (1848.19m) 25.57% 27.5 361.94 4207.3 ΔΦ Mechanical compaction: –0.2% ΔΦ Mechanical compaction: –1.76% Early ΔΦ Carbonate cementation: –12.64% 24.6 ΔΦ Carbonate cementation: –8.7% ΔΦ Quartz dissolution: +0.34% ΔΦ Quartz dissolution: +0% 3.62 21.08% (1983.06m) 17.13% (2064.49m) 13.8 16.4 62.56 ΔΦ Mechanical compaction: –0.75% ΔΦ Mechanical compaction: –1.82% ΔΦ Carbonate dissolution: +0% ΔΦ Carbonate dissolution: +0% Later (2397.65m) (2496.11m) 20.33% 15.31% 0.711 5 44.95 ΔΦ Mechanical compaction: –0.92% ΔΦ Mechanical compaction: –1.82% Pyrite cementation: –0.34% ΔΦ ΔΦ Pyrite cementation: –0.34% (3095.8m) 19.06% (2973.69m) 13.14% 28.9 0.095 Fig. 11 Porosity-permeability evolution history of different diagenetic facies low permeability Es turbidite reservoirs and permeability in the accumulation period under the 5 Cutoff-values for porosity and permeability constraint of accumulation dynamics and pore throat of turbidite reservoirs in the accumulation period structure (Wang et al. 2014a). The method procedure includes: (1) establishing a functional relationship between Capillary pressure (Pc) is the most important resistance oil–water interfacial tension and formation temperature; (2) calculating lower limiting values of maximum connected force in hydrophilic reservoir rocks. Only when the dynamic force surpasses the resistance force, can petro- pore-throat radius according to formation temperature and dynamic forces of each reservoir interval; (3) correlating leum seep into rocks and form petroleum reservoirs (Hao permeability with maximum connected pore-throat radius et al. 2010). We calculated the cutoff-values for porosity 123 Pet. Sci. (2016) 13:204–224 217 and then obtaining cutoff-values for permeability in the 6 Control on the oil-bearing potential accumulation period; and (4) calculating cutoff-values for of a reservoir by the relationship porosity on the basis of cutoff-values for permeability between permeability and dynamics according to specific correlations suitable for the type of in the accumulation period pore-throat structure (Wang et al. 2014a). According to the test data of oil–water interfacial ten- 6.1 Accumulation dynamics estimation sion (d) for different formation temperature (T) in the Es and Es reservoirs in the Dongying Sag, the functional The turbidite reservoirs are located in overpressured for- relationship can be written as (Wang et al. 2014a): mations of the Dongying Sag. Overpressure is the main 0:149 2 dynamic controlling hydrocarbon accumulation (Zhuo d ¼ 40:5  T ; R ¼ 0:65 ð1Þ et al. 2006; Sui et al. 2008; Gao et al. 2010). Disequilib- This equation could be used to calculate the oil–water rium stresses under a high subsidence rate or rapid burial interfacial tension at any given formation temperature. For and hydrocarbon generation are the two possible over- example, for a formation temperature of 125 C which is pressure generating mechanisms in sedimentary basins close to the actual formation temperature of Es in the 3 (Bao et al. 2007; Bloch et al. 2002; Taylor et al. 2010). By research area, the calculated oil–water interfacial tension is means of fluid inclusion PVT simulation, the minimum 19.7 mN/m. For a fixed critical accumulation dynamic fluid pressure in the hydrocarbon accumulation period can value P , we can get cutoffs of maximum connected pore f be obtained. According to basin modeling techniques, fluid throat radius using equation r = 2dcosh/P when the 0 f pressure resulting from disequilibrium compaction can be wetting contact angle of oil–water is 0 and interfacial determined (the balance pressure between sandstones and tension at 125 C is 19.7 