Scholarly article on topic 'The characteristics and significance of conventional and unconventional Sinian–Silurian gas systems in the Sichuan Basin, central China'

The characteristics and significance of conventional and unconventional Sinian–Silurian gas systems in the Sichuan Basin, central China Academic research paper on "Earth and related environmental sciences"

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{"(un)Conventional gas system" / "Sichuan Basin" / "Shale gas" / "Unconventional petroleum" / "Over-matured gas reservoirs"}

Abstract of research paper on Earth and related environmental sciences, author of scientific article — Caineng Zou, Zhi Yang, Jingxing Dai, Dazhong Dong, Baomin Zhang, et al.

Abstract Oil and gas discoveries within Proterozoic-Cambrian strata and the majority of shale gas production occurs in relatively stable tectonic regions and characterised by moderate thermal maturity (Ro°<°2.5%). The Sinian–Silurian gas resource located in China's Sichuan Basin is a definitely different example of a concurrent conventional and unconventional gas system within a tectonically complicated basin and sourced from overly-mature organic shales (Ro°>°2.5%). The system comprises two components, namely a conventional Sinian–Cambrian dolomite-hosted gas resource and an unconventional Cambrian-Silurian shale gas deposit, both represent trillion cubic meter accumulations. The migration-accumulation type Sinian–Cambrian gas system, is a result of numerous processes, including (1) paleo-high trapping within a relatively stable tectonic setting, (2) appropriate source materials located in a paleo-rift trough, (3) large-scale dolomite grainstone reservoirs located near the paleo-high, (4) adequate gas produced from in-situ crude oil cracking, and, (5) gypsum-salt and shale cap rock preservation. The self-contained source-reservoir Cambrian–Silurian shale gas system, is localized by deepwater organic-rich shelf facies, characterized by high silicon and calcium contents. The recent discovery of these two massive gas fields in old and over-matured sedimentary strata, has effectively extended the upper maturity limit of Ro over 3.0%, which may indicate the efficacy of broadening current natural gas exploration areas, thus potentially increasing global natural gas resources significantly. Furthermore, the discovery may spark interest in natural gas exploration in widely distributed old strata, thus encouraging co-development of conventional and unconventional petroleum accumulations.

Academic research paper on topic "The characteristics and significance of conventional and unconventional Sinian–Silurian gas systems in the Sichuan Basin, central China"

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Marine and Petroleum Geology

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

Research paper

The characteristics and significance of conventional and unconventional Sinian-Silurian gas systems in the Sichuan Basin, central China

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Caineng Zou a, Zhi Yang a' *, Jingxing Dai a, Dazhong Dong a, Baomin Zhang a,

Yuman Wang a, Shenghui Deng a, Jinliang Huang a, Keyu Liu a, Chun Yang a, Guoqi Wei b,

Songqi Pan a

a Research Institute of Petroleum Exploration and Development, PetroChina, 100083, Beijing, China b Research Institute of Petroleum Exploration and Development-Langfang Branch, PetroChina, 065007, Langfang, China

ARTICLE INFO

Article history: Received 13 December 2014 Accepted 3 March 2015 Available online 25 March 2015

Keywords:

(un)Conventional gas system Sichuan Basin Shale gas

Unconventional petroleum Over-matured gas reservoirs

ABSTRACT

Oil and gas discoveries within Proterozoic-Cambrian strata and the majority of shale gas production occurs in relatively stable tectonic regions and characterised by moderate thermal maturity (Ro°<°2.5%). The Sinian-Silurian gas resource located in China's Sichuan Basin is a definitely different example of a concurrent conventional and unconventional gas system within a tectonically complicated basin and sourced from overly-mature organic shales (Ro°>°2.5%). The system comprises two components, namely a conventional Sinian-Cambrian dolomite-hosted gas resource and an unconventional Cambrian-Silurian shale gas deposit, both represent trillion cubic meter accumulations.

The migration-accumulation type Sinian-Cambrian gas system, is a result of numerous processes, including (1) paleo-high trapping within a relatively stable tectonic setting, (2) appropriate source materials located in a paleo-rift trough, (3) large-scale dolomite grainstone reservoirs located near the paleo-high, (4) adequate gas produced from in-situ crude oil cracking, and, (5) gypsum-salt and shale cap rock preservation.

The self-contained source-reservoir Cambrian-Silurian shale gas system, is localized by deepwater organic-rich shelf facies, characterized by high silicon and calcium contents.

The recent discovery of these two massive gas fields in old and over-matured sedimentary strata, has effectively extended the upper maturity limit of Ro over 3.0%, which may indicate the efficacy of broadening current natural gas exploration areas, thus potentially increasing global natural gas resources significantly. Furthermore, the discovery may spark interest in natural gas exploration in widely distributed old strata, thus encouraging co-development of conventional and unconventional petroleum accumulations.

© 2015 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND

license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

1. Introduction

Petroleum will continue to be the main fossil resource with respect to global energy consumption over the coming three decades (EIA, 2013). Global conventional and unconventional petroleum resources occur at a ratio of about 1:4 (EIA, 2013; Zou et al., 2013a), with unconventional resources likely representing an increasingly important role in parallel with increased future

* Corresponding author. E-mail address: yangzhi2009@petrochina.com.cn (Z. Yang).

demands. In light of forecasted energy requirements, further petroleum resource exploration, including both conventional and unconventional systems, is urgently required.

The overarching approach to petroleum resource exploration aims to evaluate resource potential and predict advantageous resource locations via matching elements of the petroleum system, for example, trap formation and generation-migration-accumulation of hydrocarbons. The concept of an oil system was initially presented in the early 1970s (Dow, 1972,1974), and was based upon oil-oil and oil-source rock correlations in order to develop an understanding of oil type distribution in the Williston basin (Dow, 1974). The term 'petroleum system' was first used by Perrodon and Masse (1984) and

http://dx.doi.org/10.1016/j.marpetgeo.2015.03.005

0264-8172/© 2015 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

denoted the final result of organized defined set of geologic events with respect to both space and time. Demaison (1984) proposed the term "generative basin" and Meissner et al. (1984) introduced and defined "hydrocarbon machine". Subsequently, Ulmishek (1986) employed the term 'independent petroliferous system (IPS)', with Magoon (1987) first using the term 'elements' in reference to petroleum system components. During the early 1990s, Magoon and Dow (1994) published "The petroleum system-from source to trap", which represented the first comprehensive summary of the petroleum system theory. Within this summary, a 'petroleum system' was defined as a natural system encompassing a pod of active source rock and all related petroleum resources, and comprising all the geologic elements and processes essential to hydrocarbon accumulation.

