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Marine and Petroleum Geology 48 (2013) 113e123

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Marine and Petroleum Geology

journal homepage: www.elsevier .com/locate/marpetgeo

Fractures of lacustrine shale reservoirs, the Zhanhua Depression in theBohai Bay Basin, eastern China

Kai Jiu a,b,c, WenLong Ding a,b,c,*, WenHui Huang a,b,c, Yeqian Zhang a, Song Zhao a,Liangjun Hu a

a School of Energy Resources, China University of Geosciences, Beijing 100083, ChinabKey Laboratory of Strategic Evaluation of Shale-gas Resources, Ministry of Land and Resources, Beijing 100083, ChinacKey Laboratory of Geological Evaluation and Development Engineering of Unconventional Natural Gas Energy, Beijing 100083, China

a r t i c l e i n f o

Article history:Received 19 March 2013Received in revised form9 August 2013Accepted 11 August 2013Available online 19 August 2013

Keywords:Shale fractureTectonic and non-tectonic fracturesPore pressureReservoir performanceBohai Bay basin

* Corresponding author. School of Energy Resourcsciences, Beijing 100083, China. Tel.: þ86 10 8232062

E-mail address: dingwenlong2006@126.com (W. D

0264-8172/$ e see front matter � 2013 Elsevier Ltd.http://dx.doi.org/10.1016/j.marpetgeo.2013.08.009

a b s t r a c t

Fractures play a vital role in the exploration and development of shale oil and gas by providing effectivespace for shale reservoirs and significantly improving the fluid flow capability. Core observations,microscopic analyses of thin sections, scanning electron microscopy, and Formation MicroScanner Im-aging (FMI) were used to determine the types, causes of formation, and development characteristics ofthe fractures in lacustrine shale reservoirs in the lower part of the Paleogene Shahejie Formation (Es3) inthe Zhanhua Depression, Bohai Bay Basin, eastern China. X-ray diffraction (XRD) analysis, total organiccarbon (TOC) measurements, and porosity and permeability measurements were used to study thecontrolling factors of the fractures in the shale reservoirs, and to analyze the impact of the fractures onthe shale reservoirs properties and subsequent exploration and development. The studied shale reservoirmainly displays tectonic fractures as well as various types of non-tectonic fractures. The non-tectonicfractures mainly include over-pressure fractures, diagenetic fractures, inter-layer bedding fractures,and fractures of mixed origins. In the study area, the tectonic fractures which were formed under thecombined action of tensile and shear stress display the following characteristics. The dip angle of thetectonic fractures varies significantly. Unfilled or half-filled effective fractures have a high proportion.These fractures are mainly oriented in the NEeSW, NNEeSSW, and WNWeESE directions, with fracturesin the NEeSW direction accounting for the highest proportion. The tectonic and non-tectonic fracturedevelopment is affected by multiple types of factors such as the presence of faults, mineral composition,lithology, abnormal pressure and organic matter content. Abnormally high pore pressure is a veryimportant factor in the development of non-tectonic fracture. It is inferred that the over-pressure ismainly related to hydrocarbon generation during thermal evolution. Fractures effectively improve theporosity and permeability of the shale reservoirs, and the enhancement of permeability is particularlysignificant. The current stress field affects the fluid flow capability of the fracture reservoirs, and thepresent maximum principal stress in Zhanhua Depression is oriented in the NEEeSWW direction, whichhas a small angle with fractures in NEeSW direction. We propose that the fractures in this direction havethe greatest connectivity and thus are a high-priority target for petroleum exploration and development.

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1. Introduction

Shale is commonly treated as a source rock or cap rock intraditional petroleum geology and is rarely considered as a reser-voir (Allen and Allen, 1990). However, in practical exploration anddevelopment, more and more commercial gas flows have been

es, China University of Geo-9; fax: þ86 10 82326850.ing).

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found in shales, indicating that shale can act as a reservoir (Jarvieet al., 2007; Ross and Bustin, 2009; Kinley et al., 2009). Becauseshale reservoirs typically have low porosity and permeability,fractures play a vital role in the production of shale reservoirs(Nelson, 1985; John et al., 2002; Zeng, 2010). Fractures not onlycontrol the fluid flow property of the shale reservoirs but also affectthe strategy of development (Corbett et al., 1987; Peggy andMichele, 2001; Zhang and Sanderson, 2002; Shedid, 2006; Ahr,2008; Zeng and Li, 2009).