mN/m (Table 2). mudstones). The differences between those two pressures Establishing a correlation between permeability and are the increased minimum fluid pressure of hydrocarbon maximum connected pore-throat radius using mercury generation. For an isolated lenticular sand body without injection data (Fig. 12), we find that there is a good faults, fluid pressures generated by disequilibrium com- exponential relationship between permeability and the paction would transfer from mudstones to sandstones to maximum connected pore-throat radius as: reach a balance of fluid pressure (Cai et al. 2009). So the 1:7992 2 fluid pressure generated by hydrocarbon generation is the K ¼ 0:3927  r ; R ¼ 0:8275; ð2Þ main accumulation dynamic. For a sand body with faults -3 2 where K is the permeability, 10 lm ; r is the maximum 0 developed, the surplus pressure which is the difference connected pore-throat radius, lm. between fluid pressure and hydrostatic pressure will result Substituting the limiting value of the maximum con- in fluid migration through the faults which is the main nected pore-throat radius under different critical accumu- accumulation dynamic (Zhuo et al. 2006; Cai et al. 2009). lation dynamics into Eq. (2), a series of cutoff-values for According to the estimations of the accumulation dynamics permeability in the accumulation period can be obtained at of reservoirs in the research area (Table 3), in the early 125 C (Table 2). accumulation period the fluid pressure increase by hydro- On the basis of the classification of pore-throat struc- carbon generation is 1.4–11.3 MPa with an average of tures, according to the functional relationships between 5.14 MPa, and the surplus pressure is 1.8–12.6 MPa with K and K/U of different pore-throat structures as well as an average of 6.3 MPa. In the late accumulation period the their variation ranges (Fig. 4, Table 1), we calculated fluid pressure increased by hydrocarbon generation is cutoff-values for porosity according to variation ranges of 0.7–12.7 MPa with an average of 5.4 MPa, and the surplus permeability in Table 1 and regarded those values as cut- pressure is 1.3–16.2 MPa with an average of 6.6 MPa. The off-values for porosity in the accumulation period for the accumulation dynamics in the later accumulation period corresponding type of pore-throat structures under different are stronger than those in the early accumulation period. critical accumulation dynamics. With the same method, we can calculate the cutoff-values for porosity and perme- 6.2 Coupling of dynamics and permeability ability in the accumulation period for the corresponding in the hydrocarbon accumulation period type of pore-throat structures under different critical accumulation dynamics at different formation temperatures The estimation of the permeability of reservoirs with dif- (Fig. 13). ferent diagenetic facies indicated that the permeability of the 123 218 Pet. Sci. (2016) 13:204–224 Table 2 Cutoff-values for porosity and permeability of the low permeability Es turbidite reservoirs under the constraint of the accumulation dynamics and pore throat structure and at 125 C formation temperature -3 2 Accumulation Maximum connected pore-throat K ,10 lm U ,% cutoff cutoff dynamics P , MPa radius r , lm f 0 U U U U U U IA IB IIA IIB IIIA IIIB 0.01 48.45 422.82 24.04 – – – – – 0.02 24.22 121.49 21.62 22.68 – – – – 0.024 20.19 87.51 21.02 21.87 – – – – 0.026 18.63 75.78 20.77 21.53 – – – – 0.03 16.15 58.58 20.32 20.93 – – – – 0.04 12.11 34.91 19.44 19.77 22.63 – – – 0.05 9.69 23.37 – 18.91 21.54 – – – 0.055 8.81 19.68 – 18.56 21.09 – – – 0.06 8.07 16.83 – 18.24 20.69 – – – 0.065 