Formation and distribution characteristics of Proterozoic–Lower Paleozoic marine giant oil and gas fields worldwide
Compiled with data from IHS Energy
Formation and distribution characteristics of Proterozoic-Lower Paleozoic marine giant oil and gas fields worldwide
Xiao-Ping Liu 0 1 2 3 4
Zhi-Jun Jin 0 1 2 3 4
Guo-Ping Bai 0 1 2 3 4
Ming Guan 0 1 2 3 4
Jie Liu 0 1 2 3 4
Qing-Hua Pan 0 1 2 3 4
Ting Li 0 1 2 3 4
Yu-Jie Xing 0 1 2 3 4
0 College of Geosciences, China University of Petroleum , Beijing 102249 , China
1 State Key Laboratory of Petroleum Resources and Prospecting , Beijing 102249 , China
2 Exploration and Development Research Institute, PetroChina Tarim Oilfield Company , Korla 841000, Xinjiang , China
3 Exploration and Development Research Institute, PetroChina Huabei Oilfield Company , Renqiu 062552, Hebei , China
4 Petroleum Exploration and Production Research Institute , SINOPEC, Beijing 100083 , China
There are rich oil and gas resources in marine carbonate strata worldwide. Although most of the oil and gas reserves discovered so far are mainly distributed in Mesozoic, Cenozoic, and upper Paleozoic strata, oil and gas exploration in the Proterozoic-Lower Paleozoic (PLP) strata-the oldest marine strata-has been very limited. To more clearly understand the oil and gas formation conditions and distributions in the PLP marine carbonate strata, we analyzed and characterized the petroleum geological conditions, oil and gas reservoir types, and their distributions in thirteen giant oil and gas fields worldwide. This study reveals the main factors controlling their formation and distribution. Our analyses show that the source rocks for these giant oil and gas fields are mainly shale with a great abundance of type I-II organic matter and a high thermal evolution extent. The reservoirs are mainly gas reservoirs, and the reservoir rocks are dominated by dolomite. The reservoir types are mainly karst and reef-shoal bodies with well-developed dissolved pores and cavities, intercrystalline pores, and fractures. These reservoirs are highly heterogeneous. The burial depth of the reservoirs is highly variable and somewhat negatively correlated to the porosity. The cap rocks are mainly thick evaporites and shales, with the thickness of the cap rocks positively correlated to the oil and gas reserves. The development of high-quality evaporite cap rock is highly favorable for oil and gas preservation. We identified four hydrocarbon generation models, and that the major source rocks have undergone a long period of burial and thermal evolution and are characterized by early and long periods of hydrocarbon generation. These giant oil and gas fields have diverse types of reservoirs and are mainly distributed in paleo-uplifts, slope zones, and platform margin reef-shoal bodies. The main factors that control their formation and distribution were identified, enabling the prediction of new favorable areas for oil and gas exploration.
Giant oil and gas field; Proterozoic and Lower; Paleozoic; Marine carbonate rocks; Petroleum geological conditions; Oil and gas distribution
Oil and gas fields with recoverable reserves of more than
500 9 106 bbl of oil equivalent are referred to as giant oil
and gas field (Halbouty 2003; Bai 2006). According to the
IHS Energy Group database, as of 2014, 1087 giant oil and
gas fields have been found worldwide, accounting for
72.5% of the global conventional proven and probable
reserves, and 54.5% of them are located in marine
carbonate rocks. Therefore, marine carbonate rocks have
considerable oil and gas potential (Jia et al. 2006; Gu et al.
2012; Bai and Xu 2014). Most of the discovered oil and gas
reserves in carbonate rocks are mainly distributed in the
Mesozoic (mostly Jurassic and Cretaceous) strata, followed
by the Cenozoic and upper Paleozoic strata, with very few
in the Proterozoic–Lower Paleozoic (PLP) strata. Only
2.3% of the total carbonate oil and gas reserves in the
oldest strata have been found, because exploration has been
very limited there and thus great potential exists for
exploration, particularly in China and the Asia–Pacific
hydrocarbon-rich regions (Yu et al. 2012; Jin et al. 2013;
Bai and Cao 2014). Indeed, oil and gas fields have been
found in the PLP marine carbonate strata in dozens of
basins worldwide, including thirteen giant oil and gas fields
(Fig. 1), namely the Tahe and Tazhong 1 oil and gas fields
in the Tarim Basin; the Jingbian gas field in the Ordos
Basin; the Anyue gas field in the Sichuan Basin; the
Verkhne–Vilyuchanka, Kuyumba, Talakan, Yurubcheno–
Tokhomo oil and gas fields in the East Siberian Basin; the
Puckett and Gomez gas fields in the Permian Basin; the
Niagaran Reef Trend oil and gas field in the Michigan
Basin; the Lima–Indiana Trend oil and gas field in the
Indiana–Ohio platform; and the Makarem 1 oil and gas
field in the Oman Basin (Fig. 2; Table 1). A clearer
understanding of the geologic conditions and distribution
characteristics of these giant oil and gas fields would offer
valuable insights for further exploration of oil and gas
resources in the PLP marine carbonate strata worldwide.
2 Geological background
2.1 Tectonic evolution of the basins
The basins with giant oil and gas fields found in the PLP
strata are based on Precambrian metamorphic rocks or
granites with basement faults, and they are characterized
by the development of cratonic basins in the Proterozoic or
Paleozoic periods. These basins are very large. For
example, the East Siberian Basin covers an area of 350 9 104
km2, while the other basins are hundreds of thousands of
Oil and gas fields
Boundary of basin
Basin with giant oil and gas field
Basin with oil and gas field
Basin without oil and gas field
Recoverable reserves, MMBOE
500 1000 1500
Niagaran Reef Trend
Fig. 2 Recoverable reserves of marine carbonate giant oil and gas
fields in the Proterozoic–Lower Paleozoic strata worldwide
square kilometers in size. Except for the Michigan Basin
and Indiana–Ohio Platform, which are on stable cratons,
other basins are superimposed basins that have undergone
multistage structural evolution from stable craton basins in
the Proterozoic or Lower Paleozoic. Among them, the
Ordos Basin is a Mesozoic and Cenozoic rift basin that
evolved from a late Proterozoic to early Paleozoic craton
basin; the Tarim Basin, Permian Basin, East Siberian
Basin, and Oman Basin are Mesozoic and Cenozoic
foreland basins evolved from the Paleozoic craton basins, and
the Sichuan Basin was a Late Triassic foreland basin that
evolved from a Sinian into a Middle Triassic craton basin,
and then finally evolved into an early Jurassic to
Cretaceous depression basin.
Each basin has distinct evolutionary characteristics. The
Ordos Basin is located in the southwest of the North China
platform on an Archaeozoic and early Proterozoic granite
and metamorphic basement. It has experienced multiple
tectonic evolutions (Liu et al. 2009a; Zhao et al. 2012a).
