The concept and the accumulation characteristics of unconventional hydrocarbon resources
The concept and the accumulation characteristics of unconventional hydrocarbon resources
Yan Song 0 1 2
Zhuo Li 0 1 2
Lin Jiang 0 1 2
Feng Hong 0 1 2
0 Unconventional Natural Gas Institute, China University of Petroleum , Beijing 102249 , China
1 State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum , Beijing 102249 , China
2 Research Institute of Petroleum Exploration and Development, PetroChina , Beijing 100083 , China
Unconventional hydrocarbon resources, which are only marginally economically explored and developed by traditional methods and techniques, are different from conventional hydrocarbon resources in their accumulation mechanisms, occurrence states, distribution models, and exploration and development manners. The types of unconventional hydrocarbon are controlled by the evolution of the source rocks and the combinations of different types of unconventional reservoirs. The fundamental distinction between unconventional hydrocarbon resources and conventional hydrocarbon resources is their nonbuoyancy-driven migration. The development of the microto nano-scale pores results in rather high capillary resistance. The accumulation mechanisms of the unconventional and the conventional hydrocarbon resources are also greatly different. In conventional hydrocarbon resources, oil and gas entrapment is controlled by reservoir-forming factors and geological events, which is a dynamic balance process; while for unconventional hydrocarbon resources, the gas content is affected by the temperature and pressure fields, and their preservation is crucial. Unconventional and conventional hydrocarbons are distributed in an orderly manner in subsurface space, having three distribution models of intra-source rock, basin-centered, and source rock interlayer. These results will be of great significance to unconventional hydrocarbon exploration.
Unconventional hydrocarbon resources; Non- buoyancy-driven accumulation; Accumulation mechanisms; Distribution model
Unconventional hydrocarbon resources are becoming
increasingly significant in global energy structures. Global
petroleum exploration is currently undergoing a strategic
shift from conventional to unconventional hydrocarbon
resources. Unconventional hydrocarbon resources
(including tight oil/gas, shale oil/gas, and coal bed gas) are
becoming a significant component of world energy
consumption (Jia et al. 2012; Zou 2013). Unconventional
hydrocarbon resources are distinct from conventional
hydrocarbon resources. The characteristics of the
unconventional hydrocarbon resources are as follows: the source
and the reservoir coexist; the porosity and the permeability
are ultra-low; nano-scale pore throats are widely
distributed; there is no obvious trap boundary; buoyancy and
hydrodynamics have only a minor effect, Darcy’s law does
not apply; phase separation is poor; there is no uniform oil–
gas–water interface or pressure system; and oil or gas
saturation varies (Sun and Jia 2011; Yang et al. 2013).
Unconventional hydrocarbons in tight reservoirs show
characteristics distinct from those of the hydrocarbon
sources hosted in structural and stratigraphic traps.
Unconventional petroleum geology differs from traditional
petroleum geology in terms of trap conditions, reservoir
properties, combination of source and reservoir rocks,
accumulation features, percolation mechanisms, and
occurrence features, so different reservoir conditions and
accumulation mechanisms are essential for unconventional
hydrocarbon accumulation (Zou et al. 2012). According to
the relationship between source rock evolution and
reservoir formation, we clarify the relations of various
unconventional hydrocarbon resources, propose the identification
marks and distribution models for unconventional
hydrocarbon resources, and compare the differences between
unconventional and conventional hydrocarbon in terms of
types, characteristics, distribution models, and
accumulation mechanisms, which provide important guidance for
unconventional hydrocarbon exploration (Zou et al. 2015).
2 Concept of unconventional hydrocarbon resources
2.1 Generation of unconventional hydrocarbon
Unconventional and conventional hydrocarbon resources
are both generated during thermal evolution of source
rocks. Conventional hydrocarbon is generally defined and
classified by generation, migration, trap, and preservation,
while the unconventional hydrocarbon is defined by
kerogen type, evolution of source rocks, and reservoir types
(Song et al. 2013). Hydrocarbon generation and expulsion
from type I-II and type III kerogen during thermal
maturation are different (Tissot and Welte 1978; Huang et al.
