Diagenesis and reservoir quality of the Lower Cretaceous Quantou Formation tight sandstones in the southern Songliao Basin, China

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Sedimentary Geology 330 (2015) 90–107
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Diagenesis and reservoir quality of the Lower Cretaceous Quantou
Formation tight sandstones in the southern Songliao Basin, China
Kelai Xi a,b,⁎, Yingchang Cao a,⁎⁎, Jens Jahren b, Rukai Zhu c, Knut Bjørlykke b, Beyene Girma Haile b,
Lijing Zheng d, Helge Hellevang b
a School of Geosciences, China University of Petroleum, Qingdao, Shandong 266580, China
b Department of Geosciences, University of Oslo, P.O. Box 1047, Blindern 0316, Oslo, Norway
c Research Institute of Petroleum Exploration & Development, Beijing 100083, China
d College of Energy, China University of Geosciences, Beijing 100083, China
⁎ Corresponding author at: School of Geosciences, C
Qingdao, Shandong 266580, China.
⁎⁎ Corresponding author.
E-mail addresses: kelai06016202@163.com, xi.kelai@g
cyc8391680@163.com (Y. Cao).
http://dx.doi.org/10.1016/j.sedgeo.2015.10.007
0037-0738/© 2015 Elsevier B.V. All rights reserved.
a b s t r a c t
a r t i c l e i n f o
Article history:
Received 16 August 2015
Received in revised form 20 October 2015
Accepted 23 October 2015
Available online 30 October 2015
Editor: Dr. B. Jones
Keywords:
Tight sandstone diagenesis
Reservoir quality
Quartz cement
Carbonate cements
Oil emplacement
Songliao Basin
The Lower Cretaceous Quantou Formation in the southern Songliao Basin is the typical tight oil sandstone in
China. For effective exploration, appraisal and production from such a tight oil sandstone, the diagenesis and
reservoir quality must be thoroughly studied first. The tight oil sandstone has been examined by a variety of
methods, including core and thin section observation, XRD, SEM, CL, fluorescence, electron probing analysis,
fluid inclusion and isotope testing and quantitative determination of reservoir properties. The sandstones are
mostly lithic arkoses and feldspathic litharenites with fine to medium grain size and moderate to good sorting.
The sandstones are dominated by feldspar, quartz, and volcanic rock fragments showing various stages of disin-
tegration. The reservoir properties are quite poor, with low porosity (average 8.54%) and permeability (average
0.493 mD), small pore-throat radius (average 0.206 μm) and high displacement pressure (mostly higher than
1 MPa). The tight sandstone reservoirs have undergone significant diagenetic alterations such as compaction,
feldspar dissolution, quartz cementation, carbonate cementation (mainly ferrocalcite and ankerite) and claymin-
eral alteration. As to the onset time, the oil emplacementwas prior to the carbonate cementation but posterior to
the quartz cementation and feldspar dissolution. The smectite to illite reaction and pressure solution at stylolites
provide a most important silica sources for quartz cementation. Carbonate cements increase towards interbed-
ded mudstones. Mechanical compaction has played a more important role than cementation in destroying the
reservoir quality of the K1q4 sandstone reservoirs. Mixed-layer illite/smectite and illite reduced the porosity
and permeability significantly, while chlorite preserved the porosity and permeability since it tends to be oil
wet so that later carbonate cementation can be inhibited to some extent. It is likely that the oil emplacement oc-
curred later than the tight rock formation (with the porosity close to 10%). However, thicker sandstone bodies
(more than 2 m) constitute potential hydrocarbon reservoirs.
© 2015 Elsevier B.V. All rights reserved.
1. Introduction
As one of themost important unconventional hydrocarbon resources,
tight sandstone oil is widely distributed inmajor petroliferous basins, po-
tentially forming large-scale petroleum reserves in China (Zou et al.,
2013; Zou et al., 2014; Wang et al., 2015). Tight sandstone is defined as
reservoirs with a porosity less than 10%, in situ formation permeability
less than 0.1 mD or air permeability less than 1 mD in Chinese basins
(Zou et al., 2012). Reservoir quality is considered as the primary factor
in tight sandstone oil exploration (Fic and Pedersen, 2013; Storker et al.,
hina University of Petroleum,
eo.uio.no (K. Xi),
2013; Zou et al., 2013). In general, tight sandstone reservoirs are deeply
buried and have gone through complicated diagenetic alterations, pro-
gressively changing the reservoir quality (Vinchon et al., 1996; Karim
et al., 2010; Yang et al., 2012; Zhang et al., 2015). Therefore, it is important
to have a detailed understanding of the diagenesis (Rahman andMcCann,
2012). However, there are still uncertainties related to quantification of
mineral dissolution and precipitation processes that have significant ef-
fects on reservoir quality (Schmid et al., 2004; Gier et al., 2008; Taylor
et al., 2010; Bjørlykke, 2014). Diagenetic evolution (time and tempera-
ture), cement sources andmass transfer (open vs closed system) in sedi-
ments as well as their impacts on reservoir quality are still debated
(Schmid et al., 2004; Taylor et al., 2010; Bjørlykke and Jahren, 2012;
Yuan et al., 2015). In addition, the role of hydrocarbon emplacement on
mineral reactions is also still debated (Cao et al., 2012; Liu et al., 2014).
The Lower CretaceousQuantou Formation tight sandstone is a prolific
oil-producing unit in the southern Songliao Basin (Li et al., 2013).
91K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
Although there are many publications dealing with stratigraphy, sedi-
mentology and hydrocarbon accumulation in the southern Songliao
Basin, little attention has beenpaid to sandstone diagenesis and reservoir
quality evaluation (Li et al., 2007; Zhang et al., 2007; Hu et al., 2008;
Xiong et al., 2008; Feng et al., 2013; Dong et al., 2014). Authigenic quartz,
carbonate cements, dissolved feldspars and clay minerals are commonly
observed in the reservoirs determining the reservoir quality (Li et al.,
2013; this study). Former studies on diagenesis in this area only focused
on quartz cement and its origin, but did not investigate in detail any
other diagenesis reactions linked to reservoir quality (Xi et al., 2015). Fur-
thermore, the origin of the carbonate cements and timing of diagenesis,
especially the diagenetic history and the processes controlling reservoir
quality, have not been studied thoroughly. Understanding quantitative
diagenetic processes (including oil emplacement) and cement sources
in sandstones and their impact on reservoir quality are essential to further
exploration, appraisal and production of tight sandstone oil within this
area.
The objectives of this paper were mainly focused on the different
aspects of diagenesis compared to the former studies focusing only on
quartz cementation and its origin: (1) perform a detailed diagenetic
analysis and identify the sources of the carbonate cements in these
tight sandstones; (2) reconstruct the diagenetic history of the tight
sandstones and evaluate if oil emplacement affected the inorganic dia-
genesis; and (3) assess the effects of the different diagenetic processes
in time and space on the reservoir quality.
Fig. 1. (A) Locationmap of the study area and sub-tectonic units of the Songliao Basin (I)Weste
Uplift Zone, (V) Southeastern Uplift Zone, (VI) Southwestern Uplift Zone, (VII) Kailu Depression
2. Geological background
The Songliao Basin is a Jurassic–Neogene lacustrine basin with a
dual-structure fault-depression in northeastern China (Fig. 1). The
basin is located between 42°25′ to 49°23′ N and 119°40′ to 128°24′ E
with an area about 26× 104 km2 (Zhang and Zhang, 2013). It can be fur-
ther subdivided into seven first class tectonic zones (Zhou et al., 2012),
namely the Western Slope Zone, Northern Pitching Zone, Central
Depression Zone, Northeastern Uplift Zone, Southeastern Uplift Zone,
Southwestern Uplift Zone and Kailu Depression Zone (Xi et al., 2015)
(Fig. 1). The study area, as one of the most oil-rich areas, belongs to
the Central Depression Zone and consists of threesecondary class tec-
tonic units (Li et al., 2013), namely the Changling Sag, Huazijing Terrace
and Fuxin Uplift (Fig. 1).