Some important studies on fracture characteristics of shalereservoir in the world have been described. Curtis (2002) and Hill

Figure 1. (a) Location of the study area; Maps shows the structural features; (b) a NeS trending, structural section with the location shown in (a); (c) a EeW trending, structuralsection with the location shown in (a).

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et al. (2004) stressed the importance of the fractures for thecommercial production and primary exploration strategies ofshale reservoirs. Engelder et al. (2009) provided an improvedunderstanding of those mechanisms that control the origin,orientation and permeability of natural fractures in DevonianeMississippian gas shale in the Appalachian Basin. Gale et al.(2007) characterized natural fractures of Barnett Shale in termsof orientation, size and sealing properties and explain why naturalfractures can be useful for improving hydraulic fracture treatmentefficiency. Decker et al. (1992) reported that the fracture densityand the dispersivity of orientation are the important geologicalfactors controlling the production of shale reservoir. Comparedwith these studies, we systematically discuss the fracture char-acteristics and dominating factors of lacustrine shale reservoirs.

Moreover, the typical examples are provided to illustrate theimpact of fractures on the reservoir property and exploration ofshale gas reservoirs.

The shale oil/gas in the Zhanhua Depression of the Bohai BayBasin, eastern China, was first discovered in the early 1960s. Todate, oil and gas have been produced from about one hundred andthirty wells in the shale formation, and commercial oil and gasflows have been obtained from over thirty wells with the highestsingle well production of 93t/d, indicating a large oil and gaspotential of these reservoirs (Li et al., 2006). The lower sub-section of the third member of Shahejie Formation (Es3) is themost important and target shale oil and gas reservoir. Variousresearchers have performed the studies on the mechanism offracture formation, the distribution of fractures, and qualitative

Figure 2. Tertiary stratigraphy of the Zhanhua Depression.

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investigation of factors affecting fractures in the shale reservoir(Yin et al., 2002; Li et al., 2006; Xiang, 2008; Ning, 2008). How-ever, few investigations have been done on several scientific is-sues. Firstly, there is still a lack of classification of fracture in theshales, and systematic analyses on the development characteris-tics are still scarce. Secondly, little detailed research has beenconducted with respect to dominating controls on fractures.Finally, previous studies have failed to consider the impacts offractures on the fluid flow property. In this study, using core ob-servations, microscopic analyses of thin sections, and scanningelectron microscopy, combined with data from FormationMicroScanner Image (FMI) analysis and experimental analyses,we comprehensively investigate the classification of fracture for-mation related to shale reservoirs in the lower part of Es3 in theZhanhua Depression. We also studied the development charac-teristics, the dominating controls, and the influence of fractureson the fluid flow of shale reservoirs and attempted to provideguidance for the exploration and development of shale gas res-ervoirs in this area.

2. Geological setting

The Zhanhua Depression is a hydrocarbon-rich depressionwithin the Bohai Bay Basin of eastern China (Zhang et al., 2009; Haoet al., 2010; Tong et al., 2012) (Fig. 1a). Intensive petroleum explo-rations have suggested that petroleum reserves are greater than19.1 � 108 t (Wen et al., 2009). The basin is a complex Mesozoice

Cenozoic faulted basin with a tectonic history involving extension,strike-slip movements and tectonic inversion, amongst othertectonism within a Paleozoic cratonic platform setting (Hou et al.,2001; Shi et al., 2004; Qi and Yang, 2010). Based on the tectonicdevelopment of the basin and sedimentary depositional sequences,the Cenozoic evolution of the basin was divided into two stages:rifting from the Eocene to Oligocene and post-rifting from theMiocene to Pliocene (Fig. 2).

