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346 Pet.Sci.(2014)11:346-362 DOI 10.1007/s12182-014-0349-y Characteristics and origin of abnormally high porosity zones in buried Paleogene clastic reservoirs in the Shengtuo area, Dongying Sag, East China Cao Yingchang , Yuan Guanghui, Li Xiaoyan, Wang Yanzhong, Xi Kelai, Wang Xiaoming, Jia Zhenzhen and Yang Tian School of Geosciences, China University of Petroleum, Qingdao, Shandong 266580, China © China University of Petroleum (Beijing) and Springer-Verlag Berlin Heidelberg 2014 Abstract: There are three abnormally high porosity zones developed in buried Paleogene nearshore subaqueous fan and sublacustrine fan clastic reservoirs at 2,800-3,200 m, 3,250-3,700 m and 3,900- 4,400 m, respectively, within the Shengtuo area of the Dongying Sag. Here the porosity of reservoirs buried deeper than 4,000 m can still be greater than 20%. Investigation of these three abnormally high rd th porosity (AHP) zones in the 3 to 4 PHPEHURIWKH3DOHRJHQH6KDKHMLH)RUPDWLRQLQWKH6KHQJWXRDDUH ZDVFDUULHGRXWZLWKXWLOL]DWLRQRIFRUHREVHUYDWLRQWKLQVHFWLRQLGHQWL¿FDWLRQ6(0REVHUYDWLRQLPDJH analysis, core physical property testing and other technical methods. The results show that, the AHP ]RQHVLQPDQGP]RQHVDUHGRPLQDWHG$+3YLVLEOHE\SRUHVVLJQL¿FDQWSULPDU\ primary intergranular pores (more than 50% of the total porosity), while secondary pores and micropores in authigenic clays may develop in some reservoirs. AHP reservoirs in the AHP zone of 3,900-4,400 m are dominated by micropores in matrix, visible pores are mainly grain dissolution pores but with low absolute content (< 1%), so this zone belongs to the micropores primary AHP zone. The genesis of the three AHP zones was studied to distinguish between porosity enhancement and porosity preservation. Our research shows that, in deeply buried clastic reservoirs in the Shengtuo area, mineral dissolution occurred in a relatively closed diagenetic system with high temperature and high salinity. Reservoir rocks underwent extensive feldspar dissolution, while detrital carbonate grains and carbonate cements show QRHYLGHQFHRIH[WHQVLYHGLVVROXWLRQ$OWKRXJKVLJQL¿FDQWIHOGVSDUGLVVROXWLRQSRUHVGHYHORSHGIHOGVSDU dissolution enhanced porosity only a little due to the precipitation of almost isovolumetric dissolution products in the nearby primary intergranular pores in forms of authigenic clays and quartz cements. Net enhanced porosity originating from feldspar dissolution is generally less than 0.25%. Thus, the subsurface dissolution has little impact on the mid-deep buried high porosity reservoirs. Reservoirs in braided channels of middle fans in sublacustrine fans and reservoirs in the middle-front of fan bodies of nearshore VXEDTXHRXVIDQVSURYLGHWKHEDVLVIRUWKHGHYHORSPHQWRI$+3]RQHV7KHVKDOORZGHYHORSPHQWRIÀXLG overpressure and early hydrocarbon emplacement have effectively retarded compaction and carbonate FHPHQWDWLRQVRWKDWWKHKLJKSRURVLW\LQWKHVXSHU¿FLDOOD\HUVLVSUHVHUYHGLQWKHPLGGHHSOD\HUV7KHVH are the main controlling factors in the development of AHP zones. Key words: Dongying Sag, Shengtuo area, abnormally high porosity zone, pores, genesis unexpectedly high porosity and permeability at substantial 1 Introduction burial depth. Studies on the origin and distribution of these Studies by Bloch et al (2002) of global basins show that high-quality abnormally high porosity (AHP) reservoirs are in specific geological conditions, deeply buried reservoirs of great importance for oil-gas exploration and production. can still be effective for accumulation and production %ORFKHWDO GH¿QHG$+3DVUHVHUYRLUSRURVLW\ZKLFK of petroleum and in particular that some areas exhibit is statistically higher than the porosity values occurring in typical sandstone reservoirs of a given lithology (composition and texture), age and burial/temperature history. In sandstones *Corresponding author. email: caoych@upc.edu.cn containing abnormally high porosities, such porosities Received May 11, 2013 Pet.Sci.(2014)11:346-362 347 exceed the maximum porosity of the typical sandstone the secondary AHP zone (the relative percentage content of LWKVXESRSXODWLRQ:LQVSLUDWLRQIURPWKLVGH¿QLWLRQ0HQJHW secondary pores in reservoirs is more than 50%) (Cao et al, DO GH¿QHG$+3WKH]RQHDVWKHUHVHUYRLUGHYHORSPHQW 2013). Also, exploration ideas and methods should differ zone with porosities higher than the maximum porosity between these types of AHP zones. of clastic rocks that develop in normal sedimentary and The mid-deep clastic reservoirs (>2,500 m) in the diagenetic environments. The concept of an AHP zone Shengtuo area of the northern steep slope zone in the emphasizes only the abnormally high level of reservoir Dongying Sag developed three AHP zones at 2,800-3,200 porosity regardless of the pore types. In addition, Chinese m, 3,250-3,700 m and 3,700-4,400 m, respectively. Great scholars also referred to the AHP zone as the secondary pore success has been achieved in oil-gas exploration in Es -Es 4 3 development zone, secondary pore zone, (abnormal) pore VXEWOHUHVHUYRLUVLQUHFHQW\HDUV)RUH[DPSOHHOO:7 development zone, secondary pore development section, Well T76, Well T710, Well T719 and Well T764 all obtained etc., of which, the secondary pore development zone has high yields in the Es -Es formations. However, there is still 4 3 been used widely (Yuan and Wang, 2001; Zhu et al, 2006; much debate on pore types and genesis of the AHP reservoirs. Liu et al, 2009; Wang, 2010). Some scholars considered the Previous studies suggested that, the deep buried Paleogene relative content of secondary pores in the reservoirs (Wang clastic reservoirs in the Shengtuo area consist mainly of and Shao, 1999; Wang, 2010), for example, Wang (2010) secondary pores, and subsurface dissolution is the main VXPPDUL]HGVWXGLHVRIWKH&KLQHVHVFKRODUVDQGGH¿QHGWKH controlling factor of these AHP zones (Zhong et al, 2003; Zhu secondary pore development zone as a zone where reservoirs et al, 2006; Yuan et al, 2007; Gao et al, 2008). Among them, with high porosity (higher than the ĭ ) developed, based on Zhong et al (2003) and Zhu et al (2006) proposed that the cutoff the introduction of effective reservoir porosity cutoff (ĭ ), reservoirs consist mainly of intergranular dissolution pores, cutoff and where the percentage of secondary pores in reservoirs is and significant dissolution of carbonate cements is critical more than 50%. However, without considering the content to the AHP zones. However, Yuan et al (2007) and Gao et al of secondary pores in reservoirs, some scholars subjectively (2008) argued that the dissolution of carbonate cements is UHVHUYRLUV$+3GH¿QHGWKHFRQFHQWUDWHGGHYHORSPHQW]RQHRI not obvious, and significant feldspar pores contribute more with secondary pores as the secondary pore development WRWKHVH$+3]RQHV*HRORJLFDOIDFWRUVEHQH¿FLDOWRSULPDU\ zone (Zhong et al, 2003; Xiao et al, 2003; Liu and Zhu, 2006; Zhu et al, 2007; Zhang et al, 2011). emplacement occur commonly in the Shengtuo area (Zhang Publications suggest that both geological processes et al, 2009; Wang, 2010; Sun, 2010). However, the AHP beneficial to porosity preservation (e.g. (1) the shallow zones were identified as secondary AHP zones (secondary