Based on the filling sequence and structures, the basin evolution can
be divided into four phases: (1) a pre-rift phase, (2) a syn-rift phase,
(3) a post-rift phase, and (4) a compression phase (W. Zhang et al.,
2009). Sediments filling the basin comprise the Lower Cretaceous
Huoshiling (K1h), Shahezi (K1sh), Yingcheng (K1yc), Doulouku (K1d)
and Quantou (K1q) Formations, the Upper Cretaceous Qingshankou
(K2qn), Yaojia (K2y), Nenjiang (K2n), Sifangtai (K2s) and Mingshui
(K2m) Formations, the Paleogene Yian (Ny) Formation, the Neogene
Daan (Nd) and Kangtai (Nt) Formations, and the Quaternary Pingyuan
(Q) Formation (Xi et al., 2015) (Fig. 2). Each formation can be further
subdivided into differentmembers (Fig. 2). The Cretaceous stratigraphy
rn Slope Zone, (II) Northern Pitching Zone, (III) Central Depression Zone, (IV) Northeastern
Zone; (B) the sub-tectonic units of the study area andwell locations (from Xi et al., 2015).
Fig. 2. Generalized Mesozoic–Quaternary stratigraphy of the Songliao Basin, showing major oil and gas combinations (from Xi et al., 2015).
92 K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
contains many source rocks and reservoir rocks, which can form differ-
ent oil and gas accumulations vertically (Xi et al., 2015) (Fig. 2).
Previous studies indicated that the Songliao Basin has had a high
geothermal gradient throughout most of its history. From about
90.7 Ma to 65 Ma, the geothermal gradient has been estimated at 4.5–
5.5 °C/100 m, decreasing to about 4.0 °C/100 m after 65 Ma (Liu,
2004). During the whole burial process the Quantou formation has
been in a chemically closed system (Xi et al., 2015). Presently, the
sedimentary sequence is not at its maximum depth and temperature.
The temperature of Quantou Formation has never been more than
about 130 °C.
The studied section (Fig. 2), that is the fourth member of Quantou
Formation (K1q4), was deposited during the depression period of the
tectonic evolution, andmainly consists of delta sandstones and some in-
terbedded mudstones (Xi et al., 2015). According to oil analysis and
source rock correlation, thefirst member of the Qingshankou Formation
(K2qn1), which just overlies K1q4, is the main source rock of K1q4 reser-
voirs (Zou et al., 2005; Li et al., 2013). The oil generation (Ro= 0.5%) in
the K2qn1 began at a depth of about 1350–1450m and at a temperature
of 80–85 °C (Dong et al., 2014). TheK1q4 sandstone reservoir is tight and
strongly heterogeneous. All wells contain oil, but with low production
rates (Li et al., 2013). Reservoir quality is considered as themost impor-
tant control on hydrocarbon volumes in this area (Li et al., 2013).
3. Databases and methods
The studywas focused on the fourthmember of the Quantou Forma-
tion in the southern Songliao Basin where most of the producing oil
fields are located. Consequently, most of the drilling for oil has taken
place in this area producing core material, geophysical well logs and
many other exploration and production well data made available for
93K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
this research. The data used in this paper was derived from more than
40 wells (Fig. 1).
Rock composition data of 743 thin section samples, 8529 reservoir
porosity and permeability data points, 622 grading analysis data, 275
mercury injection capillary pressure testing data and well logging data
for all the related wells, were obtained from the Research Institute of
Petroleum Exploration & Development of the Jilin Oilfield Company,
PetroChina.
According to the study objectives and constraints of the collected
data, both sandstone and interbeddedmudstone samples were selected
from the K1q4 drill cores of 26 wells. More than 300 polished thin sec-
tions and about 210 blue or red epoxy resin-impregnated thin sections
were prepared for the analysis of rockmineralogy, diagenesis and visual
pore characteristics. Thin sections were partly stained with Alizarin Red
S andK-ferricyanide for carbonatemineral identification. Point counting
was performed on 30 thin sections to check the correctness of the col-
lected rock composition data, which provided a standard deviation of
5%or less. For the content of quartz cement, carbonate cements, primary
pores and the feldspar dissolution pores, 20micrographs each of 76 blue
or red epoxy resin-impregnated thin sectionswere takenusing the Zeiss
Axioscope A1 APOL digital transmission microscope. Then cements
and pores in each micrograph were identified under the microscope
and sketched on computer using CorelDRAW software, and the total
area of cements and pores in every micrograph was obtained using
Image-Pro Plus software. Finally, the percentages of the cements and
pores were calculated by taking the average of all values in the 20 mi-
crographs from each thin section. A total of 105 reservoir sandstone
samples and 40 interbedded mudstone samples were analyzed for
whole-rock (bulk) and clay fraction (b2 μm) mineralogy using XRD.
Preparation, analysis and interpretation procedures were modified
from Moore and Reynolds (1997) and Hillier (2003).
Thirty-one representative sampleswere viewed under a Quanta FEG
450 scanning electron microscope (SEM) equipped with an energy dis-
persive X-ray spectrometer (EDX). Cathode luminescence (CL) analyses
of 16 typical samples were made using an Olympus microscope
equippedwith a CL8200-MKS CL instrument. Thirty-seven core samples
from 12 wells were prepared as thick doubly polished thin sections for
fluorescent color observation, fluid inclusion petrographic analyses
and microthermometric measurements. The microthermometry of
fluid inclusions was studied using a petrographic microscope equipped
with a Linkam THMSG 600 heating and cooling stage which enables
temperatures of phase transitions in the range of ﹣180 to 500 °C. Preci-
sion was ±1 °C for the homogenization temperature (Th) and ±0.1 °C
for the final ice melting temperature, respectively.
Based on the petrological studies, 87 organic matter-free sandstone
samples and 30 interbeddedmudstone samples were chosen for carbon
and oxygen stable isotope analyses. These samples were analyzed using
a Thermo-FinniganMAT 253 isotope ratio mass spectrometer. Precision
was±0.08‰ for O and±0.06‰ for C. Carbon and oxygen stable isotope
data are presented in the δ notation relative to the Vienna PeeDee
Belemnite (V-PDB) standards.
Among all the analyses mentioned above, point counting, fluores-
cence observation and fluid inclusion analysis were done in the Basin
Analyses and Reservoir Geology Key Laboratory of the China University
of Petroleum. XRD, SEM, and CL were performed in the Key Laboratory
of Oil and Gas Reservoirs of PetroChina. Carbon and oxygen stable iso-
tope testing was done in the Analytical Laboratory of the CNNC Beijing
Research Institute of Uranium Geology.
4. Results
4.1. Reservoir lithologies
Petrographic investigation of the K1q4 tight sandstones shows that
the detrital components comprise 32.1–62.4% quartz (average
42.86%), 10.3–42.8% feldspars (average 26%) and 12.4–47.6% rock
fragments (average 31.14%), indicating that the sandstones are mostly
lithic arkoses and feldspathic litharenites (Fig. 3A). The majority of the
detrital quartz grains are monocrystalline. Detrital feldspars in these
sandstones are mostly plagioclase and altered K-feldspar. The rock frag-
ments contain 10.0–47.0% volcanic rocks with an average of 28.32%,
1.0–25.0% sedimentary rocks with an average of 1.26%, and 1.0–17%
metamorphic rocks with an average of 1.76%. Most of the sandstones
in main reservoir intervals generally do not contain much detrital
matrix.