The Zhanhua Depression can be summarized as a duplex half-graben rift basin with geometry and development controlled byNEeSW and East-northeast to West-southwest (ENEeWSW)trending extensional and extensional-shear faults, with multiplelow uplifts and half-graben that are steep in the north and gentle inthe south. Areas with NeS structures have structural styles asso-ciated with gentle slopes, low uplifts, sags, steep slopes, and faultzones (Fig. 1b). The Luojia nose-like structure extends into thedepression from south to north, dividing EeWtrending half-grabeninto bead-like or en-echelon secondary sags. In areas with EeWstructures, the depression is complicated by NWeSE and near NeSstriking faults that form multiple secondary sags and low uplifts(Fig. 1c). The areas examined in this study include the Bonan andSikou sags and the Luojia nose-like structure zone within theZhanhua Depression. The area is dominated by NEeSW, North-northeast to South-southwest (NNEeSSW) and West-northwestto East-northeast (WNWeESE) trending faults that developedduring two separate tectonic events: Es4eEs3 and Late Dongyingstage (Wu et al., 2004).

Figure 3. Fracture characteristics of lacustrine shale; (a) Tensile tectonic fractures with low-angle in well L69 core samples, 3049 m; (b) Shear tectonic fractures with high-angle andstable occurrence, the filling materials are carbonate minerals. (c) Diagenetic fractures of the phase transition of minerals, SEM, I/S represents mixed layer of illite and smectite andCc represents Calcite. (d) Diagenetic fractures of the phase transition of minerals, SEM, I/S represents mixed layer of illite and smectite and Cc represents Calcite. (e) Diageneticfractures of the transformation of clay minerals, SEM. (f) Photos of Abnormal pressure fractures in thin section. (g) Inter-layer fractures in cores; (h) Photos of Inter-layer fractures inSEM, the fractures were connected by fractures in a nearly vertical plane. (i) Mixed origin fractures in cores. The arrows represent the locations of the fractures. A: Diageneticfractures of the phase transition of minerals; B: Diagenetic fractures of the transformation of clay minerals; C: Abnormal pressure fractures; D: Inter-layer fractures; E: Mixed originfractures.

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The rifting tectonic sequence consists of the Paleogene Kong-dian (Ek), Shahejie (Es) and Dongying (Ed) formations thatcomprise sediments whose deposition was controlled by boundaryfaults. In comparison, the post-rifting tectonic sequence consists ofNeogene and Quaternary sediments that occupy the entire basin. Aregional unconformity separates the Paleogene and the Neogene(Tong et al., 2012). Multiple lacustrine organic-rich shale units havebeen deposited within the Zhanhua Depression since the Paleo-gene, of which the dark shalewithin the lower parts of the Es3 is themost important in terms of exploration (Wen et al., 2009). Theseshale units host dark gray to graymarls, calcareous shales, lime-richmudstones, dark gray mudstones, and shales with minor siltymudstones, all of which formed in moderate to deep lacustrineenvironments (Zhang et al., 2012). Sequence structures in the areaindicate that the lower part of the Es3 unit was deposited duringexpansion of the lacustrine system and deepening of the waterwithin the lake (Hu et al., 2001). In addition to this expansion,significant terrigenous material and aquatic organic matter weredeposited in the deep lake environment, favoring the formation ofdark shales (Li et al., 2006).

3. Samples and methods

Core samples were collected from the lower part of the Es3 withthe depth ranging from 2911.00 m to 3140.75 m of well L69. Fourhundred and thirty five samples were used for X-ray diffraction(XRD) to quantitatively analyze the mineral compositions. The XRDdata collection was performed using a Panalytical X’Pert PRODiffractometer with Cu Karadiation (40 kV, 30 mA) and scanningspeed of 2�/min. Two hundred and forty four samples were used forTOC analysis using a Leco CS-344 carbonesulfur analyser. Crushedsamples (about 100mg and 120mesh) were heated to 1200 �C in aninduction furnace after removing carbonate using hydrochloric acid(HCl). Porosity and permeability values of 535 samples weredetermined bymercury intrusionmethod performed on a CMS-300core measurement system. Cylinders with diameters of 2.5 cm,heights of 2.5 cme7.6 cm were made before testing. All the testswere completed at the Analysis and Testing Center of GeologicalResearch Institute in Sinopec Shengli Oilfield.

Several wells were typically analyzed for fracture types,including well L69, well L67, well XYS Deep 9, well L151 and well

Figure 4. Interpretation plot of tectonic fractures by FMI imaging logging and photos of cores of the lower part of Es3; (a) Tilted tectonic fractures, Well L69, 3059.8 m; (b) Tiltedtectonic fractures, well L69, 3070 m.