7.45 14.57 – 17.96 20.33 – – – 0.07 6.92 12.75 – – 20.0 – – – 0.075 6.46 11.27 – – 19.69 – – – 0.08 6.06 10.03 – – 19.41 – – – 0.09 5.38 8.12 – – 18.91 – – – 0.1 4.84 6.71 – – 18.48 – – – 0.2 2.42 1.93 – – 15.85 20.63 – – 0.3 1.62 0.93 – – 14.49 16.59 17.74 – 0.32 1.51 0.83 – – 14.29 16.02 17.09 – 0.4 1.21 0.55 – – 13.60 14.21 15.04 – 0.49 1 0.39 – – 13.0 12.74 13.39 – 0.5 0.97 0.37 – – 12.94 12.60 13.24 – 0.7 0.69 0.2 – – 12.01 10.51 10.92 – 0.9 0.54 0.13 – – – 9.18 9.46 – 1 0.48 0.11 – – – 8.68 8.90 10.29 1.2 0.4 0.077 – – – 7.86 8.02 9.05 1.4 0.35 0.058 – – – 7.24 7.34 8.11 1.5 0.32 0.051 – – – 6.97 7.06 7.73 1.6 0.3 0.046 – – – 6.74 6.80 7.38 2 0.24 0.031 – – – – 5.99 6.30 2.2 0.22 0.026 – – – – 5.67 5.89 2.4 0.2 0.022 – – – – 5.39 5.54 2.5 0.19 0.021 – – – – 5.27 5.38 3 0.16 0.015 – – – – 4.75 4.73 3.2 0.15 0.013 – – – – 4.57 4.52 3.4 0.14 0.012 – – – – – 4.33 3.6 0.14 0.011 – – – – – 4.16 4 0.12 0.009 – – – – – 3.86 6 0.08 0.004 – – – – – 2. 90 8 0.06 0.003 – – – – – 2.37 10 0.05 0.002 – – – – – 2.02 -3 2 reservoir ranged from 10 9 10 lm to 4207 9 generation is 1.4–11.3 MPa with an average value of -3 2 10 lm in the early accumulation period. When there is no 5.1 MPa. Using the minimum accumulation dynamics of fault development in the sand body, the fluid pressure 1.4 MPa, the maximum cutoff-value for permeability in the increased by hydrocarbon generation is the main accumu- accumulation period at a formation temperature of 125 C -3 2 lation dynamic. The fluid pressure increased by hydrocarbon was calculated to be 0.058 9 10 lm . The permeability of 123 Pet. Sci. (2016) 13:204–224 219 maximum cutoff-value for permeability in the accumula- 1.7992 K=0.3927r tion period at a formation temperature of 125 C was cal- R²= 0.8275 -3 2 culated to be 0.203 9 10 lm . Using the maximum accumulation dynamics of 12.7 MPa, the minimum cutoff- value for permeability in the accumulation period at a formation temperature of 125 C is calculated to be -3 2 0.001 9 10 lm . So, at the high level of accumulation 0.1 dynamics hydrocarbon can accumulate in all studied 0.01 reservoirs. Reservoirs with diagenetic facies A and diage- netic facies B do not develop accumulation conditions at 0.001 the low level of accumulation dynamics, because the per- 0.01 0.1 1 10 100 Maximum connected pore-throat radius, μm meability of reservoirs with diagenetic facies A and dia- genetic facies B is lower than the maximum cutoff value. Fig. 12 The relationship between permeability and maximum con- z The surplus pressure is 1.3–16.2 MPa with an average of nected pore-throat radius of the low permeability Es turbidite 6.6 MPa. Using the minimum accumulation dynamics reservoirs 1.3 MPa, the maximum cutoff-value for permeability in the accumulation period at a formation temperature of 125 C the reservoir in the early accumulation period was much -3 2 higher than this cutoff-value, so all the studied reservoirs was calculated to be 0.066 9 10 lm . Using the maxi- mum accumulation dynamics 16.2 MPa, the minimum could accumulate hydrocarbon. When there is fault devel- cutoff-value for permeability in the accumulation period at opment in the sand body, the surplus pressure is the main a formation temperature of 125 C was calculated to be accumulation dynamic. The surplus pressure is -3 2 0.0007 9 10 lm . So, different kinds of reservoirs can 1.8–12.6 MPa with an average of 6.3 MPa. Using the min- all accumulate hydrocarbon with high accumulation imum accumulation dynamics of 1.8 MPa, the maximum dynamics. Reservoirs with diagenetic facies A and diage- cutoff-value for permeability in the accumulation period at a netic facies B do not develop accumulation conditions at formation temperature of 125 C was calculated to be -3 2 the low level of accumulation dynamics. 