The Tarim Basin on the Tarim platform was developed on
a Precambrian crystalline metamorphic basement. It is a
multicycle superimposed basin, formed from a stably
developed Paleozoic marine cratonic basin and Mesozoic–
Cenozoic foreland basin by thrust tectonics and has
experienced multiphase tectonic movements and
superimposed sedimentation (Jia and Wei 2002; Xu et al. 2004; He
et al. 2005; Zhang et al. 2007a; Pang et al. 2012). The
Sichuan Basin is located in the northwest of the Yangtze
plate. It was superimposed on a Proterozoic crystalline
basement with a Sinian to Middle Triassic cratonic basin, a
Triassic foreland basin, and an early Jurassic to Middle
Cretaceous depression basin (Liu et al. 2011; He et al.
2011a). The Permian Basin in the southern margin of the
North American platform is a Paleozoic cratonic basin
developed on a Precambrian crystalline basement. In the
early Paleozoic period, it was a carbonate shelf deposit in a
shallow sea, gently inclining southeast and having
multistage tectonic evolutions. This basin mainly consists of the
Central Basin platform, the Delaware Basin, the Midland
Basin, and the Val Verde Basin (McKee et al. 1967; Hills
1984; Yang and Dorobek 1995). The Michigan Basin is
located in the east of the North American platform. It is a
relatively stable intracratonic basin deposited on a
Precambrian crystalline basement (Charpentier 1987;
Catacosinos et al. 1990). The East Siberian Basin was
developed on the Siberian platform on an Archean–
Proterozoic metamorphic basement. It has experienced
multiphase tectonic movements and formed the current
tectonic patterns of alternative depressions and uplifts, and
Mesozoic–Cenozoic foreland basins have developed in the
margin of the basin (Kheraskova et al. 2009; Nikishin et al.
2010; Zhu et al. 2012; Du et al. 2013; Frolov et al. 2015).
The Oman Basin is located in the southeast part of the
Arabian Plate. It is also a large superimposed basin and
evolved from a Precambrian interior cratonic rift into a
Paleozoic inland depressed basin, and subsequently
experienced multistage tectonic evolutions (Loosveld et al.
1996; Filbrandt et al. 2006; Zhu et al. 2014).
2.2 Sedimentary characteristics
The PLP strata in these basins mainly consist of marine
carbonate sediment (Fig. 3). In the early Paleozoic, the
Ordos Basin was a shallow epicontinental sea and later
evolved from a carbonate gentle slope in the epicontinental
sea into a carbonate platform and then into a weathered and
denuded paleo-continental deposit (Wei et al. 1997; Li
2009). The Tarim Basin comprised marine strata from the
Sinian to early Permian periods; its Lower part was clastic
rock intercalated with carbonate rock. The central part was
carbonate rock, and the upper part was clastic rock
intercalated with carbonate rocks, which were mostly Cambrian
and Ordovician (Jia and Wei 2002; Xiao et al. 2011). The
Sichuan Basin sediments were marine craton carbonate
with a clastic sedimentary stage in the Sinian to Middle
Triassic periods (He et al. 2011a). The Permian Basin has
been subject to Paleozoic marine and Mesozoic–Cenozoic
n n 2
iedw ,ieaL” –O1 ,ieaL” -O1 i/ngZ /anS2 O3 ” 1
titllrrscaaeazooodw /itraeangoom rrccekouo ,ili/agnng–PPO2 iiji-faagnuuxunkTm ,itit/rseaeuuouHY ijii-faagnuuxunkTm ,itit/rseaeuuouHY” ,i/isezngyuhnogD1 ii/ltseaangykynR /irsaaaykdnR2” /lssaayok1 /irsaaaykdnR2 /isnpoOm2 /isnpoOm2 ,/ili-raaaa1ngSAN3 ,lttiit/saaecannoPU /trrfe–pguoupquPS3 ,)(72000820S
P F S C Y Y Q D M U M S S S P H G
Fig. 3 Stratigraphic profiles and source-reservoir-cap rock assemblages of marine carbonate giant oil and gas fields in the Proterozoic–Lower
Paleozoic strata worldwide
continental sedimentary systems since the end of the
Cambrian period. In the Lower Paleozoic stratigraphic
sections, several unconformities exit, and most of them
between shallow shelf carbonate deposits (Hills 1984;
Adams and Keller 1996). The Michigan Basin was
deposited on a set of transgressive sandstones and sandy
dolomites in the Cambrian period, which is in
unconformable contact with Ordovician marine carbonate
rocks, shales, and sandstones. In the Silurian period,
carbonate rocks, reefs, and evaporites were alternately
deposited and formed unconformable contact with the
Devonian stratum (Fisher et al. 1988; Catacosinos et al.
1990). The sedimentary strata in the East Siberian Basin
began in the Riphean in the Proterozoic period, and the
major residual strata in the basin are Riphean, Vendian,
Cambrian, Ordovician, and Silurian. Except for the
Lower part of the Vendian and Silurian strata, which are
mainly terrigenous clastic rock, the other strata are all
carbonate (Khudoley et al. 2001; Zhu et al. 2012; Du
et al. 2013). The marine carbonate strata in the Oman
Basin are the Huqf Group, which is mainly Upper
Proterozoic to Cambrian, formed during the
transformation of the early rift into a depression basin in shallow
sea, intermittent sea, and intertidal–subtidal zone
depositional environments (Gorin et al. 1982; Filbrandt et al.
2006; Allen 2007; Zhu et al. 2014).
Trempealeau reMunising Є pp group
ArcheanL. proterozoic + +
East Siberian Basin (Baykit Basin)
Sandstone Anhydrite Salt
Fig. 3 continued
3 Basic petroleum geological conditions of the giant oil and gas fields
3.1 Source rocks
The developed horizons of the major source rocks in the
PLP marine carbonate strata of the giant oil and gas fields
range from the Proterozoic Riphean to the Paleozoic,
varying by field (Table 2). The source rocks in the PLP
were mainly formed in the cratons and passive continental
margins. In the passive continental margins, the higher
bioproductivity provided by oceanic upwelling and
deepwater anoxic conditions was beneficial for forming
highquality source rocks; in the cratons, large-scale
transgression produced source rocks with a high abundance
of organic matter. The depositional environments of the
source rocks were mainly deep-water restricted conditions
inside shelves and slopes (Zhang et al. 2005). In the basins
with giant oil and gas fields, Riphean source rocks were
developed in the Siberian plate (East Siberian Basin), and
Sinian source rocks were mostly deposited in the Yangtze
plate and the eastern margin of the Arabian plate (Oman
Basin) (Liang et al. 2006; Liu et al. 2006; Tao et al. 2012;
Nicholas and Gold 2012; Zou et al. 2014a). Because of the
rise in sea level resulting from warmer climate and rapidly
melting glaciers as the glacial period turned into the
postglacial period, Cambrian, Ordovician, and Silurian
source rocks were deposited (Zhang et al. 2005). Cambrian
source rocks are situated in the Siberian plate (East
Siberian Basin), Tarim plate (Tarim Basin), Yangtze plate
(Sichuan Basin), and Arabian plate (Oman Basin) (Terken
et al. 2001; Wang et al. 2002; Cocks and Torsvik
2011, 2013; Zou et al. 2014a); Ordovician source rocks are
deposited in the passive continental margin of Laurentia
(Permian Basin, Indiana–Ohio platform) and the Chinese
continental plate (Tarim Basin, Ordos Basin) (Wang FY,
Zhang BM, Zhang SC. Anoxia versus bioproductivity
controls on the Cambrian and Ordovician marine source
rocks in Tarim Basin, China. AAPG Annual Meeting 2002;
Cocks and Torsvik 2011, 2013); and Silurian source rocks
were mainly deposited in Laurentia (Michigan Basin)
(Klemme and Ulmishek 1991; Zhou et al. 2014).