According to grading analysis, the sandstones are fine to medium-
grained (Fig. 3B). Sorting ranges from moderately well to well sorted
(Fig. 3C), and the roundness of the detrital grains varies from sub-
rounded to rounded. Grain contacts are dominated by pointed to
tangentialcontacts, as well as concavo–convex contacts. Microscopic
stylolites can be found also between detrital grains in the sandstones.
4.2. Reservoir properties
4.2.1. Porosity and permeability
As a whole, the reservoir properties in the K1q4 sandstones are quite
poor (Fig. 4). Helium porosity of core samples ranges from 1.7% to 20%
(mainly 2.0% to 14.0%) with an average of 8.54% (Fig. 4A). Horizontal
permeability ranges from 0.01 mD to 44.5 mD (mainly less than
1mD)with an average of 0.493mD (Fig. 4B). Porosity and permeability
of the K1q4 tight sandstones decrease with an increase in burial depth
(Fig. 5). However, helium porosity and horizontal permeability show a
poor correlation relationship (R2 = 0.4789).
4.2.2. Pore types and pore-throat characteristics
Thin section and SEM observation revealed the presence of three
types of pores in the K1q4 tight sandstone reservoirs. Primary intergran-
ular pores, triangular or polygonal in shape, are affected by compaction
generally (Fig. 5). Secondary pores are mainly associated with feldspar
dissolution, which can enlarge the intergranular pores or form new
intragranular pores (Fig. 5). The development of micro-pores is chiefly
associated with diagenetic clay minerals. Among them, primary inter-
granular pores have better connectivity than secondary pores and
micro-pores.
The ratio of the visual pores in thin sections varies as the burial depth
increases. In general, the relative content of the primary pore decreases
from an average of about 80% to 50% with increasing burial depth
(Fig. 5), while the relative content of secondary pores increases from
an average of about 20% to 50% (Fig. 5). This is because compaction
and cementation destroy primary intergranular porosity during burial.
The pore-throat types for the tight sandstones mainly include
contracted throats, flake-like, curved, and thin pipe-like throats. Mercu-
ry injection capillary pressure analyses show that the displacement
pressure and the pressure corresponding to a 50% Hg-saturation of the
reservoirs have a positive correlation with permeability (Fig. 4C).
Tight sandstone reservoirs always have displacement pressures higher
than 1 MPa and the pressures correspond to a 50% Hg-saturation
approximate 10 MPa, while the conventional sandstone reservoirs are
lower than 0.1 MPa and approximate 1 MPa, respectively (Fig. 4C).
The average pore-throat radius ranges from 0.018 μm to 1.776 μm
(mainly 0.1 μm to 0.35 μm) with an average of 0.206 μm (Fig. 4D).
4.3. Diagenetic mineralogy
The K1q4 tight sandstones have undergone significant diagenetic
modification, including compaction, feldspar dissolution, quartz and
carbonate cementation, clay mineral alteration and some other minor
cementation types.
4.3.1. Quartz cement
Authigenic quartz, occurring in two different types of morphologies,
is generally one of the most common cements in the studied reservoir
Fig. 3. Rock composition, lithology and sorting distribution of the K1q4 tight sandstone reservoirs: A, Classification of sandstone using Folk's (1974) classification; B, Lithology distribution;
and C, Sorting distribution.
94 K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
rocks. The first type is partial to complete syntaxial overgrowths, which
are easy to discriminate from the detrital grains due to the existence of
some dust rims (Fig. 6A). The other quartz cement type is pore-filling
cement. This type is difficult to distinguish from detrital quartz grains
by the polarizing microscope (Fig. 6B). The CL images, however, clearly
display the boundaries between detrital quartz grains and authigenic
quartz, where the detrital grain is brightly luminescent and the
authigenic quartz is dark non-luminescent (Fig. 6C). The quartz cement
in the tight sandstone reservoirsmainly occurs as relatively large aggre-
gates of microcrystalline or macrocrystalline, euhedral authigenic
quartz approximately 30–100 μm in size (Fig. 6A–D). In addition,
authigenic quartz is always found together with clay minerals, such as
kaolinite, mixed-layer illite/smectite, illite and chlorite (Fig. 6D–F).
Fig. 4.Characteristics of the K1q4 sandstone reservoir properties: A, Porosity distribution; B, Perm
Quartz cement can be observed in most of the studied samples. The
authigenic quartz often occludes primary pores, significantly reducing
the porosity and bridging narrowpore-throats (Fig. 6A–D). Quantitative
statistical data revealed that quartz cement ranges from 1.55% to 8.38%
with an average of 5.62% (Fig. 7). The quartz cement shows a slightly
increasing trend with increasing burial depth (Fig. 7).
4.3.2. Feldspar dissolution
Detrital K-feldspar grains have encountered partial to complete dis-
solution (Fig. 8A). The shallowest K1q4 sandstones (about 600–700 m)
commonly contain secondary pores, indicating that some feldspar
dissolution may occur at a relatively early burial stage. The content of
feldspar dissolution in the studied reservoir ranges from 0.46% to
eability distribution; C, Typical capillary pressure curve;D, Pore-throat radius distribution.
Fig. 5. Pore types and their vertical distribution characteristics. FD—feldspar dissolution.
95K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
4.72% with an average of 2.85% and shows no significant trend with
increasing burial depth below 1000m (Fig. 7). Generally, feldspar disso-
lution is texturally associated with kaolinite and what is now a small
amount of microcrystalline authigenic quartz at shallow burial depth
(Fig. 8B), and filamentous and flaky illite at deeper burial depth. In addi-
tion, some primary pores and secondary pores formed fromK-feldspars
dissolution are partly to completely filled by authigenic albite (Fig. 8C),
indicating albitization of K-feldspar.
4.3.3. Carbonate cements
As another volumetrically predominant cement type, carbonate
cements mainly include ferrocalcite (Fig. 8D) and ankerite (Fig. 8E).
They occur as scattered euhedral rhombs and pore-filling blocky or
Fig. 6. Quartz cement characteristics in K1q4 tight sandstone reservoirs: A, Micrograph of thin
authigenic quartz; C, Idem with B but CL micrograph showing the detrital quartz (brightly lu
Ordered mixed-layer illite/smectite and authigenic quartz; E, Kaolinite, ordered mixed-layer ill
quartz; QD—detrital quartz grains; I/S—mixed-layer illite/smectite; I—illite; K—kaolinite; Ch—c
mosaic aggregates. The CL micrographs of carbonate cements show a
homogeneous reddish orange luminescence color (Fig. 6F). In thin sec-
tions, ferrocalcite and ankerite are mainly pore-filling cements around
the euhedral quartz overgrowth or partly replace the authigenic quartz
(Fig. 8G–I). Sometimes they precipitated in feldspar dissolution pores as
well (Fig. 8I), suggesting the conclusion that ferrocalcite and ankerite
formed during late diagenesis.
Core analyses suggest that carbonate cements are not distributed
uniformly in the K1q4 tight sandstone reservoirs. The content of carbon-
ate cement ranges from 1.97% to 12.93% with an average of 5.72% and
shows an insignificant trend with an increase in burial depth (Fig. 7).