The emergence of unconventional gas resources as a viable energy resource has necessarily lead to modifications and expansions of long-held traditional concepts pertaining to the processes of gas generation, expulsion, migration, entrapment and reservoir quality (Law and Curtis, 2002). For example, with respect to unconventional reservoir quality, the range has been effectively expanded to include low-permeability (<0.1°mD) sandstones and self-sourcing reservoirs. Schmoker (1995) has previously outlined a category of unconventional, continuous petroleum system characterized by an accumulation of hydrocarbons located within low-permeability rocks, which depend on fracture permeability for production and have low gas recovery rates (Schmoker, 1995). Shale gas systems are classified into one of two distinct types, namely biogenic and thermogenic (Claypool, 1998). The Society of Petroleum Engineers (SPE), Society of Petroleum Evaluation Engineers (SPEE), American Association of Petroleum Geologists (AAPG) and World Petroleum Congress (WPC) jointly issued a statement in 2007 which defines 'unconventional resources' as "petroleum accumulations pervasive throughout a large area and not significantly affected by hydrodynamic effects"; these are also referred to as 'continuous-type deposits'. Jarvie (2011) proposed three basic marine shale oil categories, with permeability and litho-facies variance playing key roles with respect to eventual producibility. Recently, Cander (2012) has developed an approach for defining unconventional oil and gas systems via utilization of a viscosity-permeability cross-plot. Cander (2012) also proposed that unconventional resources be defined as those which are commercially recoverable via modification of either rock permeability or fluid viscosity. Zou et al. (2012, 2013a) have referred to unconventional oil and gas system as continuous or quasi-continuous resources, only commercially recoverable through reservoir stimulation, in order to enhance permeability or fluid viscosity. Williams (2013) defined three distinct petroleum system categories based upon fundamental differences underlying the basic physics of hydrocarbon accumulation; these are conventional petroleum systems, continuous basin-centered accumulations and source rock reservoirs. In reference to an individual petroleum system, the terms conventional and unconventional petroleum are frequently used in concurrence with each other. Numerous studies have acknowledged that a new concept which comprises both conventional and unconventional petroleum resources is necessary for effective resource scanning and exploitation within a widely distributed geological unit (Pollastro et al., 2007; Jarvie et al., 2011; Zou et al., 2014; Tassone et al., 2014).

Concurrent conventional and unconventional petroleum resources are inherently associated with respect to their origin and are spatially paragenetic, thus forming a characteristically unified conventional-unconventional petroleum system. Typically, where conventional petroleum resources are discovered, unconventional oil and gas will concurrently exist in the petroleum supply direction; furthermore, where unconventional petroleum is discovered, conventional resources frequently occur in the up-dip portion.

Accordingly, via utilization of the Sinian—Silurian gas system in Sichuan Basin as an appropriate case study, the potential source, generation, migration and formation mechanism of concurrent conventional and unconventional gas systems have been analyzed from a geological perspective. In the current study, conventional and unconventional petroleum systems have been defined as being concurrently located within petroleum bearing units (basin, depression or sag), with thermal evolution, petroleum generation and expulsion of organic rich source rock, comprising an integrated coupling process. This results in the depth-related evolution of differing reservoir space and resource categories with respect to time, uniformly distributed within the spatial domain. This definition differs from the traditional 'petroleum system' (Magoon and Dow, 1994; Law and Curtis, 2002) as follows:

(1) Source rocks include both proven and potential sourcer rocks (e.g. oil shale), thus focusing on all organic rich rocks,

(2) Individual reservoirs consists of both 'sweet spots' in conventional good unconventional reservoirs and reservoirs located in petroleum source rock and along migration paths,

(3) Petroleum resources are not limited to oil and gas in conventional traps and some unconventional gas, but all types of conventional and unconventional petroleum resources (e.g. shale gas, shale oil, tight oil, etc.),

(4) The current definition and approach considers "conventional-unconventional petroleum orderly accumulation", focusing on analyses of the entire process of petroleum generation-migration-accumulation, in order to effectively locate all petroleum resource categories, and ultimately maximize feasible recovery of conventional-unconventional petroleum from the petroleum bearing unit in its entirety.

2. Concurrent conventional and unconventional Sinian—Silurian gas system in Sichuan Basin

2.1. Geological setting of Sichuan Basin

Within the Sichuan Basin, deposits include marine strata from the Sinian to Middle-Triassic and non-marine strata from Upper-Triassic to Eocene. Overall, twenty-one oil and gas-bearing formations have been located, occurring as three types of conventional and three types of unconventional petroleum system. The three conventional petroleum types comprise carbonate fractured-vuggy gas reservoirs within the Sinian Dengying Formation, porous dolomite gas reservoirs within both the Cambrian Longwangmiao Formation and Carboniferous formations and carbonate reef gas reservoirs within the Permian and Triassic formations. The three unconventional petroleum types include shale gas within the Cambrian Qiongzhusi and Silurian Longmaxi formations, tight gas within the Upper-Triassic Xujiahe formation, and tight oil within the Jurassic formation. With respect to the Sinian-Silurian combination within the Sichuan Basin, conventional and unconventional gas systems co-exist, with trillion cubic meter class reserves of Sinian-Cambrian gas and trillion cubic meter reserves of Cambrian and Silurian unconventional shale gas having been previously discovered (Fig. 1, Fig. 2). These Sinian—Cambrian conventional gas occurrences are primarily controlled by five geological factors, namely the presence of paleo-rift trough, paleosource rocks, paleo-karst reservoirs, paleo-crude oil pool cracking and paleo-high trapping. The occurrence of Cambrian and Silurian unconventional shale gases is primarily contingent upon the presence of deepwater shelf organic-rich shale facies and high silicon and calcium mineral contents.

limestone

Figure 1. Distribution of conventional-unconventional Sinian—Silurian gas systems in Sichuan Basin, central China.

2.2. Conventional Sinian—Cambrian dolomite-hosted gas 2.2.1. Overview

As shown (Fig. 3), a globally significant Sinian—Cambrian gas field has recently been discovered within the southwestern Sichuan Basin, China (Fig. 3). This vast gas field which has undergone oil to gas cracking evolved from a large-scale bulk paleo-oil reservoir. Exploration activities for Sinian—Cambrian systems in the Sichuan Basin commenced in 1940. The Well Gaoshi-1 was discovered in 2011, with gas production of 138.15 x 104 m / d (48.79°MMcf/d) from the Sinian Dengying Formation. In 2012, Well Moxi-8 was located, with effective gas production of 190.68 x 104 m3/d (67.34°MMcf/d) from the Cambrian Long-wangmiao Formation. By late 2013, 34 exploration wells had been drilled, of which 19 target the Cambrian Longwangmiao Formation and are associated with a mean daily gas production of 110 x 104 m3/d (38.85°MMcf/d). The remaining 15 wells targeted the Sinian Dengying Formation, and are characterized by a mean daily production rate of 52 x 104 m3/d (18.36°MMcf/d).

The Cambrian Longwangmiao Formation, an over-pressured gas reservoir, is associated with a pressure coefficient of 1.53—1.69, a methane content of 96.3—97.1%, an ethane content of 0.13—0.14%, an N2 content of 0.60—2.35%, a He content of 0.01% and no water. The Sinian Dengying Formation, a normal pressure gas reservoir, has a measured pressure coefficient of 1.06—1.13, a methane content of 82.6—94.6%, an ethane content of 0.03—0.05%, an N2 content of 0.44—2.46%, a He content of 0.01—0.07%; bottom water and a unified gas-water contact exist within this formation. Proven recoverable geological reserves within the Cambrian Long-wangmiao Formation exceed 3000 x 108 m3 (10.59Tcf) in 780 km2 (301.16° mi2) of the Well Moxi-8 area alone. It is forecasted that the gas-bearing area pertaining to the Cambrian and Sinian systems are >10,000 km2 (3861° mi2), and associated geological reserves will be as much as 10,000 x 108°m3 (35.31Tcf).