1984; Zhang and Zhang 1981; Martini et al. 2003), and the
relationship between reservoir characteristics and
hydrocarbon generation and expulsion determines the type of
unconventional hydrocarbon reservoirs (Song et al. 2013).
For type I–II kerogen, oil is generated from and detected in
source rocks at a relatively low maturity stage, and oil
shale is formed. During mature stage, source rocks
generate and expel a large amount of oil and gas, which
accumulates in tight reservoirs close to source rocks to form
tight oil, and remains inside source rocks to form shale oil.
During the over-mature stage, source rocks mainly
generate gas, which accumulates in tight reservoirs adjacent to
source rocks to form tight gas, meanwhile a large amount
of remaining gas inside source rocks is identified as shale
gas (Fig. 1).
Natural gas is generated from type III kerogen during
thermal evolution (Dai et al. 1992) and is stored inside the
source rocks and adjacent tight reservoirs to form shale gas
and tight gas, respectively. Coal bed methane (CBM) is
formed in coal beds during thermal maturation of coals
As shown in Fig. 3, different types of unconventional
hydrocarbons are oil and gas generated during source rock
evolution and accumulated in different unconventional
2.2 Identification marks of unconventional
Non-buoyancy-driven accumulation means that
hydrocarbon accumulation is driven by forces excluding buoyancy.
Unconventional hydrocarbon resources have the
characteristics of coexisting source rocks and reservoirs, no
obvious trap boundaries, weak fluid phase differentiation,
no uniform water–oil interface, independent pressure
system, and oil or gas saturation varying significantly (Zou
et al. 2011; Ju et al. 2015). There is a fundamentally
important geological distinction between conventional and
unconventional hydrocarbon. Conventional gas resources
are buoyancy-driven deposits, occurring as discrete
accumulations in structural and/or stratigraphic traps, whereas
unconventional gas resources are generally
non-buoyancydriven accumulations. Non-buoyancy-driven accumulation
means that buoyancy has a weak effect on hydrocarbon
migration and cannot overcome resistance.
2.2.1 Key reason of non-buoyancy-driven accumulation
Capillary pressure is the principle resistance for
hydrocarbon migration, which is controlled by the radius of
porethroats of reservoirs. The narrower the pore-throats, the
higher the capillary pressure. Thus, the key reason of
nonbuoyancy-driven accumulation of unconventional
hydrocarbon can be attributed to small pore-throats of reservoirs.
By advanced experimental test methods, it has been proved
that the widely developed micro–nano-pore-throats lead to
large resistance due to high capillary pressure (Loucks and
Ruppel 2007). The statistical analysis of global tight
reservoirs’ pore-throat diameters shows that the shale
reservoirs have the minimum pore-throat diameters, while
the tight sandstones have relatively larger pore-throat
diameters (Nelson 2009; Zou et al. 2011; Passey et al.
2011). The average pore-throat diameter of the shale gas
reservoirs is 5–200 nm (Jarvie et al. 2007), that of the shale
oil reservoirs is 30–400 nm (Montgomery et al. 2005), that
of the tight gas reservoirs is 40–700 nm, that of the tight
sandstone oil reservoirs is 50–900 nm, and that of the tight
carbonate oil reservoirs is 40–500 nm (Jia et al. 2012; Du
et al. 2014). The development of micro–nano-pores leads
to high capillary pressure in the pore structure of reservoirs.
If the diameter of pores is 10–50 nm, then the calculated
capillary pressure of those pores could be 12–24 MPa
(Zhang et al. 2014), indicating that at least under such
strength of driving force (buoyancy or abnormal pressure),
hydrocarbon could be capable of migrating.