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L152. In particular, well L69, a fully sealed well designated forcoring, was drilled for the study of shale reservoirs in the lower partof Es3 in the Zhanhua Depression. The total length of the corescollected from the well L69 is 229.75 m. The well L69 has providedimportant data for characterizing fractures.

4. Results and discussion

4.1. Fracture types

Based on observations and statistical analyses of the core frac-tures, microscopic analyses of thin sections, and scanning electronmicroscopy, as well as studies of FMI data for the shale in the lowerpart of Es3, it was found that the main fracture types in the researcharea include tectonic fractures and non-tectonic fractures. Thelatter can be further classified into four sub-types: diageneticfractures, abnormal pressure fractures, inter-layer fractures, andfractures of combined origins.

4.1.1. Tectonic fracturesTectonic fractures are those formed when rocks are under direct

regional or local tectonic stress (Zeng et al., 2010). According to themechanicas, the tectonic fractures in the study area are classified astensile fractures and shear fractures. The tensile fractures aremainly formed under the action of tensile stress. The main char-acteristics of the tensile fractures are as follows. Firstly, the occur-rence of fractures is not stable, with slightly varying angles atdifferent layers (Fig. 3a). Secondly, the fractures are often filled with

Figure 5. Pictures of the fillings of fractures and photomicrograph of lacustrine shale; (a

minerals or traces of oil. Shear fractures are mainly formed underthe action of shear stress or tensile-shear stress (Song et al., 2001),and have the following main characteristics. Their occurrence isrelatively consistent, with strong grouping and long extension. Theshear fractures are closed and the filling materials are predomi-nantly carbonate minerals (Fig. 3b). The tectonic fractures wereclearly observed by FMI and show a good correspondence withtectonic fractures in the core (Fig. 4).

4.1.2. Non-tectonic fractures4.1.2.1. Diagenetic fractures. Diagenetic contraction fractures areformed during diagenesis due to the volumetric change caused byvarious types of factors such as the transformation of clay minerals,the phase transition of minerals, and dissolution (Tang et al., 2011).Based on scanning electron microscopy (SEM) observations, thediagenetic fractures formed by the transformation of clay mineralsand phase transitions of minerals are the most common causeshere (Fig. 3c,d and e). The diagenetic fractures are mainly distrib-uted in the shale segments having a high clay content and welldeveloped horizontal beddings. The fracture apertures are mainlybetween 2 and 10 mm, and the majority is partly filled. The size ofthe individual fractures is usually small and widely distributed.

4.1.2.2. Abnormal pressure fractures. Abnormal pressure fracturesare formed when the fluid pressure in the strata acting on the shaleexceeds the breaking strength of the rocks. Abnormal pressurefractures are not directional, and the fracture surface is irregular,often with fracture branches (Fig. 3f). The core observations

) clay minerals filling; (b) bitumen filling; (c) Carbonate observed from microscope.

Figure 6. Tectonic fracture occurrence characteristics of shale; (a) fracture dip; (b) dip angel of fractures; (c) fracture strike.

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indicate that the extension of this type of fractures is generally lessthan 10 cm and disappears within the range of the stratum. Theapertures of the fractures are 0.2e2 mm and are mainly fully filledwith bitumen which suggested that the formation of this type offractures is mainly related to the abnormal pressure caused by thethermal evolution of organic matter (Zhang, 2005).

4.1.2.3. Inter-layer fractures. Interlayer fractures often appear inshale with a developed foliation and are especially developed at thecontact surface of muddy lamina and calcium lamina. In addition,interlayer fractures are mainly connected by fractures in a nearlyvertical plane that cuts through bedding. The aperture of thesefractures is usually smaller than 3 mm (Fig. 3g and h). Furthermore,the foliation surface of the mudstone and shale mainly containssandy minerals, which improves the connectivity of the foliationseams and increases reservoir space (Xu and Bao, 2009).

4.1.2.4. Mixed diagenetic fractures. Mixed diagenetic fractures aretypically formed under the control of tectonic processes at an earlystage and subsequently under the combined action of diagenesis orfluid pressure. The fracture surface is irregular with obviousbedding dislocation and is mainly filled with calcite and bitumen(Fig.3i). This type of fracture is generally less common.