The source rocks are mainly composed of mudstone and
shale, followed by marl and argillaceous dolomite. The
source rocks are often thick, with a cumulative thickness
exceeding 100 m (up to 600 m). Organic matter types are
dominated by type I and II, which are high-quality organic
matter with high hydrocarbon generation potential.
Because there were no terrestrial higher plants on Earth
before the Devonian period, the composition of organic
matter in the marine sedimentary strata is very similar all
over the world, being mainly pelagic or benthic algae
(Bazhenova 2009; Chen et al. 2012, 2013). The abundance
of organic matter in the source rocks is highly variable and
is closely related to the lithology. For example, the
abundance of organic matter in shales is often higher than that
in carbonate rocks. There has been some disagreement
regarding the lower limit of the abundance of organic
matter in effective marine hydrocarbon source rock; some
studies have shown that the limit is lower in carbonate than
shale source rocks (Peters 1986; Jarvie 1991; Jin 2005;
Peng et al. 2008), while others have found it to be similar,
with the total organic carbon (TOC) being greater than or
equal to 0.5% (Liang et al. 2000; Zhang et al. 2002; Dai
et al. 2005a; Chen et al. 2012). The TOC in PLP marine
carbonate rocks of the giant oil and gas fields is greater
Shale, argillaceous limestone 150–450
Shale, lime mudstone 200–400
than 1% with a high abundance of organic matter. Marine
source rocks lacked higher plants in the PLP. Therefore, it
is difficult to determine the maturation of the source rocks
through vitrinite reflectance; usually, the Ro values are
estimated from bitumen reflectance (Jacob 1985; Xiao
1992; Shi et al. 2015). The thermal evolution extent of the
hydrocarbon source rocks is highly mature to over-mature
in the thirteen giant oil and gas fields, except for the Lima–
Indiana Trend, which has a relatively low thermal
evolution extent. The type of hydrocarbon is mainly natural gas,
which is mostly sourced from oil cracking (Terken and
Frewin 2000; Terken et al. 2001; Dakhnova et al. 2011; Jin
2012; Qiu et al. 2012; Zhou 2013).
The developed horizons of the reservoirs in the giant oil
and gas fields in the PLP marine carbonate strata are
located from the Proterozoic Riphean to Silurian strata and
vary by field (Table 3). The Riphean reservoir in the East
Siberian Basin and the Sinian reservoir in the Anyue gas
field in the Sichuan Basin are the oldest. The Ordovician is
the most important oil and gas bearing formation in the
PLP marine carbonate strata, followed by the Cambrian
and Silurian. The burial depth of the reservoir is highly
variable. If classified by average burial depth, the Tahe,
Anyue, Gomez, and Makarem 1 oil and gas fields are
ultradeep ([4500 m); the Jingbian, Tazhong 1, and Puckett are
deep (3500–4500 m); the Kuyumba and Yurubcheno–
Tokhomo are mid-deep (2000–3500 m); and the Verkhne–
Vilyuchanka, Talakan, Niagaran Reef Trend, and Lima–
Indiana Trend are shallow (\2000 m). The lithology of the
reservoirs is mainly dolomite, followed by limestone. The
original reservoir sedimentary environments are mostly
high-energy facies such as open platforms, platform
margins, tidal flats, and shallow shelves. Reservoir space is
mainly dissolved pores and cavities—intercrystalline pores
and fractures with high heterogeneity. The average matrix
porosity is generally less than 10% with a wide range of
permeability. Usually, in the fractured zone, permeability
increases exponentially (Pang et al. 2015). For example,
the reservoir matrix porosity in the Lima–Indiana Trend oil
and gas field is generally\3.5% with a permeability of less
than 0.1 9 10-3 lm2. However, in the reservoir near the
fault zone, the porosity could be up to 6% with a
permeability of up to 600 9 10-3 lm2. Because of the
development of dissolved pores and fractures, the real porosity
and permeability are higher than those measured in the
carbonate rock matrix. There is a somewhat negative
correlation between the porosity and the top burial depth of the
reservoir; that is, the greater the burial depth is, the lower
the porosity is (Fig. 4). This is the result of deep diagenesis
of the reservoirs, such as compaction, cementation, and
filling. The reservoir types are mainly karst and reef–shoal
facies (Table 3).
3.3 Cap rock
Cap rock is one of the key factors affecting hydrocarbon
accumulation. High-quality cap rock is crucial for the
preservation of giant oil and gas fields in the PLP marine
carbonate strata, because they are old and have experienced
multiple tectonic movements (Zhang et al. 2014a). The
lithology of cap rock in the giant oil and gas fields in the
PLP marine carbonate strata is mainly evaporite and shale,
followed by dense carbonate rock (Table 4). The thickness
and lithology are two factors affecting the sealing ability.
Although thicker cap rock more effectively prevents oil
and gas from leaking and escaping, cap rock thickness is
proportional to the spatial sealing area: the thicker the
sealing cover is, the greater the oil and gas preservation is
(Lv et al. 2005). The cap rock thickness of the giant oil and
gas fields in the PLP marine carbonate strata usually
exceeds 100 m (up to 600 m), and it has a positive
correlation with oil and gas reserves (Fig. 5). Furthermore, the
lithology of cap rock influences its sealing ability.
Evaporite cap rock is the most capable because of its
considerable plasticity (Jin 2012). Ten of the thirteen giant oil and
gas fields have developed direct evaporite cap rocks,
including the fields containing the first eight recoverable
reserves. In the Niagaran Reef Trend and Talakan fields,
the cap rocks are less thick but the reserves are large,
because their high-quality evaporite cap rocks played a key
role in hydrocarbon preservation (Table 4).
3.4 Hydrocarbon generation evolution
3.4.1 Hydrocarbon generation models
Through comparative analyses of the sedimentary and
burial histories of marine source rock in the PLP giant oil
and gas fields, hydrocarbon generation models may be
classified into four patterns: (1) early deep burial followed
by continuous subsidence; (2) shallow burial, followed by
uplift and then deep burial; (3) deep burial, followed by
uplift, and then shallow burial; and (4) deep burial
followed by continuous uplift (Zhang et al. 2007b; Zhu et al.