Hydrocarbon generation model
of type I-II kerogen
Oil generation curve
Gas generation curve
Fig. 1 Relationship between type I–II kerogen maturation and hydrocarbon types
Hydrocarbon generation model of type III kerogen
Fig. 2 Relationship between type III kerogen maturation and
Within conventional petroleum systems, buoyancy is
considered to be the driving force, and capillary pressure is the
resistance for hydrocarbon migration and accumulation
(Davis 1987). According to the equation of buoyancy and
capillary pressure (Schowalter 1979), when the radius of
pore-throats decreases by 10 %, the capillary pressure
would increase tenfold. If buoyancy is still considered to be
the driving force, then hydrocarbon migration would
2.2.2 Mechanisms of non-buoyancy-driven accumulation
Fig. 3 Unconventional hydrocarbon types under source rock
maturation and reservoir type control
happen only when buoyancy correspondingly increases
tenfold. Taking one gas column with a height of 3 m and
density of 0.2 g/cm3 for an example, the buoyancy can be
0.024 MPa, but gas cannot enter the pore-throats with a
radius of 2 lm. The pore-throat diameter of tight
sandstones is mostly less than 1 lm, the capillary pressure is at
least more than 0.08 MPa. However, migration of gas with
a density of 0.2 g/cm3 needs a buoyancy of 0.07 MPa, and
the height of the gas column required would be over 10 m.
Based on the research of outcrops, thickness
measurements, and profile interpretation, the fluvial sandbodies
with a vertical thickness over 10 m are scarce (Shanley
2004). Therefore, no favorable geological conditions for
gas columns can form enough buoyancy, and buoyancy
could not be the dominant driving force for unconventional
oil and gas accumulation.
3 Characteristics of unconventional hydrocarbon accumulation
The differences between unconventional and conventional
hydrocarbons in occurrence and accumulation processes
determine the differences in accumulation mechanisms. In
order to better understand the characteristics of
unconventional hydrocarbon accumulation, unconventional gas
reservoirs characterized by adsorbed gas are taken as
examples to compare with conventional gas reservoirs.
3.1 The unconventional gas content is affected by temperature and pressure fields while the conventional gas content is controlled by dynamic balance
Conventional gas accumulation can be divided into two
processes: natural gas generated and expelled from source
rocks migrates and accumulates in reservoirs, and then it is
continuously lost by diffusion and seepage. Conventional
gas accumulation is the consequence of the balance of gas
charge and loss, namely the dynamic balance. Thus, the
intensity and time of gas charge and sealing conditions are
the key factors to natural gas accumulation.
The unconventional gas with the most common
occurrence of adsorbed gas is associated with adsorption
capacity which is controlled primarily by temperature and
pressure. The higher the pressure and the lower the
temperature are, the higher the adsorption capacity (Wang and
Reed 2009; Liu et al. 2013; Guo et al. 2014). However,
under actual geological conditions, the adsorbed gas
content in unconventional reservoirs is controlled by the
combination of the temperature and pressure changes.
Figure 4 illustrates the relationship between adsorption
capacity and depth of two different rank coal samples with
Ro of 1.0 % and 3.5 %. At depth shallower than
approximate 1000 m, the adsorption capacity is principally
Ro 1.0% curve
Ro 3.5% curve
Fig. 4 Relation of gas content with depth in the no. 3 coal bed in the
Qinshui Basin, China
controlled by pressure, and the gas content tends to
increase with the burial depth increasing; whereas at depths
deeper than 1000 m, the adsorption capacity is mainly
controlled by temperature, and the gas content tends to
decrease with the burial depth increasing.
The diffusion of the unconventional hydrocarbon can be
attributed to temperature–pressure fields. Temperature and
pressure changes lead to the conversion of adsorbed gas to
free gas, and free gas diffuses through caprocks or
formation water. Therefore, unlike the conventional gas only
needing top caprocks, the preservation of CBM needs not
only top caprocks, but also bottom caprocks. Coal beds
should be in an enclosed system in order to store a large
amount of gas (Fig. 5a). First, an enclosed system can be
overpressure to elevate the adsorption capacity of coal
beds. Second, free gas can be preserved well from diffusion
and hydrodynamic destruction. However, in most cases, an
enclosed system can be destroyed by permeable layers at
the bottom of coal beds (Fig. 5b) or on top of the coal beds
(Fig. 5c), leading to gas loss through diffusion and
formation water washing.