Some oil and gas discoveries within Proterozoic—Cambrian strata have been reported (Grishina et al., 1998; Alvaro et al., 2000; Schroderetal., 2003; Petrychenko et al.,2005; Schroderetal., 2005; Kovalevych et al., 2006; Schoenherr et al., 2007; Boswell, 2009; Kukla et al., 2011; Wang and Han, 2011; Smith, 2012; Wang et al., 2013; Zou et al., 2014). Areas with proven oil and gas resources include the East Siberian Basin in Russia, the South Oman Salt Basin in Oman, and eastern Officer Basin in South Australia, primarily comprising oil fields, condensate oil fields or oil and gas field, with lower associated thermal evolution level (Rq 1.00°~° 1.7%). Overall, 65 oil and gas fields with a cumulative proven recoverable reserves of 22.36 x 108°t(1.6 x 1010°bbl) oil equivalent have been discovered within the Proterozoic Riphean, Vendian, and Lower Cambrian Series in the East Siberian Basin, Russia. This includes proven reserves equating to 1195 x 108°m3 (4.22Tcf) within the Upper Vilyuchan-skoye gas field, where Well Yurubcheno-110 tapped an industrial oil flow of 24 m3/d (4220°cf/d) at 324 m below the Riphean erosion surface (Halbouty, 2003; Wang and Han, 2011; Zou et al., 2014). Nine carbonate oil reservoirs associated with proven geological reserves of 3.5 x 108°t°(2.5 x 109°bbl) have been located within the Proterozoic-Lower Cambrian Series in the Harweel Cluster in the South Oman Salt Basin. Sinian oil reserves were 0.86 x 108 t have been associated with Bahawalpuro-1 in the Bikaner-Nagaur Basin, India—Pakistan. Accordingly, the location of a Sinian—Cambrian trillion cubic meter within the Sichuan Basin, represents the first large-scale discovery resulting from oil to gas cracking within ancient strata. Thus, increased understanding the geo-evolutionary process of this gas reservoir is of significant importance respect to oil and gas exploration oil within ancient strata.

2.2.2. Characteristics of Sinian—Cambrian dolomite-hosted gas reservoirs

The Sinian—Cambrian system within the Sichuan Basin comprises a set of strata, with the Sinian system divided into the Lower

Figure 2. Geological stratigraphic column of Sichuan Basin, central China.

Sinian Doushantuo Formation black shales and the Upper Sinian Dengying Formation dolomites (Fig. 2). The Lower Sinian Doush-antuo Formation is rich in algae and acritarch microfossils, with a measured age of 635.2 ± 0.6°Ma-551.07 ± 0.61°Ma (Condon et al., 2005). The Dengying Formation consists of two members in unconformable contact; similar to the black shales, the dolomite member is rich in algae and acritarch microfossils, in addition to soft-bodied Vermes (non-arthropod invertebrates), cyathiforms and tubular skeleton fossils (Hua et al., 2005); with 513C measurements indicating a marked negative shift. Clastic rock strata located at the base of the upper member were deposited over the whole area, with the zircon age for the tuff of the upper member

measured at 206Pb/238U = 543 ± 12° Ma, considered a marker for isochronous correlation (Fig. 4). The Cambrian system comprises four distinct formations, as follows:

(1) The Lower Cambrian Qiongzhusi Formation black shale; these contain trilobite and small shelly fossils, with age values of 528.3 ± 2.0°Ma (Compston et al., 2008), 522.7 ± 4.9°Ma (Wang et al., 2012a,b) and 532.3 ± 0.7°Ma at the base of the formation (Jiang et al., 2009);

(2) The Canglangpu Formation argillaceous siltstone; these are associated with the middle stage of the Early Cambrian, as indicated by trilobite fossils (Xiang et al., 1999);

Figure 3. Geographic location, primary geological characteristics and sample positions of giant conventional Sinian-Cambrian gas system, Sichuan Basin, central China ((1) denotes Paleo-high axial line in Permian, (2) denotes Paleo-high axial line in present).

(3) The Longwangmiao Formation oolitic dolomite; these contain a notable trilobite Redlichia murakamii-Hoffetella belt deposited during the later stage of the Early Cambrian (Xiang et al., 1999);

(4) The Middle-Upper Cambrian Xixiangchi Formation dolomite; the top of this is considered Early Ordovician, indicated by the occurrence of a conodont Monocostodus sevierensis belt close to its top surface (Fan et al., 2013).

Located in the northwestern portion of the Yangtze platform, the Sichuan Basin developed Sinian-Middle Triassic marine strata and Upper Triassic-Eocene continental strata. Multiple stages of structural movement have occurred during its geological history, including Caledonian, Hercynian, Indosinian, Yanshan, and Himalayan movements (Fig. 2). Due to the potential impacts of these movement processes upon the original Sinian-Cambrian oil and gas reservoir, the formation and preservation of this vast reservoir in ancient strata are not well understood. However, undoubtedly these geological elements and processes have resulted in the formation and preservation of this giant Sinian-Cambrian gas field.

Contemporary seismic data and well correlation analyses from the region indicate the development of a large-scale faulted trough in the central-western Sichuan Basin (Fig. 3), caused by tectonic movement during the early stages of the Early Cambrian. This faulted trough trends from south to north, with a steep incline in the east, decreasing to a gentle incline in the west; it is associated with a minimal width of 50 km (central region) and maximum width of >100 km (northern and southern regions). Strata in the trough are 400-700°m thick, comprising Lower Cambrian Qiongzhusi Formation high-quality source rock of 120-160°m thickness. The productivity of the large-scale faulted trough was proven by Well Gaoshi-17, in which the thickness of Lower Cambrian strata increases to 530 m, with high-quality source rock located in the Qiongzhusi Formation. The source rock has a measured TOC >1.0% in association with a thickness of 140°m, increasing to a TOC of >2.0% in parallel with a thickness of 65° m.

The Qiongzhusi Formation mud shale, the major source rock in the area, is characterised by a high-abundance sapropelic-type and post-maturity. Results from 409 samples indicate a TOC range from 0.50%-8.49% (Mean 1.95%) and a discounted Ro ranging from 2.12%-3.46% (Fig. 5).

An industrial shale gas resource with considerable reserves has recently been discovered within these strata; high-quality Lower Cambrian source rock within the faulted trough, associated with a gas-generation intensity of 20-60 x 108 m3/km2 (27.27-81.81°bcf/ mi2), serves as a major petroleum supply source for the vast Sinian-Cambrian gas field.