0.037 9 10 lm . The permeability of the reservoirs in the early accumulation period was much higher than this cutoff- 6.3 Distribution of hydrocarbon resources value, so all the studied reservoirs could accumulate hydrocarbon. The Es source rocks are not fully mature, because the In the later accumulation period the permeability had -3 2 z been reduced and was in the range of 0.015 9 10 lm to burial depth of the Es turbidite reservoirs ranges from -3 2 62 9 10 lm . The fluid pressure increased by hydro- 2500 to 3500 m. Oil–source correlation analysis indicated carbon generation was 0.7 MPa to 12.7 MPa with an that the oil of the low permeability turbidite reservoirs in average of 5.4 MPa in the late accumulation period. Using the early accumulation period comes from source rocks in x s the minimum accumulation dynamics of 0.7 MPa, the Es and Es (Cai 2009). The source rocks are overlain by 3 4 Porosity and permeability cutoffs Porosity and permeability cutoffs Porosity and permeability cutoffs in accumulation time at 75 °C in accumulation time at 100 °C in accumulation time at 125 °C -3 2 -3 2 -3 2 Permeability cutoff, 10 μm Po ro sit y cu t o ff , % Permeability cutoff, 10 μm Po ro sity cu to ff , % Permeability cutoff, 10 μm Po ro sity cu to ff , % 0.001 0.01 0.1 1 10 100 1000 0 5 10 15 20 25 0.001 0.01 0.1 1 10 100 1000 05 10 15 20 25 0.001 0.01 0.1 1 10 100 1000 05 10 15 20 25 0.01 0.01 0.01 0.01 0.01 0.01C I I A A I B 0.1 0.1 0.1 0.1 0.1 0.1 II II A II II II II III 1 1 1 1 1 1 III III III III III B B 10 10 10 10 10 10 Fig. 13 Cutoff-values for porosity and permeability under different formation temperatures of the low permeability Es turbidite reservoirs Accumulation dynamic force, MPa -3 2 Permeability, 10 μm Accumulation dynamic force, MPa Accumulation dynamic force, MPa Accumulation dynamic force, MPa Accumulation dynamic force, MPa Accumulation dynamic force, MPa 220 Pet. Sci. (2016) 13:204–224 Table 3 Estimates of accumulation dynamics of the low permeability Es turbidite reservoirs (Zhang 2014) Well Depth, m Paleo-fluid Paleopressure after Geological Palaeo-burial Hydrostatic Pressure generated by Surplus pressure, Pressure Accumulation pressure, MPa disequilibrium time, Ma depth, m pressure, MPa hydrocarbon, MPa MPa coefficient period compaction, MPa Xin 154 2936 31.9 31.2 2.3 2800 28 0.7 3.9 1.14 Late Xin 154 2939 22 19.5 27.5 1950 19.5 2.5 2.5 1.13 Early Xin 154 2939 26.8 23.7 7.5 2350 23.5 3.1 3.3 1.14 Late Xin 154 2942.8 29.6 31.2 2.3 2800 28 – 1.6 1.06 Late Niu 108 3146.5 23.8 22.4 25.3 2200 22 1.4 1.8 1.08 Early Niu 108 3146.5 33.2 21.6 11 2000 20 11.6 13.2 1.66 Late Niu 108 3146.5 18.6 21.6 11 2000 20 – – 0.93 Late Niu 35 2991.7 22.3 21.4 9.8 2100 21 0.9 1.3 1.06 Late Niu 107 3272.5 34.6 23.9 9.5 2290 22.9 10.7 11.7 1.51 Late Shi128 3099 33.3 32.2 2.6 2850 28.5 1.1 4.8 1.17 Late Shi 128 3099 27.8 22 9.3 2140 21.4 5.8 6.4 1.30 Late Niu 20 3073 43 30.3 3 2680 26.8 12.7 16.2 1.60 Late Niu 20 3073 28.3 22.5 9.1 2150 21.5 5.8 6.8 1.32 Late Niu 24 3159.2 27.9 24.3 25.9 2150 21.5 3.6 6.4 1.30 Early Niu 24 3159.2 29.1 25.4 6 2450 24.5 3.7 4.6 1.19 Late Niu 24 3159.2 32.9 31.2 3.6 2710 27.1 1.7 5.8 1.21 Late Niu 24 3175.6 38.6 27.3 4.7 2630 26.3 11.3 12.3 1.47 Late Niu 24 3175.6 32.2 25.3 24.8 2400 24 6.9 8.2 1.34 Early Niu 24 3175.6 36.6 25.3 24.8 2400 24 11.3 12.6 1.53 Early Niu 24 3175.6 27 23.7 9.8 2350 23.5 3.3 3.5 1.15 Late Niu 24 3175.6 26.4 23.7 9.8 2350 23.5 2.7 2.9 1.12 Late 4145000 4140000 4135000 4145000 4140000 4135000 1.1 1.1 1.7 1.4 1.3 1.1 1.3 