GHYHORSPHQWRIÀXLGRYHUSUHVVXUHDQGFKORULWHFRDWVDQG pore development zones) by previous studies (Zhong et al, early hydrocarbon emplacement) and processes beneficial 2003; Zhu et al, 2006; Yuan et al, 2007; Gao et al, 2008), to porosity enhancement (mineral dissolution) can be the which is questionable. Using core observation, thin section important controlling factors to the development of mid- identification, SEM analysis, image analysis, rock physical deep AHP reservoirs (Ehrenberg, 1993; Warren and Pulham, property tests, fluid inclusion analysis, statistical analysis 2001; Luo et al, 2002; Bloch et al, 2002; Marchand et al, and other techniques, on the basis of the distribution of AHP 2002; Zhong et al, 2003; Zhu et al, 2004; 2006; Zhang et al, zones in the Shengtuo area, we studied the pore types and the 2007; Yu et al, 2008; Peng et al, 2009; Zhong et al, 2008; genesis of these AHP zones. Taylor et al, 2010; Meng et al, 2010; Wang, 2010; Jin et al, 2011; Chen et al, 2011; Zhu et al, 2012). Even recently, 2 Geological background most Chinese scholars still thought that burial dissolution of The Dongying Sag is a sub-tectonic unit lying in the minerals (particularly mesogenenic dissolution) is the main southeastern part of the Jiyang Depression of the Bohai Bay controlling factor of the mid-deep AHP zones (Zhang et al, %DVLQ(DVW&KLQD)LJD ,WLVD0HVR]RLF&HQR]RLF 2003; Zhu et al, 2004; Yuan et al, 2007; Zhu et al, 2006; Yu half graben rift-downwarped lacustrine basin, developed on et al, 2008; Zhong et al, 2008; Zhu et al, 2012). In recent Paleozoic bedrock paleotopography (Yuan et al, 2007). The years, many foreign scholars and some Chinese scholars Dongying Sag, which is located west of the Qingtuozi Salient, began to accentuate the importance of geological processes north of the Luxi Uplift and Guangrao Salient, east of the beneficial to porosity preservation (e.g. fluid overpressure, Linfanjia and Gaoqing Salient, south of the Chenjiazhuang- hydrocarbon emplacement and chlorite coats), and rethought Binxian Salient. It covers an area of 5,850 km with an east- the importance of secondary pores (Bloch et al, 2002; Taylor et al, 2010; Berger et al, 2009; Marchand et al, 2002; Higgs the Dongying Sag is a half graben with a faulted northern et al, 2007; Jin et al, 2011; Ehrenberg et al, 2012; Yuan et margin and a gentle southern margin. In plan, the Dongying DOE :KHQJHRORJLFDOSURFHVVHVEHQH¿FLDOWRSRURVLW\ preservation serve as main controlling factors, AHP reservoirs sag is further subdivided into secondary structural units, such consist mainly of primary pores; while when the secondary as the northern steep slope zone, middle uplift belt, trough dissolution is the main controlling factor, the AHP reservoirs zones of the Lijin, Minfeng, Niuzhuang and Boxing subsags, consist mainly of secondary pores (Bloch et al, 2002; Meng et DQGWKHVRXWKHUQJHQWOHVORSH]RQH=KDQJHWDO )LJ al, 2006; 2010). Thus, we suggested dividing the AHP zones 1(b)). into two types: the primary AHP zone (the relative percentage The Shengtuo area is located in the middle part of the content of primary pores in reservoirs is more than 50%) and northern steep slope zone of the Dongying sag, with the ZHVWD[LVRINPDQGDQRUWKVRXWKD[LVRINP,QSUR¿OH SRUHSUHVHUYDWLRQVXFKDVÀXLGRYHUSUHVVXUHDQGK\GURFDUERQ Qingtuozi Salient Shicun fault zone 348 Pet.Sci.(2014)11:346-362 (a) 42° N (b) Sag 0 100km N 0 10 20km Uplift 40° Beijing Yanshan Chenjiazhuang Salient Ƚ Dalian Bohai Bay 38° ċ Coast line China slope zone Northern Jinan 36° steep Beijing Minfeng Ď Tanlu strike-slip fault zone Binxian subsag 114° 116° 118° 120° 122° 124° Salient Binnan-lijin fault zone Middle uplift Lizezheng subsag Qingcheng Boxing subsag Salient Boxing fault zone Paleogene Paleogene area overlap zone Luxi Uplift Study Major Paleogene area fault denuded zone (a) Tectonic setting of the Dongying Sag in the Jiyang Depression ( ) of the Bohai Bay Basin, East China. Fig. 1 Other depressions in the Bohai Bay Basin are Jizhong Depression ( ), Huanghua Depression (II), Bozhong Depression (IV), Liaohe Depression (V) and Dongpu Depression (VI) (After Liu et al, 2012). (b) Structural map of the Dongying Sag. The area in the green line is the study area (After Zhang et al, 2006). Chenjiazhuang Salient to the north, the central faulted in the Shengtuo area, the quartz content is 5%-63% with anticlinal zone to the south, the Lijin subsag to the southwest an average of 32%, the feldspar content is 4%-74% with an and the Minfeng subsag to the southeast, with an exploration average of 37% and the detritus content is 3%-88% with an area of 230 km *DRHWDO )LJE 7KHEDVLQ average of 30%. The reservoir rocks consist mainly of lithic controlling boundary Chennan fault and the secondary Tuo- DUNRVHDQGIHOGVSDWKLFOLWKLFVDQGVWRQHV)LJ 2QWKH Sheng-Yong sub fracture system, jointly controlled the whole, detrital grains are moderately to poorly sorted, with terrace tectonic style in the Shengtuo area, and had important sub-angular or sub-rounded shapes. Grain contacts are mainly LQIOXHQFHRQVHGLPHQWVDQGUHVHUYRLUV)LJ 'XULQJWKH point contact and point-line contact. early period of Es , the Tuo-Sheng-Yong sub fracture system 3.2 Diagenesis features had not yet begun to develop, and nearshore subaqueous IDQVGHSRVLWHG)URPWKHODWHSHULRGRI(V to the period of According to the new diagenetic stage division standard Es , the Tuo-Sheng-Yong sub fracture system developed and of clastic reservoirs in China’s oil and gas industry (Standard formed the terrace. The nearshore subaqueous fans deposited No. SY/T5477-2003), the Paleogene Es -Es reservoirs at 4 3 on the terrace that was constrained by the Chennan fault and depths of 1,500-4,500 m in the Shengtuo area are mainly in Tuo-Sheng-Yong sub fracture system, and sublacustrine fans the eogenetic and mesogenetic stages. Among them, 1,500- deposited in the subsag that was close to the Tuo-Sheng- 2,200 m belongs to the eogenetic stage A period, 2,200-3,000 RQJ<VXEIUDFWXUHV\VWHP$Q )LJ &RQWUROOHG m belongs to the B period of the eogenetic stage, 3,000-3,500 by the tectonic setting, the formation fluid pressure in the m belongs to the A1 sub-period of the mesogenetic stage, Shengtuo area has apparent zoning. Normal and weak fluid and 3,500-4,500 m belongs to the mesogenetic stage A2 sub- overpressure developed mainly in the nearshore subaqueous period (Table 1). The major diagenetic events in the reservoir fans, and medium-strong overpressure with the pressure rocks include compaction, carbonate cements (mainly calcite, dolomite, ferroan calcite and ankerite), quartz cements, et al, 2008; An, 2010). feldspar dissolution, quartz dissolution, authigenetic clays NDROLQLWHDQGLOOLWH DQGLOOLWL]DWLRQRINDROLQLWH)LJ) LJ 3 Petrography and diagenesis 5). Using textural evidence of precipitation and dissolution of minerals and the homogenization temperatures (T ) of 3.1 Petrography fluid inclusions, the epigenetic sequence was determined The data show that in the mid-deep Paleogene reservoirs as follows: 1) compaction, early carbonate cementation Tuo-Sheng-Yong sub-fracture Chennan fault Guangrao Salient Southern slope zone Lijin subsag Chenguanzhuang-wangjiagang fault zone Niuzhuang subsag Fold Belt Linfanjia Salient Bamianhe fault zone Uplift Uplift Gaoqing fault zone Liaodong Uplift Luxi Cangxian uplift Jiaodong Uplift Taihangshan FRHI¿FLHQWRIGHYHORSHGLQWKHVXEODFXVWULQHIDQV*DR Pet.Sci.