Although carbonate cements can occur anywherewithin the reservoir in-
tervals, they develop more intensely along the sandstone and mudstone
section showing quartz overgrowth; B, Micrograph of thin section showing pore-filling
minescent) and quartz cement (darkly non-luminescent) and microscopic stylolites; D,
ite/smectite and authigenic quartz; F, Illite, chlorite and authigenic quartz. QA—authigenic
hlorite; Ms—microscopic stylolites.
Fig. 7. The vertical distribution characteristics of quartz cement, carbonate cement, feldspar dissolution and intergranular volume.
Fig. 8. The characteristics of feldspar dissolution and carbonate cementation: A, Micrograph of thin section showing the feldspar partly and completely dissolved; B, Micrograph of SEM
showing feldspar dissolution, authigenic kaolinite and quartz cement; C, Micrograph of SEM showing feldspar dissolution and authigenic albite; D, Micrograph ofthin section showing
the ferrocalcite cementation; E, Micrograph of thin section showing the ankerite cementation; F, CL micrograph of carbonate cements; G, Micrograph of thin section showing ferrocalcite
cements around the euhedral quartz overgrowth and partly replacing the authigenic quartz; H, Micrograph of thin section showing carbonate cement replacing quartz overgrowth; I,
Micrograph of thin section showing ferrocalcite filling feldspar dissolution pores. QD—detrital quartz; QA—authigenic quartz; FD—feldspar dissolution; K—kaolinite; AL—albite;
Fc—ferrocalcite; An—ankerite.
96 K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
97K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
contact surface (Fig. 9). For example, the samples at depths of 2192.2 m,
2218 m in Well Qian 223 and 1853.7 m in Well Rang 24, which are very
close to the sandstone and mudstone contact surface, have much more
carbonate cements than the samples at depths of 2212.35 m in Well
Qian 223 and 1846.09m and 1872.2m inWell Rang 24, which are in cen-
tral part of the sandstone body (Fig. 9). That is a commonphenomenon in
otherwells in the study area aswell. As a result, the reservoirs close to the
sandstone and mudstone contact surface always have a poorer quality
with lower porosity and permeability (Fig. 9).
The carbon and oxygen isotope datamay help to decipher the timing
and sources of materials for carbonate cementation (Irwin et al., 1977;
Armitage et al., 2010). XRD analysis data and rock thin sections indicate
that the carbonate cements in the studied samples are mainly pure
ferrocalcite and ankerite, even though very few samples contain
mixed carbonate cements (Table 1). The δ13C value (V-PDB) ranges
from −12.2‰ to −0.9‰ with an average of −8.11‰, and the δ18O
value (V-PDB) ranges from −22.9‰ to −18.2‰ with an average of
−20.66‰ (Table 1).
According to the thin section and fluorescence observation, aqueous
inclusions (two phases) are commonly present in authigenic quartz (Xi
et al., 2015), but extremely rare in the carbonate cements (only 5 inclu-
sions found).Microthermometry studies show that the homogenization
temperature of the aqueous inclusions ranges from 98 °C to 108 °Cwith
an average of 101 °C in carbonate cements (Table 2).
4.3.4. Minor cements
Pyrite and feldspar overgrowths are two kinds of minor cements
observed in K1q4 tight sandstone reservoirs. Pyrite framboids fill inter-
granular pores (Fig. 10A) or occurs over the carbonate cements, which
probably formed during two stages, namely early and late. Feldspar
overgrowth occurs as rare, small discrete or coalesced adularia-like
crystals around detrital feldspar. The overgrowths are corroded by
ankerite and ferrocalcite (Fig. 10B), and thus may predate carbonate
cementation. However, these two cements occur in less than 1% of the
sandstones, and have negligible effects on reservoir quality.
Fig. 9. Stratigraphy and reservoir quality of Well Qian 223 and Well Rang 24. It shows that th
surface.
4.3.5. Clay minerals
Various types of clay minerals with different amounts and textural
habits occur in the K1q4 tight sandstone reservoirs, as revealed by XRD
and SEM, including kaolinite, mixed-layer illite/smectite, illite and
chlorite. Minor amounts of kaolinite occur mainly as booklets of
vermicularly stacked pseudohexagonal crystals. Kaolinite is always ac-
companied by minor amounts of microcrystalline authigenic quartz
(Fig. 10C). Mixed-layer illite/smectite occurs as honeycomb-textured,
approximately 70%–95% illite with an R = 1 or R = 3 Reichweite
order (Fig. 10D). Fibrous and flaky illite is mainly presents in primary
pores and sometimes on grain surfaces and in feldspar dissolution
pores, locally bridging pore-throats (Fig. 10E). Needle and rosette
shaped chlorite found in primary pores (Fig. 10F) and on grain surfaces
is also an important clay mineral in the studied tight sandstone
reservoirs.
Mixed-layer illite/smectite is the dominating clay mineral in K1q4
tight sandstone reservoirs, and all the clay minerals show trends with
increasing burial depth (Fig. 11). Small amounts of kaolinite mainly
exist at depths shallower than about 1800 m, and reduce rapidly
below that depth, particularly, deeper than about 2000 m (Fig. 11),
where temperatures approach to 120 °C. On the contrary, the percent-
age of illite in the mixed-layer illite/smectite increases quickly deeper
than about 1800 m and 2000 m (Fig. 11). The content of chlorite and
mixed-layer illite/smectite shows an increasing trend between 1800
m–2150 m and 2150 m–2450 m, respectively (Fig. 11). Mixed-layer il-
lite/smectite contains less than 85% illite with R = 1 Reichweite order
above about 1800 m, and increases to more than 85% illite with R = 3
Reichweite order below 1800 m (Fig. 11).
4.4. Oil presence characteristics
Based on the thin section evidence and fluorescence observations,
oil is present in most of the samples in the K1q4 tight sandstones
(Fig. 12). The fluorescence colors of oil and hydrocarbon inclusions are
all primarily blue and white (Fig. 12), indicating a relatively mature
e carbonate cements develop more intensely along the sandstone and mudstone contact
Table 1
Mineralogical and isotopic composition of carbonate cements, and calculated formation temperature of cements in the K1q4 sandstone reservoirs. An—ankerite; Fc—ferrocalcite.