2010). The major source rock in the PLP giant oil and gas
fields has been deeply buried and has a high degree of
organic matter maturation.
The hydrocarbon generation model for the source rock
in the PLP giant oil and gas fields in the Tarim, Oman, and
Permian basins is (1): early deep burial followed by
continuous subsidence (Fig. 6a–c). The common feature is that
despite multiple tectonic uplifts, the burial depth of the
major source rock generally continued to increase; in the
d d d d d d d d d
Average porosity of reservoirs, %
Niagaran Reef Trend
early stages (Caledonian and Hercynian), these basins had
a higher subsidence rate, resulting in the source rock
entering the oil window earlier. Because of differences in
tectonic activities, the extent of hydrocarbon generation
evolution varies by basin. The Middle and Lower
Cambrian source rock in the Tarim Basin reached the peak of
the oil generation stage in the late Caledonian–early
Fig. 4 Correlation between reservoir porosity and top burial depth
for marine carbonate giant oil and gas fields in the Proterozoic–Lower
Paleozoic strata worldwide
Hercynian, the condensate oil and wet gas generation stage
in the late Hercynian, and the dry gas generation stage in
the Himalayan period. The Middle and Lower Ordovician
source rock was at low maturity in the late Caledonian and
early Hercynian periods and reached the peak of the oil
generation stage in the late Hercynian, and the condensate
oil and wet gas generation stage in the Yanshanian and
Himalayan periods. The Upper Ordovician source rock
matured in the late Hercynian and reached the peak of the
oil generation stage in the late Yanshanian and the
condensate oil stage in the Himalayan (Zhao et al. 2008; Jin
et al. 2012). The source rock in the Huqf Supergroup of the
Oman Basin was most deeply buried in the late Permian to
Tertiary periods, which was the main period of
hydrocarbon generation and expulsion (Terken et al. 2001). The
Ordovician Simpson shale in the central platform of the
Permian Basin sank deep enough to enter the oil window in
the late Permian. In the subsequent 210 Ma years, it was
consistently in an effective hydrocarbon generation and
expulsion period, reaching its peak in the Late Triassic and
ending in the middle Tertiary period (Fan 2005; Dutton
et al. 2005).
The hydrocarbon generation model for the source rock in
the PLP giant oil and gas fields in the Ordos Basin and
Sichuan Basin is (2): shallow burial, followed by uplift, and
then deep burial. The major source rock was buried in the
Caledonian period and began to generate oil, but
subsequently experienced uplift in the Hercynian period and
continued to settle in the late Hercynian, reaching its deepest
in the Yanshanian period, when it attained its peak
hydrocarbon generation and expulsion. During the Himalayan
stage, it was uplifted gradually (Fig. 6d, e). The Ordovician
6 Ro, % 0.5-0.7
100 150 200
Average thickness of caprocks, m
Fig. 5 Correlation between recoverable reserves and average cap rock thicknesses for marine carbonate giant oil and gas fields in the
Proterozoic–Lower Paleozoic strata worldwide
K Ter. Dekpmth, ЄO1Oy+1mmO2Op3 S D C1 C2 P1P2T1T+23 J1 J2J3 K1 K2 E
Niagaran Reef Trend
6 Ro, %1.0-1.3
TMimae, (b600) Om5a05n 4B3a8s4i0n8 (3C60en2t8r6a2l4O8 m21a3n1S44alt B65asin)
V Є O S D C P T J K E N Dekpmth, O S D M Penn. P T J
TMimae, 486 414 342 270 198 126 54
(d) Ordos Basin (Central Ordos)
TMimae, (f)80E0as7t0S0ibe6r0i0an B50a0sin40(0Tun3g0u0ska20D0ep1r0e0ssion)
carbonate source rock in the Ordos Basin began to generate
oil in the Middle Triassic, reached peak oil generation in the
Jurassic, and over-matured to generate gas in the Early
Cretaceous (Tang et al. 2000). The Lower Cambrian source
rock in the Sichuan Basin entered a mature stage during the
Caledonian movement and stopped generating hydrocarbon
as a result of the Caledonian uplifting. It reached its peak
hydrocarbon generation and expulsion stage in the Permian
to Triassic periods, and then this ended in the early
Cretaceous (Liu et al. 2009b; Sun et al. 2010).
The hydrocarbon generation depressions in the East
Siberian Basin follow model (3): They experienced
multiperiod tectonic movements of deep burial, followed by
uplift, and then shallow burial (Fig. 6f). The Riphean
source rock reached its maximal burial depth after the
sedimentary stages of the Riphean rift and
Vendian–Paleozoic stable platform. The whole basin was uplifted
because of strong Hercynian orogeny movements in the
late Paleozoic, while the marginal depressions were
shallowly buried in the Mesozoic and Cenozoic. The Riphean
source rocks in the Tunguska Depression began to mature
and generate oil in the Vendian, reaching their peak in the
Ordovician period. A large number of oil and gas reservoirs
were formed in the early Paleozoic, while gas was mainly
generated in the Early Triassic period. The main period of
hydrocarbon generation and expulsion of the Cambrian
source rocks was during the Devonian to Triassic periods
(Zhu et al. 2012).
The hydrocarbon generation model for source rocks in
the PLP giant oil and gas fields in the Michigan Basin and
Indiana–Ohio platform in North America follow model (4):
deep burial followed by continuous uplift (Fig. 6g). During
the Ordovician to Mississippian periods, the basin was at a
stable deposition stage and had not experienced much
tectonic movement. From the late Pennsylvanian period,
the basin began to uplift and was subjected to erosion until
the Holocene. The major carbonate source rocks in the
Salina A-1 group of the tidal flat facies of the Upper
Silurian experienced early continual settlement, and their
main hydrocarbon generation and expulsion period was
between the Devonian and Carboniferous periods (Cercone
1984; Charpentier RR. A summary of petroleum plays and
characteristics of the Michigan basin. USGS Open-File
Report 87-450R 1987).
In summary, since the major source rocks in the PLP
giant oil and gas fields experienced long periods of burial
and thermal evolution, they had early and long-lasting
hydrocarbon generation times. Except for the relatively
simple tectonic movements of pattern (4), the other three
models involved multiperiod tectonic movements, and thus
multiperiod hydrocarbon generation and expulsion are the
most favorable conditions for the formation of giant oil and
3.4.2 Origin of gas
According to the four hydrocarbon generation models,
there are some differences in the hydrocarbon-generating
processes of the major source rocks in the PLP giant oil and
gas fields. The first three models have the following
common features. First, the basins underwent multistage
tectonic movements, and the source rocks were buried for a
long duration with great burial depth and a high degree of
thermal evolution; the resulting oil and gas fields that
formed are dominated by hydrocarbon gas reservoirs (such
as Jingbian, Anyue, Puckett, Gomez and Makarem 1).
