lable at ScienceDirect

Marine and Petroleum Geology 56 (2014) 87e96

Contents lists avai

Marine and Petroleum Geology

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

Research paper

Modeling free gas content of the Lower Paleozoic shales in theWeiyuan area of the Sichuan Basin, China

Qin Zhou a, Xianming Xiao a,*, Hui Tian a, Lei Pan a,b

a State Key Laboratory of Organic Geochemistry, Guangzhou Institute of Geochemistry, Chinese Academy of Sciences, Guangzhou 510640, ChinabUniversity of Chinese Academy of Sciences, Beijing 100049, China

a r t i c l e i n f o

Article history:Received 9 October 2013Received in revised form3 April 2014Accepted 6 April 2014Available online 18 April 2014

Keywords:Sichuan BasinWeiyuan areaLower PaleozoicOrganic-rich shaleShale gasGas content

* Corresponding author. Tel.: þ86 20 85290176.E-mail address: xmxiao@gig.ac.cn (X. Xiao).

http://dx.doi.org/10.1016/j.marpetgeo.2014.04.0010264-8172/� 2014 Elsevier Ltd. All rights reserved.

a b s t r a c t

Two sets of Lower Paleozoic organic-rich shales develop well in the Weiyuan area of the Sichuan Basin:the Lower Cambrian Jiulaodong shale and the Lower Silurian Longmaxi shale. The Weiyuan area un-derwent a strong subsidence during the Triassic to Early Cretaceous and followed by an extensiveuplifting and erosion after the Late Cretaceous. This has brought about great changes to the temperatureand pressure conditions of the shales, which is vitally important for the accumulation and preservationof shale gas. Based on the burial and thermal history, averaged TOC and porosity data, geological andgeochemical models for the two sets of shales were established. Within each of the shale units, gasgeneration was modeled and the evolution of the free gas content was calculated using the PVTSimsoftware. Results show that the free gas content in the Lower Cambrian and Lower Silurian shales in thestudied area reached the maxima of 1.98e2.93 m3/t and 3.29e4.91 m3/t, respectively (under a pressurecoefficient of 1.0e2.0) at their maximum burial. Subsequently, the free gas content continuouslydecreased as the shale was uplifted. At present, the free gas content in the two sets of shales is 1.52e2.43 m3/t and 1.94e3.42 m3/t, respectively (under a current pressure coefficient of 1.0e2.0). The resultsare roughly coincident with the gas content data obtained from in situ measurements in the Weiyuanarea. We proposed that the Lower Cambrian and Lower Silurian shales have a shale gas potential, eventhough they have experienced a strong uplifting.

� 2014 Elsevier Ltd. All rights reserved.

1. Introduction

Lower Cambrian and Lower Silurian shales, characterized bytheir organic-richness, widely developed in the Upper Yangtze re-gion of southern China. They are the key target in the region forshale gas exploration and evaluation (Dong et al., 2009;Wang et al.,2009; Zhu et al., 2010; Nie et al., 2011; Nie and Zang, 2011, 2012;Huang et al., 2012a,b; Chen et al., 2012; Wang et al., 2012). Thetwo sets of shales are highly mature, with equivalent vitrinitereflectance (EqRo) ranges of 2.0e3.0% for the Lower Silurian and2.5e3.5% for the Lower Cambrian based on their measured pyro-bitumen reflectance (Zhu et al., 2006a; Wang et al., 2009; Nie et al.,2011; Yu et al., 2012; Cheng and Xiao, 2013; Xiao et al., 2013). Overthe geological history, the Lower Paleozoic strata experienced deepburial during the Early Mesozoic and followed by an intenseuplifting from the Late Mesozoic to the Cenozoic (Zhu et al., 2006b;Ma et al., 2008; Zhang et al., 2008; Liu et al., 2009; Xiao et al., 2012).

By the end of the Early Cretaceous, the Mesozoic strata (Triassic toLower Cretaceous) had a general thickness in the range of 5000e6000 m, with the Lower Paleozoic shale possibly reaching a burialdepth of 7000e9000 m (CPGEC, 1989). In the Late Cretaceous, theUpper Yangtze region experienced uplift and erosion, with adenudation of 3000e6000 m (Zhu et al., 2006b; Ma et al., 2008;Wei et al., 2008). At present, the burial depth of the Lower Paleo-zoic shale varies with locations in the Upper Yangtze region, and ismostly within a range of 2000e7000 m in the Sichuan Basin. Insome strongly uplifted areas, the shales occur as outcrops. Thisindicates that the Lower Paleozoic shales in the Upper Yangtzeregion have undergone a complicated tectonic evolution whichbecomes one of the most vital factors influencing the gas content inthe shales.

The natural gas in shale (shale gas) can occur in three formsdepending on its state of preservation: free gas, absorbed gas anddissolved gas. For a highly mature (Ro > 2.0%) shale with a highformation temperature (>100 �C), the gas is stored primarily as freegas (Montgomery et al., 2005) with very little absorbed and dis-solved gas (Montgomery et al., 2005; Ross and Bustin, 2008; Zhanget al., 2012). In the Upper Yangtze region, the Paleozoic shale has

Q. Zhou et al. / Marine and Petroleum Geology 56 (2014) 87e9688

undergone hydrocarbon generation, expulsion and accumulationduring its burial in the early Mesozoic (from the Triassic to EarlyCretaceous), and followed by a strong uplifting, which has greatlychanged the accumulation and preservation conditions for shalegas. Therefore, an understanding of the evolution of free gas con-tent over geological history is significant for evaluations of shale gascontent.

The Weiyuan area of the Sichuan Basin, where the burial depthof the Paleozoic shales is relatively shallow (1600e3600m), is a keyarea for shale gas exploration (Song,1996; Dai et al., 1999; Zhu et al.,2006b, 2010; Zeng et al., 2011; Nie and Zang, 2012; Huang et al.,2012a,b). Previous work studied the tectonic evolution (Zhu et al.,2006b; Wei et al., 2008), the distribution of sedimentary faciesand the organic-rich shales (Wei et al., 2008; Wang et al., 2009;Huang et al., 2012a, 2012b; Li et al., 2013), geochemical character-istics (Zhu et al., 2006b, 2010; Wang et al., 2009; Sun et al., 2012),and the porosity and pore structure (Wang et al., 2009; Ma et al.,2012; Nie et al., 2011; Nie and Zang, 2012; Chen et al., 2012; Tianet al., 2012) of the Paleozoic shales in this area, suggesting thepresence of shale gas play. However, the gas content characteristics,especially the free gas evolution through geological history, of thePaleozoic shales have not been extensively discussed. In this paper,the geological and geochemical models of the two sets of LowerPaleozoic shales in the Weiyuan area are examined. The free gascontent in the shales is simulated and quantified with the PVTSimsoftware, and the changes in the gas during its geological evolutionare discussed. The aim is to provide a theoretical guidance for theexploration and development of shale gas in the Weiyuan area aswell as other areas in the Sichuan Basin.