1.4 1.2 1.4 1.1 1.1 Pet. Sci. (2016) 13:204–224 221 z z Immature source rock in Es Immature source rock in Es 3 3 Lowly mature source rock in Es Fluid pressure decrease Later accumulation period (13.8–0 Ma) Early accumulation period (34–24.8 Ma) Legend Low permeability Overpressure High permeability Early Later Oil-source Carbonate Early hydrocarbon Later hydrocarbon sandstone sandstone hydrocarbons hydrocarbons fault cement migration migration fracture Fig. 14 The hydrocarbon accumulation patterns of low permeability Es turbidite reservoirs 20620000 20625000 20630000 20635000 20640000 20645000 20650000 01 2km Niuxie 879 Niuxie 113 Niuxie 878 He 127 Niuxie 109 Niuxie 874 Niuxie114 He 129 He 45 Wangxie 583 Niuxie 44 Wangxie 582 Wang 60 Wang 588–10 Wangxie 115 Shixie 137 Wang 545 Wang 27 Wang 57–2 Wangxie 543 Wang 127 Wang 542 C Xinwang 50 Wangxie 544 Wang 72 Wangxie 118 Wangxie 114 Wang 102-202 Wang 2 Shixie 132 F3 Niu1–Wang52 Fault Niu 12 Niu 93 Niu 100 Niuxie 302 Niu 100 C Niu35 Pressure Fault Well Oilfields coefficient 20620000 20625000 20630000 20635000 20640000 20645000 20650000 Fig. 15 The hydrocarbon distribution of the low permeability Es turbidite reservoirs the reservoir rocks, and the generated oil migrates from the and Es accumulate hydrocarbon easily. Duo to hetero- lower part to the upper part (the reservoir). Faults in source geneity caused by diagenetic processes (Liu et al. 2014a), rocks controlled the accumulation of reservoirs. The oil of hydrocarbon accumulation mostly occurred in the reser- the low permeability turbidite reservoirs in the late accu- voirs with high permeability under the control of oil-source x s mulation period comes from source rock in Es ,Es , and faults (Fig. 14). The fluid pressure increased by hydrocar- 3 4 bon generation is the main accumulation dynamic for iso- Es (Li et al. 2007). The source rocks are either below the reservoirs or both the source rocks and reservoir rocks are lated lenticular sand bodies without faults in the later accumulation period. All types of reservoirs with high from the same formation. Surplus pressure is the main accumulation dynamic in accumulation dynamics can accumulate hydrocarbon. Reservoirs with diagenetic facies A and diagenetic facies B the early accumulation period. In the early accumulation period, the permeability of all reservoirs is higher than the do not develop accumulation conditions at the low level of accumulation dynamics in the later accumulation period cutoff-values for permeability. So, the sand bodies with fault development and connected with source rock in Es because the permeability of reservoir with diagenetic facies 1.4 1.2 1.4 1.3 1.2 1.3 1.2 1.2 1.5 F1 Xianhe Fault 1.5 1.3 1.3 F2 Niu27–He122 Fault 1.5 1.5 1.4 1.3 Legend 1.2 222 Pet. Sci. (2016) 13:204–224 A and diagenetic facies B is lower than the maximum second hydrocarbon filling ? second quartz over- cutoff value. Surplus pressure is the main accumulation growth/authigenic kaolinite precipitation ? the dynamic for sand bodies with fault development. All types second group of carbonate cementation/pyrite of reservoirs with high accumulation dynamics can accu- cementation. Compaction existed throughout the entire burial and evolutional processes. mulate hydrocarbon. Reservoirs with diagenetic facies A and diagenetic facies B do not develop accumulation (2) In the early accumulation period, the reservoirs except for diagenetic facies A had middle to high conditions at the low level of accumulation dynamics. -3 2 Hydrocarbon always accumulated in reservoirs with high permeability ranging from 10 9 10 lm to -3 2 4207.3 9 10 lm , all the studied