Second, the early-formed oil reservoirs are preserved in
some areas, and the oil and gas fields feature the
coexistence of oil and gas or are dominated by oil (such as the
giant oil and gas fields in the Tarim Basin and East Siberian
Basin). Although in the basins of model (4), the source
rocks were buried deeply in the early period with mature to
highly mature thermal evolution and massive hydrocarbon
generation, later continuous uplift ceased the hydrocarbon
generation much earlier. The present burial depth of the
source rocks is relatively shallow, and the oil and gas fields
formed are dominated by liquid oil (such as the Niagaran
Reef Trend and Lima–Indiana Trend oil and gas fields).
Gas is the most important resource in the PLP marine
strata (Wang and Han 2011; Wang et al. 2013a) and has
many types of hydrocarbon sources (Zhao et al. 2006; Liu
et al. 2012a). Three major types of hydrocarbon sources
exist: insoluble, soluble, and acid-soluble organic matter.
Some insoluble hydrocarbon sources are aggregated (such
as coal and oil shale) and others are dissipated (such as
different types of kerogens). The soluble hydrocarbon
sources include aggregated, dissipated, and transformed
soluble organic matter; aggregated soluble organic matter
is the oil reservoir formed in the early stage (paleo-oil
reservoirs), dissipated soluble organic matter refers to
chloroform asphalt ‘‘A’’ inside the source rocks and soluble
organic matter migrated outside them (such as bitumen in
migration paths or hydrocarbons without
reservoir-forming), and transformed soluble organic matter comprises
varieties of evolved or oxidized bitumen. Acid-soluble
organic matter indicates that the hydrocarbon source
existed as organic acid salts in the geological body (Liu et al.
The origins of gas in the PLP marine strata are
characterized by multiple hydrocarbon generation conversion
processes, and oil-cracking gas is one of the most important
types (Zhao and Zhang 2001; Zhao et al. 2006; Zhang and
Zhu 2006; Wang et al. 2009a; Zhang et al. 2014b; Zheng
et al. 2015). The Anyue gas field in the Sichuan Basin is a
typical case of oil-cracking gas. Its Sinian source rocks
began to generate oil in the middle to late Cambrian period,
stopped generating oil during the Caledonian uplift
movement, and generated oil once again from the Permian
to Triassic periods. Meanwhile, the liquid hydrocarbons
from source rocks were accumulated into the Gaoshiti–
Moxi paleo-uplift and formed paleo-reservoirs. Before the
Late Triassic, oil began to crack into gas in the
paleoreservoirs and oil and gas reservoirs were formed; oil
continually cracked into gas during the Late Triassic to
Cretaceous periods, and giant oil-cracking gas reservoirs
were formed. The hydrocarbon-generating process in
Cambrian source rocks was similar to that in Sinian source
rocks with later periods of hydrocarbon generation and oil
cracking (Wei et al. 2015a).
4 Reservoir types and distribution characteristics of the giant oil and gas fields
4.1 Reservoir types
The reservoir types of the giant oil and gas fields in the PLP
marine carbonate strata are complex and diverse. The most
highly developed are stratigraphic reservoirs and
structural–lithologic, structural–stratigraphic, and lithologic–
stratigraphic reservoirs, followed by structural reservoirs
and then lithologic reservoirs. In the thirteen giant oil and
gas fields, six have stratigraphic reservoirs; five have
structural–lithologic, structural–stratigraphic, or lithologic–
stratigraphic reservoirs; four have structural reservoirs, and
three have lithologic reservoirs (Table 5). Among the fields
with reserves of more than 1000 million barrels, the Tahe,
Talakan, and Yurubcheno–Tokhomo fields have mainly
stratigraphic reservoirs, while the Niagaran Reef Trend
field is reef lithologic, and the Anyue gas field is both
structural–lithologic (Cambrian Longwangmiao
Formation) and structural–stratigraphic (Sinian Dengying
Formation) (Fig. 7).
4.2 Characteristics of distribution
The distribution of the giant oil and gas fields in the PLP
ancient marine carbonate strata was greatly influenced by
regional paleo-uplift. The fields mainly developed in the
paleo-uplift area, slope area, and platform margin reef–
shoal bodies in the basins (Table 5). There are more oil and
gas fields in the slope area than in the higher part of the
uplift. This is mainly because the high part has been
strongly denuded and destroyed, resulting in the escape of
oil and gas accumulated in the early stage. For example,
the Tazhong 1 and Tahe fields are located in the slopes of
Tazhong and Tabei paleo-uplifts in the Tarim Basin (Jiang
et al. 2010), and the Jingbian gas field is situated in the
Yishan paleo slope in the Ordos Basin. Vertically, karst
reservoirs in the weathering crust of Ordovician carbonate
rocks are the main production layers. The Anyue field is
located in the north slope zone of the Weiyuan uplift and
gas accumulated under the control of the Gaoshiti–Moxi
paleo-uplift. The dolomite grain beach reservoir body was
mainly developed in the Cambrian period (Zou et al.
2014b; Wei et al. 2015b; Zhu et al. 2015; Li et al. 2015).
The Gomez and Puckett fields are located at the anticlinal
flanks of the Delaware and Val Verde basins. The
production layer is the weathered crystalline dolomite of the
Lower Ordovician Elenburger Group (Ijirigho and
Schreiber 1988). The Makarem 1 gas field is located in the
Type of the main oil/gas reservoirs
Stratigraphic unconformity gas reservoirs
Fault-anticline oil and gas reservoirs, reef-shoal
facies oil and gas reservoirs
Stratigraphic unconformity oil reservoirs
Structural-lithologic gas reservoirs
Stratigraphic-structural gas reservoirs
Stratigraphic, structural, lithologic oil and gas
Structural oil and gas reservoirs
Buried hill oil and gas reservoirs
Stratigraphic-structural (fault-anticline) gas
Stratigraphic-anticline gas reservoirs
Reef oil and gas reservoirs
Anticline oil and gas reservoirs, stratigraphic oil
and gas reservoirs
Anticline gas reservoirs
Yishan slope of Ordos Basin
TZ1 faulted slope-break zone in the northern slope of
Tazhong low uplift of Tarim Basin
Slope in the southern margin of Akekule rise of Tabei uplift
in Tarim Basin
North slope of Weiyuan uplift in Sichuan Basin
Predpatom basin in East Siberian Basin
The middle part of Baykit anticline of Kamal uplift in East
Nepa-Botuobin anticline in East Siberian Basin
The middle part of Baykit anticline of Kamal uplift in East
Flanks of anticlines in Delaware Basin in Permian Basin
Flanks of anticlines in Delaware Basin in Permian Basin
Marginal platform of Michigan Basin
Yutyakh Fm. dolomite
Fig. 7 Proterozoic–Lower Paleozoic marine giant oil and gas
reservoir types. (a) Makarem 1 gas reservoir; (b) Verkhne–Vilyuchanka oil
and gas reservoir; (c) Jingbian gas reservoir; (d) Yurubcheno–
Tokhomo oil and gas reservoir; (e) Niagaran Reef Trend oil and gas
reservoir; (f) Lima–Indiana Trend oil and gas reservoir; (g) Kuyumba
oil and gas reservoir; (h) Anyue gas reservoir; (i) Tahe oil and gas
Unconformity of Lateral Barrier
Black River Fm.
