Paleoporosity and critical porosity in the accumulation period and their impacts on hydrocarbon accumulation—A case study of the middle Es3 member of the Paleogene formation in the Niuzhuang Sag, Dongying Depression, Southeastern Bohai Bay Basin, East China

Petroleum Science, Oct 2014

Similar reservoir sandbodies and fault conduit systems in the sandstone reservoirs in the middle Es3 member of the Niuzhuang Sag have been problematic for a long time. The following problems remain unsolved: 1) The distribution of sandstone porosity is inconsistent with the hydrocarbon accumulation. The oil sandstones have low porosity instead of high porosity. 2) Sandstones, which have the same properties, have different levels of oiliness, and the sandstones with almost the same properties show different degrees of oil-bearing capacity. This study analyzes the condition of reservoirs in the research area during the accumulation period in terms of paleoporosity estimation and discusses the critical porosity of the sandstone reservoirs during the same period. The following conclusions can be drawn from the results. 1) Although reservoir properties are low at present and some reservoirs have become tight, the paleoporosity ranging from 18% to 25% is greater than the critical porosity of 13.9%. As the loss of porosity is different in terms of burial history, the present porosity cannot reflect porosity during the accumulation period. Similarly, high porosity during the accumulation period does not indicate that the present porosity is high. 2) The present reservoir location is consistent with the distribution of high paleoporosity during the accumulation period. This result indicates that high porosity belts are prone to hydrocarbon accumulation because of the dominant migration pathways generated as a result of property discrepancies under similar fault conduit conditions. Consequently, the hydrocarbon mainly accumulates in high porosity belts. Paleoporosity during the accumulation period is found to be a vital controlling factor. Therefore, high paleoporosity sandstones in the middle Es3 member of the Niuzhuang Sag have great potential for future exploration.

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Paleoporosity and critical porosity in the accumulation period and their impacts on hydrocarbon accumulation—A case study of the middle Es3 member of the Paleogene formation in the Niuzhuang Sag, Dongying Depression, Southeastern Bohai Bay Basin, East China

Pet.Sci. Paleoporosity and critical porosity in the accumulation period and their impacts on hydrocarbon accumulation-A case study of the middle Es member of the Paleogene formation 3 in the Niuzhuang Sag, Dongying Depression, Southeastern Bohai Bay Basin, East China Liu Mingjie 2 3 Liu Zhen 1 2 Sun Xiaoming 1 2 Wang Biao 0 2 0 member , Niuzhuang Sag, Bohai Bay Basin 1 State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing) , Beijing 102249 , China 2 China University of Petroleum (Beijing) and Springer-Verlag Berlin Heidelberg 2014 3 School of Geoscience and Technology, Southwest Petroleum University , Chengdu, Sichuan 610500 , China Similar reservoir sandbodies and fault conduit systems in the sandstone reservoirs in the middle Es3 member of the Niuzhuang Sag have been problematic for a long time. The following problems remain unsolved: 1) The distribution of sandstone porosity is inconsistent with the hydrocarbon accumulation. The oil sandstones have low porosity instead of high porosity. 2) Sandstones, which have the same properties, have different levels of oiliness, and the sandstones with almost the same properties show different degrees of oil-bearing capacity. This study analyzes the condition of reservoirs in the research area during the accumulation period in terms of paleoporosity estimation and discusses the critical porosity of the sandstone reservoirs during the same period. The following conclusions can be drawn from the results. 1) Although reservoir properties are low at present and some reservoirs have during the accumulation period. Similarly, high porosity during the accumulation period does not indicate that the present porosity is high. 2) The present reservoir location is consistent with the distribution of high paleoporosity during the accumulation period. This result indicates that high porosity belts are prone to hydrocarbon accumulation because of the dominant migration pathways generated as a result of property discrepancies under similar fault conduit conditions. Consequently, the hydrocarbon mainly accumulates in high porosity belts. Paleoporosity during the accumulation period is found to be a vital controlling factor. Therefore, high paleoporosity sandstones in the middle Es3 member of the Niuzhuang Sag