Cambrian-Sinian natural gas in the Sichuan Basin originated from secondary cracking of crude oil (Wei et al., 2014), as proven by the following:

(1) As shown (Fig. 6; Table 1), significant variance has been noted with respect to the C2/C3 ratio in the Cambrian-Sinian natural gas in the Sichuan Basin, in concurrence with minor variance of the C1/C2 ratio. As the C1/C2 of kerogen pyrolysis gas increases gradually, its C2/C3 will not vary significantly; conversely, the C1/C2 of crude oil secondary cracking gas will exhibit little variation while its C2/C3 will gradually increase (Behar et al., 1991; Prinzhofer et al., 1995);

(2) As previously shown (Hu et al., 2005), crude oil secondary cracking gas comprises greater proportions of iso-paraffin and cyclo-paraffin than kerogen pyrolysis gas. Typically, the methylcyclohexane/n-heptane ratio is >1.0 and the (2-methylhexane+3-methylhexane)/n-hexane ratio is >0.5 in crude oil cracked gas (Hu et al., 2005); thus, it is indicated that the Cambrian-Sinian natural gas in the Sichuan Basin originated from the crude oil secondary cracking (Fig. 6);

(3) Reservoir bitumen represents the residue of crude oil secondary cracking within paleo-oil reservoirs, with bitumen abundance controlled by the paleo-high prior to the completion of crude oil secondary cracking. As shown (Fig. 6), the bitumen content in the crest of Well Goashi-1

Figure 4. Paleontology, carbon/oxygen isotopes and zircon dating data in the Sinian Dengying Formation of the giant conventional Sinian-Cambrian gas system, Sichuan Basin, central China.

averages 9.21%, with the mean bitumen content decreasing gradually on the slope.

Within the Sichuan Basin, algal mounding and grain shoal deposits developed in the Sinian Dengying Formation, with intra-platform shoal deposits developing in the Cambrian Long-wangmiao Formation. During two periods of Tongwan movement (Zou et al., 2014b), these two carbonate reservoirs experienced intense contemporaneous dolomitization, supergenetic karsting and later-stage burial dissolution. Consequently, fracture-cavity carbonate reservoirs developed within the Sinian system, while pore-type dolomite reservoirs developed in the Cambrian system.

The fourth member of the Sinian Dengying Formation in central Sichuan Basin comprises a series of dolomites with a residual thickness range of 250—350° m. The associated dolomitization model is characterized by vaporization, infiltration-circumfluence and buried dolomitization (Fig. 7), under the background of an evaporative paleoclimate (Zou et al., 2014). The associated sedimentary facies is composed of a platform shallow-water (10° m supra-tidal zone) mound—shoal complex, with mounds associated with numerous origins. The most favorable reservoir rock facies belts include platform-marginal microbial framework and clotted lime mound cores, mound-flank dolo-arenites and dolo-rudites of various origins. Reservoir space is primarily comprised of

Figure 5. Geochemical characteristics of giant conventional Sinian-Cambrian gas system, Sichuan Basin, central China.

(hydrothermal mineral filled) residual pinholes, pores, karst caves and unfilled fractures of the Late Yanshanian-Himalayan.

Associated diagenesis is characterized by minor cements precipitated in a hot, dry, paleoclimate, including fibrous or microcrystalline rim and shallowly buried prismatic dolomite of submarine cementation, in addition to later-stage saddle dolomite and quartz cements.

Weathering crust karst reservoirs primarily influenced by mound beach facies typically dominate the origin type. The Lower

Cambrian Longwangmiao Formation located within the central Sichuan Basin comprises a set of dolomite beds with a residual thickness of 80-100°m; the associated dolomitization model encompasses vaporization, infiltration-circumfluence and burial dolomitization (Fig. 8) under an evaporative paleoclimate background. Related sedimentary facies includes inner gentle slope, grain-supported beach and evaporative lagoon-evaporative tidal flat subfacies of the gentle slope-type platform. The aforementioned grain-supported beach, which is proximate to evaporative

Figure 6. Evidence of crude oil cracking within the giant conventional Sinian—Cambrian gas system, Sichuan Basin, central China. (A) Profile of the Weiyuan-Ziyang-Sinian—Cambrian giant gas system; (B) In(C1/C2) versus In(C2/C3) of marine gases; (C) Relationship between iso-paraffin and cyclo-paraffin; (D) Typical reservoir microphotograph showing the variation of bitumen content within different tectonic locations.

lagoons and evaporative tidal flats represent the most favorable reservoir rock facies belt.

Reservoir space and type may be classified as one of the three following categories: (1 ) matrix pore-type consisting of intergranular (dissolved) pores and worm-mold (dissolved) pores, (2) facies-controlled karst pore-cavity type formed by superimposition of multiperiod supergenetic karst and (3) fault-controlled large-scale cave reservoirs. Reservoir formation and evolution typically underwent four stages of constructive diagenesis, as follows: (1 ) syngenetic-penecontemporaneous vaporization, (2) infiltration-circumfluence

dolomitization, (3) syngenetic-penecontemporaneous meteoric fresh-water dissolution and (4) weathering crust karstification dating to the end of Longwangmiao Formation deposition, and particularly, the following Middle Caledonian—Middle Hercynian period layer-parallel karstification.

Multiple sets of mudstone serving as direct cap rock have developed in the Sinian—Cambrian system including upper members of the Dengying Qiongzhusi Formations. Drilling results indicate that regional gypsum-salt rock developed during the Middle-Lower Cambrian within the basin, with cap rocks comprised of

Table 1

Natural gas components and carbon and hydrogen isotopic compositions of the giant gas field in Sichuan Basin.

Well Fm. Main components (%) C1/(C1+C2) <513 C(%o)PDB <5D(%0)

CH4 C2H6 N2 CO2 H2S He CH4 C2H6 CH4

M9 €1l 95.16 0.13 2.35 2.35 0.00 0.01 0.9986 -32.8 -32.8 -134

M11 Upper €1l 97.09 0.13 0.67 2.04 0.00 0.01 0.9987 -32.5 -32.4 -133

M8 Upper €1l 96.80 0.14 0.60 2.26 0.00 0.01 0.9984 -32.4 -32.3 -133

M11 Lower €1l 97.12 0.13 0.65 1.69 0.00 0.01 0.9987 -32.6 -32.5 -132

M8 Lower €1l 96.85 0.14 0.60 1.78 0.00 0.01 0.9984 -33.1 -33.6 -134

M8 Z2d4 91.40 0.04 1.65 5.87 0.96 0.05 0.9996 -32.8 -28.3 -147

G1 Upper Z2d4 91.22 0.04 1.36 6.35 1.00 0.03 0.9996 -32.3 -28.1 -137

G3 Upper Z2d4 90.19 0.04 0.73 8.30 0.68 0.06 0.9996 -33.1 -28.1 -138

G1 Lower Z2d4 90.11 0.04 0.44 8.36 0.97 0.02 0.999 -32.7 -28.4 -135

G6 Lower Z2d4 89.99 0.04 1.49 8.32 0.13 0.02 0.9995 -32.9 -28.6 -139

G1 Z2d2 82.65 0.04 2.12 14.19 0.85 0.04 0.9982 -32.3 -28.7 -137

G6 Z2d2 94.61 0.04 0.93 4.14 0.18 0.02 0.9996 -32.8 -29.1 -140

M10 Z2d2 93.13 0.05 0.86 4.64 1.30 0.02 0.9995 -33.9 -27.8 -139

M11 Z2d2 89.87 0.03 2.32 7.32 / 0.05 0.9997 -32.0 -26.8 -150

M8 Z2d2 91.42 0.04 2.46 6.01 / 0.05 0.9996 -32.3 -27.5 -147

M9 Z2d2 91.82 0.05 0.96 4.24 2.75 0.02 0.9995 -33.5 -28.8 -141

0 2.0 4.0 6.0 8.0 10.0

porosity(%)