Makarem paleo-uplift zone in the Oman Basin. The
carbonate reservoirs are Ara subsalt and intersalt dolomite
belts, overlaid with thick evaporites of the Ara Group that
provide high-quality regional cap rocks (Alkindi and
Richard 2014). The Niagaran Reef Trend field is mainly
distributed on the slope of annular deposits between the
carbonate platform and the center of the Michigan Basin,
where oil and gas are accumulated in the middle Silurian
pinnacle reefs (Ritter 2008). The four fields in the East
Siberian Basin are mainly distributed on the
Nepa-Botuobin and Baykit paleo-uplifts and their slopes. The gas
and oil reserves in the Baykit uplift are mostly distributed
in the middle part of the secondary low uplifts, while those
in the Nepa-Botuobin uplift are mainly at the top or
southern slope. For example, the Yurubcheno–Tokhomo
field is located in the middle part of the Kamo uplift in the
Baikit Anticline. Within 100 m under the unconformity
surface is a high oil and gas production segment. At the
high position of the uplift, the dolomite experienced strong
structural movements and dissolution. Dissolved pores,
cavities, and fractures were well developed with
highquality reservoir properties for oil and gas accumulation.
Meanwhile, very thick evaporites were developed in the
lower part of the Lower Cambrian strata in the central and
southern regions, which acted as a high-quality regional
cap layer preventing the upward migration of lower fluids
and the dissipation of lower oil and gas (Kontorovich et al.
1981; Du et al. 2009).
5 Main factors controlling the formation and distribution of the giant oil and gas fields
Numerous studies have been conducted to define the factors
that control the oil and gas enrichment in marine carbonate
strata with respect to source rocks, reservoirs, cap rocks,
unconformities, faults, paleo-uplifts, and slopes (Jin
2010, 2014; Jin et al. 2012; Zhao et al. 2012b; Pang et al.
2013, 2014; Zhao et al. 2007; Zhang et al. 2007b; Yi et al.
2012; Liu et al. 2009b; Sun et al. 2010; Wei et al. 2015a, b;
Wang et al. 2013a; Zou et al. 2014b). Through the
comparison of the formation conditions and distribution
characteristics of the giant oil and gas fields in the PLP marine
carbonate strata, it is clear that the main factors controlling
the formation and distribution of the oil and gas fields are
large-scale efficient hydrocarbon kitchens, favorable
hydrocarbon accumulation zones, large-scale high-quality
reservoirs, and a large area of high-quality cap rock.
5.1 Large-scale efficient hydrocarbon kitchens
Large-scale efficient hydrocarbon kitchens offer the
essential material base for the formation of giant oil and
gas fields. Ancient marine strata are characterized by
multisource hydrocarbon generation. Based on their
forming processes, these can be classified as original
source rock, regenerative hydrocarbon source rock, and
chemical hydrocarbon source rock (Liu et al. 2012a; Zhao
et al. 2012b). The original source is sedimentary organic
matter, which is the conventional parent material of the
hydrocarbon generated from kerogen thermal degradation.
The regenerative hydrocarbon sources and chemical
hydrocarbon sources are derivatives of the original source.
Large-scale efficient hydrocarbon kitchens here mainly
refer to widely distributed original source rocks with a
highly effective hydrocarbon generation ability. They
meet the following three conditions. First, the
hydrocarbon source rocks have a large distribution area (for
example, effective source rocks in the Tarim, Sichuan,
Ordos, East Siberian, and Oman basins are over 10 9 104
km2 in size). Second, they have a great abundance of
organic matter, a high thermal evolution extent (Table 2),
and a long period of immense hydrocarbon generation and
expulsion. The average TOC of the hydrocarbon source
rocks of the thirteen giant oil and gas fields is greater than
1%. Except for the Lima–Indiana Trend, which is at a
mature phase, the thermal evolution extent in these fields
is highly mature to over-mature, and they have all
experienced the full course of oil- and gas-forming
processes. The regenerative hydrocarbon sources, paleo-oil
reservoirs, and soluble organic matter (such as asphalts)
inside and outside the source rock are important parent
materials for gas formation in the highly mature to
overmature stages. Third, they have a large effective
hydrocarbon supplying area. The giant fields are mostly located
near hydrocarbon kitchens. For example, the Tahe Oilfield
is situated on the Akekule uplift in the Tarim Basin, and
on three sides, it is surrounded by hydrocarbon source
rocks with a short migration distance to supply sufficient
oil and gas. The Jingbian gas field is located in the
eastcentral Yishan slope in the Ordos Basin, which is adjacent
to a hydrocarbon-generating depression. The vitrinite
reflectance (Ro) of the upper Paleozoic source rock is
greater than 1.5% and the hydrocarbon-generating
intensity is generally greater than 20 9 108 m3/km2 with a
sufficient supply of oil and gas (Yang et al. 2013). The
hydrocarbon reservoirs on the Nepa–Botuoba and Paikit
paleo-uplifts in the East Siberian Basin are flanked by
Riphean hydrocarbon kitchens in the Yenisey and
PrePatom Depressions (Fig. 8a). The two source kitchens
have had long-term thermal evolution and are in highly
mature to over-mature stages. The hydrocarbon of the
Makarem 1 field in the Oman Basin is mainly generated
from the high-quality source rocks of the Nafun
Formation of the Huqf Group in the two large salt basins around
the Makarem uplift (Fig. 8b).