4.2. Characteristics of fracture development

Of the two main fracture types that were discussed above, thetectonic fractures are the principal fracture type and are the mostimportant reservoir space and fluid flow pathway. Therefore,

Figure 7. Structural styles interpreted from seismic profiles (a) and tectonic fractures stylesbottom of the Guantao formation in Neogene. T6 represents the bottom of Es3. The section

statistical analyses of the basic development characteristics of thetectonic fractures, such as the length, width, occurrence, fracturedensity, and filling conditions, were performed by the core obser-vations and the interpretation of FMI results.

The length of the tectonic fractures is generally less than 15 cmand mainly between 2 and 8 cm; the fracture apertures are mainlybetween 50 and 100 mm. The majority of the fractures are unfilled,with little half-filled and fully filled fractures. Specifically, as to wellLuo69, unfilled, half-unfilled and fully-filled fractures account for62.81%, 9.47% and 27.73%, respectively. The filling materials aremainly bitumen, calcite, and clay minerals (Fig. 5a and b).

The fractures dip is predominantly orientated in the NW-SEdirections (Fig. 6a). The tilt angle of the fractures varies signifi-cantly and is mainly between 30� and 50� (Fig. 6b), indicating thatthe tectonic fractures are dominated by tilt fractures formed underthe combined action of tensile and shear stress (Song et al., 2001).The fractures are mainly oriented in the NEeSW direction, with aminor occurrence of North-northeast to South-southwest (NNEeSSW) and West-northwest to East-southeast (WNWeESE) frac-tures (Fig. 6c), which is consistent with the direction of the mainfaults in the research area (Wu et al., 2004), demonstrating thedominance of the faults and paleostress on the fracture orientation.

The fracture density can be evaluated by the linear density,which is the ratio between the number of fractures intersected by astraight line and the length of this line (Narr and Currie, 1982). Ourresults indicate that the fracture density is high. The maximumfracture density for the well L69 is 20 fractures/m with an averageof 11 fractures/m. The maximum fracture density for the Luo 67well is 18 fractures/m with an average of 9 fractures/m.

observed from cores (b) both display the extensional structural styles. T2 represents theprofiles AeB with the location shown in (a).

Figure 9. Mineral composition triangle of shale in the lower part of Es3 in the ZhanhuaDepression.

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The quantitative assessment of the FMI well-imaging for thewell L69 indicates the following: the maximum fracture density(FVDC) is up to 18; the fracture width (PVA) is 10e100 mm; and themaximum visual porosity of fractures (FVPA) is 0.3%, with themajority of values occurring between 0.09% and 0.27%. In general,almost all parameters of the fractures, as interpreted from FMI, areless than those observed for fractures in the cores. The reason ofthis difference is that the release of stress changes original fracturesby increasing the width and length and even forms new fractureswhen the core is retrieved from the well to the surface, therebyincreasing the fracture density.

4.3. Dominating controls on fracture formation

The formation of fractures in shale is affected by many factors(Aplin and Matenaar, 2003; Ding et al., 2011), the fracture forma-tion here is mainly affected by faults, lithology, content of organicmatters, and abnormal pressure.

4.3.1. FaultsThe Zhanhua Depression has experienced multiple tectonic

movements during the Cenozoic, mainly occurring as tenso-shearfaulting, and folding is relatively weak (Wu et al., 2004; Shi et al.,2004). The development of fractures is mainly controlled byfaults. Core observations show frequent tectonic fractures withobvious bedding dislocation pattern. The pattern is consistent withthe characteristics of the regional faults (Fig. 7), which reflects therelatively close relationship between these features.

Under extension, the research area developed mainly synsedi-mentary faults. The controlling effects of faults on fracture devel-opment are: (1) Intensity of the synsedimentary faults; (2) thedistance from the fault; and (3) the variation at different parts ofthe faults. Agust et al. (2010) provided new data to prove thefracture frequency as a function of distance from the fault core andDorothea et al. (2012) showed a pronounced difference on fracturedensities and apertures between fault damage zones and the hostrocks for carbonates.