Figure 7. Reservoir characteristics of the Sinian Dengying Formation, Sichuan Basin, central China. (A) Characteristics of sedimentary facies and reservoirs of the Upper Sinian Dengying Formation in well G1 cores. I dolorudite, lime mound flank microfacies, developed pinholes and dissolved pores, matrix porosity 8.02%, matrix permeability 0.487 x 10~3°mm2,4956.67-4956.86°m in depth. II clotted dolomite, clotted lime mound core microfacies, developed dissolved pores, partially filled by hydrothermal dolomite and pyrobitumen, 4958.32-4958.40°m in depth. Ill dolorudite, lime mound flank microfacies, pinholes and dissolved pores distributed along bedding planes, and Late Yanshanian and Himalayan vertical fractures also developed, 4966.98-4967.07°m in depth. IV clotted dolomite, lime mound flank microfacies, developed dissolved pores, matrix porosity 6.04%, matrix permeability 0.945 x 10~3°mm2,4982.72-4982.84°m in depth. (B) Characteristics of microsedimentary facies and reservoirs of the Upper Sinian Dengying Formation in cast thin sections of Well G1. I doloarenite, lime mound flank microfacies, pyrobitumen developed within the remnant inter-granular dissolved pores and inter-crystalline pores, blue cast thin sections viewed under plane-polarized light, 4957.12 m in depth. II clotted dolomite, clotted lime mound core microfacies, pyrobitumen developed within the clotted dolomite remnant dissolved framework pores, blue cast thin sections viewed under plane-polarized light, 4959.42-4959.66°m in depth. III doloarenite, lime mound flank microfacies, keatite (white part in figure) and pyrobitumen developed within the remnant pores, blue cast thin sections viewed under plane-polarized light, 4963.76°m in depth. IV dolorudite, lime mound flank microfacies, pyrobitumen distributed in doloarenite bedding planes and fine-crystalline dolomite remnant pores, blue cast thin sections viewed under plane-polarized light, 4967.07-4967.21 °m in depth. V crystal powder dolomite, pyrobitumen found in remnant intergranular dissolved pores and intercrystalline pores, with Late-Yanshanian and Himalayan microfractures additionally developed, red cast thin sections viewed under plane-polarized light, 4973.6°m in depth. VI clotted dolomite, clotted lime mound core microfacies, pyrobitumen developed within the clotted dolomite remnant dissolved framework pores, blue cast thin sections viewed under plane-polarized light, 4976.26°m in depth. VII clotted dolomite, clotted lime mound core microfacies, remnant dissolved framework pores and clotted dolomite micropores, red cast thin sections viewed under plane-polarized light, 4982.31 m in depth. VIII clotted dolomite, clotted lime mound core microfacies, keatite and pyrobitumen developed within the remnant dissolved framework pores, blue cast thin sections viewed under plane-polarized light, 4985.03 m in depth. (C) Characteristics of core porosity and permeability in the Upper Sinian Dengying Formation in Well G1. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

overpressured Permian mudstones and Middle-Lower Triassic gypsum-salts occurring regionally, thus providing appropriate regional conditions for formation of the giant Sinian—Cambrian gas field (Fig. 2).

The Leshan-Longnusi paleo-high is characterized by a large irregular nose structure developed in the central-western Sichuan Basin, with sedimentary cap rock of Sinian, Paleozoic, Mesozoic and Cenozoic age. Multiple regional unconformities have developed in this area, including Z2dn2/Z2dn3, Z/G and O/S unconformities (Fig. 3). This paleo-high represents an inherited uplift influenced by both basement and faulting, the majority of which developed during the Caledonian. The paleo-high core, comprising an area of 6 x 104okm2, was eroded flat during the late Silurian and pre-Permian via long-term weathering and erosion, thus resulting in an absence of

Devonian and Carboniferous systems from west to east (i.e. Sinian, Cambrian, Ordovician and Silurian systems were eroded successively) (Fig. 3). Both the northern and southern flanks of the Leshan-Longnusi paleo-high have subsided irregularly since the Indosinian period of movement, giving rise to rotation of the structural axis of the top Sinian system from NEE to NE (Fig. 3). Myriad trap categories were developed in the Sinian Dengying and Cambrian Long-wangmiao formations under paleo-high conditions; structural and stratigraphic-lithologic traps developed within the Sinian Dengying Formation, while lithologic and stratigraphic trap clusters developed in the Cambrian Longwangmiao Formation (Fig. 5).

Faults interconnecting source rock with regional unconformities represent major pathways for petroleum migration. Extensional movement during the Early Cambrian gave rise to fault

Figure 8. Reservoir characteristics in the Cambrian Longwangmiao Formation of the giant Sinian—Cambrian gas system, Sichuan Basin, central China. (A) Characteristics of sedimentary facies and reservoirs of the Cambrian Longwangmiao Formation in Well M12 cores. I grain dolostone, inner gentle slope grain beach subfacies, doloarenite beach microfacies, enhanced dissolution of pinholes and worm mold pores, semi-filled by pyrobitumen, 4621.04°m in depth. II grain dolostone, inner gentle slope grain beach subfacies, doloarenite beach microfacies, enhanced dissolution of worm mold pores, distributed along bedding planes, 4621.26—4621.40°m in depth. III grain dolostone, inner gentle slope grain beach subfacies, doloarenite beach microfacies, dissolution of pinholes, partially filled by pyrobitumen and dolomites, 4640.15—4640.30°m in depth. IV grain dolostone, inner gentle slope grain beach subfacies, doloarenite beach microfacies, enhanced dissolution of worm mold pores, 4649.22—4649.28°m in depth. (B) Characteristics of microsedimentary facies and reservoirs of the Cambrian Longwangmiao Formation in cast thin sections of Well M12. I remnant oolitic dolomite, inner gentle slope grain beach subfacies, oolitic beach microfacies, intergranular dissolved pores developed and partially filled with pyrobitumen, blue cast thin sections viewed under plane-polarized light, 4620.61—4620.76°m in depth. II remnant oolitic dolomite, inner gentle slope grain beach subfacies, oolitic beach microfacies, intergranular dissolved pores developed and partially filled with pyrobitumen, blue cast thin sections viewed under plane-polarized light, 4622.05—4622.21 °m in depth. III remnant oolitic dolomite, inner gentle slope grain beach subfacies, oolitic beach microfacies, intergranular dissolved pores and microfractures developed and partially filled with pyrobitumen, blue cast thin sections viewed under plane-polarized light, 4626.30—4626.49°m in depth. IV remnant oolitic dolomite, inner gentle slope grain beach subfacies, oolitic beach microfacies, enhanced dissolution of worm mold pores, partially filled with pyrobitumen, blue cast thin sections viewed under plane-polarized light, 4631.23—4631.35°m in depth. V remnant oolitic dolomite, inner gentle slope grain beach subfacies, oolitic beach microfacies, intergranular and intercrystalline dissolved pores, partially filled with pyrobitumen, blue cast thin sections viewed under plane-polarized light, 4642.52—4642.72°m in depth. VI remnant dolosiltite and dung pellet dolomite, inner gentle slope grain beach subfacies, interval-beach bottomland microfacies, intergranular and intercrystalline dissolved pores, partially filled with pyrobitumen, blue cast thin sections viewed under plane-polarized light, 4643.87—4644.07°m in depth. VII fine-crystalline dolomite, inner gentle slope grain beach subfacies, grain beach microfacies, developed dissolved intercrystalline pores, blue cast thin sections viewed under plane-polarized light, x40, 4644.50—4644.60°m in depth. VIII remnant doloarenite, inner gentle slope grain beach subfacies, doloarenite beach microfacies, developed intergranular dissolved pores and partially filled with pyrobitumen, blue cast thin sections viewed under plane-polarized light, x20,4651.56—4651.74°m in depth. (C) Characteristics of core porosity and permeability of the Cambrian Longwangmiao Formation in Well M12. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