Fig. 8 Distribution relationships between the ancient marine carbonate giant oil and gas fields and source rocks in a the East Siberian Basin and
b the Oman Basin (Zhu et al. 2012; Terken et al. 2001)
Boundary of basin
Riphean source rock
Natih source rock
5.2 Large-scale high-quality reservoirs
Large-scale high-quality reservoirs have developed in the
giant oil and gas fields in the PLP marine carbonate
strata, with a distribution area ranging from a few to tens
of thousands of square kilometers. They may be thick
monolayers or vertically stacked reservoir layers of
various types. The formation of high-quality reservoirs is
integrated and controlled by many factors, such as the
structure, deposition, diagenesis, and fluid (Tucker and
Wright 1990; Moore 2001; Lucia 2007; Ma et al. 2011;
Du et al. 2014; He et al. 2011b, 2016). Although the
characteristics and formation mechanisms of the
highquality reservoirs may be different (Table 3), they have
some similarities. First, the original sedimentary
environments are all high-energy facies, such as open
platform, shallow continental shelf, tidal flat, platform edge
reef, and shoal sedimentary facies of large area and heavy
thickness. Second, they experienced diagenetic epigenesis
evolution conducive to reservoir development; among
these, dolomitization and supergene karstification play an
0 40 80 120 160 km
Huqf source rock
Hahaban source rock
important role for the development of high-quality
reservoirs (Kupecz and Land 2009). Third, they
experienced multiperiod tectonic movements, where structure–
pressure coupling controlled the development of the
fractures in the reservoirs. These fractures not only
expanded the reservoir spaces but also improved the
reservoir permeability, providing spaces for the
interaction between the rocks and acid fluids: CO2, in the early
stage, and acid fluids such as H2S in the late stage (Gale
and Gomez 2007; Zhu et al. 2007; Xiang et al. 2010; Ma
et al. 2011; Husnitdinov 2014). The multiperiod tectonic
movements resulted in the uplift and erosion of strata,
forming large unconformities and providing conditions for
the formation of weathering crust karst reservoirs. For
example, the multiperiod tectonic movements in the PLP
marine strata in the Tarim, Sichuan, East Siberian, and
Permian basins produced large-scale karst reservoirs
(Postnikova et al. 2002; Dutton et al. 2005; Kang 2008;
Zhang et al. 2007b; Luo et al. 2008; Liu et al. 2010; Zhao
et al. 2012b; Wang et al. 2013b; Zhou 2013; Du et al.
2014; Yang et al. 2014).
5.3 Large area of high-quality cap rock
5.4 Favorable hydrocarbon accumulation zones
Large-area distribution of high-quality cap rock and
superior preservation conditions are key factors shaping the
distribution of the ancient marine carbonate giant oil and
gas fields. After comparing the basic geological
characteristics of the ancient marine carbonate giant oil and gas
fields worldwide, we found that these fields have developed
one or more sets of high-quality regional cap rock
(Table 4). High-quality cover, especially of gypsum-salt
cap rock, is key to the formation of large- and
mediumsized oil and gas fields (Jin et al. 2009; Jin 2014). For
example, the Yurubcheno–Tokhomo field in the East
Siberian Basin has Lower Cambrian thick gypsum-salt
regional cap rock, which is widely distributed across the
basin (Fig. 9). In the early and middle Cambrian, the East
Siberian Basin was in an evaporated lagoon environment in
a relatively closed sea, forming three sets of stably
distributed gypsum-salt rock. The accumulated thickness of
the regional gypsum-salt rock is 1000–1500 m with each
single layer being 10–20 m. These are interbedded with
carbonate rocks, and the accumulated thickness of the pure
salt layer is 300–400 m. This stably distributed
highquality regional cap rock provides superior preservation for
oil and gas in the southern uplifts and fault terrace zones in
the basin (Du et al. 2013).
Statistical analysis of the distributions of PLP marine
carbonate giant oil and gas fields (Table 5) shows that they are
mainly distributed in paleo-uplifts, slope zones, and
platform margin reef–shoal bodies in the basins. The slope
zones can be divided into depositional, structural, and
superimposed slopes. The platform margin reef–shoal body
is actually part of a platform margin slope zone, or a type
of depositional slope. Therefore, in general, paleo-uplifts
and slope zones are the most favorable hydrocarbon
accumulation zones in the PLP marine carbonate
The paleo-uplifts and the slope zones in the basins are
favorable directional zones for oil and gas migration (Zhou
2000; He et al. 2000; Jin et al. 2009; Jin 2010, 2012; Zhao
et al. 2012b; Wei et al. 2015a; Zou et al. 2015). In marine
carbonate basins, low- and high-energy facies are often
superimposed on paleo-uplifts and slope zones during the
deposition process of transgressive–regressive cycles. The
reef and shoal deposits in the high-energy facies can form
superior primary reservoirs, while shale and argillaceous
carbonate rocks in the low-energy facies can directly
develop into cap rocks, resulting in well-developed
reservoir–caprock assemblages (Dutton et al. 2005; Lin et al.
2009; He et al. 2008). In addition, the paleo-uplifts and the
Formation: vn-Vanavarskaya; bls-Belskaya; us-Usolskaya; bl-Bulay; an-Angara
Fig. 9 Cap rock in the Yurubcheno–Tokhomo hydrocarbon accumulation belt (He et al. 2008)
Plane of unconformity
slope zones in the basins are often the most weathered and
eroded areas during tectonic uplifts and are therefore
favorable areas for the development of weathering crust
karst reservoirs. When oil and gas are adequate and
regional cap rocks are of high quality, paleo-uplifts and
slope zones are favorable for oil and gas enrichment. For
example, the Akekule area in the North Uplift of the Tarim
Basin, where the Tahe Oilfield located, is a long-term
inherited paleo-uplift resulting from an intracratonic
deformation and always the target area of oil and gas
migrations. Especially, in the Himalayan period,
Ordovician source rocks in the slope and depression continually
generated hydrocarbons, and oil and gas migrated to the
Middle and Lower Ordovician paleo-karst reservoirs in
both sides of the paleo-uplift and both slopes (mainly along
the unconformities) to form giant oil and gas fields in the
gathering area (Xiang et al. 2010; Jin 2012) (Fig. 10).
6 Exploration and research prospects
6.1 Exploration prospects in China
Among the factors that controlled the formation and
distribution of the PLP giant oil and gas fields, the size and
hydrocarbon generation potential of the hydrocarbon
source rocks determines the quantity of hydrocarbon
generated in petroliferous basins; the sealing ability of regional
cap rocks after oil and gas accumulation and the ability to
maintain the sealing ability determine the amount of oil
and gas accumulation. Therefore, the effective
development of source rocks and cap rocks facilitates the
development of giant oil and gas fields, where hydrocarbon is
controlled by source and cap rocks. Paleo-uplifts and
slopes are favorable tectonic belt structures for the
largescale accumulation of oil and gas; specifically, these
structures control hydrocarbon accumulation. The
development of high-quality reservoirs determines the specific
sites for oil and gas reservoirs and also controls the
reservoirs. Therefore, by analyzing the controlling factors
at these three levels, it is possible to make a meaningful
prediction for favorable areas in PLP oil and gas
There are abundant oil and gas resources and broad
exploration prospects in the Tarim, Sichuan, and Ordos
basins, where the marine carbonate strata are well
developed. The prospective oil and gas resources of the Tarim
Basin are 229 9 108 t; the marine oil and gas resources in
the Sichuan Basin are 6.24 9 1012 m ; and the total
resources of oil and gas in the Ordos Basin are 195 9 108 t
oil equivalent, with the Lower Paleozoic natural gas
resource being 1.62 9 1012 m3 and the upper Paleozoic
natural gas resource being 9.5 9 1012 m3. Proterozoic–
Paleozoic oil and gas exploration prospects are mainly
focused in the Tarim Basin, the Sichuan Basin and its
adjacent areas, and the Ordos Basin. Cambrian–Ordovician
hydrocarbon source rocks have developed throughout the
Tarim Basin. The paleo-uplift and slope belt areas are gas
and oil enrichment zones. The Cambrian subsalt uplift and
slope are particularly favorable positions for exploring for
giant oil and gas fields. In the Sichuan Basin, natural gas
has accumulated in long-term developed paleo-uplifts and
their surrounding areas, forming a natural gas gathering
area from the Leshan to Longnu¨si paleo-uplift, and the
Luzhou to Kaijiang paleo-uplift. These paleo-uplifts and
slopes are conducive to natural gas accumulation and are
priority areas for large gas field exploration. The
paleouplifts in the Ordos Basin controlled Paleozoic sedimentary
facies and weathering crust zonation, where the Lower
Paleozoic natural gas distribution is correlated to the
positive ancient topography in the early Paleozoic uplifts and
their gentle slope zone. These sedimentary facies and
weathering crust zones are mostly enriched zones for
natural gas (Cai et al. 2008; Jin 2010, 2012).