2. Geological settings

2.1. Structures and stratigraphy

The Sichuan Basin is an important part of the Upper Yangtzeregion. The Weiyuan area extends over about 2700 km2 in thesouthwestern part of the Sichuan Basin. It locates on the

Figure 1. Sketch map showing of the structural outline of

southeastern edge of the Leshan-Longnvsi paleo-uplift (Fig. 1) (Zhaiet al., 1989), and is characterized as a large-scale NEEeSEW ori-ented domal anticline. The strata present in the Weiyuan areaconsist of Sinian, Cambrian, Ordovician, Silurian, Permian andTriassic units (Fig. 2). A total of 659e670 m of the Upper Sinian issubdivided into the Dengying and Doushantuo formations (Weiet al., 2008). The Dengying Formation, composed mainly ofmicrocrystalline dolomite, is the main conventional gas reservoir intheWeiyuan area (Dai, 2003; Wei et al., 2008). The Cambrian units,with a total thickness of 766e1019 m, consist of the Jiulaodong andYuxiansi formations in the Lower Cambrian and the XixiangchiFormation in the Upper Cambrian. The Jiulaodong Formation,containing a set of organic-rich black shales with a thickness of230e400m, is the main source rock of the Sinian gas reservoir (Dai,2003). With a total thickness of 356e504 m, the Yuxiansi andXixiangchi formations are mainly intertidal shoal sediments andsupratidal dolomite interbedded with sandstone and siltstone. Dueto the Caledonian orogeny, the Ordovician strata developed poorlyin the Weiyuan area with a total thickness of only 182e355 m. TheLower Ordovician Luohanpo and Dachengsi formations are domi-nated by dolomite and limestone, whereas the Middle OrdovicianBaota Formation is primarily limestone with less shale. The Silurianstrata are missing in the northwestern part of the Weiyuan area,but present in its southeastern part where the Lower SilurianLongmaxi Formation has developed as a set of organic-rich shalesand silty mudstones with a thickness of about 140 m. The Devonianand Carboniferous strata are missing in this region because of theuplifting of the Hercynian orogeny (Dai, 2003;Wei et al., 2008). ThePermian contains the lower Maokou Formation and the upperLongtan Formation. The Maokou Formation is characterized bylimestone with a thickness of 204e459 m, whereas the LongtanFormation consists of limestone, shale and coal with a thickness of188e242 m. About 842e1565 m of Triassic strata consist of a set oflimestone, dolomite, shale and coal in the middle-to-lower parts ofthe section and a set of sandstone interbedded with shale in theupper part. The Jurassic and younger strata are presently missing inmost of the Weiyuan area. However, according to the regional

the Sichuan Basin and location of the Weiyuan area.

Figure 2. Schematic diagram showing the stratigraphy system of the Weiyuan area, as well as the sedimentary environments and main tectonic events.

Q. Zhou et al. / Marine and Petroleum Geology 56 (2014) 87e96 89

sedimentary records, a large thickness (about 3000e4500 m) offluvialedeltaicelacustrine sediments was ever deposited duringthe Jurassic to the early Cretaceous periods in the Weiyuan area(Zhu et al., 2006b; Wei et al., 2008). However, both the Yanshanorogeny in the Early Cretaceous and the Himalayan orogeny after-ward severely uplifted this area, resulting in complete erosion ofthe Jurassic and early Cretaceous strata and forming the presentstratigraphic pattern.

2.2. Organic-rich shale

Two sets of organic-rich shale have developed in the LowerPaleozoic strata in the Weiyuan area: the Lower Cambrian

Jiulaodong Formation shale and the Lower Silurian Longmaxi For-mation shale (Fig. 2). The Jiulaodong Formation shale, which has athickness of over 230 m, is distributed stably in the Weiyuan area.The total organic carbon content (TOC) in the shale ranges from 0.6to 6.46%, with an average of 2.06% (Huang et al., 2012a). This shale ischaracterized mainly as a type I kerogen for its original organicmatter (Zhu et al., 2006b) and it is highly mature with an EqRorange from 2.56 to 3.14% based on the measured pyrobitumenreflectance value (Wang et al., 2009; Huang et al., 2012a). TheLower Silurian Longmaxi Formation shale, which is characterizedas graptolite shale, is mainly distributed on the southeastern flankof the Weiyuan anticline. It has a maximum thickness of about140 m in the Weiyuan area and becomes thicker towards the

Q. Zhou et al. / Marine and Petroleum Geology 56 (2014) 87e9690

southeast (Zhu et al., 2010; Zeng et al., 2011; Huang et al., 2012b; Liet al., 2013). The TOC of this shale is in the range of 0.51e4.88%, withan average value of 1.86% (Wang et al., 2009). This shale is alsomainly organic type I (original kerogen type) with an EqRo rangefrom 1.80 to 2.24% (Wang et al., 2009; Huang et al., 2012b). Thesetwo sets of shales are now shallowly buried, with a current burialdepth of 2500e3600 m for the Lower Cambrian shale and 1600e3200 m for the Lower Silurian shale (Figs. 3 and 4). These are themost favorable targets for shale gas exploration in the SichuanBasin.

3. Methods and data sets

3.1. Methods

The simulation and calculation of the free gas content inorganic-rich shales is carried out with the software PVTSim 10.0.2,which was developed by the Calsep Company. The PVTSim soft-ware, by adopting a SoaveeRedlicheKwong state equation, can beused to simulate various physical parameters of fluid in rocks undergeological situations with numerous effective applications (e.g.,Aplin et al., 1999, 2000; Tseng and Pottorf, 2003; Liu et al., 2003; Miet al., 2003). In this paper, we have comprehensively considered theimpacts of porosity, water saturation, temperature and pressure onthe free gas content in shales. By simulating a mixture of water andhydrocarbon gas under different conditions, we have obtainedvarious data including themolar volume, density, molarmass, masspercentage, compressibility coefficient, thermal entropy, and

Figure 3. Distribution of the Lowe Cambrian shale in Weiyuan and nearby areas in the southet al., 2012a,b; Li et al., 2013).

thermal enthalpy as well as the compositions of the vapor andliquid fluids within the pore space of shales. Using these data, wecan roughly calculate the free gas content of a shale under certaingeological conditions. The calculation formula can be expressed asfollows:

A ¼�f�ð1�SwÞ�Cv

Vv þ f�Sw�CaVa

�� 22:4� 1000

r;

where A is the free gas content, m3/t; f is the shale porosity; Sw isthe water saturation in the shale pore space; Cv is the percentage ofhydrocarbon gas in gaseous phase; Ca is the percentage of hydro-carbon gas in liquid phase; Vv is the molar volume of the gaseousphase; Va is themolar volume of the liquid phase; r is the density ofthe shale, 2.6 t/m3.

3.2. Geological models and geochemical parameters

The gas generation potential of shale is vitally important for itsgas content by providing with gas source. The porosity of the shaleand its water saturation, the geological temperature and pressurethe shale experienced in geological history are the main factors tocontrol its gas storage. These are the basic parameters used in thePVTSim simulation of free gas content in shales.

3.2.1. Burial historyAs described above, the Weiyuan area has experienced two

episodes of sedimentation and uplifting during its tectonic

ern Sichuan Basin, showing the isopach and isobath of the shale (modified from Huang

Figure 4. Distribution of the Lowe Silurian shale in Weiyuan and nearby areas in the southern Sichuan Basin, showing the isopach and isobath of the shale (modified from Huanget al., 2012a,b; Li et al., 2013).