development, trending NEE and NW on both sides of the faulted trough, with particularly active fault movement during the Qiongzhusi stage, becoming significantly weaker during the Longwangmiao stage. Vertically, the Dengying and Qiongzhusi formations comprise the highest fault concentration, gradually dissipating within the Canglangpu and Longwangmiao formations. Unconformities such as Z2dn3/Z2dn2 and e1q/Z2dn4 represent significant lateral conduits for natural gas.

2.2.3. Formation mechanisms of the Sinian—Cambrian dolomite-hosted gas

As evidenced above, the vast Sinian—Cambrian gas field located within the Sichuan Basin is in possession of favorable coincident conditions for petroleum geology, including a stable local tectonic

setting, preservation of multiple regionally distributed gypsum-salt rocks and mud shale cap rock arrays and subsequent petroleum migration (Wei et al., 2014) (Fig. 9). Multi-period Tongwan-Caledo-nian tectonic movements have resulted in the formation of numerous arrays of Dengying Formation karst weathering curst reservoirs and unconformable conduit layers. Rapid filling of extensional faulted troughs during the Tongwan period has led to the formation of high-quality muddy source rock, in concurrence with a conduit system comprised of intersecting faults within the source rock. The Longwangmiao Formation dolomitic, a grain-supported beach facies reservoir body, has undergone significant spatial development. From the Paleozoic to the Meso-Cenozoic, the Leshan-Longnusi paleo-high retained its geometry, albeit, the axial direction has changed gradually from approximately EW to NE. Under the

Figure 9. Reservoir formation synthesizing map of the giant conventional Sinian—Cambrian gas system, Sichuan Basin, central China.

paleo-high setting, myriad trap cluster types have developed, leading to the formation of hydrocarbon accumulation over an extended time period. The generation of hydrocarbons primarily occurred during the Middle-Late Cambrian, with large-scale paleo-oil reservoirs formed during the Middle Ordovician-Permian, which represented a significant period of oil generation. During the Middle-Late Triassic-Cretaceous, gas generation occurred due to the cracking of oil in the reservoir, thus leading to the development of this vast overly mature oil-cracking gas field, with maximum formation temperatures of >230 oC. Although some minor modifications have taken place, overall the gas field has been well preserved.

2.3. Unconventional Cambrian—Silurian shale gas

2.3.1. Overview

China initiated shale gas geological resource evaluation, potential basin screening and pilot testing in 2005. However, major

exploration activities did not get underway for another four years, aided by a shale gas technology sharing agreement between the USA and China, in addition to promotion of shale-gas development investment in China. Industrial shale gas was discovered in the Weiyuan area in 2010, southwest of the Sichuan Basin, with the Wei-201 exploration well locating a shale gas reserve in the Lower Cambrian strata (Fig. 10). To date, shale gas has been located within three distinct formations in the Sichuan Basin, including the Lower Cambrian Qiongzhusi Formation (e1q), the Upper Ordovician Wufeng Formation (O3w) and the Lower Silurian Longmaxi Formation (S1l) (Fig. 2). In the current study, these are collectively referred to as the Sichuan Longmaxi—Qiongzhusi (SLQ) shale gas reserve. Thus far, approximately 80 wells (including 40 horizontal wells) have been drilled in the area. Subsequent to well stimulation via hydraulic fracturing, the initial daily shale gas production ranges from 1.982 x 103 m3 to 5.46 x 106 m3 (0.07—193°MMcf/d), with a mean individual well production equating to approximately

Figure 10. Map of the Sichuan Basin indicating the primary shale gas exploration blocks; Weiyuan, Fushun, Yongchuan, Changning and Fuling, shale gas wells, and the distribution and the maturity of the Lower Silurian Longmaxi Shale.

12.9 x 104 m3 (4.54° MMcf/d) (Zou et al., 2014). The primary shale gas reservoirs within the region are Early Cambrian (e1q) (570-510°Ma) and Late Ordovician-Early Silurian (O3w-S1l age) (445-425°Ma) (Fig. 2). Sedimentary facies are dominated by marine organic-rich black shales, with reservoir thickness ranging from 98 to 140° m and a total organic carbon (TOC) content of 0.43-25.73%. The thermal maturity (equivalent Ro) is 2.2-4.5%, with in-situ porosity and permeability ranges of 1.2-8.0% and 0.042-1.9°mD, respectively. The measured gas content is within the range 51.5-229.4 ft3/t, with burial depths ranging from 1300 to 4500 m. Preliminarily, the demarcated area with favourable conditions for shale gas preservation is approximately 30,000 km2, in concurrence with a predicted individual well reserve of 1.48-3.81 billion cubic feet (BCF). Overall, predicted recoverable resources equate to 152 trillion cubic ft (TCF), with 4.9 BCF extracted from 19 producing wells during 2013 (Zou et al., 2014).

2.3.2. Characteristics of the Sichuan Longmaxi-Qiongzhusi shale gas reserve

The Sichuan Longmaxi-Qiongzhusi shale gas reserve is located in the southern portion of the Sichuan Basin (Fig. 10), and is characterised by a 200 km wide (N-S) and 400 km long (E-W) gas field area. The gas field has a spatial extent of approximately 65,000 km2 within a region of low-lying land (Elevation 200-750 m above sea level) (Figs. 10 and 11), with the Yangtze River and its tributaries intersecting the gas field area. As the Sichuan Longmaxi-Qiongzhusi reserve is located within the major conventional oil and gas producing region, a well established local pipeline network pre-exists.