reservoirs can accumulation dynamics and oil-source faults development. Source rocks of the lower part of Es have a high maturity accumulate hydrocarbon. In the later accumulation period the reservoirs except for diagenetic facies C when the burial depth of turbidite reservoir is more than 3000 m (Hao et al. 2006). The oil in the reservoirs came have low permeability ranging from -3 2 -3 2 0.015 9 10 lm to 62 9 10 lm , all the stud- from the source rocks both at the same burial depth as the reservoirs and from a deeper burial depth than the reser- ied reservoirs can accumulate hydrocarbon at the high level of accumulation dynamics. Reservoirs voirs. The closer to the source rocks, the higher accumu- with diagenetic facies A and diagenetic facies B do lation dynamics and the higher the hydrocarbon-filling not develop accumulation conditions at the low level degree. So isolated lenticular sand bodies can accumulate of accumulation dynamics. hydrocarbon. As the distances from source rocks to reser- voirs increases, the accumulation dynamics for the reser- (3) The hydrocarbon-filling degree is higher when the burial depth of turbidite reservoirs is more than voirs decrease and the hydrocarbon-filling degree decreases as well. The distance limit for an isolated lenticular sand 3000 m. Isolated lenticular sand bodies can accu- mulate hydrocarbon. When the burial depth of body to accumulate hydrocarbon is about 225 m from the lower part of source rocks (Song et al. 2014) (Fig. 14). turbidite reservoirs is less than 3000 m, isolated lenticular sand bodies cannot accumulate hydrocar- When the burial depth of turbidite reservoir is less than 3000 m, the oil in the reservoirs came from the source bon. Hydrocarbons always accumulate in reservoirs around the oil-source faults and areas near the center rocks at deeper burial depth than the reservoirs. The oil- of subsags with high accumulation dynamics. source faults controlled the accumulation of reservoirs. Taking the Niuzhuang subsag as an example, hydrocarbon always accumulated in reservoirs around the oil-source Acknowledgments This work is supported by the National Natural faults and areas near the center of subsag with high accu- Science Foundation of China (Grant No. U1262203), the National Science and Technology Special Grant (No. 2011ZX05006-003), the mulation dynamics (Fig. 15). Fundamental Research Funds for the Central Universities (Grant No. 14CX06070A), and the Chinese Scholarship Council (No. 201506450029). The Shengli Oilfield Company of SINOPEC pro- vided all the related core samples and some geological data. The 7 Conclusions authors wish to thank editors and reviewers for their thorough and very constructive review that greatly improved the manuscript. (1) Es turbidite sandstones in the Dongying Sag are Open Access This article is distributed under the terms of the mostly lithic arkoses, and composed of mainly fine Creative Commons Attribution 4.0 International License (http://crea to medium sized grains. Low permeability reservoirs tivecommons.org/licenses/by/4.0/), which permits unrestricted use, distribution, and reproduction in any medium, provided you give with middle to high porosity are most common, and appropriate credit to the original author(s) and the source, provide a the reservoir space is mainly primary pores. There link to the Creative Commons license, and indicate if changes were are three broad types of pore throat structures which made. are subdivided into six sub-types. The major diage- netic events are mechanical compaction, cementa- tion, replacement, and dissolution. 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