have great potential for future exploration. Paleoporosity; critical porosity; dominant migration pathways; hydrocarbon accumulation - Hydrocarbon mainly migrates during the accumulation period. Both primary and secondary migration is closely related to the properties of reservoirs. The capacity of the hydrocarbon to migrate to sandstone reservoirs depends on the pressure difference between the source rocks and the reservoir rocks and indicates the lower limit of sandstone reservoirs in the accumulation period. The indicated lower limit is a critical property of sandstone (Liu et al, 2006; 2007a; 2012) . Hydrocarbon can accumulate only if reservoir porosity is greater than the critical porosity. S e v e r a l s t u d i e s f o c u s o n t h e l o w e r l i m i t o f t h e petroliferous reservoir, and many methods have been proposed to determine the cutoff value (Guo, 2004; Wang et al, 2009; Cao et al, 2009) . In addition, quantitative analyses have been performed on the lower porosity limit (Pang et al, 2003; Zhu et al, 2006; Zhu, 2008; Jiao et al, 2009) . Although much research has been done on the cutoff value of sandstone, these studies focus only on the accumulative condition of the reservoir at present. The critical porosity of the reservoir during the accumulation period is seldom studied. By researching the main controlling factors of lithologic reservoirs in different types of basins, Liu et al (2006; 2007a; 2012) proposed the theory of four-factors mainly controlling accumulation, wherein the critical porosity during the accumulation period was determined to be one of the factors. Pan et al (2011a) determined that the critical porosity of tight sandstone in the Chang 8 member in the area, the critical porosity of the Chang 8 member sandstone 2012). Several problems have remained unsolved for a long time in the middle Es3 member of the Niuzhuang Sag. The oiliness of sandstones in the same reservoir is different, thus indicating that the sandstones with low properties possess superior oil-bearing capacity; the oil-bearing sandstones with similar properties have different degrees of oil-bearing capacity. Conventional accumulation theories have been unable to provide satisfactory solutions to these problems, as the present properties will not be the same as the properties during the accumulation period. In this study, we attempt to examine this by analyzing the relation between reservoir porosity and hydrocarbon formation and enrichment. 2 Geologic setting and stratigraphy The Bohai Bay Basin, an important hydrocarbonproducing basin in China, is located in eastern China and covers an area of approximately 200,000 km2. Since the Paleogene period, this basin has undergone complex tectonic evolution, which can be divided into the synrift stage and the postrift stage (Hu et al, 2001; Qi et al, 2008; Li et al, 2010; Li et al, 2013) . The Bohai Bay Basin consists of several sub-basins, namely, the Liaohe, Liaodong Bay, Bozhong, Jiyang, Huanghua, Jizhong, and Linqing, as shown in Fig. 1(a) (Gong, 1997) . The Dongying Depression lies south of the Jiyang Sub basin with an area of 5,850 km2 (Zhang et al, 2009) . It is further subdivided into four sags (the Minfeng Sag, the Lijin Sag, the Niuzhuang Sag, and the Boxing Sag) by several normal faults and an uplift in the central anticline belt (Fig. 1(b)). The Dongying Depression is an asymmetric half graben lacustrine basin that developed as a result of a Tertiary rift. As zones from north to south; the northern steep slope zone, the northern zone (Lijin Sag), the central anticline zone, the southern zone (Niuzhuang Sag), and the southern gentle slope zone (Chen et al, 2008; Guo et al, 2010) . The depression is filled with Cenozoic sediments, which are formations from the Paleogene, Neogene, and Quaternary periods. As shown in Fig. 2, the formations from the Paleogene period are the Kongdian (Ek), Shahejie (Es), and Dongying (Ed); the formations from the Neogene period are the Guantao (Ng) and Minghuazhen (Nm); and the formation from the Quaternary period is the Pingyuan (Qp). Detailed descriptions of the Paleogene stratigraphy have been provided by several authors (Zhang et al, 2004; Zhang et al, 2010; Guo et al, 2012a) . The most important petroleum generation and accumulation layer of Es can be divided into four members: Es1 to Es4 in descending order. The Es3 has a thickness ranging from 700 m to 1,200 m and is characterized by lacustrine oil shale with high sedimentation rates, dark gray mudstones, and calcareous mudstones. Es3 can be further divided into three, namely, the upper Es3, the middle Es3, and the lower Es3 members (Lampe et al, 2012). The Niuzhuang Sag, which is located southeast of the Dongying Depression, covers an area of 600 km2 that extends from east to west. This sag has simple tectonic features that are composed primarily of synclines. Few faults exist in this area, except at the boundaries of the rift basin. In the Niuzhuang Sag, the strata generally develop completely. This study mainly focuses on the western part of the Niuzhuang Sag and the middle Es3 member. When the target stratum was deposited, tectonic movement was strong, and the basin subsided rapidly. Therefore, large amounts of detrital materials were transported into the basin and formed delta and turbidite fan sedimentary facies (Li, 2004; Chen et al, 2009) . 