Well Depth, m Carbonate
minerals
δ13CPDB,
‰
δ18OPDB,
‰
Z
value
Temperature, °C
δ18OSMOW = ﹣7‰
Well Depth, m Carbonate
minerals
δ13CPDB,
‰
δ18OPDB,
‰
Z
value
Temperature, °C
δ18OSMOW = ﹣7‰
C10 2280.75 100% An −3.6 −20.6 109.67 120.73 R24 1869.3 100% Fc −9 −18.2 109.67 83.79
C10 2284.49 100% An −3.7 −20.7 109.41 121.75 R24 1872.2 100% Fc −9.9 −21.1 109.41 110.75
C10 2302 100% An −4.7 −20.6 107.42 120.73 R24 1872.4 100% Fc −6.3 −19.5 107.42 95.13
C10 2311.15 100% An −6 −20.9 104.60 123.83 R24 1872.7 100% Fc −9.7 −22.7 104.60 128.56
C10 2312.26 100% An −5.6 −20.6 105.57 120.73 R24 1874.02 100% Fc −10.2 −21.4 105.57 113.90
C10 2312.37 100% An −5.9 −20.9 104.81 123.83 R24 1875.12 100% Fc −6.5 −18.2 104.81 83.78
C10 2316.04 100% An −5.1 −18.2 107.79 98.35 R24 1875.63 100% Fc −9.4 −18.4 107.79 85.46
C19 2282.45 100% Fc −11.9 −20.2 92.87 101.72 R24 1878.35 100% Fc −11.4 −22.1 92.87 121.59
C19 2284.35 60% Fc + 40% An −9.4 −21.6 97.29 116.05 R59 2040.13 100% Fc −3.3 −21.8 97.29 118.24
C19 2285.15 100% Fc −8.2 −21.5 99.80 114.97 R59 2044.74 100% Fc −3.7 −19 99.80 90.64
C21 2107.4 100% Fc −5.8 −19.5 105.71 95.13 R59 2047.47 100% Fc −2.9 −18.3 112.25 84.61
C21 2127.3 100% Fc −9.1 −20.5 98.45 104.66 R59 2054.49 100% Fc −6.2 −21.6 103.85 116.05
C21 2132.1 100% Fc −9.2 −20.7 98.15 106.66 R59 2099.93 100% Fc −10.5 −21.4 95.14 113.90
C21 2144 100% An −5.8 −20.4 105.26 118.71 R59 2100.62 100% Fc −10.7 −19.9 95.48 98.86
C21 2145.8 100% An −1.1 −20.2 114.99 116.72 R59 2101.19 100% Fc −11.6 −22.2 92.49 122.73
C21 2149.25 100% An −9 −20.5 98.66 119.71 R59 2101.76 100% Fc −11 −21.6 94.02 116.05
G27 1195.64 100% Fc −2.2 −20.5 112.59 104.66 R59 2103.11 100% Fc −11 −21.9 93.87 119.35
G27 1204.6 100% Fc −0.9 −19.4 115.80 94.22 R59 2107.27 100% Fc −10.2 −21.6 95.65 116.05
G27 1208.42 100% Fc −1.3 −19.9 114.73 98.56 R59 2107.37 100% Fc −11.5 −21.9 92.84 119.35
G27 1226.4 100% Fc −2.6 −20 112.02 99.80 R59 2108.2 100% Fc −10.4 −20.8 95.64 107.67
G27 1232.16 100% Fc −1.3 −20 114.68 99.80 R59 2109.23 100% Fc −10 −20.6 96.56 105.65
G27 1233.62 100% Fc −1.2 −19.9 114.93 98.56 R59 2110 100% Fc −10.1 −20.9 96.21 108.68
G31 1503.45 100% Fc −5.1 −19.4 107.19 94.22 R59 2111.14 100% Fc −10.1 −21.8 95.76 118.24
G31 1506.4 100% Fc −7.2 −18.7 103.24 88.01 R59 2111.87 100% Fc −9.4 −21 97.59 109.71
G31 1515.5 90% Fc + 10% An −7.8 −20.2 101.27 102.65 R59 2112.52 100% Fc −11.1 −22.3 93.46 123.87
G31 1518.1 100% Fc −7.4 −18.4 102.98 85.46 R59 2112.69 100% Fc −10.6 −21.9 94.69 119.35
G31 1519 100% Fc −6.1 −18.6 105.54 87.16 R59 2116.41 100% Fc −9.3 −18.4 99.09 85.46
G31 1520.2 85% Fc + 15% An −6.6 −19.4 104.12 95.33 R59 2117.84 100% Fc −10.7 −20.6 95.13 105.65
G31 1521.99100% Fc −6.4 −18.6 104.93 87.16 R59 2120.69 100% Fc −9.2 −19.2 98.90 92.42
G31 1524.19 100% Fc −9 −21.7 98.06 117.14 R59 2121.2 100% Fc −10 −20.2 96.76 101.72
H160 2523.08 100% Fc −4.2 −20.9 108.29 108.68 R59 2124.05 100% Fc −9.1 −18.2 99.60 83.78
H160 2525.25 100% Fc −4.4 −21.3 107.68 112.84 R59 2125.85 100% Fc −10 −20.6 96.56 105.65
H160 2526.1 100% Fc −4.5 −21.9 107.18 119.34 R59 2127.36 100% Fc −8.4 −18.7 100.78 88.02
H160 2526.4 100% Fc −4.8 −22.2 106.41 122.73 R59 2128.59 100% Fc −10.9 −21.9 94.07 119.35
H160 2533.9 100% Fc −10.6 −22.3 94.49 123.87 R59 2130.02 100% Fc −9.7 −21.8 96.58 118.24
R24 1846.09 100% Fc −11.1 −22.7 93.26 128.56 X125 1340 100% Fc −9.2 −20.5 98.25 104.66
R24 1847.3 100% Fc −9.3 −21.7 97.45 117.14 X125 1343 100% Fc −10.9 −21.5 94.27 114.97
R24 1853.7 100% Fc −10.3 −22.2 95.15 122.73 X125 1343.6 100% Fc −11 −20.9 94.36 108.68
R24 1854 100% Fc −10.5 −21.9 94.89 119.35 X125 1345.32 100% Fc −10.6 −21.3 94.98 112.84
R24 1854.35 100% Fc −10.4 −22.2 94.95 122.73 X125 1346.4 100% Fc −11.4 −20.3 93.84 102.69
R24 1860.8 100% Fc −10.1 −20.2 96.56 101.72 X125 1357.5 100% Fc −11.3 −20.8 93.80 107.67
R24 1861.3 100% Fc −11.3 −21.8 93.30 118.24 X125 1363.57 100% Fc −11.4 −20.7 93.64 106.66
R24 1862.7 100% Fc −11.9 −22.9 91.52 130.96 X125 1369 100% Fc −12.2 −21 91.86 109.71
R24 1863.5 100% Fc −10.7 −22.1 94.38 121.59
Note: The formula used in calculating calcite mineral temperature is 1000lnαcalcite-water = 2.78 × 106/T2-2.89 (Friedman and O'Neil, 1977); the formula used in calculating dolomite
mineral temperature is 1000lnαdolomite-water = 3.06 × 106/T2-3.24 (Matthews and Katz, 1977), and 1000lnαcarbonate-water = δ18Ocarbonate–δ18O water.
98 K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
and light oil (L. Zhang et al., 2009; Dong et al., 2014). The oil can be
observed in the studied reservoirs in the following locations: (1) in
the primary intergranular pores (Fig. 12A); (2) in the intergranular
pores of the quartz cement (Fig. 12B); (3) in the narrow gaps left
by carbonate cementation (Fig. 12C, D); (4) in the cleavage of feld-
spar (Fig. 12E); (5) in the secondary pores of feldspar dissolution
(Fig. 12F, G); (6) in the micropores of authigenic clay minerals
(Fig. 12H); (7) in the hydrocarbon inclusions along the fractures
(Fig. 12I). However, there are few oil traces that can be observed be-
tween quartz grains and overgrowths (Fig. 12B), and few hydrocar-
bon inclusions are captured by quartz cements. These phenomena
indicate that oil emplacement mainly started to occur after the initial
Table 2
Microthermometric data of the aqueous fluid inclusions in K1q4 sandstone reservoirs.
Well Depth, m Host mineral Size, μm types
Rang54 1938.1 Carbonate cement 3 × 10 Aqueous
Rang54 1938.1 Carbonate cement 3 × 7 Aqueous
Rang54 1938.1 Carbonate cement 2 × 5 Aqueous
Rang54 1938.1 Carbonate cement 5 × 6 Aqueous
Rang54 1938.1 Carbonate cement 2 × 7 Aqueous
Th—homogenization temperature; Tm—final ice melting temperature.
formation time of authigenic quartz, reducing possible inclusion for-
mation sites and feldspar dissolution.