6.2 Research prospects
6.2.1 Multiple source rock discrimination
In many old marine basins, multiple source rocks have
developed. These rocks are old, with a high thermal
evolution extent, and have experienced multiple hydrocarbon
generations and expulsions. Therefore, there are mixed
sources for oil and gas, making it difficult to identify the
source. Thus, the sources of oil and gas in some giant fields
are still controversial. For example, it is unclear whether
the Jingbian gas field of the Ordos Basin contains
oilformed gas from Ordovician shales and carbonate rocks or
coal-formed gas from the Carboniferous–Permian coal
measure strata (Chen 1994, 2002; Dai et al. 2005b; Huang
et al. 1996; Wang et al. 2009b; Chen et al. 2011; Liu et al.
2012b) and whether the Lower Paleozoic oil and gas in the
Tarim Basin are mainly from the Cambrian or Ordovician
strata (Liang et al. 2000; Li et al. 2010; Zhang et al. 2012;
Tian et al. 2012a, b). Because of the lack of widely
recognized key geochemical samples, the main hydrocarbon
source in the Tarim Basin will be debated for a long time,
which will affect accurate spatial and temporal localization
of the hydrocarbon source rock and hydrocarbon supply
zone (Jin 2014). Therefore, it is imperative to define the
multiple sources of Proterozoic–Paleozoic oil and gas for
further petroleum exploration.
6.2.2 Dynamic cap rock evolution
In cap rock research, most studies have concentrated on
lithologic characterization, static sealing performance and
mechanisms, or thickness and spatial distribution. Little
has been published on dynamic cap rock evolution.
Assessments of the sealing ability of the cover layer during
the buried stage mainly correlate the porosity with the
breakthrough pressure, only considering the effect of
compaction on porosity. To consider only the rupture of
rock caused by the change of formation, pressure in the
uplift stage does not enable an accurate assessment of the
sealing ability. For mechanistic studies on the microscopic
sealing of different lithology covers, previous work has
been conducted mostly on mudstone, with little attention to
gypsum and dense carbonate rocks. For practical
applications, more studies are required to investigate the
relationships between different cover layers (regional cap
rocks and direct cap rocks) and the distribution of oil and
gas (Jin 2014).
6.2.3 Identification of a tectonic hinge zone
Uplifts and slopes are favorable places for oil and gas
accumulation in old Proterozoic–Paleozoic layers. Over
geological history, sedimentary depressions, slopes, and
uplifts may have migrated or converted between depression
and uplift in a ‘‘seesaw’’ movement, where the fulcrums are
linearly distributed in the plane, forming a hinge zone for
tectonic activity. For the migration and the preservation of
oil and gas, or the formation and reformation of the
highquality carbonate reservoirs, the hinge structure is highly
favorable (Jin 2012). At present, the spatial distribution of
a hinge zone is estimated mainly through the calculation of
denudation quantity and reconstruction of the
paleo-structure, and qualitatively used to define its relationship with
oil and gas accumulation (Li et al. 2009; Wang et al. 2011;
2012; Jin 2012). In the future, more studies are required to
classify tectonic hinge zones and recognize and
characterize them quantitatively. This would require investigating
the formation, evolution, and spatial distribution of
different structural hinge belts. Furthermore, the control of
structural hinge belts on various reservoir-formation
factors, such as hydrocarbon sources, reservoirs, migration
systems, traps, migration, accumulation, and preservation
should be investigated against the backdrop of multistage
tectonic change and multistage oil and gas accumulation.
1. The major hydrocarbon source rocks in the PLP marine
carbonate giant oil and gas fields are mainly shales of
considerable thickness. The types of organic matter are
I–II, with such matter being highly abundant and most
of it highly mature to over-mature. The reservoirs are
mainly gas, and the reservoir rocks are dominated by
dolomite. Karst and reef–shoal reservoirs are the main
types with well-developed dissolved pores and
cavities, and intercrystalline pores and fractures. These
reservoirs are characterized by a high degree of
heterogeneity. The reservoir depth varies considerably
and is somewhat negatively correlated to the porosity.
The lithology of the cap rocks is mainly dominated by
evaporite and thick shale. The thickness is positively
correlated to the oil and gas reserves. The development
of high-quality evaporite cap rock is highly favorable
for oil and gas preservation.
The major source rocks have undergone a long period
of burial and thermal evolution and are characterized
by early and long periods of hydrocarbon generation.
They can be divided into four hydrocarbon generation
models: early deep burial followed by continuous
subsidence; shallow burial followed by uplifting and
then deep burial; deep burial followed by uplifting and
then shallow burial; and deep burial followed by
The oil and gas reservoir types are diverse. Most of
them are stratigraphic or structural–lithologic,
structural–stratigraphic, or lithographic–stratigraphic
complex reservoirs, mainly developed in the paleo-uplifts,
slope zones and platform margin reef–shoal bodies in
The main factors that control the formation and
distribution of the ancient marine carbonate giant oil
and gas fields are large-scale efficient hydrocarbon
kitchens, favorable hydrocarbon accumulation zones,
large-scale high-quality reservoirs, and large areas of
high-quality cap rocks.
Based on hydrocarbon control by source and cover,
accumulation control by paleo-uplifts and slopes, and
reservoir control by high-quality reservoir layers, it is
possible to predict favorable areas for PLP oil and gas
exploration. The Tarim, Sichuan, and Ordos basins
have well-developed marine carbonate strata and have
great potential for abundant oil and gas resources.
Acknowledgements This work was sponsored by the National Key
Basic Research Program of China (973 Program, 2012CB214806) and
the National Natural Science Foundation of China (No. 41372144).
We thank Liu Wenhui, Sun Dongsheng, Yin Jinyin, and Sun Naida
for their help and insightful suggestions for this research.
Open Access This article is distributed under the terms of the
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tivecommons.org/licenses/by/4.0/), which permits unrestricted use,
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appropriate credit to the original author(s) and the source, provide a
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