Tectonically, the Sichuan Basin comprises part of the Yangtze Platform, with the basin having undergone five orogenies including the Caledonian, Hercynian, Indosinian, Yanshanian and

Himalayan orogenies, since the Sinian (pre-Cambrian). The present basin configuration was formed during the Himalayan Orogeny; the basin is typified by a large syncline in the south and a dividing synclinal area in the east; the entire basin is enclosed by fold belts (Fig. 11).

The Sichuan Basin basement is comprised of 1000-10,000°m thick middle to upper Proterozoic metamorphic and magmatic materials (Fig. 11); the basin has evolved from a Paleozoic marine cratonic basin to a Cenozoic (initiated during the late Triassic) terrestrial foreland basin. Paleozoic-Cenozoic sediments ranging from 6000 - 15,000°m in thickness comprise the primary basin fill material (Wang et al., 2012a,b). Paleozoic sediments within the basin are 1400-3600° m thick and comprise four marine black shales, namely, the Sinian Doushantuo Formation, the Lower Cambrian Qiongzhusi Formation, the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation (Fig. 2; Fig. 11). The Lower Cambrian Qiongzhusi Formation, the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation black shales encompass the primary shale gas production intervals within the Sichuan Longmaxi-Qiongzhusi shale gas play; production intervals range from 1000 to 5000° m, with a mean depth of 3000° m.

As previously outlined in several studies (Cheng et al., 1995; Wang et al., 2012a,b; Loucks and Ruppel., 2007), feasible development of a shale gas reserve depends primarily upon on the volume and quality of organic-rich shales, which is in turn primarily influenced by the associated depositional environment. Based upon previous core and outcrop analyses, the depositional environmental associated with the Long-maxi-Qiongzhusi shales are highly similar to those of the Devonian shales in the Appalachian Basin (1EA, 2013). During the early Cambrian and early Silurian, the Sichuan Basin was

Figure 11. Cross-sections of Sichuan Basin indicating basin architecture and structural configurations (Cross section locations provided in Fig. 10).

Figure 12. Thickness isoline map of Qiongzhusi shale.

Table 2

Key geological parameters of the Sichuan Longmaxi—Qiongzhusi Shale gasfield.

Shale formation

Depth (m)

Prospect Recoverable Thickness Geochemical parameters Petrophysical Gas

resources (103 km2) (TCF)

Kerogen type

properties F (%) K(mD)

content (ft3/t)

Mechanical characteristics

Mineral PR Young's

components Modulus

Weiyuan Longmaxi 1300-3700 2.8 8.8 45 2.7 2.7 I, II1 5.3 0.042 103.0 Brittle: 66.4% Clay: 33.6% 0.18 13.3

Qiongzhusi 2600-4000 2.8 8.5 60 2.8 3.4 I, II1 2.2 0.1 98.8 Brittle: 73.8% Clay: 26.2% 0.21 31

Fushun- Longmaxi 3200-4500+ 13.5 91.7 80 3.8 3 I, II1 4.2 0.2 Brittle: 61.3% 0.23 31

Yongchuan Clay: 38.7%

Changning Longmaxi 2000-4500 4.3 19.4 60 4 3 I, II1 5.4 0.3 144.7 Brittle: 69.5% Clay: 30.5% 0.18 25

Fulinga Longmaxi 2200-4500 8.15 23.8 62 3.5 2.7 I 4.6 250 123.5 Brittle 64.4% Clay: 34.6%

Data from Guo and Zhang (2014); PR: Poisson's Ratio.

dominated by deep to semi-deep shelf deposits, corresponding with periods of rising global sea level (Fig. 12). Accordingly, surface waters were warm, oxygen and nutrient rich and thus, conducive with flourishing plankton levels including various algae, radiolarians, foraminifera and sponge spicules. Concurrently anoxic sea bottom conditions lead to rapid accumulation and preservation of plankton (Wang et al., 2012a,b), thus forming high-quality hydrocarbon source intervals and providing a significant biogenic source for the development of brittle mineral layers within the shale formations. For example, planktonic algae may be converted to sapropel type organic matter via biodegradation, and subsequently converted to high-quality hydrocarbon generation source materials. Conversely, siliceous biological remains (e.g. diatoms, radiolarians, sponge spicules, etc.) may form amorphous biogenic silica, thus leading to the development of brittle minerals within the shale matrix. The Longmaxi—Qiongzhusi shales are siliceous, organic-rich shales with a mean TOC of 2.7—4.0%. The measured thickness of shales within the study area is 98—140°m (Table 2). The Longmaxi and Qiongzhusi formations are typical of highly and overly mature shales (Table 2), based upon existing gas shale maturity classification structures (Cheng, 1995; Jarvie, 2007). The mean measured TOC content within the Longmaxi Formation in the Weiyuan, Changning and Peiling Blocks are 2.7%, 4.0% and 2.4%,

• Barnett shale + Fayetteville shale A Western Canada basin • Appalachian basin(shale gas) • Longmaxi shale 1 * Yanchang shale ♦ « tfw* ♦ t - « > , ♦ ♦ H

. íÁ

0.08 0.16 0.48 0.8 1.6 4.8 8 16 24

Wetness (EC2-Cs/EC,-C„%)

Figure 13. Cross-plot of S13C2-S13Ci and wetness values of Longmaxi shale gas showing the typical isotopic reversal phenomenon (Sourced from Jarvie et al., 2007; Jarvie, 2012; USGS, 2013; Faraj et al., 2004; Carter et al., 2011; Gatens, 2005).

respectively; associated organic material categories are primarily composed of Types I and Hi. The shale gas thermal maturity within the Weiyuan Block reaches 2.7% Rq (eq), compared with 3.0% within the Changning Block. The Qiongzhusi Formation is characterized by a mean TOC content of 2.8% and a thermal maturity of 3.4%; the organic material category is analogous to that found in the Longmaxi Formation (Table 2).

The future role of organic-rich shales as a valuable commercial gas source will depend upon key factors, which will include, the presence of adequate brittle minerals, appropriate gas storage capacity and adequately high gas content (Zou et al., 2012, 2013a, 2013b, 2014; Engelder et al., 2009; Hammes et al., 2011; Curtis, 2002; Li et al., 2007). Shale brittleness is mainly driven by lith-ofacies; pores within the shale matrix and the degree of natural fracture development directly influence gas storage capacity (typically measured via physical parameters including porosity and permeability). The siliceous and calcareous-siliceous Longmaxi—Qiongzhusi shales are characterized by high brittleness and low permeability reservoirs. The physical properties of the Wufeng—Longmaxi shales are similar to those of the Barnett Shales (Table 2); brittle minerals such as quartz, feldspar and carbonate account for approximately 61.3—69.5%, whereas the clay mineral content is <40%. Typically, measured porosity is >5.0%, while permeability is characteristically <900° nD. Conversely, the Qiongzhusi shales are more brittle, with the percentage of brittle minerals reaching 73.8% and clay mineral content accounting for just 26.2%. Moreover, Qiongzhusi shales are characterised by relatively low porosity and permeability of 2.2% and 147°nD, respectively (Table 2). Drilling results indicate that gas reserves are present over the entire Longmaxi Shale interval. An abnormal high pressure zone exists in the central area of the basin adjacent to the basin slope and syncline areas, with the formation pressure coefficient reaching 1.4 (basin slope) to 2.0 (syncline area), respectively. The mean measured gas content for the interval is 144.7 ft3/ t (e.g. the Changning Block), with overpressure zones covering an area of >25,000 km2. Conversely, no overpressure zones have been associated with the basin edge of the field (e.g. Zhaotong Block, Weiyuan Block), which are associated with a formation pressure coefficient of 1.0 and a gas content within the range 81.3—103 ft3/t. To date, few wells have penetrated to the Qiongzhusi shale interval; however, shale gas has been located in the Weiyuan Block, which is associated with a formation pressure coefficient of 1.0 and a mean gas content of 98.8 ft3/t. Consequently, the measured formation pressure and gas content within the Longmaxi—Qiongzhusi Shales in the Sichuan Basin are comparable with those of the