(2014)11:346-362 349 Well-T 714 Well-T 145 SP RT SP RT 04 2 km N Lithologic Lithologic . . ȍ m ȍ m mv mv column column 10 100 -10 90 080 0 20 Chenjiazhuang Salient T105 T75 T175 T116 T137 T104 T174 T145 T127 T123 T131 T125 T122 T129 Tg2 T121 T160 T82 120 T126 T128 T24 T156 T170 T158 T112 T81 T17 T167 T714 T164 T76 T732 T713 T764 T166 T761 T766 T7 T717 T71 T765 T746 T742 T153 T715 T718 Well site Normal Contour line Root of fan body Middle-front of fan body Fan edge subfacies Sublacustrine Deep lake Middle Gritstone Fine Fine sandstone Sand- Mudstone /well number fault of sand content in subaqueous fan in subaqueous fan facies conglomerate in subaqueous fan fan conglomerate conglomerate Fig. 2 (a) Distribution map of nearshore subaqueous fans and sublacustrine fans in Es LQWKH6KHQJWXRDUHDPRGL¿HGIURP$Q 2010). (b) Depositional sequence of sublacustrine fans and deep lake facies. (c) Depositional sequence of nearshore subaqueous fans 9%. The quartz cements, generally less than 1% in reservoirs, Quartz, % DUHPDLQO\TXDUW]JURZWKVRYHU)LJF I K DQGDIHZ Quartz arenite quartz crystals. The distribution of authigenic clay minerals in Subfeldsarenite Sublitharenite reservoirs has a regularity: above 3,150 m is mainly kaolinite, DQGVKDUSO\EHORZPNDROLQLWHWUDQVIRUPVWRLOOLWH)LJ )URPWKHVKDOORZWRWKHGHHSOD\HUVWKHUHODWLYHFRQWHQW of illite/smectite mixed layer minerals increases, but the ratio of smectite in illite/smectite mix minerals decreases gradually )LJ 6FDO\RUSHWDOVKDSHGFKORULWHEXWQRHDUO\JUDLQ coating chlorite, develops in some reservoir rocks (Zhu et al, 2008; Chen et al, 2009). 80 4 Distribution of porosity intervals and zones Lithic Feldspathic feldsarenite litharenite Litharenite Feldsarenite 100 80 60 40 20 0 RVLW\LQWHUYDODQG]RQHFODVVL¿FDWLRQVFKHPH3RU Feldspar, % Rock fragment, % Core porosities of Paleogene Es -Es reservoirs were 4 3 Fig. 3 Ternary plot showing composition of Paleogene Es -Es reservoirs XVHGWRSORWWKHSRURVLW\GHSWKSUR¿OH,QWKHSRURVLW\GHSWK 4 3 in the Shengtuo area, the Dongying Sag (using sandstone classification profile, normal porosity development depth intervals, AHP VFKHPHRI)RONHWDO development depth intervals, and AHP zones, high porosity zones, low porosity zones in different depth intervals were )LJF G IHOGVSDUGLVVROXWLRQTXDUW]FHPHQWDWLRQ identified with the constraints of three curves, namely, the DXWKLJHQLFNDROLQLWHSUHFLSLWDWLRQ)LJF TXDUW] normal evolution curve of average porosity, the normal U evolution curve of maximum porosity and the porosity GLVVROXWLRQTXDUW]FHPHQWDWLRQ)LJJ LOOLWL]DWLRQRI HQYHORSHFXUYH,QWKHSRURVLW\GHSWK SUR¿OHWKH]RQHVZKHUH NDROLQLWHDQGDXWKLJHQLFLOOLWHSUHFLSLWDWLRQ)LJH I reservoirs with porosities that deviated from the normal The compaction was mainly mechanical compaction, evolution curve of maximum porosity to higher values is and pressure dissolution was weak. The dissolution mainly recognized as AHP zones; the zones where reservoirs with LQFOXGHVIHOGVSDUGLVVROXWLRQ)LJF H J )LJF porosities that deviated from the normal evolution curve of (e)), a little dissolution of aluminosilicate detrital grains maximum porosity to lower values but deviated from normal DQGTXDUW]JUDLQV'HWULWDOFDUERQDWHJUDLQV)LJE H evolution curve of average porosity to higher values is I DQGFDUERQDWHFHPHQWV)LJF K VKRZQRHYLGHQFH recognized as high porosity zones; the zones where reservoirs of significant dissolution. Carbonate cements represent the with porosities that deviated from normal evolution curve of PRVWDEXQGDQWSRUH¿OOLQJFHPHQWV)LJ ZLWKDPD[LPXP average porosity to lower values is recognized as low porosity FRQWHQWXSWR)LJ DQGDQDYHUDJHFRQWHQWRI zones. In the porosity-depth profile, the depth interval (b) (c) (a) Chennan Fault Tuo-Sheng-Yong sub fracture system Depth, m 3300 3250 3200 3150 Depth, m 2150 2100 2050 2000 GLVVROXWLRQODWHFDUERQDWHFHPHQWDWLRQ)LJJ IHOGVSD Debris Feldspar Quartz Carbonate cements Feldspar cements Quartz cements Compaction Temperature, °C Depth, m Eodiagenesis Mesodiagenesis 350 Pet.Sci.(2014)11:346-362 Table 1 Diagenetic stages and main characteristics of the Es -Es reservoirs in the Shengtuo area, the Dongying Sag 4 3 Diagenetic Authigenic cements in sandstones Dissolution Organic matter stage %S Contact Pore in Relative type type Maturity K I I/S Ch I/S R , % Stage Period yield Organic acids Oil Primary Immature A 65 Point CO 2 dominant 2200 100 0.35 Middle Line Primary point secondary B mature ĉ 3000 120 0.5 Line point, Low Primary A1 mature ĉ Point secondary line 3500 35 0.7 Point Primary line, Mature secondary A2 Line 4500 160 1.3 Point High Secondary line, mature dominant Line 5000 180 1.5 with AHP zones is recognized as the AHP development Comparison between calculated mudstone fluid pressure depth interval and the depth interval without AHP zones and measured adjacent sandstone fluid pressure shows is recognized as the normal porosity development depth that the difference is always less than 5%. As well, the oil- interval. bearing properties of more than 8,000 reservoir samples with core porosity data were analyzed with core-logging 4.2 Normal evolution curve of maximum (average) PDWHULDOV6HFRQGE\UHMHFWLQJWKHSRURVLWLHVUHODWLQJWRÀXLG porosity overpressure and/or high-level oil saturation (oil immersion, oil saturated and oil rich) from the porosity database, one The normal evolution curve of maximum porosity SRURVLW\GHSWKSUR¿OHZDVSORWWHGXVLQJUHVHUYRLUSRURVLWLHV in clastic reservoirs refers to the evolution curve of the with normal pressure and low level oil content (oil-free, oil maximum porosity evolving with the burial depth in trace, fluorescence and oil patches). The normal evolution reservoirs that did not experience abnormal geological curve of maximum porosity in Es -Es reservoirs in the processes in favor of porosity enhancement and porosity 4 3 northern steep slope zone in the Dongying Sag was then preservation during deep burial. It can be determined by determined through the smooth connection of maximum connecting the maximum porosity at different depths with SRURVLWLHVDWIHUHQWGLIGHSWKVLQVXFKDSRURVLW\GHSWKSUR¿OH a smooth curve in the porosity-depth profile. Among these )LJ $VHDUO\JUDLQFRDWLQJFKORULWHZDVQRWGHYHORSHG abnormal geological processes, the process in favor of and reservoirs with significant dissolution also have porosity enhancement is the dissolution of unstable minerals relatively good oiliness, the rejection of porosities relating (e.g. feldspars and carbonate minerals), while the processes to fluid overpressure and/or high-level oil saturation from in favor of porosity preservation consist mainly of fluid porosity database promises the elimination of the influence overpressure, early hydrocarbon emplacement, and grain of abnormal geological processes (fluid overpressure, coats. Thus, the normal evolution curve of maximum porosity hydrocarbon emplacement, grain coats and rims, and almost follows the compaction curve. dissolution) on porosities in the Shengtuo area. In order to determine the distribution of AHP zones in The normal evolution curve of average porosity in clastic WKH6KHQJWXRDUHDZHGLGWKHIROORZLQJZRUN)LUVWZLWK reservoirs refers to the evolution curve of the average porosity WKHFRQVWUDLQWVRIWKHPHDVXUHGIRUPDWLRQÀXLGSUHVVXUHWKH evolving with the burial depth in reservoirs that did not formation fluid pressure of over 300 wells in the northern experience abnormal geological processes in favor of porosity steep slope zone in the Dongying Sag was calculated by enhancement and porosity preservation during deep burial. On the equivalent-depth method with acoustic logging data. Pet.Sci.