3.2 Unconventional gas accumulation is controlled by preservation, while the conventional hydrocarbon accumulation is controlled by the best match of petroleum systems
Conventional gas accumulation generally experiences
processes of gas generation, migration, concentration, and
preservation. The best match of static factors such as
source rocks, reservoirs, and caprocks and the dynamic
factors such as natural gas generation, migration,
entrapment, and accumulation controls the hydrocarbon
Unconventional gas accumulation generally undergoes
three distinct stages: (a) gas generation and adsorption,
(b) increasing adsorption and desorption, and (c) diffusion
(a) Best preservation with top
and bottom caprock
(b) Bad preservation with
only top caprock
Fig. 5 Relationship between CBM preservation and caprocks
and preservation (Fig. 6). It has been confirmed that most
shale gas and coal bed methane reservoirs discovered in
China have experienced intense uplift. During the basin
evolution, the pressure and temperature increase with time.
There were two phases of gas generation and adsorption in
most basins with gas generated and stored primarily as an
adsorbed phase in the coal seams.
CBM loss is primarily due to tectonic uplift and
pressure–temperature changes, which result in desorption of
gas. There are three diffusion paths for reservoir gas. First,
free gas diffuses by overcoming capillary pressure of
sealing rocks (Song et al. 2007). Second, dissolved gas in
water diffuses because of a concentration difference. Third,
gas is flushed directly by flowing water (Qin et al. 2005).
Thus, tectonic evolution, hydrodynamics, and sealing
conditions are three major controlling factors for CBM
accumulation and enrichment (Song et al. 2012).
CBM reservoir accumulation depends on the
preservation conditions resulting from tectonic uplift. The higher
the coal seam is uplifted, the poorer the preservation
conditions will be. During tectonic uplifting when gas
generation ceased, if the coal seam was uplifted to a depth still
below the present weathering zone, CBM would be
preserved through enhanced adsorption capacity (Song et al.
Geological age, Ma
Fig. 6 Accumulation mechanisms of CBM entrapment
(c) Bad preservation with
only bottom caprock
2005). The CBM abundance is then dependent on the
thickness of the overlying strata. The thicker the overlying
strata are, the higher the CBM abundance will be (Fig. 6).
The formation of unconventional gas reservoirs is
controlled by the key time of structural evolution, which is
different from the charge time of the conventional gas.
3.3 Synclinal accumulation of unconventional gas is controlled by water potential and pressure and conventional gas is distributed in structural highs under control of gas potential
Conventional gas is featured by accumulation in structural
highs under control of gas potential. Regionally,
unconventional gas is characterized by synclinal accumulation
mainly controlled by water potential and pressure field. A
low potential area enclosed by high potential layers is
located in reservoirs. The low potential area with high
porosity and permeability is a favorable area for
hydrocarbon accumulation and preservation, indicating that the
oil and gas potential controls the accumulation of
conventional hydrocarbon. Low potential is generally located
at structural highs and is the migration direction, so the
conventional hydrocarbon mainly accumulates in the
Synclinal accumulation of the unconventional
hydrocarbon is a combined result of favorable tectonic evolution,
hydrodynamic, and sealing conditions. The synclinal CBM
pooling model from the Qinshui Basin in China is
illustrated in Fig. 7. For a regional syncline, the surface water
may permeate through outcrops near the elevated margins
of the syncline and flow downwards to the axis direction
due to gravity, forming water seals on both limbs of the
syncline by downward water flow, and thus resulting in
excellent preservation conditions for CBM. In addition, the
central axial area with thick and stable caprocks above is
deeply buried and structurally stable and less susceptible to
fracturing, which is favorable for preservation of
Fig. 7 Structure and gas contents of coal seams in the Jincheng area, Qinshui Basin
overpressure. CBM accumulation is dually controlled by
flow potential and pressure potential in the reservoir
system. Therefore, the central axial area of a syncline is the
most favorable place for CBM accumulation and
preservation, usually with the highest abundance and saturation.