Q. Zhou et al. / Marine and Petroleum Geology 56 (2014) 87e96 91

evolution, respectively controlled by the Caledonian and Himalayanorogenies. Xiao et al. (2012) rebuilt the burial history of well W-117(Fig. 5). The data show that the Caledonian orogeny lasted from theend of Silurian to the beginning of Permian, resulting in themissingof Devonian and Carboniferous strata and the erosion of the UpperSilurian strata. This area continued to receive sediments from theEarly Permian to the Early Cretaceous, with the development of alarge thickness of Mesozoic strata. The maximum thickness of the

Figure 5. Burial history of the well W117 in the Weiyuan area.

section from the Lower Cretaceous to the Lower Cambrian andLower Silurian is 7250 and 6100 m, respectively. Strong upliftingbegan at the end of the Early Cretaceous in this area, resulting in thetotal erosion of the Lower Cretaceous, Jurassic and part of the UpperTriassic strata. The present burial depths of the Lower Cambrianand Lower Silurian layers are 2950 and 1800 m, respectively.

3.2.2. Thermal history and gas generationAccording to vitrinite and bitumen reflectance data of the core

samples of well W-117, a simplified thermal gradient evolutionhistory was established for the Weiyuan area by the reflectanceinversion method: 32 �C/km (>96 Ma) e 30 �C/km (96e65 Ma) e27 �C/km (<65 Ma) (Xiao et al., 2012). Additionally, the thermalevolution histories of the Lower Cambrian and Lower Silurian shalein well W-117 (Fig. 6a) are reconstructed by combining the thermalgradient model and their burial histories (Fig. 5). Based on thethermal evolution history, the EasyRo evolution history wassimulated and established, which was transformed into theequivalent vitrinite reflectance (EqRo) model (Fig. 6b) with theirtransformation relationship from Tang et al. (1996). Moreover, thegas generation kinetics parameters of a reference sample areneeded in order to simulate the gas generation history of the LowerCambrian and Lower Silurian shales. The thermal maturity levels ofthe two sets of shales in the Sichuan Basin and other Upper Yangtzeregion are very high, unsuitable to obtain the reliable parameters.The gas generation kinetics parameters of a Lower Paleozoic shalefrom the Tarim Basin reported by Tian et al. (2007) were applied tothis simulation and calculation since it has a comparable

a0

50

100

150

200

250

300

0 100 200 300 400 500 600Age (Ma)

Tem

pera

ture

()

Lower CambrianLower Silurian

b0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

0 100 200 300 400 500 600Age (Ma)

Equ

ival

ent R

o (%

)

Lower CambrianLower Silurian

c0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

0 100 200 300 400 500 600Age (Ma)

Gas

gen

erat

ion

(m3 /t)

Lower CambrianLower Silurian

Figure 6. Plots showing the thermal evolution (a), the maturity evolution (b) and thegas generation (c) of the Lower Cambrian and Lower Silurian shales at the well W117.

Q. Zhou et al. / Marine and Petroleum Geology 56 (2014) 87e9692

geochemical characteristics with the studied shales, and both ofthem formed in similar depositional environments. An average TOCof 2.06% for the Lower Cambrian shale and 1.86% for Lower Silurianshale were adopted in the calculation, and a maximum gas gener-ation potential of 350 m3/t TOC was assigned for the two sets ofshales (Wang et al., 2009; Huang et al., 2012b). The modelingsoftware is Kinetics 2000 developed by Braun and Burnham (1998).The results are displayed in Figure 6c.

From Figure 6, the Lower Cambrian shale began to generate oilat the end of Permian (about 259Ma) when the shale reached 70 �Cand the Ro exceeded 0.5%. During the early Jurassic (about 185 Ma),the shale reached 156 �C and the Ro reached 1.2%, thereby attainingthe lower limit of oil generation and beginning the gas producingstage. In themid-late Jurassic (about 165Ma), the shale attained themain gas generation stage at 180 �C and a Ro of about 1.56%, andabout 1.62 m3/t (cubic meters per ton shale) of hydrocarbon gas

could be generated. By the end of the Early Cretaceous (about96 Ma), the shale had almost attained the lower limit of gas gen-eration with the temperature reaching 247 �C and Ro reachingabout 3.02%; gas generation also reached a maximum value of7.21m3/t. The present temperature of this shale is 94.7 �C and its Rois 3.09%.

The Lower Silurian shale reached 70 �C with a Ro over 0.5% inthe middle Triassic (about 222 Ma) and started to generate oil. Atthe end of Jurassic (about 155 Ma), the temperature reached 155 �Cand Ro reached 1.17%, thereby attaining the lower limit of oil gen-eration and beginning gas generation. In the early Cretaceous(about 135 Ma), the shale attained the main gas generation stage at178 �C and a Ro of 1.53%, and gas generation reached 1.59 m3/t. Bythe Late Cretaceous (96 Ma), the shale had reached 210 �C and Roapproached about 2.20%, and gas generation reached a maximumof 5.5 m3/t. As a result of the uplift, gas generation from the shalestopped. The present shale temperature is about 63.6 �C, and the Rois about 2.3%.

According to the model above, it is clear that these two sets ofshale have experienced a complete evolution of hydrocarbon gen-eration phases, including oil generation, oil cracking to gas andresidual kerogen cracking to gas. With continuous gas generation, alarge number of nanopores were created, which provided extraspaces for shale gas storage (Jarvie et al., 2007; Loucks et al., 2009;Tian et al., 2013; Wang et al., 2013).

3.2.3. Shale porosityThemain factors that influence the porosity of a shale include its

inorganic and organic compositions, and its diagenesis or thermalmaturation experienced (Jarvie et al., 2007; Katsube et al., 1992,1994, 2000; Kuila and Prasad, 2010). While the original intergrainpores in shale will decrease with increasing diagenesis, the sec-ondary pores, especially the intragrain organic nanopores could beformed (Katsube et al., 1992,1994, 2000; Kuila and Prasad, 2010). Asillustrated by Jarvie et al. (2007), the organic nanopores will becreated when a shale is matured to the stage of oil window as aresult of the hydrocarbon generation and expulsion, and the poresizes and volumes will increase with further increasing the thermalmaturity. The Lower Cambrian shale in the Weiyuan area has aporosity in the range between 0.82 and 4.86%, with an average of2.44% (Huang et al., 2012a), whereas the Lower Silurian has arelatively higher range between 1.70 and 5.80%, with an average of4.20% (Huang et al., 2012b).Wang et al. (2013) recently reported therelationship between TOC and porosity in the Lower Cambrian andSilurian shales in the southern Sichuan Basin. Based on this rela-tionship and the average TOC of 2.06% for the Lower Cambrian shaleand 1.86% for the Lower Silurian shale, the calculated averageporosity for the Lower Cambrian and Silurian shales are 2.39% and4.81%, respectively, which are quite consistent with the measuredresults of Huang et al. (2012a, b), further supporting that the TOCcould be used as a parameter for the calculation of shale porosity(Chalmers et al., 2012; Tian et al., 2013).