5. Discussion
5.1. Source of quartz cement
The origin of quartz cement has been debated a long time with re-
spect to external versus internal silica sourceswithin a given sandstones
(Gier et al., 2008; Islam, 2009). Because the solubility of SiO2 (aq) is
extremely low in relatively closed system (Ronald and Edward, 1990;
Bjørlykke and Jahren, 2012), together with constraints of water volume
Th, °C Tm, ice/°C Salinity, NaCl wt.% equiv. (from Bodnar, 1993)
100 −2 3.39
98 −3.6 5.86
100 −3.7 6.01
99 −3.7 6.01
108 −2.1 3.55
Fig. 10. The characteristics ofminor cements and clay minerals: A,Micrograph of SEM showing pyrite framboids filling the intergranular pore; B, Micrograph of thin section showing feld-
spar overgrowth and ankerite replacement; C, Micrograph of SEM showing authigenic quartz, kaolinite and some illite; D, Micrograph of SEM showingmixed-layer illite/smectite; E, Mi-
crograph of SEMshowingfibrous illite; F,Micrograph of SEM showing rosette-shaped chlorite. Py—pyrite; FA—feldspar overgrowth;An—ankerite; I/S—mixed-layer illite/smectite; I—illite;
QA—authigenic quartz; Ch—chlorite.
99K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
and considerable heterogeneity in porosity and permeability, neither
advective flow, thermal convection or diffusion can explain long
distance and massive transfer of external SiO2 (aq) into sandstones
(Bjørlykke et al., 1988; Bjørlykke, 2011; Bjørlykke and Jahren, 2012).
Thus, the internal sources, such as biogenic silica, feldspar dissolution,
unstable volcanic rock fragments, clay mineral diagenesis and pressure
solution of detrital grains, are possible silica sources for quartz cement
(Bjørlykke and Egeberg, 1993; Kim and Lee, 2004; Peltonen et al.,
2009; Hyodo et al., 2014). On the basis of these theories, the sources
of quartz cement have already been thoroughly studied in the K1q4
tight sandstone reservoirs (Xi et al., 2015). The results showed that
the quartz cement formed in a continuous process from about 60 °C to
Fig. 11. The vertical distribution ch
130 °C (Fig. 13). Mass balance calculation indicated that the smectite-
to -illite reaction can provide 50–60% silica source for the quartz cemen-
tation in the K1q4 tight sandstone reservoirs, which may explain the
quartz cement formed from 60 to 100 °C, especially 70–90 °C (Xi et al.,
2015). Furthermore, the other part of silica source for the quartz cemen-
tationwasmainly provided by pressure solution (chemical compaction)
between detrital quartz, which can explain the quartz cement formed
above about 100 °C (Xi et al., 2015). In addition, the K-feldspar and
kaolinite to illite reaction can provide only a small amount of silica
source for the quartz cement formed from about 120 °C to 130 °C (Xi
et al., 2015). The internal supplied silica precipitate within a closed
system where the transport mechanism is diffusion (Xi et al., 2015).
aracteristics of clay minerals.
Fig. 12. Oil presence forms in K1q4 sandstone reservoirs from thin section and fluorescence observation.
100 K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
5.2. Source of carbonate cements
Carbonate cements have many potential sources, including internal
(e.g. locally reprecipitated detrital carbonate grains or bioclasts), exter-
nal (from adjacent mudstones or source rocks, etc.), or mixed sources
(Gier et al., 2008; Dutton and Loucks, 2010). Sandstone petrology and
provenance evidences show no detrital carbonate grains and bioclasts
existing in the reservoirs, suggesting that internal sources were proba-
bly insignificant for the carbonate cement.
The relatively low negative δ13C values suggest that decarboxylation
of organic matter in adjacent mudstones and source rocks must have
Fig. 13. Histograms of homogenization temperature (Th) for aqueous inclusions in quart
overgrowth and pores filling authigenic quartz in K1q4 tight sandstone reservoirs.
been an important carbon source in the K1q4 tight sandstone reservoirs
(Table 1; Fig. 14A) (Irwin et al., 1977; Curtis, 1978; Morad, 1998). The
δ13C values increase with the increasing distance of samples to source
rocks (Fig. 14B), also providing an evidence for carbonate cements
affected by organic matter decarboxylation from adjacent mudstones
and source rocks.
In order to precipitate the ferrocalcite and ankerite, Ca2+, Mg2+ and
Fe2+ ionsmust be present in the formation water. Asmentioned above,
a large amount of unstable volcanic rock fragments are present in the
studied interval and smectite- to -illite reactions are very common as
well. Conversion of volcanic rock fragments and the smectite- to -illite
reaction can provide extra Ca2+, Mg2+ and Fe2+ (Boles and Franks,
1979; Storker et al., 2013). As in the sandstones, the smectite- to -illite
reaction can also occur in the interbedded mudstones and source
rocks at the right temperature. Unlike Si4+ and Al3+, however, Ca2+,
Mg2+ and Fe2+ can be expelled frommudstones to adjacentsandstones
(McHargue and Price, 1982; Chen et al., 2009; Yuan et al., 2015). Thus,
their concentrations along the sandstone andmudstone contact surface
are higher than in the central part of the sandstone body that has insig-
nificant changes in lithological composition. When these ions are
released into the pore water of sandstones and mixed with the CO32−
derived from organic matter decarboxylation, the initial physical and
chemical equilibrium is broken, allowing carbonate to precipitate
(Milliken and Land, 1993; Chen et al., 2009; Dutton and Loucks, 2010;
Li et al., 2014). In this case, the carbonate cements in sandstones may
form along the sandstone and mudstone contact surfaces first, and
then gradually spread into the sandstone bodies by diffusion. The distri-
bution patterns of carbonate cements in sandstones, i.e. that extensive
cementation occurs along the sandstone andmudstone contact surfaces
(Fig. 9), also supports external sources of carbonate cements in the K1q4
Fig. 14. The distribution characteristics of isotopes: A, Introduction of carbonate and oxygen isotope distribution (modified from Irwin et al., 1977; Guo and Wang, 1999); B, δ13C values
increase with the increasing distance of samples to source rocks.
Fig. 15. Comparison of the homogenization temperatures of the aqueous inclusions in
quartz cements, carbonate cements and hydrocarbon inclusions.
101K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
tight sandstone reservoirs, which are related to interbeddedmudstones
and source rocks.
Bulk rock XRD data show that interbedded mudstones contain an
average of 2.82% carbonate minerals. The δ13C value (V-PDB) ranges
from −13.3‰ to −0.9‰ with an average of −6.17‰, and the δ18O
value (V-PDB) ranges from −21.7‰ to −12.1‰ with an average of
−16.46‰ (30 samples), which are similar to the carbonate cements
in sandstones (Table 1). With relative high temperature, large amounts
of organic acids and CO2 derived from the thermal evolution of organic
matter can dissolve some carbonates in interbedded mudstones
(Dutton and Loucks, 2010), which may be another carbon source of
carbonate cements. In addition, plagioclase dissolution and associated
illitization of kaolinite can also provide some Ca2+ for carbonate cemen-
tation (Macaulay et al., 1993; Milliken et al., 1994). However, these two
sources are not important since feldspar dissolution and carbonate
minerals are very limited in the studied reservoirs and interbedded
mudstones, respectively.
5.3. Paragenetic sequence of diagenesis
Below, petrographic observationswill be integratedwith fluid inclu-
sion and isotope analysis data to help discern the relative timing of each
diagenesis and reconstruct the diagenetic history and hydrocarbon
emplacement process in the K1q4 tight sandstone reservoirs.