(2014)11:346-362 351 Qa FD Qa Qa FD Qa FD FD 200ȝP 200ȝP (a) Well T165, 3236.08 m (-) (b) Well T145, 2018.3 m (-) FD FD FD FD FD FD K Qa FD 100ȝP 25ȝP (c) Well T714, 2841.3 m (-) (d) Well T714, 2841.3 m (-) Qa Qa FD Qa FD 100ȝP 100ȝP (e) Well T720, 3671.1 m (-) (f) Well T720, 3671.1 m (-) An FD An Qa 50ȝP 100ȝP (g) Well T168, 3110.1 m (-) (h) Well T713, 3032.45 m (+) Fig. 4 Photomicrographs showing diagenetic features related to feldspar dissolution in Paleogene Es -Es reservoirs in the Shengtuo area, the Dongying Sag. (a) Primary pores dominate, surface porosity 4 3 of feldspar dissolution is 0.1%; (b) Primary pores dominate, surface porosity of feldspar dissolution is 0.5%; (c) Massive quartz overgrowths and kaolinite, surface porosity of feldspar dissolution is 2.462%; (d) Authigenic kaolinite and its micropores; (e) feldspar secondary pores and authigenic illite; (f) Quartz JURZWKVRYHUDQGDXWKLJHQLFLOOLWHJ )HOGVSDUSRUHVSDUWLDOO\¿OOHGZLWKDQNHULWHK 4XDUW]JURZWKVRYHU SDUWLDOO\UHSODFHGE\DQNHULWHWKLQVHFWLRQDJ UHGHSR[\U HVLQ±LPSUHJQDWHGWKLQVHFWLRQ)')HOGVSDU dissolution pores; Qa: Quartz overgrowths; K: Kaolinite; I: Illite; An: Ankerite the basis of the normal evolution curve of maximum porosity 4.3 Porosity intervals and zones in clastic reservoirs, the normal average porosity of different With the constraints of the three curves, 3,880 core depth intervals can be calculated using reservoir porosities porosities in the Shengtuo area show one normal porosity with normal pressure and low oil-bearing saturation. Then development depth interval at depth of 1,300-2,800 m and in the porosity-depth profile, the normal evolution curve of three AHP development depth intervals developed vertically average porosity in clastic reservoirs can be determined by in Es -Es reservoirs in the Shengtuo area. The three AHP 4 3 connecting the average porosities at different depths with a development depth intervals are at 2,800-3,200 m, 3,250- VPRRWKFXUYH)LJ 3,700 m, 3,900-4,400 m respectively, and three AHP zones 352 Pet.Sci.(2014)11:346-362 Cc Cc Cc Cd 200ȝP 100ȝP (a) Well T167, 2969.63 m (+) (b) Well T165, 3236.08 m (+) Cc Cc FD F F As 50ȝP 50ȝP (c) (d) Well T73, 3371.25 m (-) Well T73, 3371.25 m (+) Cc Cc Cd Cd FD FD 200ȝP 200ȝP (e) Well T720, 3535.0 m (-) (f) Well T720, 3535.0 m (+) Qa-Ċ An An Qa-ĉ FD (h) Well T724, 4169.8 m, SEM 25ȝP (g) Well T720, 3535.0 m (+) 5/11/2006 HFW WD Mag 20.0μm Fig. 5 Photomicrographs showing diagenetic features related to carbonate cements in Paleogene Es -Es 4 3 reservoirs in the Shengtuo area, the Dongying Sag. (a) Carbonate cement filled most pores, (b) Carbonate detrital grain and the carbonate overgrowths, (c), (d) Intact early carbonate cement cladding and extensive IHOGVSDUGLVVROYHGGLVVROXWLRQIHOGVSDUSRUHVSDUWLDOO\¿OOHGZLWKDVSKDOWH I ,QWDFWFDUERQDWHGHWULWDOJUDLQV and early carbonate cement cladding, extensively dissolved feldspars, (g) Two stages of quartz overgrowths, intact ankerite wrapped in Qa-II, (h) Euhedral ankerite cements. (a, b, g): thin sections; (c-f) red epoxy resin– LPSUHJQDWHGWKLQVHFWLRQ&F&DUERQDWHFHPHQWV&G'HWULWDODUERQDWHFJUDLQ)')HOGVSDUGLVVROXWLRQSRUHV As: Asphalt; An: Ankerite; Qa: Quartz overgrowths H[LVWLQWKHWKUHH$+3GHYHORSPHQWGHSWKLQWHUYDOV)LJ GLVWULEXWHGLQ)LJ ,QWKHSRURVLW\GDWDVHWWKH Low porosity zones and high porosity zones develop in the low porosities account for 35%, the high porosities 33%, and normal porosity development depth interval, while the three the abnormally high porosities 32%. In the AHP development AHP development depth intervals contain the corresponding interval II (3,250-3,700 m), the histogram of porosities low porosity zones, high porosity zones and AHP zones. shows negative skewness, and the porosities are mainly In the AHP development interval I (2,800-3,200 m), GLVWULEXWHGLQ)LJ ,QWKHSRURVLW\GDWDVHWWKH porosities have a bimodal distribution pattern, and are mainly low porosities account for 46%, the high porosities 37%, and Pet.Sci.(2014)11:346-362 353 Core porosity, % Kaolinite, wt% Illite, wt% Illite/Smectite, wt% %Smectite in I/S Chlorite, wt% Carbonate cements, wt% 0 10 20 30 40 50 020 40 60 80 0 20 40 60 80 020 40 60 80 020 40 60 80 0 2040 6080 010 20 30 40 50 1.0 1.0 Es Es Es Es 1.5 1.5 Normal porosity development 2.0 interval 2.0 Normal evolution curve of average porosity 2.5 2.5 Porosity envelope curve Abnormally high porosity 3.0 3.0 Anomalously development high porosity intervalĉ zoneĉ Abnormally high porosity Anomalously 3.5 development 3.5 high porosity intervalĊ zoneĊ z z z z z z 4.0 4.0 Es Es Es Es Es Es 3 3 3 3 3 Abnormally x x x x x x Es high porosity Es Es Es Es Es Anomalously 3 3 3 3 3 3 development high porosity s s s s s s Es Es Es Es Es Es interval ċ 4 4 4 4 4 4 zone ċ x x x x x Es Es Es Es Es Es Normal evolution curve 4 4 4 4 4 4 of maximum porosity 4.5 4.5 Fig. 6 Vertical distribution of core porosities, clays and carbonate cements in Paleogene Es -Es 4 3 reservoirs in the Shengtuo area, the Dongying Sag the abnormally high porosities 23%. In the AHP development PDLQO\GLVWULEXWHGLQ)LJ 7KHORZSRURVLWLHV interval III (3,900-4,400 m), the histogram of porosities account for 1%, the high porosities 9%, and the abnormally distribution shows positive skewness, and the porosities are high porosities 90%. 30 30 2800-3200 m 3250-3700 m 3900-4400 m Sample No.: 1203 25 Sample No.: 1105 25 Sample No.: 88 20 20 20 15 15 15 10 10 10 5 5 5 0 0 0 0 4 8 12 16 20 24 28 0 4 8 1216202428 0 4 8 1216 20 24 28 Porosity, % Porosity, % Porosity, % Fig. 7 Histograms of porosities in different AHP development depth intervals in the Shengtuo area, the Dongying Sag )RU$+3]RQH,,,P WKHSHUFHQWDJHRI 5 Reservoir pores secondary surface porosity in the total surface porosity In order to determine the type of an AHP zone, the relative is about 100%, but its absolute value is always less than content and absolute content of primary pores and secondary &RUHSRURVLWLHVFDQUHDFKXSWR)LJ and polished thin section and SEM samples show that it can be seen that, with an increase of core porosity, both the PLFURSRUHVLQWKHPDWUL[)LJJ K )LJF GHYHORS primary thin section porosity and the secondary thin section and contribute much more to the core porosity than secondary porosity tend to increase, but the percentage of primary thin SRUHV$VDUHVXOWWKLV]RQHVKRXOGDOVREHLGHQWL¿HGDVWKH section porosity increases and the percentage of secondary primary AHP zone, but with predominantly micropores in the WKLQVHFWLRQSRURVLW\GHFUHDVHVJHQHUDOO\)RU$+3]RQH, matrix. (2,800-3200 m) and II (3,250-3,700 m), reservoirs with AHP The pores in high porosity sandstones in different AHP FRQVLVWPDLQO\RIYLVLEOHSRUHV)LJD E )LJD E development depth intervals are complex, and the reservoir and the content of micropores is much less than that of visible VSDFHFRQVLVWVRIQRWRQO\SULPDU\SRUHV)LJ)LJE pores. In reservoirs with AHP, primary pores dominate the (e)), but sometimes secondary pores. However, for the low visible pores and account for 50%-90% of the total visible porosity reservoirs, due to strong compaction or extensive SRUHV)LJ ]RQHV$+3VR,DQG,,VKRXOGEH$+3SULPDU\ carbonate cementation, the reservoir space consists just a zones. The secondary surface porosity in reservoirs with AHP small proportion of secondary pores or matrix micropores ranges from 0.5% to 3.0%. Micropores in authigenic clays )LJ)LJF I L DQGYLVLEOHSRUHVGRQRWGHYHORS DOVRGHYHORSZKHQVLJQL¿FDQWGLVVROXWLRQSRUHVGHYHORS Depth, km Frequency, % Depth, km Frequency, % Frequency, % SRUHVLQUHVHUYRLUVVKRXOGEHFRQVLGHUHGWRJHWKHU)URP)LJ 354 Pet.Sci.