4 Distribution characteristics of unconventional hydrocarbon
4.1 Coexistence of unconventional and conventional
Unconventional hydrocarbon can be generated in different
maturation stages of source rocks (reservoirs), and the
genetic types of unconventional hydrocarbon are controlled
by the evolution process of source rocks and the
characteristics of reservoirs. Therefore, different unconventional
hydrocarbons can be distributed in an orderly manner with
conventional hydrocarbon reservoirs (Zou et al. 2014).
Down slope into the basin center, sandstone reservoirs may
change to mudstone reservoirs. Vertically, as the burial
depth increases, the source rocks become mature or
overmature, and generate oil and gas. Meanwhile, the reservoirs
also become tight during complex diagenesis processes.
Thus, in self-source systems, unconventional hydrocarbon
(shale gas, tight gas, shale oil, tight oil and oil shale) and
conventional hydrocarbon are always spatially distributed
from the deep formations to the shallow formations,
characterized by spatial integration and continuity (Fig. 8).
An introduction to an unconventional hydrocarbon
accumulation mechanism is provided by comparing its
characteristics of pore diameter and the relationship with
source rocks (Table 1). Conventional hydrocarbon
Fig. 8 Coexistence of conventional and unconventional hydrocarbons
accumulation usually refers to an individual hydrocarbon
accumulation in a single trap with a uniform pressure
system and oil–water contact. In conventional hydrocarbon
accumulations, hydrocarbon migration is attributed to
effects of gravitational segregation and buoyancy, and fluid
flow follows Darcy’s law. Conventional hydrocarbon is
entrapped individually or sealed in a low potential zone or
in a structural trap under impermeable rocks. Tight oil and
gas accumulates close to source rocks under control of a
pressure difference between source rocks and reservoirs,
experiencing primary migration or short-distance
secondary migration with the occurrence of free gas (Li et al.
2015; Sun et al. 2014). Shale gas refers to unexpelled gas in
shale generated in the mature stage, occurring as adsorbed
gas and free gas, and shale gas often changes between the
adsorbed state and free state during accumulation, i.e., as
the temperature–pressure conditions change, after the
fulfillment of self adsorption of shale, free shale gas occurs
Table 1 Accumulation mechanisms of different unconventional hydrocarbons
Conventional oil and gas
Tight oil and gas
Shale oil and gas
d [ 2 lm 2 lm [ d [ 0.03 lm
Long distance migration through preferential Driven by pressure difference,
pathways, secondary migration short-distance migration
Distant from source rocks Near source rocks
and migrates inside shales (Curtis 2002; Bowker 2007;
Ross and Bustin 2009). CBM is mainly adsorbed gas also
characterized by accumulating in the source, and the
generated gas is directly adsorbed by coal on the surfaces of
4.2 Distribution models of unconventional
Three models of unconventional hydrocarbon distribution
can be determined in petroliferous basins, namely the
intrasource rock model, the basin-centered gas model, and the
source rock interlayer model.
4.2.1 The intra-source rock model
Oil shale, shale oil, shale gas, and CBM are accumulated in
mudstones, shales, and coal beds, characterized by
‘‘selfsource and self-reservoir’’ (Fig. 9). Shale gas generated at
mature and overmature stages exists in three forms: (1) free
gas in pores and fractures, (2) adsorbed gas in organic
matter and on inorganic minerals, and (3) dissolved gas in
oil and water (Curtis 2002; Martini et al. 2003; Bowker
2007; Kinley et al. 2008). A strong positive correlation
between total organic carbon (TOC) and total gas content
shows that the total organic matter content is primarily
responsible for shale gas yield. CBM generated during
different maturation processes is primary adsorbed in coal
Fig. 9 The intra-source rock distribution model of coal bed methane
Fig. 10 Distribution model of the tight sandstone gas in the Triassic
Xujiahe Formation in Sichuan
beds. The methane adsorption content linearly increases
with the increase of TOC and micropore surface area
(micropore size \ 2 nm), indicating microporosity
associated with the organic fraction has a primary control on
CBM accumulation. Mudstones with relatively higher
capillary pressure on the top and bottom of coal seams are
not only advantageous to provide favorable sealing
conditions for the free CBM in coal beds, but also favorable
for overpressure and adsorbed CBM preservation.