Petrographic evidence described in the preceding part of the text,
including cross-cutting relationships of cements, dissolution–filling
relationships of diagenetic minerals and fluorescent bitumen can be
used to infer the relative sequence of each diagenetic event. Moreover,
the authigenic mineral forming temperatures that can be measured
from aqueous inclusions or calculated by oxygen isotope values are
able to provide amore accurate relative timing of the different diagenetic
reactions. The homogenization temperature of the aqueous inclusions
ranges from 60 to 130 °C (Fig. 13) with an average of 82.1 °C in
authigenic quartz (Xi et al., 2015).
In order to make up for the data deficiencies of the homogenization
temperature in carbonate cements, the δ18O values are used to calculate
the precipitation temperatures of carbonate cements. The obtained δ13C
and δ18O values cannot represent the original pore water, so it is neces-
sary to estimate the δ18O values before the calculation. For Jurassic
and younger samples, the best discrimination between marine and
fresh-water carbonate is given by the equation of Keith and Weber
(1964):
Z ¼ a δ13Cþ 50
� �
þ b δ18Oþ 50
� �
; ð3Þ
in which a and b are 2.048 and 0.498, respectively.
Marine carbonate is characterized by a Z-value above 120, fresh-
water types with a Z-value below 120, and indeterminate types with a
Z-value near 120 (Keith and Weber, 1964). The calculation results of
the studied reservoirs show that the Z-values range from 91.52 to
115.8with an average of 100.75 (Table 1),which indicate that the origin
of the pore water is mainly fresh-water with a slight mixed of salt-
water. This calculated result coincideswith thefinal icemelting temper-
ature and salinity data measured from aqueous inclusions in carbonate
cements (Table 2). Using the δ18O values of these carbonate cements,
the assumed precipitation temperature of 20 °C and the fractionation
equation of Friedman and O'Neil (1977), the oxygen isotope value of
the pore water from which carbonate cements have precipitated is
approximately −7‰ relative to SMOW, which corresponds to the
δ18O value of pore water mixing of fresh water and slightly salt water
(Mansurbeg et al., 2008). Finally, combined with the δ18O value of
−7‰ (SMOW), the XRD analysis data and different oxygen isotope
fractionation factors for dolomite-water (Matthews and Katz, 1977)
and calcite-water (Friedman and O'Neil, 1977), the approximate
carbonate cements precipitation temperatures are calculated for all
the studied samples. The calculated temperature range from 83.78 °C
to 130.96 °C with an average of 108.59 °C (Table 1), which is similar
to the homogenization temperature measured from carbonate cements
(Table 2).
There are many hydrocarbon inclusions developed in quartz micro-
fractures (Fig. 12I). The coeval aqueous inclusion homogenization tem-
perature is a good approximation of the trapping temperature of the
coexisting hydrocarbon inclusions (Dong et al., 2014).Microthermometry
studies show that the homogenization temperature of the coeval aqueous
inclusions ranges from 73 °C to 119 °C, with an average of 93.08 °C
(Fig. 15). By comparison based on this result, the start of oil emplacement
was prior to the onset of carbonate cementation but posterior to the onset
of quartz cementation (Fig. 15).
102 K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
In summary, synthesizing the petrographic evidences, the mineral
reactions associated with cement source analysis, and the calculated
temperature of major cements and oil emplacement, the paragenetic
sequence of diagenesis and the hydrocarbon emplacement are recon-
structed and illustrated in Fig. 16.
5.4. Diagenetic controls on reservoir quality
Reservoir quality, defined here as porosity and permeability, is a
function of provenance and depositional controls on grain size and
sorting as well as diagenetic controls of compaction, cementation,
Fig. 16. Burial, thermal, diagenetic history and average thin section porosity evolution trend of
rate of authigenic minerals and oil-charging.
dissolution and development of authigenic clay minerals (Schmid
et al., 2004; Islam, 2009; Rahman andMcCann, 2012). In the studied res-
ervoirs, the grain size and sorting are slightly different in each sample,
probably with insignificant effects on reservoir quality. Thus, the reser-
voir quality at this stage is controlled mainly by diagenesis.
Mechanical compaction, starting immediately after deposition, can
be evaluated by the intergranular volume (IGV). The intergranular vol-
ume (IGV) found in the studied samples from the petrographic analysis
shows very little depth dependence, with values between about 11.09%
and 25.94%, with an average of 15.46% (Fig. 7). These large variations in
intergranular volume (up to 10%–15%) are probably related to both the
the K1q4 sandstone reservoirs. The width of the symbols represents the relative occurring
Fig. 18. Plot of intergranular volume (IGV) versus volume of cement inK1q4 sandstone res-
ervoirs (modified from Houseknecht, 1987 and Lundegard, 1992).
103K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
original volcanic content and the content of ductile volcanicgrains.
Sandstones with abundant, mechanically unstable minerals commonly
suffer more rapid reduction in porosity and permeability during burial
because of mechanical compaction. The sandstones with more quartz
grains will have a larger intergranular volume (Fig. 17); however, the
more feldspar grains and ductile rock fragments, the smaller the inter-
granular volume will be (Fig. 17). This is because the quartz grains are
hard andmore compression resistant. The rock fragments deform easily
due to breakage along grain boundaries resulting in ductile deformation
lowering the IGV in-between the fragmented lithoclasts and also
between the disintegrated rock fragments and the larger feldspar and
quartz grains. Feldspar grains may also deform preferentially during
early burial due to weakening by chemical dissolution processes. Thus,
reservoirs with originally more quartz grains and less ductile rock
fragment and feldspar grains will be more mechanically more stable
and preserve a higher IGV.
A plot of intergranular volume (IGV) versus cement volume indi-
cates that mechanical compaction has played a more important role
than cementation in destroying the primary porosity of the K1q4 sand-
stone reservoirs (Fig. 18). Mechanical compaction has accounted for
45.89%–66.51% (with an average of 58.08%) of the total intergranular
pore volume loss (PVL) during the burial process (assuming an initial
porosity of 40%).
Cementation also played a major role in reducing porosity and per-
meability in the studied sandstone reservoirs, even though mechanical
compaction is volumetrically the most important. The most abundant
pore-occluding cement types recognized in this study are quartz,
carbonate and authigenic clay minerals. The different types of cement
occlude both pores and pore-throats, making the reservoir quality ex-
tremely poor. Quartz cements were found in all samples. The amounts
of quartz cement show no significant trend with the distance to the
sandstone and mudstone contact surface (Fig. 19), indicating that
quartz cement precipitation was not related to interbeddedmudstones.
This could be regarded as evidence showing that the sources of quartz
cement were internal. Porosity destroyed by quartz cement ranges
from 1.55% to 8.38% with an average of 5.62%.
Fig. 17. Relationships between detrital grains and inte
Carbonate cements, formed relatively late during diagenesis based
on isotopes, were mainly related to adjacent mudstones or source
rocks thicker than 2 m. Quantitative analysis indicates that the carbon-
ate cement content, porosity and permeability were significantly influ-
enced by proximity to the sandstone–mudstone interface (Fig. 19).
Generally, sandstones less than 1.0 m from the sandstone–mudstone
contact surface have a carbonate cement content above 8%, with poros-
ity and permeability lower than 6.5% and 0.05mD respectively (Fig. 19).
On the other hand, samples takenmore than 7maway from sandstone–
mudstone contact surfaces have carbonate cement contents less
than 3%, and porosity and permeability higher than 10% and 0.3 mD
rgranular volumes in K1q4 sandstone reservoirs.