3 Method 3.1 The principle of paleoporosity estimation T h e k e y p o i n t o f t h i s r e s e a r c h i s e s t i m a t i n g t h e paleoporosity during the accumulation period. In this study, we apply the principle of effect-oriented simulation to estimate paleoporosity in the accumulation period. According to the porosity variation effect, the process of porosity evolution can be divided into the increasing porosity and the decreasing porosity models (Fig. 3). When the two models are superimposed at the same time or at the same burial depth, the actual porosity in geological history is obtained. 3.2 Decreasing porosity model The decreasing porosity of the middle Es3 member has been affected by compaction and cementation, and the effect of decreasing porosity continues with the burial of strata. In this process, compaction plays a major role, particularly in the shallow layers. However, both compaction and cementation control the evolution of porosity in the deep layers. The whole process is continuous, the trend of decreasing porosity in the shallow and deep layers is consistent, and the effect-oriented model of decreasing porosity is successional and consistent (Fig. 4). Therefore, the pore volume reduction of the shallow and deep layers can be obtained from the same model. Athy (1930) provided a model postulating that the porosity of mudstone is an exponential function of the burial depth in normal compaction conditions. This model has been applied in the study of sandstone for a long time. However, in-depth studies found that the porosity of sandstone is not only related to burial depth but also to geological age (Maxwell, 1964; Schere, 1987; Hayes, 1991; Ehrenberg et al, 2009) . Liu et al (2007 b) demonstrated that porosity can be expressed as a binary function of burial time and burial depth; therefore, when the burial depth and the burial time are obtained, the porosity of sandstone can be computed using multiple regression analysis. Therefore, the following decreasing porosity model is established. 48e 0.00057z 0.0003t 0.00000052zt (1) n n burial depth, m; t: burial time, Ma. 3.3 Increasing porosity model Increase in porosity is known to be generated by solution, which is a result of organic acids dissolving minerals such as carbonate and feldspar when the temperature is within a specific range ( Carothers and Kharaka, 1978 ; Surdam et z: Fig. 1 of sections DE and FG, wells and normal faults for the top of Es3 interval in the study area. (c) Cross section DE showing the different tectonic-structural zones and key stratigraphic intervals System Series Formation Interval Symbol Quarternary Pingyuan Age Ma 5.1 24.6 28.1 32.8 42.5 50.4 65.0 Thickness m V I e g a t S I I I e g a t S I e g a t S e g a t s ittfr s o P Stage II e g a t s iftr n y S e n e g o e N e n e g o e l a P e n e c o li P e n e c o i M e n e c o g il O e n e c o E e n e c o e l a P Minghuazhen o a t n a u G e ji e h a h S g n i y g Second n o D Upper Lower First Third First Second Third Fourth First n a i g Second d n o K Third Qp Nm Ngu NgL Ed1 Ed2 Ed3 Es1 Es2 Es4 Ek1 Ek2 Ek3 Es3 U M L Conglomerates Sandstones Siltstones Mudstones Carbonates Volcanic rocks Evaporites Unconformity Model of Model of Process of decreasing porosity + increasing porosity = porosity evolution al, 1984; 1989; Zhang et al, 2009; Schieber, 2011). With regard to the Niuzhuang Sag, Chen et al (2009) proposed that carbonate cements were dissolved in the Jiyang sub basin when the paleotemperature was about 70 °C. The timing of the oil charge in the Dongying Depression is inferred to be around 24 Ma to 20 Ma (Guo et al, 2012a) , during which time the temperature in the Niuzhuang Sag was about 90 °C (Fig. 5). As the hydrocarbon charging inhibits mineral dissolution further (Johnson, 1920; Hawkins, 1978; Hayes, 1991), we define the acidified window as the period when the geothermal temperature ranged from 70 °C to 90 °C. If the temperature was below 70 °C, the organic acid was was over 90 °C, the solution became weak because of the reduction of the concentration of organic acids and hydrocarbon emplacement. 