3.2.4. Water saturationWater occurring in shale pore space occupies some of the space

otherwise available for free gas storage, and can also dissolves acertain amount of gas. Therefore, the water saturation has a directeffect on the free gas storage. In this paper, the water saturationdata of North American gas shales are cited since there is no watersaturation data reported from theWeiyuan area so far. The data arepresented as follows: Barnett, 25e35% (Frantz et al., 2005); EagleFord, 7e31% (Cusack et al., 2010; Mullen, 2010; Stoneburner, 2009);Haynesville, 15e35% (Stoneburner, 2009); Fayetteville, 25e50%(Bresch and Carpenter, 2009); andMarcellus,12e35% (Jarvie, 2012).These shales are of different maturities, but there is no obvious

0

1

2

3

4

5

6

7

8

0100200300400500600Age(Ma)

Res

erve

(m3 /t)

0

1

2

3

4

5

6

7

8

Bur

ial d

epth

(km

)

Reserves of Lower Cambrian ShaleReserves of Lower Silurian ShaleDepth of Lower Cambrian ShaleDepth of Lower Silurian Shale

0

1

2

3

4

5

6

7

8

0100200300400500600Age(Ma)

Res

erve

(m3 /t)

0

1

2

3

4

5

6

7

8

Bur

ial d

epth

(km

)

Reserves of Lower Cambrian ShaleReserves of Lower Silurian ShaleDepth of Lower Cambrian ShaleDepth of Lower Silurian Shale

0

1

2

3

4

5

6

7

8

0100200300400500600Age(Ma)

Res

erve

(m3 /t)

0

1

2

3

4

5

6

7

8

Bur

ial d

epth

(km

)

Reserves of Lower Cambrian ShaleReserves of Lower Silurian ShaleDepth of Lower Cambrian ShaleDepth of Lower Silurian Shale

a

b

c

Figure 7. Evolution history of the burial depths (dotted lines) and free gas contents(solid lines) of the Lower Cambrian and Lower Silurian shales with pressure co-efficients of 1.0 (a), 1.5 (b) and 2.0 (c).

Q. Zhou et al. / Marine and Petroleum Geology 56 (2014) 87e96 93

relationship between thewater saturations and thermal maturities,with a main range between 10% and 30%. Among these shales, theMarcellus shale has the highest maturity, with a Ro mainly in therange of 1.5e3.5% (Zagorski et al., 2011), which is generally com-parable with the maturity level of Lower Paleozoic shales in theWeiyuan area. Therefore, an average water saturation value of theMarcellus shale (23.5%) is used for both Lower Cambrian LowerSilurian shales in the present study.

3.2.5. Fluid pressureFluids in a shale gas system may be normal or abnormal pres-

sure (Loucks et al., 2009; Sondergeld et al., 2010b; Liu et al., 2008;Wang et al., 2012). For instances, the fluid pressure coefficient of theHaynesville shale, Eagle Ford shale, Barnett shale and Marcellusshale in North America is 2.00, 1.33, 0.96e1.16 and 0.93e1.56,respectively (Loucks et al., 2009; Sondergeld et al., 2010b). Pres-ently, there is a lack of field test data for the fluid pressure in theLower Cambrian and Lower Silurian shales in the Weiyuan area.However, based on gas-logging data and calculation results, someof the boreholes are considered to be overpressured. The pressurecoefficient of the Lower Cambrian shale in some boreholes in theWeiyuan area is as high as 2.05 (Liu et al., 2008), whereas the valuesfor the Lower Silurian shale in the southern Sichuan Basin varybetween 1.2 and 2.3 (Wang et al., 2012). Therefore, three differentfluid pressure coefficients: hydrostatic pressure, 1.5 times of over-pressure and 2 times of overpressure, are used for the simulation ofthe free gas content in the Lower Paleozoic shales in the Weiyuanarea.

In summary, we provide the simplified geological andgeochemical models for the two sets of Paleozoic shales in theWeiyuan area as follow. Porosity is 2.44% for the Lower Cambrianshale and 4.20% for the Lower Silurian shale. Water saturation is23.5%. The thermal history and gas generation model is based onWellW-117 (Fig. 6). And the fluid pressure is assessed at hydrostaticpressure (HP), 1.5 times of HP and 2 times of HP.

3.3. Model of free gas reserve

Using the above models, the free gas reserve for the two sets ofshales can be simulated and quantified with a commercial PVTmodeling software, PVTSim (Calsep, 1997). It is worthy to note thatthe calculated reserve is a maximum value that corresponds to thefree gas storage capacity of the shales when they are saturated withgas. At the lowmaturity stage when only a small amount of gas wasgenerated from the shales, their porosity may be unsaturated withgas with some residual oil and water. Thus, both the shale gasgeneration model and the free gas storage capacity model have tobe combined to obtain the evolutionary model of the free gas re-serves. When the gas generated is less than the free gas storagecapacity of the shale, it is assumed that all the generated gas isstored in the shale, i.e., the generated gas can be considered as freegas reserve. However, when the gas generated exceeds the free gasstorage capacity of the shale, the fluid system will be balanced bygas migration and expulsion. In this case, the free gas storage ca-pacity of the shale corresponds to the free gas reserve.

4. Results and discussion

4.1. Free gas content evolution model of shale

The free gas content evolution models of the two sets of shalesunder the three different pressure coefficients were reconstructedby combining the gas generation with the gas storage capacity ofshales (Fig. 7). Under the hydrostatic pressure conditions, it reachesa maximum value at the deepest burial (96 Ma), with 1.98 m3/t for

the Lower Cambrian shale and 3.29 m3/t for the Lower Silurianshale (Fig. 7a). The free gas content in the Lower Cambrian shalewas not obviously reduced when its burial depth decreased from7250 to 5000 m, remaining in the range 1.98e1.90 m3/t, with adecrease of only about 4.0%. However, the free gas content decreasesignificantly when the shale was lifted from 5000 m to the presentdepth (2950 m), from 1.90 m3/t to 1.52 m3/t, a decrease of 20%. Theamount of total free gas decreased about 23.3% over the wholeuplifting process. When the Lower Silurian shale was uplifted from6100 to 4000 m, the free gas content decreased by about 8.8% from3.29 m3/t to about 3.0 m3/t. It further decreased from 3.0 m3/t to1.94 m3/t, when the burial depth changed from 4000 m to thepresent depth of 1800 m. During the whole uplift process, the totaldecrease of the free gas content in the Lower Silurian shale was

0

1

2

3

4

5

0 10 20 30 40 50 60

Water saturation (%)

Res

erve

s(m

3 /t)

Lower CambrianLower Silurian

Figure 8. Plot showing the relationship between the free gas content and the watersaturation in two sets of shales in Weiyuan area under the condition presented at themaximum burial depth.

Q. Zhou et al. / Marine and Petroleum Geology 56 (2014) 87e9694

about 41%, much higher than that of the Lower Cambrian shale,which indicates that the free gas loss are closely related to theirspecific temperatures and pressures.