(2014)11:346-362 Percentage of primary Percentage of secondary Primary Secondary surface porosity in total surface porosity in total Porosity surface porosity, % surface porosity, % Core porosity, % surface porosity, % surface porosity, % intervals 0 10 203040 50 02 4 6 8 10 12 02 4 6 810 12 020 40 60 80 020 40 60 80 100 1.5 1.5 2.0 2.0 Normal porosity development interval Normal evolution curve of 2.5 2.5 average porosity Porosity envelope curve Abnormally Primary high porosity 3.0 3.0 abnormally development high porosity intervalĉ zone Abnormally high porosity Primary 3.5 3.5 abnormally development intervalĊ high porosity zoneĊ 4.0 4.0 Primary abnormally Abnormally high porosity high porosity zone development 2% 2% interval ċ Normal evolution curve 1% 1% of maximum porosity 4.5 4.5 Anomalously high porosity reservoir High porosity reservoir Low porosity reservoir Fig. 8 Core plug porosity, secondary surface porosity, percentage of secondary surface porosity in total surface porosity and percentage of primary surface porosity in total surface porosity in Paleogene Es -Es reservoirs in the Shengtuo area, Dongying 4 3 6DJ)RUHDFKFRUHSRURVLW\VDPSOHWKHUHDUHPDWFKHGWKLQVHFWLRQDQGUHGHSR[\UHVLQ±LPSUHJQDWHGWKLQVHFWLRQ Anomalously high porosity sandstones High porosity sandstones Low porosity sandstones (a) 200ȝP (b) (c) 100ȝP 200ȝP Tuo76, 2942.02 m, ĭ =22.3%; Tuo168, 3098.24 m, ĭ =15.6%; Tuo167, 2969.63 m, ĭ =2.6%; primary pores (-) primary pores (-) little secondary pores (-) B-1 (d) B-2 (e) B-3 (f) 200ȝP 100ȝP 100ȝP Tuo720, 3671.1 m, ĭ =14.2%; Tuo73, 3371.25 m, ĭ =10.2%; Tuo73, 3368.4 m, ĭ =3.5%; primary pores (-) mainly primary pores (-) debris secondary pores (-) (h) (g) 200ȝP (i) 200ȝP B-3 5/9/2006 HFW WD Mag 50.0μm 3 20 47 PM SD 13 μmSD μm Tuo764, 3949.45 m, ĭ =10.9%; Tuo764, 3951.05 m, ĭ =14.6%; Tuo764, 3950.25 m, ĭ =1.8%; micropores in matrix dominate (-) micropores in matrix, SEM little debris secondary pores (-) Fig. 9 Photomicrographs showing pores of Paleogene Es -Es reservoirs with different porosity levels in different AHP development 4 3 intervals. (a-g, i): red epoxy resin–impregnated thin section Depth, km (3900-4400m) Abnormally high (3250m-3700m) Abnormally high (2800m-3200m) Abnormally high porosity development interval porosity development interval porosity development interval Depth, km Pet.Sci.(2014)11:346-362 355 50 50 50 Well T720P D PP 7PHOO: (b) PP (c) PP Well T764P ĭ=19.0% k P' ĭ =22.3%k P' ĭ=14.4% k P' 40 Well T126P 40 40 Well T764P Well T76P ĭ =16.6%k P' ĭ=6.1% k P' ĭ=12.9% k P' Well T167P Well 764P Well T73P 30 30 30 k P' ĭ=4.6% k P' ĭ=1.8% ĭ=3.5% k P' 20 20 20 10 10 10 0 0 0 3RUHUDGLXVȝP Pore radius, ȝP Pore radius, ȝP Micro pores Macro pores Micro pores Macro pores Micro pores Macro pores AQRPDORXVO\KLJKSRURVLW\VDQGVWRQHV +LJKSRURVLW\VDQGVWRQHV /RZSRURVLW\VDQGVWRQHV Fig. 10 Pore-throat radius distribution of Paleogene Es -Es reservoirs with different porosity levels in 4 3 different AHP development intervals 1) Fluid inclusions 6 Genesis of AHP zones Quartz overgrowths are common in reservoirs and their WKLFNQHVVJHQHUDOO\UDQJHVIURPȝPWRȝP$VSUHVVXUH 6.1 Diagenetic environment and mineral dissolution dissolution was weak, the quartz cements probably mainly originate from feldspar dissolution (Yuan et al, 2013a). T of 6.1.1 Diagenetic environment ÀXLGLQFOXVLRQVLQTXDUW]JURZWKVRYHUFRQFHQWUDWHVLQ& )HOGVSDUGLVVROXWLRQFDUERQDWH dissolution, authigenic -130 °C and 160 °C -180 °C (Table 2), respectively, indicating kaolinite and quartz cements indicate that reservoirs that reservoirs experienced two stages of feldspar dissolution and product precipitation in the diagenetic process. This experienced an acidic diagenetic environment; and quartz FDQDOVREHYHUL¿HGE\WKHWZRVWDJHVRITXDUW]JURZWKVRYHU dissolution, feldspar overgrowths, carbonate cements are LQWKLQVHFWLRQV)LJJ 7KHVDOLQLW\RIIOXLGLQFOXVLRQV symbols that reservoirs experienced an alkaline diagenetic usually exceeds 10%. The high T and salinity indicate a weak environment (Zhou et al, 2011). With extensive feldspar LQÀXHQFHRIPHWHRULFZDWHURQDEOHIHOGVSDU OHDFKLQJVR7 dissolution and weak quartz dissolution in Paleogene we conclude that feldspar dissolution and authigenic quartz reservoirs, we focus on the acidic diagenetic environment that cementation in Es -Es reservoirs occurred in a deep burial 4 3 is critical to secondary pores. diagenetic environment. Table 2)OXLGLQFOXVLRQVGDWDRITXDUW]RYHUJURZWKVLQ3DOHRJHQH(V UHVHUYRLUVLQWKH6KHQJWXRDUHD'DWDIURPWKH*HRORJLFDO6FLHQWL¿F 5HVHDUFK,QVWLWXWHRI6,123(&6KHQJOL2LO¿HOG&RPSDQ\ Size, Vapor phase, Salinity, Well No. Depth, m Strata Host minerals Type T , °C T , °C h ice ȝP vol.% %NaCl Tuo719 3562.1 Es Quartz overgrowth Salt-water 7 6 103.7 -10.4 14.4 Tuo719 3562.1 Es Quartz overgrowth Salt-water 4 5 124.4 -8.0 11.7 Tuo719 3562.1 Es Quartz overgrowth Salt-water 7 10 128.1 -6.9 10.4 Tuo719 3562.1 Es Quartz overgrowth Salt-water 5 7 179.6 -13.5 17.3 Tuo762 3451 Es Quartz overgrowth Salt-water 6 9 168.7 -6.2 9.5 2) Fluid pressure at 40 Ma and in Es reservoirs at 14 Ma (Tang, 2007; Sun, With disequilibrium compaction, hydrocarbon generation 2010) when the reservoir burial depth exceeded 2,200 m. In and clay dehydration, fluid overpressure developed in the source rocks, kerogen began to generate large amounts of Es -Es reservoirs in the Shengtuo area, especially in the organic acids and CO when the depth exceeded 2,000 m. So 4 3 2 sublacustrine fans (Zhang et al, 2009). According to the JDQLFZKHQDFLGVVLJQL¿FDQWDQGRU&2 were expelled into the PHDVXUHGÀXLGSUHVVXUHGDWDZHDNÀXLGRYHUSUHVVXUHEHJDQ reservoirs, overpressure was generated. This suggested that to develop at 2,000 m in the northern steep slope zone, and feldspar dissolution occurred in a relatively closed diagenetic medium-strong fluid overpressure developed commonly V\VWHPZLWKÀXLGRYHUSUHVVXUH ZKHQWKHEXULDOGHSWK$FFRUGLQJH[FHHGHG P)LJ 3) Thermal evolution of organic matter and acidic fluid source 12), fluid overpressure began to develop in Es reservoirs )URP&WR&WKHNHURJHQYLWULQLWHUHIOHFWDQFH 0.000 0.006 0.010 0.016 0.025 0.040 0.063 0.10 0.16 0.25 0.40 0.63 1.00 1.60 2.50 4.00 6.30 10.0 16.0 25.0 40.0 63.0 0.000 0.006 0.010 0.016 0.025 0.040 0.063 0.10 0.16 0.25 0.40 0.63 1.00 1.60 2.50 4.00 6.30 10.0 16.0 25.0 40.0 63.0 0.000 0.006 0.010 0.016 0.025 0.040 0.063 0.10 0.16 0.25 0.40 0.63 1.00 1.60 2.50 4.00 6.30 10.0 16.0 25.0 40.0 63.0 Percentage, % Percentage, % Percentage, % WRHYROXWLRQKLVWRU\RIÀXLGSUHVVXUHLQWKH6KHQJWXRDUHD)LJ 356 Pet.Sci.