30°C 40°C 50°C 60°C Porosity, % 2 3 4 5 6 78 910 20 30 40 50 60 0 0 2 A c c o r d i n g t o t h e t h e o r y o f c h e m i c a l d y n a m i c s , reaction rate is proportional to concentration. Therefore, the dissolution rate of a mineral is proportional to the acid concentration such that s t k1'C c0' (2) s k1' : constant of proportionality; C: concentration of the organic acid, mol/L; c0' : undetermined constant. When the concentration of the organic acids in the formation water of the Niuzhuang Sag reached the maximum level, the corresponding geothermal temperature was about 80 °C. Therefore, we establish the relationship between organic acid concentration and geothermal temperature as follows: C T: formation temperature, °C; a1, b1, c1: undetermined constants. In a particular period, burial depth is proportional to burial time and to the geothermal temperature. Therefore, the change rate of porosity in the acidified window can be modeled as follows: a', b', c': undetermined constants. We convert the time to geohistorical time, define the time when the geothermal temperature first reaches 70 °C as t1 reaches 90 °C as t2. When t=t1, s=0; t=t2, s. As the curve of increasing porosity is centrosymmetric, we can solve the equation above and obtain the model of the secondary 2 t 3 t t1 3 2 t t1 2 3 t t t1: time when the geothermal temperature first reaches 70 °C, Ma; t2: time when the temperature first reaches 90 °C, Ma; t: time interval of the layer in the acidified window, Ma; t= t 2 t1, Ma. 3.4 The model of paleoporosity estimation Based on the analysis above, the process of porosity evolution can be divided into three stages: (1) before the layer are found, and porosity simply decreases by compaction; (2) are not only increasing by solution but also decreasing by compaction and cementation; and (3) after the layer exits the is constant. At this stage, the layer is compacted based on the secondary pores. We can then estimate the paleoporosity as follows: 0 0 0 e az bt czt e az bt czt e az bt czt 2 t 3 t t1 3 3 t 2 t t1 2 t t1 t1 t t2 t binary function. Based on the present lower porosity limit of the reservoir and with the aid of burial history research, the current study determines the critical porosity by tracing the porosity section : time interval of the layer in the =t2 t1; a, b, c: constants of the 0.01 0 5 10 15 Porosity , % 20 25 30 Fig. 6 Cross-plot of porosity versus permeability with well test result, which shows the cutoff values of middle Es3 member in the Niuzhuang Sag from the present time back to the accumulation period (Pan et al, 2011a; Guo et al, 2012b; Liu et al, 2012) . The paleoporosity i s e s t i m a t e d u s i n g t h e p r i n c i p l e o f e ff e c t - o r i e n t e d simulation with the current porosity as the boundary constraint condition (Pan et al, 2011b; Guo et al, 2012b) . Therefore, the rule of hydrocarbon accumulation and enrichment is demonstrated by comparing paleoporosity with the critical porosity and by analyzing the distribution relationship between paleoporosity and the reservoir. 4 Results 4.1 Cutoff value of the present reservoir In this study, the cutoff value of the present reservoir is determined by the cross-plot method of porosity and permeability and the oil occurrence method (Pan et al, 2011a; Jin et al, 2012; Guo et al, 2012b; Liu et al, 2012) based on well testing and core logging data. 4.1.1 Data statistics of well testing The relationship between well testing and reservoir properties is established by using relevant data from the middle Es3 10-3 μm2. The data suggest that a complex relationship exists between the reservoir properties and hydrocarbon. A reservoir with good properties may not be an oil layer, but it may be a water zone or even a dry bed. Conversely, a reservoir with poor properties can be an oil layer. The reservoir with properties of equal value can be an oil layer, water zone, or a -3 μm2 are the cutoff values obtained from the well testing data (Fig. 6). (3) (4) (5) 1000 100 2 -3 0 10 1 , k y liit b ea 1 m r e P 0.1 4.1.2 Data statistics of core logging Similarly, the relationship between core logging and reservoir properties is established using relevant data from the middle Es3 member. For the oil-rich sandstone, porosity -3 μm2. For the oil-soaked sandstone, μm2. The sandstone property that indicates oil occurrence has no strict boundaries. These values suggest an irregular relationship between reservoir properties and hydrocarbon. The sandstones with properties of high value may be -3 μm2 are the cutoff values obtained from the well logging data (Fig. 7). By comprehensively analyzing the cutoff values obtained from the well testing and core logging data, the cutoff values of the present reservoir in the middle Es3 member of the -3 μm2. 