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Haynesville Shales, Marcellus Shales, Eagle Ford Shales and Mon-tney Shales in North America (EIA, 2013). The aforementioned Longmaxi Qiongzhusi shales are characterized by low regional tectonic activity and high thermal evolution. Tectonic activities adjacent to the Sichuan Basin have reactivated frequently since the Sinian Period; this has led to large-scale uplift of the upper Paleozoic in the vicinity of the peripheral basin area and fault development, thus resulting in a cessation of favorable preservation conditions for shale gas. Nonetheless, shale gas reserves have been well preserved in the southern part of the basin, for three primary reasons:

1. Overlying strata of the upper Paleozoic shales are well

preserved,

2. Faults are less developed,

3. The Longmaxi Qiongzhusi shales are bounded by a limestone

unit at the bottom and a thick black shale and mudstone unit at

the top.

Accordingly, shale gas in this area is dominated by hydrocarbon gas in the absence of liquid hydrocarbons (Fig. 13). The gas comprises 97.79% methane, 1.16% ethane, 0.29% C3 to C5 hydrocarbons with minor amounts of CO2 and N2 and an absence of H2S. The ethane carbon isotopes exhibit an isotopic reversal, similar to typical shale gases in North America (Fig. 13).

To date, approximately 80 wells have been drilled in the area equating to a proven effective resource area of 30,000 km2 and a predicted recoverable resource of 176°TCF. Demarcated regions of particular interest ('sweet spots') within the area include the Weiyuan, Changning, Fushun—Yongchuan and Peiling Blocks (Fig. 1; Table 2), equating to a total area of 16,500 km2. Predicted single well production is 1.5—3.8 BCF, with a total proven recoverable reserve from the aforementioned sweet spots equalling approximately 81.9°TCF. Shale gas production in 2013 amounted to 17.6°bcf, with annual shale gas production projected to reach

1.1 °TCF over the coming 5—10 years.

2.3.3. Implications

The Sichuan Longmaxi Qiongzhusi shale gas reserve represents the oldest shale gas field in the world with an early Cambrian to early Silurian age (570—420°Ma). Gas shales have the highest known thermal maturity for producing shale gas, with the Qiongzhusi and Longmaxi Formations associated with Ro values of

3.2 3.6% and 2.5 3.2%, respectively.

The key production intervals for shale gas in North America are typified by the more recent Devonian—Cretaceous (420—65° Ma) stratigraphic formations, which are characterised by moderate thermal maturity (Rq°<°2.5%) (EIA, 2013). The majority of shale gas production occurs in relatively stable tectonic regions; therefore shale gas occurrence and preservation is relatively simple. The Sichuan Longmaxi Qiongzhusi shale gas reserves are located in a relatively stable region within a tectonically complicated basin. The discovery has effectively extended the upper maturity limit of Ro over 3.0% (Cheng et al., 1995), thus demonstrating the potential for viable commercial shale gas extraction from overly-mature organic shales. Moreover, this may demonstrate the efficacy of broadening current shale gas exploration areas within ancient sedimentary basins, thus potentially increasing global shale gas resources significantly. Furthermore, this may represent the beginning of a paradigm shift with respect to current understanding of the underlying mechanisms of shale gas accumulation and preservation. Accordingly, the development of a suite of innovative shale gas evaluation and site screening techniques may now be undertaken, permitting the provision of a globally effective analogue for shale gas exploration in old strata.

In addition to China, shale gas has been discovered in 11 other Silurian (>440° Ma) or pre-Silurian marine strata (e.g. Tannezuft, Qusaiba, Utica, Goldwyer) in North Africa, Eastern Europe, North America, Western Europe, Australia and Central Asia. These discoveries include five intervals within the Silurian, three intervals in the Ordovician, one interval in the Cambrian and two intervals in pre-Cambrian strata (Table 3) (EIA, 2013). The total global prospective area of shale gas occurrence and production in old marine strata is estimated to be greater than one million km2, with estimated recoverable resources of approximately 1190°TCF. The Silurian Tannezuft Shale in North Africa alone represents the largest individual reserve, with a potentially productive area of 600,000 km2 and a recoverable resource of 557°TCF (Table 3). Accordingly, the discovery and successful production of Sichuan Longmaxi—Qiongzhusi shale gas may not only change shale gas exploration in China, but lead to the development of shale gas exploration in ancient, deeply buried marine strata on a global stage.

3. Conclusions

Conventional and unconventional petroleum system theory indicates that, unconventional petroleum typically occurs in the hydrocarbon supply direction of conventional petroleum reserves, while conventional petroleum may appear in the outer space of unconventional petroleum reserves. Accordingly, the Sinian-Silurian gas system in Sichuan Basin represents a definitely different and typical example of a concurrent conventional and unconventional gas system within a tectonically complicated basin and sourced from overly-mature organic shales (Ro°>°2.5%).

The Sinian—Silurian gas system in Sichuan Basin comprises two components, namely a conventional Sinian-Cambrian dolomite-hosted gas resource and an unconventional Cambrian-Silurian shale gas deposit, both represent trillion cubic meter accumulations. (1)The migration-accumulation type Sinian—Cambrian gas system, is a result of numerous processes, including paleo-high trapping, paleo-rift trough, large-scale dolomite grainstone reservoirs, adequate in-situ crude oil cracking gas and gypsum-salt and shale seal. (2)The self-contained source-reservoir Cambrian—Silurian shale gas system, is localized by deepwater organic-rich shelf facies, characterized by high silicon and calcium contents.

The massive Sinian—Silurian gas discovery in Sichuan Basin in old and over-matured sedimentary strata, has effectively broadened current natural gas exploration areas and increased global natural gas resources significantly, thus may spark interest in natural gas exploration in old strata globally widespread, and encourage co-development of conventional and unconventional petroleum accumulations.

Acknowledgements

This work was supported by the National Key Basic Research and Development Program (973 Program), China (Grant 2014CB239000); China National Science and Technology Major Project (Grant 2011ZX05001). This work could not have been achieved without the cooperation and support from the Research Institute of Exploration and Development and PetroChina Southwest Oil & Gas Field Company. The authors appreciate both Journal editors and anonymous reviewers for their precious time and useful suggestions.

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