(2014)11:346-362 Fluid pressure, MPa Fluid pressure coefficient CO in natural gas, % R , % Temperature, °C 0 102030 40 5060 0.6 0.8 1.0 1.2 1.4 1.6 1.8 0 0.5 1.0 1.5 0 50 100 150 0 5 10 15 20 1.0 0.35 0.7 1.3 1.5 2.0 B sub-stage 2.5 of eogenesis 3.0 Early-A sub-stage of mesogenesis 3.5 Late-A sub-stage of mesogenesis Hydrostatic pressure 4.0 4.5 Fig. 11'LVWULEXWLRQRIPHDVXUHGÀXLGSUHVVXUHNHURJHQYLWULQLWHFWDQFHUHÀHR ), formation temperature and CO o 2 contents in the northern steep slope zone of the Dongying Sag (R ) is 0.35%-0.70% in the diagenetic stage from period B authigenic kaolinite and quartz overgrowths with red epoxy of the eogenetic stage to sub-period A1 of the mesogenetic UHVLQ±LPSUHJQDWHGWKLQVHFWLRQV)LJVKRZVWKDWZLWKRXW stage. Thermal evolution of organic matter can generate calibration of kaolinite micropores, the difference between the large amounts of organic acids and CO )LJ 7KHVH contents of feldspar pores and byproducts is generally below 0. acidic fluids expelled into reservoirs from source rocks He and Nan (2004) found authigenic kaolinite microporosity by compaction and overpressure related to hydrocarbon to be 25%-50%. With an average value of 37%, we made the generation and clay dehydration should be the most likely correction of kaolinite content. Then, the difference between source of acids for stage-I feldspar leaching. The stage-II contents of feldspar pores and byproducts was generally less feldspar dissolution mainly occurred at 160 °C to 180 °C. WKDQDQGXVXDOO\YHU\FORVHWR)LJ UDQVIHU7 When the temperature exceeded 160 °C, the degradation of of the dissolution byproducts out of the sandstones may take organic matter in source rocks generated CO . Meanwhile, place during dissipation of overpressure, resulting in some the organic acid generated earlier experienced intense enhanced porosity. However, the data demonstrate that, in a decarboxylation, and its concentration decreased sharply. UHODWLYHO\FORVHGV\VWHPVLJQL¿FDQWIHOGVSDUSRUHVH[LVWEXW CO generated in these processes diffused into the pore the feldspar dissolution has little impact on porosity. The main water and released H , which controlled the pH and provided function of feldspar dissolution is converting primary pores acidic fluids for the stage II feldspar leaching (Surdam et into isovolumetric feldspar secondary pores and micropores al, 1989). CO detected in the fluid inclusions in quartz in authigenic clays. overgrowths also suggests the formation of these cements in In relatively closed diagenetic systems, the feldspar the presence of CO (Chen et al, 2010). In addition, in the oil- dissolution products cannot be effectively removed from the gas reservoirs below 4,000 m, the low CO content indicates sandstones. Precipitation occurs in forms of authigenic clay the consumption of CO E\IHOGVSDUGLVVROXWLRQ)LJ minerals (kaolinite and illite) and quartz cements in situ, and 6.1.2 Little porosity enhancement from feldspar the maximum enhanced porosity by dissolution of one unit dissolution volume of K-feldspar, albite and anorthite is 13%, 7% and Whether feldspar dissolution can effectively increase 4%, respectively (Giles and de Boer, 1990). The maximum the reservoir porosity depends on whether the dissolution amount of feldspar pores in reservoirs in the Shengtuo area byproducts can be removed from the dissolution area. The is about 3%, then, the maximum enhanced porosity due to feldspar dissolution in Es -Es reservoirs occurred in a feldspar dissolution (suppose all are K-feldspars) is just 0.4% 4 3 relatively closed diagenetic system with high temperature and (3%×13%=0.4%), which is in consistent with the statistical salinity. We can also determine this from microscopy, which data. shows that if the feldspar dissolution is weak, the dissolution 6.1.3 Little dissolution of carbonate minerals byproducts are less; if feldspar dissolution is abundant, the Based on the negative relationship between core porosity dissolution byproducts are abundant. To objectively evaluate and the amount of carbonate cements, Zhong et al (2003), the impact of feldspar dissolution on reservoir porosities, Zhu et al (2007) and Zhang et al (2007) argued that the low using interactive image analysis techniques, quantitative content of carbonate cements in the high porosity reservoirs statistics were collected for the contents of feldspar pores, Depth, km LQWKH6KHQJWXRDUHDRULJLQDWHGIURPVLJQL¿FDQWGLVVROXWLRQRI s Es Es Es Es Pet.Sci.(2014)11:346-362 357 Tectonic stage Rifting stage Tectonic uplift stage Depression period 50 40 30 20 10 Age, Ma Stratigraphy Es Es Es Ng Q Ed Nm 4 2 1 20ņ 40ņ 60ņ 80ņ 100 ņ 120 ņ 140 ņ 160 ņ Well Tuo-764 160 ņ 1.8 Pressure increasing stage Pressure stable Pressure decreasing Pressure increasing stage due to due to low compaction stage with stage with hydrocarbon generation with 1.6 with rapid subsidence slow subsidence tectonic uplift relative rapid subsidence 1.4 1.2 1.0 Oil charging period 35-26Ma Oil charging period (13.8-0Ma) Normal-weak Hydrocarbon charging Medium-high overpressure 0.8 overpressure intermission period accumulation system accumulation system st st 1 period hydrocarbon including fluid 1 period hydrocarbon including fluid x z nd nd Es -Ex 2 period hydrocarbon including fluid Es 3 3 4 2 period hydrocarbon including fluid Present formation fluid Present formation fluid Normal pressure Pressure increasing stage 1.8 Stable pressure Pressure decreasing Pressure increasing stage due to stage with rapid due to low compaction stage with stage with hydrocarbon generation with subsidence with rapid subsidence slow subsidence tectonic uplift relative rapid subsidence 1.6 and hydrocarbon generation 1.4 1.2 Oil charging period 1.0 (39-31.9Ma) Weak-medium Oil charging period(13-0Ma) Hydrocarbon charging overpressure Medium-high overpressure 0.8 intermission period accumulation accumulation system system Fig. 12 Burial and thermal history, fluid pressure evolution history and hydrocarbon charging history of VXEODFXVWULQHIDQVLQWKH6KHQJWXRDUHD'DWDRIK\GURFDUERQJLQJFKDUKLVWRU\DQGÀXLGSUHVVXUHHYROXWLRQKLVWRU\ from Cai et al (2009) and Sun (2010)) FDUERQDWHFHPHQWVDQGWKHVLJQL¿FDQWJUDQXODULQWHUSRUHVDUH These phenomena demonstrate that carbonate cements and mainly carbonate cement dissolution pores. detrital carbonate grains were not noticeably corroded. As no With observation of nearly 200 thin sections and red HYLGHQFHVKRZVVLJQL¿FDQWGLVVROXWLRQRIFDUERQDWHFHPHQWV epoxy resin–impregnated thin sections and 55 SEM samples a large number of intergranular pores are likely to be primary in the Shengtuo area, we found carbonate cements occur as intergranular pores instead of carbonate cement dissolution FRQQHFWHGSDWFKHV)LJD VLQJOHFU\VWDO)LJJ RU pores. The most likely reason for the negative relationship JUDLQFRDWLQJFDUERQDWH)LJF I DQGFRPPRQO\H[KLELW between porosity and percent carbonate cements should be HXKHGUDOFU\VWDOIDFHVZKHUHDEXWWLQJRSHQSRUHVSDFH)LJ the carbonate cementation degree, rather than the carbonate 5(h)). The euhedral dolomite coated with stage-II quartz cement dissolution degree. RYHUJURZWKV)LJJ VXJJHVWVWKDWFDUERQDWHPLQHUDOV About