The free gas evolution models under the overpressured condi-tions show a similar trendwith that observed under the hydrostaticpressure conditions, but the amount of free gas is larger because ofthe enhanced pressures (Fig. 7b, c). With a pressure coefficient of1.5, the maximum free gas contents in the Lower Cambrian andLower Silurian shale are of 2.53 m3/t and 4.23 m3/t, respectively attheir greatest burial depth (Fig. 7b). The present free gas content ofthe Lower Cambrian shales is 2.04 m3/t with a total decrease ofabout 19.4% when they are uplifted from 7250 m to the presentdepth of 2950 m. The present value of the Lower Silurian shale is2.77 m3/t, with a total decrease of about 34.5% during the upliftingfrom 6100 m to the present depth of 1800 m. With a pressure co-efficient of 2.0, the respective free gas content of Lower Cambrianand Lower Silurian shales also reached their maxima of 2.93 m3/tand 4.90 m3/t at their deepest burial, and then decreases to2.43m3/t and 3.42m3/t at the present depth. The free gas content ofthe two sets of shales decreases by about 17.1% and 30.3%, respec-tively (Fig. 7c).

4.2. Shale gas potential of the Weiyuan area

Except for the free gas, the absorbed gas is another importanttype of gas in shales, but the data are rare for the Lower Cambrianand Lower Silurian shales in the Weiyuan area. Although thedirectly measured data are the surface excess (excess adsorptionamount) of shales using a commercial high pressure gas adsorptioninstrument, the reported data are usually converted to the Lang-muir adsorption, i.e., the absolute adsorption amount (Chalmersand Bustin, 2008; Ambrose et al., 2010). Since the absoluteadsorption amount is much greater than the excess adsorption,Ambrose et al. (2010) pointed out that when it is used to evaluateadsorbed gas, the volume of adsorbed gas must be considered andhence the space actually available for the free gas become less thanthe measured total pore spaces. Therefore it is wise to use theexcess adsorption amount to evaluate the adsorbed gas whenmeasured porosities are applied to calculate free gas. This willensure that the total gas content would not be doubly calculated.Rexer et al. (2013) proposed a general geological model of theexcess adsorption for a shale with a TOC of 6.35% and an EqRo of2.25%. According to thismodel, the excess adsorption amount of theshale decreases dramatically with increasing burial depth. It isabout 2.9 m3/t at 2000 m, 1.6 m3/t at 3000 m, and becomes negli-gible at a depth greater than 5000 m (50 MPa and 160 �C). Thismeans that the free gas contents of the Lower Cambrian and Silu-rian shales in the present models (Fig. 7) are very close to the totalgas contents at their greatest burial depth (6000e7000m), and lessthan the total gas contents at their current burial depth (2000e4000 m).

Thus, the free gas contents of 1.98e2.93 m3/t in the LowerCambrian shales and 3.29e4.91 m3/t in the Lower Silurian shales atthe end of the Early Cretaceous in Figure 7 could be considered tobe the maximum average potentials for these two sets of shalesunder the given geological and geochemical parameters. During theuplifting, part of the free gas could be converted to the absorbed gasaccording to the model proposed by Rexer et al. (2013) or wouldalso lose due to the development of faults and fissures in the shalesystem. Although it will be very farfetched to evaluate the excessadsorption amount of the two sets of shales using the available dataand the model of Rexer et al. (2013) since the excess adsorptioncould be significantly changed by a few other factors such as theTOC content, mineral composition as well as water saturation of theshales (Hildenbrand et al., 2006; Chalmers and Bustin, 2008), the

present free gas contents ( 1.52e2.43 m3/t and 1.94e3.42 m3/t forthe Lower Cambrian and Lower Silurian shales, respectively) couldbe regarded as their minimum gas contents under the given con-ditions. Field test data from a pilot borehole in the Weiyuan areashow that the gas content of the Lower Cambrian shale varies from0.85 to 4.83 m3/t, with an average of 2.10 m3/t (Huang et al., 2012a)and the gas content data for 21 Lower Silurian shale samples fromthe Weiyuan area show a range of 0.3e5.09 m3/t (Huang et al.,2012b), and the average gas content of the shale samples withTOC > 2.0% is as high as 2.5 m3/t. Therefore, the average gas con-tents of the two sets of shales are observed to bewithin the range ofthe minimum to maximum values predicted by the present modelbased on the specific geological and geochemical models. Addi-tionally, based on the field test data from the Weiyuan area andelsewhere in the southern Sichuan Basin, the gas content of LowerSilurian shale is apparently higher than that of the Lower Cambrianshale (Huang et al., 2012a,b). This situation also coincides with thepresent modeling results.

The minimum gas content in shales with commercial exploita-tion value is widely considered to be at least 1.0e2.0 m3/t (Hill andNelson, 2000; Curtis, 2002). Themain range of gas content of shalesin North American shale gas plays is 0.44e9.91 m3/t, or morespecifically, 1.70e6.23 m3/t for Fayetteville shale and 1.70e2.83 m3/t for Marcellus shale (Curtis, 2002; Sondergeld et al., 2010a,b). Thismeans that the gas content of the Lower Cambrian and LowerSilurian shales in the Weiyuan area are comparable with those ofNorth America, and the Lower Paleozoic shales in theWeiyuan areahas good shale gas potential, which also provides confidence on theexploration of shale gas in the southern China region where strongtectonic uplifting is common.

The free gas contentmodeled andpredicted in thepresent study isbased on the simplified geological and geochemical models, i.e., anaveragedporosity, an assumedwater saturation and an assignedfluidpressure coefficient, which may influence the accuracy of the pre-dicted free gas content. The free gas content of the two sets of shalescould be higher at locations where the shales have larger porosities.Additionally, the relationships between the free gas content withwater saturationaswell asfluidpressure coefficient for the twosets ofshales under conditions present at their greatest burial depths areestablished based on the simulation data. The results show that thefree gas content linearly decreases with increasing water saturation(Fig. 8). Although some gas could dissolve inporewater, its amount isfar less than that of the free gas in pore space (Zhou et al., 2013).Considering that the two sets of shale are very highly mature, andhave experienced awhole evolution process, including oil generation

0

1

2

3

4

5

6

0.8 1 1.2 1.4 1.6 1.8 2 2.2

Pressure coefficient

Res

erve

s(m

3 /t)

Lower CambrianLower Silurian

Figure 9. Plot showing the relationship between the free gas content and the fluidpressure coefficient in two sets of shales in Weiyuan area under the condition pre-sented at the maximum burial depth.

Q. Zhou et al. / Marine and Petroleum Geology 56 (2014) 87e96 95

andexpulsion, andgasgenerationandexpulsion, the shaleporewatermight be expelled together with the oil and gas, thus the watersaturation may be lower than the assumed value in the models.Therefore, the free gas content could be deduced to be even largerthan the modeled results. Note that the free gas content of the shaleincreases with fluid pressure, displaying a nearly linear relationship(Fig. 9). Although there is lack in accurate pressure coefficient data, anoverpressure fluid in the shale system is widely observed in theWeiyuanandotherareas in theSichuanBasin (ZhangandDong,2000;Li, 2001;Xie et al., 2004;Cai et al., 2005;Maetal., 2005). Thus, as shalegas explorationexpands in thestudiedareaandmore relativedata areobtained, the geological models and geochemical parameters couldbe further refined, and free gas content results will be more reliablypredicted.