1000 100 2 -3 0 10 1 , k y ilit b ea 1 m r e P 0.1 =3.5% Oil rich Oil-soaked Fluorescent k=0.1×10-3 2 20 25 0.01 0 5 10 15 Porosity , % 4.2 Critical property in the accumulation period After the accumulation period, the middle Es3 member subsided and reached the present maximum burial depth. porosity section. The porosity section in the maximum burial period is estimated subsequently. According to the evolution trend of the porosity section at the maximum burial depth, we trace the difference between the maximum burial depth and the depth during the accumulation period to estimate the porosity section during the accumulation period. The porosity variation is the difference in porosity between the accumulation period and the present after reservoir formation. By adding the porosity variation and the present cutoff value, the critical porosity during the accumulation period can be obtained. Several studies have investigated the accumulation period in the Dongying Depression or Niuzhuang Sag (Qiu et al, 2000; Jiang et al, 2003; Zhu et al, 2004; Zhu et al, 2007; Guo et al, 2012a) . The results of these studies show that the hydrocarbon in the middle Es3 member accumulated mainly at the time of the end of the Dongying Formation and at the beginning of the Guantao Formation (25 Ma). Both stages are the focus of the current work to estimate paleoporosity. In the present study, five typical wells were selected to calculate the critical porosity. In the following discussion, N6 is used as an example. The burial and geothermal histories of well N6 suggest that hydrocarbon accumulated at the end of the uplifting in 25 Ma (Fig. 5). It was then uplifted for a short period and then continuously subsided until the present time, reaching its maximum burial depth. The strata subsided by 1,108 m from the accumulation period to the maximum burial period. 1,108 m according to the porosity section, we determine that the porosity variation from the accumulation period to the and the present cutoff values of reservoir porosity, the critical 4.3 Paleoporosity estimation in the accumulation period Paleoporosity estimation is a difficult problem, and researchers have proposed various methods from different aspects (Meng et al, 2003; Pan et al, 2011b; Qu et al, 2012) . Inspired by the methods of Pan et al (2011b) and Guo et al (2012b), the present study uses the principle of effect-oriented simulation with current porosity as the boundary constraint condition. Therefore, porosity evolution can be divided into two processes: increasing porosity and decreasing porosity. The superimposition of the two effects comprises the porosity evolution process; thus, paleoporosity can be estimated from geological history. With well N117 as an example, we choose the point with simulate porosity evolution from the aspects of time (Fig. 9(a)), burial depth (Fig. 9(b)) and synthesized evolution (Fig. 9(c)) respectively. 1) The depositing of the middle Es3 member began in 42.1 2) The strata subsided continuously until the burial depth was 1,049 m in 35.7 Ma. Meanwhile, the porosity decreased 3) The strata were in the acidified window from 35.7 Ma to 30.4 Ma, when the geothermal temperature was 70 when hydrocarbon was charged in 30.4 Ma. The porosity Layer Pingyuan Formation Minghua zhen Formation Guantao Formation Dongying Formation H: the settling volume of the layer from the accumulation period to present : the variation of the sandstone porosity from the accumulation period to present 4) The strata subsided continuously from 30.4 Ma to 26.6 Ma until the burial depth was 1,876.9 m. Meanwhile, cementation. 5) The strata were uplifted from 26.6 Ma to 24.5 Ma, and burial depth was shallower than the previous maximum burial depth. Therefore, burial depth had no effect on porosity. 6) The strata subsided continuously from 24.5 Ma until the present time, reaching the maximum burial depth. The The middle Es3 member in the western part of the Niuzhuang Sag shows six stages of delta growth (Fig. 10), which can be recognized by seismic reflection terminal relations as onlap, truncation, and downlap. T4 and T6 are the top and bottom layers of the middle Es3 member, respectively. T51, T52, T53, T54, and T55 are the division surfaces of the six stages. This study selects 26 wells to estimate the paleoporosity of T53 and 28 wells for T54 (Table 2). 5 Discussion 5.1 The relationship between paleoporosity and critical porosity Table 2 suggests that the porosity of producing and dry wells is greater than the critical porosity during the accumulation period. This result indicates that the reservoirs of the middle Es3 member could all have been charged by hydrocarbon. 