the selective dissolution phenomena between were not leached when stage-II feldspar dissolution and feldspars and carbonate minerals, we explain this as follows: quartz cement precipitation took place. In addition, detrital 1) At depths of 2,500-3,500 m, the formation temperature carbonate grains and grain coating carbonate cements show in the Dongying Sag is about 100 °C-130 °C, and the R of QRHYLGHQFHRIGLVVROXWLRQ)LJF I 7KHFDUERQDWH NHURJHQLQVRXUFHURFNVLVZKLFKDUHEHQH¿FLDO overgrowths are often found accompanying detrital carbonate for the generation and preservation of organic acids. Organic JUDLQV)LJE +RZHYHUIHOGVSDUJUDLQVZUDSSHGE\ acids control the alkalinity of pore water, and the pCO is early grain coating carbonate cements or close to detrital UHODWLYHO\KLJK)LJ ,QVXFKDQRUJDQLFDFLGV±FDUERQLF FDUERQDWHJUDLQVZHUHGLVVROYHGH[WHQVLYHO\)LJF I acid–pCO –carbonate minerals–aluminum silicate minerals Pressure evolution and oil Pressure evolution and oil Burial and thermal history x z charging history in Es charging history in Es -Ex 4 3 3 Pressure coefficient Pressure coefficient Depth, km 358 Pet.Sci.(2014)11:346-362 Feldspar pores, % Kaolinite, % Quartz overgrowth, % A, % B, % 012 300 12 3 0.2 0.4 0.6 0.8 1 -1 0 1 -0.5 0 0.5 1.0 1.9 2.1 2.3 2.5 2.7 2.9 3.1 3.3 A, %: Difference between feldspar pore content and dissolution byproducts; B, %: Difference between feldspar pore content and 62.5% of kaolinite content and quartz overgrowth content Amount of feldspar pores, dissolution products, and their differences in Es -Es reservoirs Fig. 13 4 3 buffer system, the carbonate minerals tend to be precipitated 5) The calculation of Meshri (1986) shows that at 25 °C rather than to be corroded, but the feldspars tend to be leached G) for leaching of anorthite (Surdam et al, 1989). and K-feldspar by acetic acid to form kaolinite is –36.9 kJ/ 2) Thick gypsum and salt layers and carbonate layers ǻGPRODQG±N-PRODQG of the reaction between calcite exist in the Palaeogene Es )RUPDWLRQDQGVXJJHVWDKLJK and acetic acid is +11.20 kJ/mol. Meanwhile, as temperature salinity and strong alkalinity of the sedimentary water (Wang, DQGSUHVVXUHLQFUHDVHǻG of reaction between organic 6DOLQLW\GDWDRIÀXLGLQFOXVLRQVLQTXDUW]JURZWKVRYHU acid and feldspars decreases (Huang et al, 2009b), while as LQGLFDWHWKHOHDFKLQJRIIHOGVSDUVE\DFLGLFÀXLGVZLWKKLJK temperature increases, the solubility of carbonate minerals salinity (Table 2). The modern pore water in reservoirs has decreases sharply. Therefore, in a relatively closed diagenetic 2+ 2+ high salinity, and the concentration of Ca and Mg is high environment with high temperature, the organic acids tend to 2+ )LJ +LJKVDOLQLW\DQGKLJKFRQFHQWUDWLRQRI&D and dissolve feldspars rather than carbonate minerals. 2+ Mg probably inhibit carbonate dissolution, and promote its 6.2 Geological processes in favor of porosity precipitation due to the common-ion effect. preservation 3) The main source rocks in the Dongying Sag contain high percentage of carbonate minerals (up to 50%), feldspars 6.2.1 Sedimentary facies DQGRWKHUXQVWDEOHPLQHUDOV4LDQHWDO )LQHXQVWDEOH Statistical data show that sedimentary facies in the minerals with high specific surface area in source rocks Shengtuo area have significant influence on the reservoir UHDFWHG¿UVWZLWKWKHJDQLFRUDFLGVWKDWZHUHUHOHDVHGGXULQJ porosity. On the whole, porosities of sublacustrine fan thermal evolution of organic matter due to their proximity reservoirs are higher than those of nearshore subaqueous (Giles and Marshall, 1986). In addition, the initial salinity of fans, which might be related to the fluid overpressure in SRUHZDWHUZDVKLJKVRÀXLGH[SHOOHGIURPVRXUFHURFNVLQWR VXEODFXVWULQHIDQV)RUH[DPSOHLQ$+3GHYHORSPHQW reservoirs would be rich in various ions. As the fluid with intervals I and II, reservoirs in sublacustrine fans have an high salinity and weak acidity entered into the reservoirs, its average porosity of 15.03% and 10.72%, while the average acidity decreased further, in such condition, the carbonate porosity of reservoirs in nearshore subaqueous fans is minerals tended to be precipitated, rather than be dissolved just 10.43% and 6.43% (Table 3). In sublacustrine fans, (Zeng, 2001). porosities of reservoirs in braided channels in the mid-fan 4) The study by Song and Huang (1990) shows that are the best, followed by porosities of main channels inner- carbonate minerals may precipitate at a pH between 5 and fan, and porosities of outer fan and inter-channels in mid- 6, although most scholars argued that carbonate minerals fan are the worst. In nearshore subaqueous fans, porosities of begin to precipitate when pH exceeds 8.4. In addition, the reservoirs in middle-front of fan body are the best, porosities calculation results by Huang et al (2009a) show that, for of reservoirs in root of fan body and fan edge are worse (Table carbonate dissolution in deep buried reservoirs ( 3,000 m), 3). the pH of fluid should be lower than 5. However, CaCl - type pore water with high salinity of the relatively stagnant 6.2.2 Fluid overpressure environment in the Shengtuo area is generally weakly acidic The fluid pressure in the Es formation experienced five ZLWKS+EHWZHHQDQG)LJ ZKLFKLVQRWIDYRUDEOHIRU stages: 1) normal pressure stage with rapid subsidence at 49- carbonate dissolution in deep burial. 40 Ma, 2) pressure increase stage due to low compaction with Depth, km DQGEDUWKH*LEEVIUHHHQHUJ\ǻ Pet.Sci.(2014)11:346-362 359 + + 2+ 2+ í 2í í pH K & Na , mg/L Ca , mg/L Mg , mg/L Cl , mg/L SO , mg/L HCO , mg/L Total salinity, mg/L Water type 4 3 6.0 7.0 1000 100000 100 10 1000 1000 100000 100 1000 100 10000 1000 100000 CaCl NaHCO MgCl 2 3 2 1.5 2.0 2.5 3.0 3.5 Es Es Es Es Es 4.0 Fig. 14 Characteristics of pore water in Palaeogene Es -Es formation 4 3 Table 3GHYHORSPHQWLQWHUYDOV$+3IHUHQWIHUHQWVHGLPHQWDU\IDFLHVPLFURIDFLHV ÀXLGSUHVVXUHDQGRLOLQHVVLQGLI5HVHUYRLUSRURVLW\RIGLI Sedimentray facies )OXLGSUHVVXUH Oiliness of sandstones Controlling Contro olling factors fa actors Nearshore subaqueous fan Sublacustrine fan Normal Medium Strong Oil -weak No oil, Oil Root of Middle- Main over- over- immersion, Braided Inter over- oil trace spot P P Porosity orosity T To otal t fan front of Total water pressure pressure oil bearing channel channel Por Porosity o osity pressure i i intervals ntervals body fan body channel M Min, % Min, % 1.0 1. 