The index of fault growth is established for characterizing thestrength of fault activity (Thorsen, 1963). The statistical fit betweenthe width of the fracture zone and the growth index of its con-trolling fault indicates a good positive correlationwith a correlationcoefficient of up to 0.72 (Fig. 8). Accordingly, a larger growth indexof faults corresponds to a wider fracture zone. This relationshipindicates that stronger fault activity corresponds to a greater like-lihood for the formation of a fracture. Fractures are more developedwhen being closer to the fault. The summary of the drilling con-dition indicates that the oil- and gas-producing wells are mainlydistributed near fault zones and exhibit a banded distribution alongthese fault zones (Ci et al., 2006).

Figure 8. Relationship of fault growth index and width of the fracture zone in theZhanhua Depression.

However, it should be noted that the relationship between faultand fracture formation is complicated, which is indicated by thefact that different parts of faults have different impacts on the de-gree of fracture development. Fractures are generally developed inareas such as the turning ends of faults, ends of faults, intersectionsof different faults, and between fault zones, which are also the areaswhere the shale reservoirs are developed. Fractures are not welldeveloped near every fault, and there is fracture development inregions without fault development, indicating that fracture for-mation is subject to the influence of other factors.

4.3.2. Mineral composition and lithologyThe X-ray diffraction analyses of mineral compositions of well

L69 indicate that the mineral compositions mainly include detritalminerals, carbonate, and clay minerals. The detrital mineralsinclude quartz and small amounts of potassium feldspar andanorthite. The carbonate minerals include calcite, dolomite, and asmall amount of siderite. The clay minerals mainly include a mixedillite/smectite, illite, kaolinite, and chlorite. In particular, the sam-ples having a quartz content of less than 20% account for 76.3% ofthe total samples; the average quartz content of the whole rock is19.83%, which is relatively low, and quartz mainly exists disper-sively with small impacts on the brittleness of the shale. The claymineral contents are 1e48%; the average for the whole rock is18.59%. Carbonates are the most significant type of mineral in theshale of the lower section of Es3, and the samples with carbonatecontents greater than 45% account for 78.6% of the total samples,with an average of 61.57% (Fig. 9). Quartz, feldspar, and carbonatesare considered the main brittle minerals for shale reservoirs (Hill

Figure 10. Relationship of fracture density and carbonate content of differentlithologies.

Figure 11. (a) Frequency distribution of organic carbon content in the lower part of Es3; (b) Fracture density versus rock type.

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and Nelson, 2000). Therefore, regarding the shale reservoir in thelower part of Es3 in the research area, the carbonate content(Fig. 5c) is the main factor that affects the brittleness.

Ding et al. (2011) proposed that shale reservoirs with a highcontent of brittle minerals can readily form natural fractures andthat such minerals can lead to fractures under external forces. Thestatistical analyses of the carbonate rock contents with differentlithologies indicate that the carbonate content varies for differentlithologies with the following order: laminated calcareousmudstone > laminated marl > calcareous mudstone > marl > oilshale > blocky mudstone > silty mudstone. The statistical analysisof the fracture density for the different lithologies indicates that thecarbonate content has a significant impact on the degree of fracturedevelopment, which is indicated by the positive correlation be-tween a higher carbonate content and a higher degree of fracturedevelopment. The lithologic fracture density trend is from high tolow: laminated calcareous mudstone, laminated marl, oil shale,calcareous mudstone, marl, blocky mudstone, and silty mudstone(Fig. 10).

4.3.3. Organic matter contentsThe analysis of organic carbon (TOC) content data indicates that

the TOC content in the lower part of Es3 is 0.06e9.32%, with mostvalues between 2 and 4%. The samples with TOC contents >1%

Figure 12. Relationship of distribution of the shale fractures in the lower part of

account for 94.2%, indicating that the overall content of organiccarbon is high (Fig. 11a).