5.2 The control of paleoporosity on hydrocarbon accumulation According to the relation of paleoporosity isograms and reservoir distribution (Figs. 11 and 12, respectively), paleoporosity is demonstrated to be high in the east and low in the west. Furthermore, an apparent boundary exists between the reservoir region and the dry area. In the producing wells, is mainly developed in the area where the paleoporosity is paleoporosity of the producing wells mainly ranges from 0 -1 0 Porosity decrease process + Porosity increase process = Porosity evolution process 50 40 a 30 M , e m iT 20 10 0 0 0 0 1000 m , h t p e D 2000 3000 0 Fig. 9 The simulation of sandstone porosity evolution of well N117 from time (a), depth (b), and synthesized evolution (c) respectively 3000 3050 3100 3150 3200 3250 3300 3350 3400 result suggests that hydrocarbon enrichment is affected by paleoporosity to some extent. 5.3 The relationship between dominant migration pathways and hydrocarbon accumulation The dominant migration pathway is defined as a passageway that hydrocarbon goes through in the secondary migration, during which no outside interference emerges. The interaction of several factors forms this pathway: the anisotropy of the system, the heterogeneity of the energy field, and the flow of fluid (Dembicki and Anderson, 1989; Hindle, 1997; Chen et al, 2007; Luo et al, 2007; Pang et al, 2008; Lei et al, 2013) . The dominant migration pathways may be faults, unconformable surfaces, or beds with high porosity and permeability. Traps in the dominant migration pathways are prone to hydrocarbon accumulation. B y a n a l y z i n g t h e r e l a t i o n o f p a l e o p o r o s i t y a n d hydrocarbon formation and enrichment, the study concludes that the reservoirs of the middle Es3 member mainly have differential dominant pathways, which were formed as a result of the difference in porosity and permeability distribution of the target strata. The delta prograded into the basin from east to west during the deposition of the Dongying Formation; therefore, paleoporosity is high in the east and low in the west. Hydrocarbon always migrates along the dominant migration pathways with superior properties and accumulates in sandstones with high porosity. This result indicates that hydrocarbon accumulation is controlled by the properties of the reservoir in the accumulation period (Fig. 13). 6 Conclusions 1) The paleoporosity of the middle Es3 member is estimated with the principle of effect-oriented simulation and with the use of current porosity as the boundary constraint condition in the accumulation period, which covers time of the end of the Dongying Formation and the beginning of the Guantao Formation. The critical porosity of the middle Es3 based on the cutoff value of present reservoirs. 2) In comparing the relationship between critical porosity and paleoporosity in the accumulation period of 16 producing wells and 11 dry wells, the paleoporosity of both types of wells is found to be greater than the critical porosity. Therefore, all wells could have been charged by hydrocarbon in the accumulation period. The difference in porosity variation after accumulation leads to the inconsistency between present properties and oiliness. 3) The conformity between contour and reservoir distribution at the top of T53 and T54 indicates the existence of a significant boundary between the reservoir area and the dry region. The hydrocarbon mainly accumulates in reservoirs with high paleoporosity so the paleoporosity of sandstone in the accumulation period affects the distribution 5000 m 24% 23% 22% 21% 20% 19% N 24% 23% 22% 21% 20% 19% Producing well Dry well Contour of paleoporosity Reservoir Fault Wedge out of sandbody Boundary between reservoir region and dry area of hydrocarbon. 4) The sandstone reservoirs of the middle Es3 member in the Niuzhuang Sag with similar fault conduction systems as well as inconsistent present porosity and oiliness generate the dominant migration pathways as a result of the differences in reservoir paleoporosity. Oil and gas tend to be trapped in the dominant migration pathways; therefore, hydrocarbon accumulation and enrichment are controlled by the reservoir paleoporosity. Acknowledgements T h i s s t u d y i s s u p p o r t e d b y t h e Yo u n g S c h o l a r s Development Fund of SWPU. The Xianhe Production acknowledged for providing the data used in this study. 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Mingjie Liu, Zhen Liu, Xiaoming Sun, Biao Wang. Paleoporosity and critical porosity in the accumulation period and their impacts on hydrocarbon accumulation—A case study of the middle Es3 member of the Paleogene formation in the Niuzhuang Sag, Dongying Depression, Southeastern Bohai Bay Basin, East China, Petroleum Science, 2014, 495-507, DOI: 10.1007/s12182-014-0365-y