Fig. 19. Relationships between reservoir quality and the distance from the contact surface of sandstone and mudstone.
104 K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
respectively (Fig. 19). The carbonate cement content ranges from about
3% to 8%, and the porosity and permeability range from 6.5% to 10% and
0.05 mD to 0.3 mD, respectively (Fig. 19). Thicker sandstone bodies al-
ways show enhanced cementation along the contact surfaces between
sandstone and mudstone intervals while retaining better reservoir
properties relatively farther away from the contact surface. However,
thin sandstone layers (mainly less than 2 m) are evenly carbonate
cemented, resulting in poor reservoir properties in such thin sandstone
sections. The uneven distribution of carbonate cement foundwithin the
sandstones indicates the intercalated mudstones as an external source
of the carbonate cements. Since the cement distribution and reservoir
properties are a function of distance to the interbedded mudstones
(above or below) on a local scale, the system seems to have been
relatively closed (diffusion only) also with respect to late carbonate
cementation.
According to the XRD analysis data, the total content of clayminerals
ranges from 4.1% to 26.5% with an average of 14.3%. The clay minerals
present in the studied sandstone reservoirs are mainly authigenic
clays, consisting mostly of mixed-layer illite/smectite with R = 3
Reichweite order, illite, chlorite and a small amount of kaolinite. The
clay minerals reduced the porosity and permeability, occurring as
pore-lining and pore-filling clays. The relative abundance of the differ-
ent clay minerals has various effects on the reservoir qualities. Honey-
comb mixed-layer illite/smectite mainly occluded the primary pores
and thus destroyed the reservoir quality, especially the porosity
(Fig. 20). Illite tended to plug the pores and pore-throats with fibrous
and flaky crystallite types, which can divide macro-pores into micro-
pores and lower the reservoir quality, particularly the permeability
(Fig. 20). There is no evidence to indicate that chlorite inhibited quartz
cementation effectively, indicating that the chlorite precursor was not
attached to detrital mineral surfaces (quartz and feldspar). However,
there is a positive correlation between the content of chlorite and reser-
voir properties (Fig. 20). Although chlorite can fill pores and reduce the
diameter of pore-throats, the crystals of chlorite are commonly small
and do not cause severe occlusion of pores (Morad et al., 2010). In
addition, chlorite tends to be oil wet while illite is commonly water
wet (Barclay and Worden, 2000; Morad et al., 2010). Thus oil is
easier to accumulate in reservoirs with more chlorite. As a result, late
carbonate cementation may be inhibited to some extent due to mixed
wettability (Fig. 12C, D). The data from Well Rang 59 show that oil
saturation increases with an increase in chlorite, while carbonate has a
decreasing trend (Fig. 21). Authigenic clay minerals always contain a
large amount of micropores that have negligible contributions for
permeability, which can be regarded as the most probable explanation
for the extremely low permeability and the poor relationship between
porosity and permeability in K1q4 sandstone reservoirs (Fig. 4A, B).
In addition, early feldspar dissolution resulted in the formation of
some secondary pores in the K1q4 sandstone reservoirs (Fig. 8A–C).
Due to the formation of kaolinite and weakening of compression resis-
tance, however, feldspar dissolution does not improve the reservoir
quality effectively. Instead, the connectivity of secondary pores is
poor and thus makes the pore-throat texture of tight sandstones more
intricate, which is not an advantage with respect to oil accumulation
and development.
The porosity and permeability will change due to diagenetic modifi-
cations. If one assumes that the initial porosity of the studied reservoir
was 40% (Houseknecht, 1987; Lundegard, 1992), combing the diagenetic
history and quantitative data of each diagenetic modification, the
approximate trend of the porosity (visual porosity from the average of
each thin section) for the K1q4 tight sandstone reservoirs can be seen
in Fig. 16. From this trend, compaction and quartz cementation are the
major factors that decreased the sandstone porosity. Carbonate cemen-
tation also increased the degree of densification during later diagenesis.
Moreover, pore-filling and pore-lining authigenic clay minerals, mainly
formed at earlier stages during diagenesis, also damaged the reservoir
quality significantly. As mentioned above, the oil emplacement occurred
mainly before carbonate cementation and after the onset of quartz
cementation. Most probably the oil emplacement occurred after most
of the sandstones had become tight reservoirs (with porosity close to
10%). This may help to explainwhy most of the tight reservoirs have
Fig. 20. Relationship between reservoir properties and different clay minerals.
105K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
low oil saturation (mostly between 30%–40%) and that the oiliness is not
dependent of porosity and permeability in the K1q4 tight sandstone
reservoirs.
6. Conclusions
1. The sandstones of K1q4 are mostly lithic arkoses and feldspathic
litharenites with a fine to medium grain size and moderate to
good sorting, which are characterized by abundant volcanic rock
fragments.
Fig. 21. Relationship between oil saturation, carbonate conte
2. The reservoir properties in the K1q4 sandstones are quite poor with
low porosity and permeability, small pore-throat radii and high
displacement pressures. The relative contents of the primary pores
decreasedwith increasing burial depth, while the amount of second-
ary pores shows an increasing trend.
3. The tight sandstone reservoirs have undergone significant diagenetic
alterations such as mechanical compaction, feldspar dissolution,
quartz cementation, carbonate cementation (mainly ferrocalcite
and ankerite) and clay mineral alteration. Oil emplacement was
prior to the carbonate cementation but posterior to feldspar dissolu-
tion and the onset of quartz cementation.
nt and the relative content of chlorite in Well Rang 59.
106 K. Xi et al. / Sedimentary Geology 330 (2015) 90–107
4. Smectite- to -illite reaction and pressure solution at stylolites provided
themost important internal silica sources for the quartz cementation;
however, carbonate cements mainly precipitated from external
sources related to interbedded mudstones and source rocks.
5. Mechanical compaction has played a more important role than ce-
mentation in destroying the reservoir quality of the K1q4 sandstone
reservoirs. The large variations in intergranular volume, reflecting
mechanical compaction, are mainly related to the original volcanic
content and the content of ductile volcanic grains.
6. Different chemical diagenetic processes have different impacts on
reservoir quality. Quartz cement is evenly distributed within the
sandstone bodies, while carbonate cement amounts are always
higher along sandstone–mudstone contact surfaces compared to
the center of individual sandstone bodies. Due to the formation of ka-
olinite and weakening of compression resistance, however, feldspar
dissolution has not improved the reservoir quality effectively.
7. The relative abundance of different clay minerals has various effects
on the reservoir qualities. Mixed-layer illite/smectite and illite re-
duced the porosity and permeability significantly, while chlorite
may have preserved the porosity and permeability somewhat since
it tends to be oil wet and the mixed wettability may have inhibited
carbonate cementation to some extent.
8. Based on the evidence presented in this study, oil emplacement
occurred first when most of the sandstones had already reached
tight reservoir conditions (porosity close to 10%). However it is likely
that thicker sandstone bodies within the studied section (at least
thicker than 2 m) could be potential hydrocarbon reservoirs.
Acknowledgments
The research was co-funded by the National Natural Science
Foundation of China (Grant No. U1262203), the Fundamental
Research Funds for the Central Universities (Grant No. 14CX06013A),
and the Chinese Scholarship Council (No. 201406450019). Engineers
Desheng Zhu, Jianchang You and Jianming Li at the Research Institute
of Petroleum Exploration & Development are thanked for SEM, XRD
and QEMSEM analyses. We also thank the Jilin Oil Field, PetroChina,
for providing data.
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