5. Conclusions

(1) Two sets of organic-rich shales developed in the Weiyuanarea of the Sichuan Basin: the Lower Cambrian and LowerSilurian shales. This area experienced a continuous sedi-mentation from the Triassic to Early Cretaceous, and theshales reached a burial depth of 6000e7000m. Since the endof the Early Cretaceous, this area has undergone a severeuplifting and erosion and the present burial depth of theshales ranges from 2000 to 4000 m, which makes theWeiyuan area a favorable spot for the shale gas exploration inthe Sichuan Basin.

(2) Based on available data, geological and geochemical modelsof the Lower Cambrian and Lower Silurian shales have beenestablished and their free gas content evolution has beensimulated. The results show that the free gas contents of theLower Cambrian and Lower Silurian shales in the Weiyuanarea reach their maxima, i.e., 1.98e2.93 m3/t and 3.29e4.91 m3/t, respectively at their deepest burial. The free gascontent decreases during the uplifting, and the present freegas contents are modeled to be 1.52e2.43 m3/t for the LowerCambrian shales and 1.94e3.42 m3/t for the Lower Silurianshales. These results indicate that the two sets of shale havegood shale gas potential, even though they have experienceda severe uplifting.

Acknowledgments

The authors are indebted to Dr. B. J. Katz, Dr. K. Y. Liu and twoanonymous reviewers for their insightful comments and suggestions

that have significantly improved the manuscript, Special acknowl-edgements are given to Prof. Yongtai Yang for his time to edit themanuscript and to Dr. R.W. T.Wilkins for assistancewith the Englishlanguage presentation. This studywas supported by theNational KeyBasic Research Program of China (973 Program: 2012CB214705) anda special program of Chinese Academy of Sciences (XDB10040300).This is contribution No. IS-1880 from GIGCAS.

References

Aplin, A.C., Larter, S.R., Bigge, M.A., Macleod, G., Swarbrick, R.E., Grunberger, D.,2000. PVTX history of the North Sea’s Judy oilfield. J. Geochem. Explor. 69e70,641e644.

Aplin, A.C., Macleod, G., Larter, S.R., Pedersen, K.S., Sorensen, H., Booth, T., 1999.Combined use of confocal laser scanning microscopy and PVT simulation forestimating the composition and physical properties of petroleum in fluid in-clusions. Mar. Pet. Geol. 16, 97e110.

Ambrose, R.J., Hartman, R.C., Diaz-Campos, Sondergeldet, C.H., 2010. New pore-scale considerations for shale gas in Place calculations. In: SPE Unconven-tional Gas Conference, Pittsburgh Pennsylvania, 2010.

Braun, R.L., Burnham, A.K., 1998. Kinetics User Manual. http://www.humble_inc.com/k2000.htm (accessed 08.10.04.).

Bresch, C., Carpenter, J., 2009. Preliminary analytical results: Haynesville Shalein Northern Panola County, Texas. Gulf Coast Assoc. Geol. Soc. Trans. 59,121e124.

Cai, L.G., Rao, D., Pan, W.L., Zhang, G.X., 2005. The evolution model of the Puguanggas field in Northeast of Sichuan. Pet. Geol. Exp. 27, 462e467 (in Chinese withEnglish abstract).

Calsep, 1997. PVTsim, Version 10. http://www.Calsep.com/PVTsim.htm.Chalmers, G.R.L., Bustin, R.M., 2008. Lower Cretaceous gas shales in northeastern

British Columbia, part I: geological controls on methane sorption capacity. Bull.Can. Pet. Geol. 56, 1e21.

Chalmers, G.R.L., Bustin, R.M., Power, I.M., 2012. Characterization of gas shale poresystems by porosimetry, pycnometry, surface area, and field emission scanningelectron microscopy/transmission electron microscopy image analyses: exam-ples from the Barnett, Woodford, Haynesville, Marcellus, and Doig units. AAPGBull 96 (6), 1099e1119.

Chen, S.B., Zhu, Y.M., Wang, H.Y., Liu, H.L., Wei, W., Fang, J.H., 2012. Structurecharacteristics and accumulation significance of nanopores in Longmaxi shalegas reservoir in the southern Sichuan Basin. J. China Coal Soc. 37, 438e444 (inChinese with English abstract).

Cheng, P., Xiao, X.M., 2013. Gas content of organic-rich shales with very high ma-turities. J. China Coal Soc. 38, 737e741 (in Chinese with English abstract).

Chinese Petroleum Geology Editorial Committee (CPGEC), 1989. Petroleum Geologyof China, vol. 10. Petroleum Industry Press, Beijing, pp. 125e189 (in Chinesewith English abstract).

Curtis, J.B., 2002. Fractured shale-gas systems. AAPG Bull. 86, 1921e1938.Cusack, C., Beeson, J., Stoneburner, D., Robertson, G., 2010. The discovery, reservoir

attributes, and significance of the Hawkville Field and Eagle Ford Shale trend,Texas. Gulf Coast Assoc. Geol. Soc. Trans. 60, 165e179.

Dai, H.M., Wang, S.Y., Wang, H.Q., Huang, Q.D., 1999. Formation characteristics ofnatural gas reservoirs and favorable exploration areas in Sinian Cambrian pe-troleum system of Sichuan Basin. Pet. Explor. Dev. 26, 16e20.

Dai, J.X., 2003. Pool formation periods and gas sources of Weiyuan gasfield. Pet.Geol. Exp. 25, 473e479 (in Chinese with English abstract).

Dong, D.Z., Cheng, K.M., Wang, S.Q., Lv, Z.G., 2009. An evaluation method of shalegas resource and its application in the Sichuan basin. Nat. Gas Ind. 29, 33e39 (inChinese with English abstract).

Frantz, J.H., Williamson, J.R., Sawyer, W.K., Johnston, D., Waters, G., Moore, L.P.,MacDonald, R.J., Pearcy, M., Ganpule, S.V., March, K.S., 2005. Evaluating BarnettShale production performance e using an integrated approach. In: SPE AnnualTechnical Conference and Exhibition, 9e12 October 2005, Dallas, Texas. http://dx.doi.org/10.2118/96917-MS. ISBN, 978-1-55563-150-5.

Hildenbrand, A., Krooss, B.M., Busch, A., Gaschnitz, R., 2006. Evolution of methanesorption capacity of coal seams as a function of burial historyda case studyfrom the Campine Basin, NE Belgium. Int. J. Coal Geol. 66, 179e203.

Hill, D.G., Nelson, C.R., 2000. Gas productive fractured shales-an overview andupdate. Gas Tips 6, 4e13.

Huang, J.L., Zou, C.N., Li, J.Z., Dong, D.Z., Wang, S.J., Wang, S.Q., Cheng, K.M., 2012a.Shale gas generation and potential of the Lower Cambrian Qiongzhusi Forma-tion in Southern Sichuan Basin, China. Pet. Explor. Dev. 39, 69e75.

Huang, J.L., Zou, C.N., Li, J.Z., Dong, D.Z., Wang, S.J., Wang, S.Q., Wang, Y.M., Li, D.H.,2012b. Shale gas accumulation conditions and favorable zones of SilurianLongmaxi Formation in south Sichuan Basin, China. J. China Coal Soc. 37, 782e787 (in Chinese with English abstract).