1.0 2.6 1.9 1.4 3.5 1.4 1.7 1.8 1.0 1.8 1.4 1.0 1.4 2.9 Abnormally Max, % 22.0 19.2 22.0 23.6 29.5 19.7 29.5 21.1 19.9 27.0 19.9 29.5 26.9 23.8 29.5 high porosity development Ave, % 10.43 7.46 12.92 6.62 15.03 10.33 17.70 8.34 9.02 11.20 11.62 15.39 10.22 11.35 16.55 interval ĉ Sample No. 516 50 302 164 873 78 595 27 173 426 294 669 363 425 601 Min, % 0.7 0.7 1.8 2.9 1.1 1.5 1.6 1.2 1.1 0.7 1.1 1.2 0.7 1.3 1.5 Abnormally Max, % 20.9 8.8 20.9 20.9 32.9 28.1 32.9 16.8 19.9 11.4 22.1 32.9 22.1 28.1 32.9 high porosity development Ave, % 6.43 3.57 8.60 11.06 10.72 9.66 12.55 6.89 7.16 5.27 10.18 11.92 6.44 10.02 13.63 intervalĊ Sample No. 171 71 70 30 793 166 451 93 83 142 544 278 345 293 326 Min, % ʊʊ ʊ ʊ 1.8 ʊ 1.8 ʊʊ ʊ 1.8 ʊ 1.8 6.1 8.6 Abnormally Max, % ʊʊ ʊ ʊ 22.3 ʊ 22.3 ʊʊ ʊ 22.3 ʊ 13.9 22.3 21.7 high porosity development Ave, % ʊʊ ʊ ʊ 15.12 ʊ 15.12 ʊʊ ʊ 15.12 ʊ 9.56 14.71 16.22 interval ċ Sample No. ʊʊ ʊ ʊ 88 ʊ 88 ʊʊ ʊ 88 ʊ 11 13 64 rapid subsidence and hydrocarbon generation at 40-31.9 Ma, development at 35-24.6 Ma. Moderate-strong overpressure 3) stable pressure stage with slow subsidence at 31.9-24.6 Ma, 4) pressure decrease stage with tectonic uplifting at 24.6- :KHQÀXLGRYHUSUHVVXUHEHJDQWRGHYHORSWKHEXULDOGHSWKV 14 Ma and 5) pressure increase stage due to hydrocarbon of sublacustrine fan reservoirs in Es and Es are always 3 4 JHQHUDWLRQZLWKUHODWLYHO\UDSLGVXEVLGHQFHDW0D)LJ shallower than 2,200 m. The shallow development of fluid 12) (Zhang et al, 2009; Sun, 2010). overpressure retarded compaction during deeper burial and Before 13 Ma, fluid pressure in sublacustrine fans in pores in reservoirs were preserved to greater depths. Es was generally normal, but with weak overpressure Data in Table 3 show that as fluid overpressure Depth, km EHJDQWRGHYHORSDIWHUDERXW0D)LJ &DLHWDO )DQHGJH )DQHGJH 360 Pet.Sci.(2014)11:346-362 increases, the average porosity of reservoirs in the three 7 Conclusions AHP development intervals increases significantly. In AHP 1) Three AHP zones developed in Palaeogene Es -Es development interval I, reservoirs with normal-weak pressure 4 3 reservoirs in the Shengtuo area of the Dongying Sag, at KDYHDQDYHUDJHSRURVLW\RIWKRVHZLWKPLGGOHÀXLG depths of 2,800-3,200 m, 3,250-3,700 m and 3,900-4,400 m, overpressure have an average porosity of 11.62%, and those respectively. with high fluid overpressure have an average porosity of 2) AHP zones at depths of 2,800-3,200 m and 3,250-3,700 15.39% (Table 3). In AHP development interval II, reservoirs m are visible pore primary AHP zones, with visible primary ZLWKQRUPDOÀXLGSUHVVXUHDQGZHDNÀXLGRYHUSUHVVXUHKDYH intergranular pores dominating. AHP zones at the depth of an average porosity of 5.27%, those with middle overpressure 3,900-4,400 m are micropores primary AHP zones, with have an average porosity of 10.18%, and those with strong micropores in matrix dominating. overpressure have an average porosity of 11.92% (Table 3). In 3) In the relatively closed diagenetic system with high temperature and salinity, burial dissolution contribute overpressure, and the average porosity is up to 15.12% (Table little to the AHP zone due to low porosity enhancement 3). So we can say that the shallow development of fluid by feldspar dissolution and little dissolution of carbonate overpressure effectively retarded the compaction, leading to cements. Reservoirs in braided channels of middle fans point contact and line-point contact of detrital grains in deeply in sublacustrine fans and reservoirs in middle-front of fan EXULHGUHVHUYRLUV)LJD J 7KXVVKDOORZGHYHORSPHQW bodies of nearshore subaqueous fans provided the basis for RIÀXLGRYHUSUHVVXUHLVRIVLJQL¿FDQFHWRWKHGHYHORSPHQWRI $+3WKHGHYHORSPHQWRI ]RQHV6KDOORZGHYHORSPHQWRIÀXLG AHP zones in deeply buried strata. overpressure and early hydrocarbon emplacement preserved 6.2.3 Hydrocarbon emplacement high porosity in deep layers by inhibiting compaction and Hydrocarbon emplacement in Es reservoirs occurred carbonate cementation effectively during deep burial. Thus, PDLQO\DW0DDQG0D)LJ 6XQ the favorable exploration targets should be reservoirs with x z Hydrocarbon emplacement in Es -Es reservoirs occurred 3 3 good primary porosity that experienced fluid overpressure PDLQO\DW0DDQG 0D)LJ &DLHW developed from shallow layers, early hydrocarbon al, 2009), and the second stage is more important. When emplacement, and good preservation during later burial. hydrocarbon emplacement took place, the reservoirs were always shallower than 2,500 m. The early hydrocarbon Acknowledgements emplacement inhibited carbonate cementation during late burial and reservoir pores were preserved to deeper depth. This study was financially supported by the National Data in Table 3 show that as oil saturation increases, the 1DWXUDO6FLHQFH)RXQGDWLRQRI&KLQD1R81R average porosity of reservoirs in the three AHP development 41102058), a National Science and Technology Special Grant intervals increases sharply, and carbonate cement content 1R=; DQG)RXQGDWLRQIRUWKH$XWKRURI decreases significantly. In AHP development interval I, National Excellent Doctoral Dissertation of China. We also reservoirs with no oil, fluorescence or oil trace have an thank the following individuals and institutions: Jon Gluyas average porosity of 10.22% and an average carbonate cement of Durham University, Meng Yuanlin of Northeast Petroleum content of 11.22%. Reservoirs with oil spots have an average University, Zhu Guohua in the Hangzhou Institute of porosity of 11.35% and an average carbonate cement content Petroleum Geology, CNPC, and reviewers of this manuscript. of 12.32%. Oil saturated or oil rich reservoirs have an 7KH6KHQJOL2LO¿HOG&RPSDQ\RI6,123(&SURYLGHGDOOWKH average porosity of 16.55% and an average carbonate cement related core samples and some geological data. content of 6.99% (Table 3). In AHP development interval References ,,UHVHUYRLUVZLWKQRRLOÀXRUHVFHQFHRUMXVWDWUDFHRIRLO have an average porosity of 6.44% and an average carbonate An J. The study of sedimentary reservoirs of sand-conglomerate bodies cement content of 9.95%. Reservoirs with oil spots have an in the Es -Es Members in the Shengtuo area. Master Thesis. China 3 4 average porosity of 10.02% and an average carbonate cement University of Petroleum (East China). 2010 (in Chinese) content of 15.60%. Oil saturated or oil rich reservoirs have an Ber ger A, Gier S and Krois P. Porosity-preserving chlorite cements in average porosity of 13.63% and an average carbonate cement shallow-marine volcaniclastic sandstones: Evidence from Cretaceous content of 5.15% (Table 3). In AHP development interval VDQGVWRQHVRIWKH6DZDQJDV¿HOG3DNLVWDQ$$3*%XOOHWLQ 93(5): 595-615 ,,,UHVHUYRLUVZLWKQRRLOÀXRUHVFHQFHRURLOWUDFHVKDYHDQ Blo ch S, Lander R H and Bonnell L. Anomalously high porosity and average porosity of 9.56% and an average carbonate cement permeability in deeply buried sandstone reservoirs: Origin and content of 14.20%. Reservoirs with oil spot have an average predictability. AAPG Bulletin. 2002. 86(2): 301-328 porosity of 14.71% and an average carbonate cement content Cai L M, Chen H H, Li C Q, et al. Reconstruction of the paleo-fluid of 10.40%. Oil saturated or oil rich reservoirs have an average SRWHQWLDO¿HOGRI(V in the Dongying Sag of the Jiyang Depression porosity of 16.22% and an average carbonate cement content ZLWKV\VWHPDWLFÀXLGLQFOXVLRQDQDO\VLV2LO *DV*HRORJ\ of 9.82% (Table 3). So we can say that the early hydrocarbon 30(1): 17-24 (in Chinese) emplacement effectively inhibited carbonate cementation and Cao Y C, Yuan G H, Li X Y, et al. Types and characteristics of WKDWHDUO\K\GURFDUERQHPSODFHPHQWLVRIVLJQL¿FDQFHWRWKH anomalously high porosity zones in Paleogene mid-deep buried development of AHP zones in deeply buried strata. reservoirs in the northern slope, Dongying Sag. Acta Petrolei Sinica. $+3GHYHORSPHQWLQWHUYDO,,,DOOUHVHUYRLUVKDYHPLGGOHÀXLG Pet.Sci.(2014)11:346-362 361 2013. 34(4): 683-691 (in Chinese) sandstones. 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Petroleum Science – Springer Journals
Published: Jul 11, 2014
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