The samples were classified into six grades according to themagnitude of the TOC value: 0e1%, 1e2%, 2e3%, 3e4%, 4e5%, andTOC>5%. Fracture densities at individual grades indicate that thedegree of fracture development is closely related to the organicmatter content; in particular, the fracture density increases as theTOC content increases (Fig. 11b). This trend is explained by the factsthat the carbonaceous residue enhances the brittleness of rocksduring the thermal evolution of organic matter. Ro ranges from0.79% to 1.15%, showing the organic matter is at mature stage. Moreimportantly, the increasement of the TOC is related to algal bloomswhich also promote the formation of primary carbonates (Liu et al.,2001). The carbonate rocks increase the brittleness of the shalereservoir, which is conducive to the formation of fractures. There-fore, a higher organic matter content in the shale corresponds to agreater brittleness of the muddy shale. In addition, the largeamount of gas produced during the thermal evolution would in-crease the pressure of the surrounding rocks, and thus fractures areeasily formed in rocks under external forces.

4.3.4. Abnormally high pressureThe majority of shale reservoirs that have been drilled in the

lower part of Es3 in the research area are located in a region having

Es3 and formation pressure (data from the wells) in the Zhanhua Depression.

Figure 13. Evolution of Mohr circles with changes of abnormally pressure; dN: normal stress; s: shear stress; d1: Maximum principal stress; d3: Minimum principal stress.

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abnormal pressure. For example, the pressure coefficient in WellXinyi Shen 9 is up to 1.77, corresponding to a super-high pressure.The overlap between the distribution range of abnormal pressureand the area of shale fracture development indicates good consis-tency, reflecting the controls of abnormal pressure on the forma-tion of fractures in the shale reservoirs (Fig. 12). Abnormal fluidpressure can be formed by multiple factors in theory, such asundercompaction, hydrothermal pressurization, transformation ofclay minerals, tectonic compression, and hydrocarbon generation(Narr and Currie, 1982; Hunt, 1990; Osborne and Swarbrick, 1999;Cao et al., 2006). The organic carbon contents are high within theshale of the lower section of Es3 in the Zhanhua Depression and aretypically within the oil-generating range. Observed from the cores,the fractures formed by abnormal pressure are predominantly filledwith bitumen.

For rock to rupture and form micro-fractures, it is necessarythat the fluid pressure exceeds the minimum principal stress andthe tensile strength of the rock (Jean, 1981), i.e., Pf � d3 þ R,where Pf is the pressure of fluid (Mpa), d3 is the minimumprincipal compressive stress (Mpa), and R is the tensile strengthof rocks (Mpa). Based on the stress analysis using Mohr’s circle,when there is abnormal pressure in the stratum, such pressurewill offset the confining pressure, which decreases the effectivestress acting on the rock. Thus, the overall Mohr’s circle of stressshifts to the left and approaches the rupture envelope of rocks,allowing the rock to rupture more easily. When the abnormalfluid pressure reaches a certain strength, the minimum principalstress will shift from positive (compressive stress) to negative(tensile stress) to form tensile fractures perpendicular to theminimum principal stress (Zeng and Li, 2010). Therefore, whenboth the increase in fluid pressure and the decrease in minimumprincipal stress are satisfied, rocks are capable of rupturing toform fractures (Fig. 13).

Figure 14. Relationship of porosity and permeability of the lower part of Es3.

Abnormal fluid pressure can cause the rock to rupture to formabnormal pressure fractures. The high geothermal gradient causedby abnormally high pressure accelerates the transformation ofsmectites to illites, which can form additional mineral contractionfractures. These fractures cause abnormal pressure fractures, tec-tonic fractures, and diagenetic fractures to connect each other toform the fracture network. In addition, abnormally high pressurecan minimize the extent of compaction, which plays a role in pre-serving and improving interlayer seams, micro-fractures, and pri-mary pores (Zhang et al., 2010; Song, 2011).

4.4. Impact of fractures on shale reservoir

4.4.1. The impact of fractures on the reservoir property of shalereservoirs

The analysis of the porosity and permeability of 535 shalesamples from the lower section of Es3 in the research area indicatesthat the porosity of the shale reservoirs of the lower section of Es3 ismainly within the range of 2e6%, with an average porosity of 5.51%.The number of samples having a permeability <10 md accounts for88.34%, with an average permeability of 9.19 md. The averageporosity of samples with fractures is 5.83%, 14.64 md, respectively.The average porosity of samples without fractures is 5.07%, with anaverage permeability of only 0.28md. The relationship between theporosity and permeability (Fig. 14) indicates that both the porosityand permeability of samples with fractures are higher than those ofsamples without fractures. The permeability of the samples withfractures is significantly increased.