Jarvie, D.M., Hill, R.J., Ruble, T.E., Pollastro, R.M., 2007. Unconventional shale-gassystems: the Mississippian Barnett shale of north-central Texas as one modelfor thermogenic shale-gas assessment. AAPG Bull. 91, 475e499.

Jarvie, D.M., 2012. Shale resource systems for oil and gas: part 1-Shale-gas resourcesystems. In: Breyer, J.A. (Ed.), Shale Reservoirs e Giant Resources for the 21stCentury, AAPG Memoir, vol. 97, pp. 69e87.

Q. Zhou et al. / Marine and Petroleum Geology 56 (2014) 87e9696

Katsube, T.J., 2000. Shale Permeability and Pore-structure Evolution Characteristics.Geological Survey of Canada Report, 2000eE15; 9p. Online:. Toll-froo: 1-888-252-4031. http://www.nrcan.gc.ca/gsc/bookstore.

Katsube, T.J., Williamson, M.A., 1994. Effects of digenesis on shale nano-porestructure and implications for sealing capacity. Clay Minerals 29, 451e461.

Katsube, T.J., Williamson, M., Best, M.E., 1992. Shale pore structure evolution and itseffect on permeability. In: Thirty-third Annual Symposium of the Society ofProfessional Well Log Analysts (SPWLA), Symposium, vol. 3, pp. 1e22.

Kuila, U., Prasad, M., 2010. Pore Size Distribution and Ultrasonic Velocities ofCompacted Na-montmorillonite Clays, pp. 2590e2594. http://dx.doi.org/10.1190/1.3513379. SEG Technical Program Expanded Abstracts 2010.

Li, X.Q., Zhao, P., Sun, J., Fu, T.Y., Lai, S.N., Tian, X.W., Ma, S.M., Wang, F.Y., 2013. Studyon the accumulation conditions of shale gas from the Lower Paleozoic in thesouth region of Sichuan Basin. J. China Coal Soc. 38, 864e869 (in Chinese withEnglish abstract).

Li, Z.D., 2001. Study on relationship between the high pressure of carbonate rockand accumulation of gas. J. Mineral. Petrol. 21, 53e58 (in Chinese with Englishabstract).

Liu, D.H., Xiao, X.M., Mi, J.K., Li, X.Q., Shen, J.K., Song, Z.G., Peng, P.A., 2003. Deter-mination of trapping pressure and temperature of petroleum inclusions usingPVT simulation software e a case study of Lower Ordovician carbonates fromthe Lunnan Low Uplift, Tarim Basin. Mar. Pet. Geol. 20, 29e43.

Liu, S.G., Ma, Y.S., Cai, X.Y., Xu, G.S., Wang, G.Z., Yong, Z.Q., Sun, W., Yuan, H.F.,Pan, C.L., 2009. Characteristic and accumulation process of the natural gas fromSinian to Lower Paleozoic in Sichuan Basin, China. J. Chengdu Univ. Technol.(Sci. Technol. Ed.) 36, 345e354 (in Chinese with English abstract).

Liu, S.G., Ma, Y.S., Sun, W., Cai, X.Y., Liu, S., Huang, W.M., Xu, G.S., Yong, Z.Q.,Wang, G.Z., Wang, H., Pan, C.L., 2008. Studying on the differences of Siniannatural gas pools between Weiyuan gas field and Ziyang gas-brone area,Sichuan Basin. Acta Geol. Sin. 82, 328e337.

Loucks, R.G., Reed, R.M., Ruppel, S.C., Jarvie, D.M., 2009. Morphology, genesis, anddistribution of nanometer-scale pores in siliceous mudstones of the Missis-sippian Barnett shale. J. Sediment. Res. 79, 848e861.

Ma, W.X., Liu, S.G., Huang, W.M., Zeng, X.L., Zhang, C.J., Wang, J., 2012. Mud shalereservoirs characteristics of Qiongzhusi Formation on the margin of SichuanBasin, China. J. Chengdu Univ. Technol. (Sci. Technol. Ed.) 39, 182e189 (in Chi-nese with English abstract).

Ma, Y.S., Cai, X.Y., Li, G.X., 2005. Basic characteristics and concentration of thePuguang gas field in the Sichuan Basin. Acta Geol. Sin. 79, 858e865.

Ma, Y.S., Zhang, S.C., Guo, T.L., Zhu, G.Y., Cai, X.Y., Li, M.W., 2008. Petroleum geologyof the Puguang sour gas field in the Sichuan Basin, SW China. Mar. Pet. Geol. 25,357e370.

Mi, J.K., Xiao, X.M., Liu, D.H., Shen, J.K., 2003. Paleo pressure in gas pools using thePVT simulating characteristics of the fluid inclusions in reservoirs e a casestudy on the Upper Paleozoic gas pool in Erdos Basin. Sci. China (Ser. D) 33,679e685.

Montgomery, S.L., Jarvie, D.M., Bowker, K.A., Pollastro, R.M., 2005. MississippianBarnett shale, Fort Worth Basin, north-central Texas: gas-shale play withmultietrillion cubic foot potential. AAPG Bull. 89, 155e175.

Mullen, J., 2010. Petrophysical characterization of the Eagle Ford Shale in SouthTexas. In: Canadian Unconventional Resources and International PetroleumConference, 19e21 October 2010, Calgary, Alberta, Canada http://dx.doi.org/10.2118/138145-MS. ISBN, 978-1-55563-312-7.

Nie, H.K., Zang, J.C., 2011. Types and characteristics of shale gas reservoir: a casestudy of Lower Paleozoic in and around Sichuan Basin. Pet. Geol. Exp. 33, 219e225 (in Chinese with English abstract).

Nie, H.K., Zang, J.C., 2012. Shale gas accumulation conditions and gas contentcalculation: a case study of Sichuan Basin and its periphery in the LowerPaleozoic. Acta Geol. Sin. 86, 349e360.

Nie, H.K., Zang, J.C., Li, Y.X., 2011. Accumulation conditions of the LowerCambrian shale gas in the Sichuan Basin and its periphery. Acta Geol. Sin. 32,959e967.

Rexer, T.F.T., Benham, M.J., Aplin, A.C., Thomas, K.M., 2013. Methane adsorption onshale under simulated geological temperature and pressure conditions. EnergyFuels 27, 3099e3109.

Ross, D.J.K., Bustin, R.M., 2008. Characterizing the shale gas resource potentialof DevonianeMississippian strata in the Western Canada sedimentary ba-sin: application of an integrated formation evaluation. AAPG Bull. 92, 87e125.

Stoneburner, R.K., 2009. The Haynesville and Hawkville Fields: two world-class gasshale plays. Houst. Geol. Soc. Bull. 52, 31e33.

Sondergeld, C.H., Ambrose, R.J., Rai, C.S., Moncriff, J., 2010a. Micro-structural studiesof gas shales. In: SPE Unconventional Gas Conference, 23e25 February 2010,Pittsburgh, Pennsylvania, USA http://dx.doi.org/10.2118/131768-MS. ISBN, 978-1-55563-287-8.