4.2.2 The source rock interlayer model
Oil and gas is expelled from source rocks, migrates within
short-distances into the coexisting tight sandstone and
carbonate interlayers of the source rocks, and forms tight
oil and tight gas, such as the interlayer tight sandstone gas
in the Triassic Xujiahe Formation in the west Sichuan
foreland basin (Li et al. 2010; Zou et al. 2013) (Fig. 10).
The formation of the Xujiahe gas reservoirs is primarily
attributed to the pressure gradient from source rocks to
interlayer tight sandstone reservoirs. After short-distance
migration from source rocks to reservoirs, oil and gas
mainly charges the sheet-like interlayer tight sandstone
reservoirs, and the source rock interlayer distribution
model develops in a large area.
Gas reservoirs Source rocks Mountain belt
4.2.3 The basin-centered gas model
The basin-centered distribution model of tight sandstone
gas reservoirs is characterized by regionally pervasive
accumulation, abnormal pressure (high or low), an inverse
or ill-defined gas–water contact and low-permeability
reservoirs. For instance, the Elmworth gas field in the
Alberta Basin and the Mesa Verde tight sandstone gas field
in the Piceance Basin, overpressure is the primary driving
force for hydrocarbon migration from source rocks
upwards into tight sandstone reservoirs. Basin-centered
tight sandstone gas reservoirs always have low porosity and
low permeability, so buoyancy is not the driving force for
gas accumulation. Unlike conventional gas accumulation,
basin-centered gas reservoirs always show a characteristic
of gas–water inversion. Tight sandstone gas reservoirs are
widely distributed regionally, covering several thousand
square kilometers, and consist of single or isolated
reservoirs a few meters thick or vertically stacked reservoirs
several thousand meters thick, controlled by structural
traps, stratigraphic traps and lithological traps (Fig. 11).
Tight sandstone gas reservoirs are gas-saturated with little
or no producible water, do not have an obvious trap
boundary or intact caprocks, and are downdip from
waterbearing reservoirs, widely distributed in deep depressions,
central synclines and downdip of structural slopes.
(a) Red Desert Basin
The types of unconventional hydrocarbon resources
include oil shale, tight oil/gas, shale oil/gas, and
CBM. These are controlled by the evolution of
source rocks and the combinations of different
The fundamental differences of unconventional
hydrocarbon from conventional hydrocarbon
resources are tight reservoir properties,
non-buoyancy-driven migration, and no obvious trap
boundary. The essential reasons for non-buoyancy-driven
accumulation are widespread micro- and nano-scale
pores, the resistance of high capillary pressure in
tight reservoirs and lack of formation conditions
providing strong buoyancy.
The differences in occurrence and accumulation
processes between unconventional and conventional
hydrocarbon result from the great differences in
accumulation mechanisms. For unconventional
hydrocarbon, subsurface temperature–pressure fields
control the gas content, preservation conditions
affect the critical time for hydrocarbon
accumulation, and water potential and pressure result in
accumulation in synclines. For the conventional
hydrocarbon resources, dynamic balance processes
(b) Green River Basin
(c) Alberta Basin
(d) Ordos Basin
Fig. 11 Basin-centered gas model of unconventional hydrocarbon
control the hydrocarbon accumulation, the best
match of reservoir-forming factors and geological
events controls the entrapment time, and gas
potential controls the accumulation in structural highs.
Unconventional and conventional hydrocarbons
coexist and are distributed in an orderly manner in
sedimentary basins. The unconventional
hydrocarbon has three distribution models, namely the
intrasource rock model, the basin-centered gas model,
and the source rock interlayer model.
Acknowledgments This research was supported by Major Projects
of Oil and Gas of China (No. 2011ZX05018-002). We thank Profs.
Zou Caineng, Jiang Zhenxue, and anonymous reviewers for their
critical and constructive comments. We also thank Ji Wenming and
Xiong Fengyang for improving the English of the manuscript.
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