Figure 15 shows the vertical fracture distribution for the shalesegment of well L69 in the research area and a diagram of variationof the shale porosity and permeability. These data show that thesegment between 3036 m and 3068 m has a high fracture density,and the porosity and permeability of the shale reservoirs are alsohigh in this segment. Moreover, the permeability is the highestamong the entire well segment, and the results of well loggingindicate abnormal pressure. This portion of the core is identified asthe reservoir segment and occurs as a fractured shale reservoir. Inaddition, the sections at 2932 me2960 m and 3007 me3019 mhave a high fracture density, and the corresponding porosity andpermeability exhibit a similar pattern. This result indicates that thedegree of fracture development is the key factor that controls theproperty of shale reservoirs. The fractures not only provide effectivereservoir space for shale reservoirs but also significantly improvethe fluid flow performance.

4.4.2. The impact of fractures on the exploration of shale gasreservoirs

Fractures are of significance for the deployment ofwell networksat the early stage of reservoir development. The current stress field

Figure 16. Present maximum principle stress direction in the Zhanhua Depression.

Figure 15. Relationship of the fracture development and porosity, permeability in thelower part of Es3; well L69.

K. Jiu et al. / Marine and Petroleum Geology 48 (2013) 113e123122

controls the aperture and connectivity of fractures (Zeng and Tian,1998). If the orientation of fractures is parallel to the orientation ofcurrent maximum principle stress, the aperture and connectivity offractures are optimal. In contrast, if the orientation of fractures isperpendicular to the orientation of current maximum principlestress, the aperture size is minimized, and the connectivity is poor.In addition, if the orientation of fractures obliquely intersects theorientation of the current maximum principal compressive stress, asmaller angle of intersection corresponds to a greater aperture andconnectivity of fractures (Mohammed et al., 2012). The currentorientation of the maximum principal compressive stress for theZhanhua Depression is oriented in an ENEeWSW direction andobliquely intersects with fractures in the NEeSW, NNEeSSW, andNWeSE directions (Fig. 16). In addition, the angle of intersection

with fractures is the smallest in the NEeSW direction. Thus, wepropose that the fractures in NEeSW direction have the best flowproperty, and the initial deployment of a well network should focuson fractures oriented in a NEeSW direction.

5. Conclusions

(1) The shale reservoir in the lower part of Es3 in ZhanhuaDepressionmainly displays tectonic fractures as well as varioustypes of non-tectonic fractures, including over-pressure frac-tures, diagenetic contraction fractures, inter-layer beddingseams, and fractures of mixed causes. The tectonic fractures arethe principal fracture type.

(2) The tectonic fractures are mainly oriented in the NEeSW,NNEeSSW, and WNWeESE directions which are consistentwith the direction of the faults, and the proportion of unfilledor half-filled effective fractures is high. The parameters of thefractures interpreted from FMI are smaller than those observedfor fractures in the cores.

(3) The fracture development of shale is affected by factors such asthe presence of faults, mineral composition and lithology,abnormal pressure and organic matter content.

(4) The properties of shale reservoir are closely related to thedevelopment of fractures that provide effective space for shalereservoir and significantly improve thefluidflowcapability. Thefractures are significant for the development ofwell patterns. Atpresent, the maximum principal stress (NEEeSWW direction)in Zhanhua Depression has a small angle with fractures in NEeSW direction. We propose that fractures in this direction havethe bestfluidflowproperty and are a high-priority target for thedevelopment and deployment of initial well networks.

Acknowledgments

The study was sponsored jointly by the National Natural Sci-ence Foundation Project (41372139, 41072098, 41002072), Na-tional Special Project of Investigation and Evaluation on StrategicScreening for National Oil & Gas Resources “Potentials of Shale GasResources in Key Chinese Areas and Optimization of FavorableAreas” (No. 2009GYXQ-15), Major Special Project for NationalScience and Technology (2011ZX05018-001-002, 2011ZX05009-

K. Jiu et al. / Marine and Petroleum Geology 48 (2013) 113e123 123

002-205). We are greatful to the Analysis and Testing Center ofGeological Research Institute in Shengli Oilfield, that helped to testand analyze samples.

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