Sondergeld, C.H., Newsham, K.E., Comisky, J.T., Rice, M.C., Rai, C.S., 2010b. Petro-physical considerations in evaluating and producing shale gas resources. In:Pittsburgh: SPE Unconventional Gas Conference, 23e25 February 2010, Pitts-burgh, Pennsylvania, USA. http://dx.doi.org/10.2118/131771-MS. ISBN, 978-1-55563-287-8.

Song, W.H., 1996. Research on reservoir-formed conditions of large-medium gasfields of Leshan-Longmenshan palaeohigh. Nat. Gas Ind. 16, 13e26 (in Chinesewith English abstract).

Sun, W., Liu, S.G., Ran, B., Wang, S.Y., Ye, Y.H., Luo, C., Tian, M.N., 2012. Generalsituation and prospect evaluation of the shale gas in Niutitang Formation ofSichuan Basin and its surrounding areas. J. Chengdu Univ. Technol. (Science &Technol. Ed.) 39, 170e175 (in Chinese with English abstract).

Tang, Y., Jenden, P.D., Nigrini, A., Teerman, S.C., 1996. Modeling early methanegeneration in coal. Energy Fuel 10 (3), 659e671.

Tian, H., Pan, L., Xiao, X.M., Wilkins, R.W.T., Meng, Z.P., Huang, B.J., 2013.A preliminary study on the pore characterization of Lower Silurian black shalesin the Chuandong Thrust Fold Belt, southwestern China using low pressure N2adsorption and FE-SEM methods. Mar. Pet. Geol. 48, 8e19.

Tian, H., Xiao, X.M., Wilkins, R.W.T., Li, X.Q., Gan, H.J., 2007. Gas sources of the YN2gas pool in the Tarim Basin e evidence from gas generation and methanecarbon isotope fractionation kinetics of source rocks and crude oils. Mar. Pet.Geol. 24, 29e41.

Tian, H., Zhang, S.C., Liu, S.B., Zhang, H., 2012. Determination of organic-rich shalepore features by mercury injection and gas adsorption methods. Acta Pet. Sin.33, 419e427 (in Chinese with English abstract).

Tseng, H.Y., Pottorf, R.J., 2003. The application of fluid inclusion PVT analysis tostudies of petroleum migration and reservoirs. J. Geochem. Explor. 78-79, 433e436.

Wang, F., Guan, J., Feng, W., Bao, L., 2013. Evolution of overmature marine shaleporosity and implication to the free gas volume. Pet. Explor. Dev. 40, 819e824.

Wang, S.Q., Chen, G.S., Dong, D.Z., Yang, G., Lv, Z.G., Xu, H.Y., Huang, Y.B., 2009.Accumulation conditions and exploitation prospect of shale gas in the LowerPaleozoic Sichaun Basin. Nat. Gas Ind. 29, 51e58 (in Chinese with Englishabstract).

Wang, Y.M., Dong, D.Z., Li, J.Z., Wang, S.J., Li, X.J., Wang, L., Cheng, K.M., Huang, J.L.,2012. Reservoir characteristics of shale gas in Longmaxi Formation of the LowerSilurian, southern China. Acta Pet. Sin. 33, 551e561 (in Chinese with Englishabstract).

Wei, G.Q., Chen, G.S., Du, S.M., Zhang, L., Yang, W., 2008. Petroleum systems of theoldest gas field in China: neoproterozoic gas pools in the Weiyuan gas field,Sichuan Basin. Mar. Pet. Geol. 25, 371e386.

Xiao, X.M., Tian, H., Liu, D.H., Liu, Z.F., 2012. Evaluation of Deep Burial Source Rocksand Their Natural Gas Potentials in Sichuan Basin. Annual Report of State MajorResearch Program of China (Project No. 2011ZX05008-002-40), Internal Report,Guangzhou Institute of Geochemistry of Chinese Academy of Sciences, pp. 1e68(in Chinese with English abstract).

Xiao, X.M., Song, Z.G., Zhu, Y.M., Tian, H., Yin, H.W., 2013. Summary of shale gasresearch in North America and revelations to shale gas exploration of LowerPaleozoic strata in China south area. J. China Coal Soc. 38, 721e727 (in Chinesewith English abstract).

Xie, Z.Y., Wei, G.Q., Li, J., Yang, W., Zhang, L., 2004. Feixianguan formation ooliticbeach reservoir bitumens and gas reservoiring process in northeast Sichuan.Nat. Gas Ind. 24, 17e19 (in Chinese with English abstract).

Yu, C., Bao, S.J., Qin, Q.R., Nie, H.K., Zhu, H., Shao, X.Z., 2012. Analysis of reservoir-forming conditions of shale gas in Lower Silurian of southeast Sichuan area.J. Oil Gas Technol. 34, 41e45.

Zagorski, W.A., Bowman, D.C., Emery, M., Wrightstone, G., 2011. An overview ofsome key factors controlling well productivity in core areas of the AppalachianBasin Marcellus shale play. In: AAPG Annual Conversion and Exhibition,Houston, Texas, USA, Oral Presentation, April 10-13, 2011.

Zeng, X.L., Liu, S.G., Huang, W.M., Zhang, C.J., 2011. Comparison of Silurian Longmaxishale of Sichuan Basin in China and carboniferous barnett formation shale ofFort Worth Basin in United States. Geol. Bull. China 30, 372e384 (in Chinesewith English abstract).

Zhai, G.M., et al., 1989. Petroleum Geology of China, vol. 10). Petroleum IndustryPress, pp. 389e424.

Zhang, L., Wei, G.Q., Han, L., Wang, L.L., Wang, D.L., 2008. Evaluation of the high andover matured Sinian-Lower Palaeozoic source rocks in the Sichuan Basin. Pet.Geol. Exp. 30, 287e291 (in Chinese with English abstract).

Zhang, Q.M., Dong, W.L., 2000. Overpressure system of hydrocarbon-bearing basinsin China. Acta Geol. Sin. 21, 1e11.

Zhang, T.W., Ellis, G.S., Ruppel, S.C., Milliken, K., Yang, R.S., 2012. Effect of organic-matter type and thermal maturity on methane adsorption n shale-gas sys-tems. Org. Geochem. 47, 120e131.

Zhou, Q., Tian, H., Chen, G.H., Xu, Q., 2013. Geological model of dissolved gas in porewater of gas shale and its controlling factors. J. China Coal Soc. 38, 800e804 (inChinese with English abstract).

Zhu, G.Y., Zhang, S.C., Liang, Y.B., Li, Q.R., 2006a. The origin and its evidence of theH2S in the Weiyuan gas field, Sichuan Basin. Chin. Sci. Bull. 51, 2780e2788.

Zhu, G.Y., Zhang, S.C., Liang, Y.B., Ma, Y.S., Dai, J.X., Li, J., Zhou, G.Y., 2006b. Thecharacteristics of natural gas in Sichuan Basin and its source. Earth Sci. Front. 13,234e248 (in Chinese with English abstract).

Zhu, Y.M., Chen, S.B., Fang, J.H., Luo, Y., 2010. The geological background of theSilurian shale-gas reservoiring in Sichuan, China. J. China Coal Soc. 35, 1160e1164 (in Chinese with English abstract).