The Lower Cretaceous Bashijiqike Formation of the Kuqa Depression is made up of
ultra-deeply buried sandstones in fold-and-thrust belts. Few researches have
linked diagenetic processes with structure. To fill this gap, a
comprehensive analysis integrating diagenesis with structure pattern,
fracture and in situ stress is performed following a structural diagenetic
approach. The results show that the pore spaces include residual
intergranular pores, intergranular and intragranular dissolution pores, and
micro-fractures. The sandstones experienced a high degree of mechanical
compaction, but compaction is limited in well-sorted rocks or abundant in
rigid quartz grains. The most volumetrically important diagenetic minerals
are calcites. The framework grains experienced a varied degree of
dissolution, and intergranular and intragranular dissolution pores are
formed. Special attention is paid on the dissolution associated with the
fracture planes. Large numbers of natural fractures are cemented by
carbonate cements, which limit fluid flow. In addition, the presence of
fracture enhances dissolution and the fracture planes are enlarged by
dissolution. Cementation and dissolution can occur simultaneously in
fracture surfaces, and the enlarged fracture surfaces can be cemented by
late-stage cements. The in situ stress magnitudes are calculated using well
logs. The horizontal stress difference (Δσ) determines the
degree of mechanical compaction, and rocks associated with low Δσ experienced a low degree of compaction, and these contain
preserved intergranular pores. Natural fractures are mainly related to the
low Δσ layers. The presence of intergranular and
intragranular dissolution pores is mainly associated with the fractured
zones. The high-quality reservoirs with intergranular pores or fractures are
related to low Δσ layers. The structural diagenesis
researches above help the prediction of reservoir quality in ultra-deep
sandstones and reduce the uncertainty in deep natural gas exploration in
the Kuqa Depression.
Introduction
The Kuqa Depression is a foreland depression that experienced multistage tectonic
evolutions during Mesozoic to Cenozoic periods; consequently many high and
steep thrust faults and fault-related folds were formed (Feng et al., 2018;
Neng et al., 2018; Lai et al., 2019a). In addition, the dominant gas-bearing
Lower Cretaceous Bashijiqike Formation is buried to an ultra-deep depth of
5500–8000 m (Lai et al., 2019a). The ultra-deep burial depths, complex
structure patterns and concentrated stress will result in complex diagenetic
modifications and pore evolution histories (Laubach et al., 2010; Wu et al.,
2019; Del Sole et al., 2020). Previous studies have individually unraveled
the structural evolution, in situ stress, fracture and diagenesis of
Bashijiqike Formation in the Kuqa Depression (Jia and Li, 2008; Lai et al.,
2017a; Shen et al., 2017; Nian et al., 2018; Ju and Wang, 2018; Lai et al.,
2019a). Despite the extensive researches on diagenesis and structure, few
researches have been conducted on the structural diagenesis by interacting
structure with diagenesis.
Structural diagenesis, a cross-disciplinary approach investigating
relationships between structures (deformation, fractures, etc) and
diagenesis (Laubach et al., 2010), helps us to better understand the changes in
reservoir petrophysical properties and subsurface fluid flow (Vandeginste et
al., 2012; Matonti et al., 2017; Ferraro et al., 2019; Wu et al., 2019;
Rodrigues et al., 2021). Foreland fold-and-thrust belts are challenging for
hydrocarbon exploration due to their structural complexity and heterogeneous
reservoir quality distribution (Vandeginste et al., 2012). Actually the
structural complexity highly impacts fluid flow and diagenetic processes
(Vandeginste et al., 2012; Wang et al., 2021). The impact of diagenesis and
diagenetic minerals on reservoir quality are well described (Lai et al.,
2017a), while little is known about the fracture-induced diagenesis, which
is present throughout the entire Bashijiqike formation. Therefore the
comprehensive structural diagenesis analysis in the Kuqa Depression is of great
scientific and practical significance.
This study is focused on linking diagenesis to structural complexity and is
organized according to the following goals:
to describe the lithology and pore spaces;
to unravel
the type and degree of diagenesis and diagenetic minerals;
to
characterize the fracture using core and image logs;
to unravel the
dissolution and cementation along the fracture surfaces;
to calculate the
in situ stress magnitudes;
to describe the in situ stress, compaction and
preservation of intergranular pores, as well as the fracture enhanced
dissolution;
to unravel the diagenesis (preservation of intergranular
pores, formation of dissolution pores and fracture) within the structural
complexity. It is hoped that the results of this study will help us to better understand the
structural and diagenetic processes and reduce the uncertainty for
reservoir quality prediction of ultra-deep sandstones in the Kuqa Depression and
similar basins worldwide.
Geological settings
The Kuqa Depression is located in the North Tarim Basin, western China (Fig. 1). The petroliferous Tarim Basin is located between the Tian Shan and
Kunlun Mountains and occupies an area of 56×104 km2
(Fig. 1) (Jin et al., 2008; Qiu et al., 2012; Gao et al., 2016; Jiang et
al., 2016; Fu, 2019; Lai et al., 2021a; Zhang et al., 2021). The Kuqa Depression experienced a long and complex evolutionary history during the
Mesozoic to Cenozoic time, forming two sags and three structural belts:
Baicheng and Yangxia Sag, northern monoclines, and Kelasu and Qilitage structural
belts (Lai et al., 2015; Shen et al., 2017; Feng et al., 2018; Ju and Wang,
2018). Large numbers of thrust faults and fault related folds, which act as
structural traps for oil and gas in the Kuqa Depression (Fig. 1), were
formed due to the multistage tectonic activity and strength tectonic stress
(Zhang and Huang, 2005; Zeng et al., 2010; Nian et al., 2016; Feng et al.,
2018; Zeng et al., 2020). Four well blocks are recognized in the Kelasu
structural belts, and they include Bozi, Dabei, Keshen and Kela well blocks
(Fig. 1).
Map showing the structural divisions of the study area (Jin et al., 2008; Lai et al., 2017b; Wei et al., 2020).
The Mesozoic and Cenozoic strata are over 10 000 m thick (Chen et al.,
2000; Zou et al., 2006). There is a well-developed reservoir-cap rock
assemblage in the Kuqa Depression (Jin et al., 2008). Among the Cretaceous Formations, the Lower
Cretaceous Kapushaliang Group (K1kp) and Bashijiqike Formation
(K1bs) are the dominant reservoir intervals, and many giant gas fields
including Kela 2, Awa, Bozi, Dina, Dabei and Keshen gas fields have been
discovered in this gas-bearing formation (Fig. 1) (Jin et al., 2008; Shen et
al., 2017; Nian et al., 2018). The overlying Kumugeliemu group
(E1-2km) acts as the regional cap rocks in the Kuqa Depression due to the
favorable cap property of the thick-layer gypsum salt rocks (Fig. 1).
Additionally, the underlying Triassic–Jurassic coal-bearing formations
(Jurassic Yangxia formation (J1y), Triassic Karamay (T2k) and
Huangshanjie (T3h) formations) are the source rocks in the Kuqa Depression
(Zhao et al., 2005; Shen et al., 2017).
The lithology section and well log curves of Well Bozi 9 in the Kuqa Depression (Zeng et al., 2020).
The Lower Cretaceous Bashijiqike Formation is divided into three members
(K1bs3, K1bs2 and K1bs1) from bottom to top.
Depositional facies of the Bashijiqike Formation are recognized as
fan-braided deltaic environments (Jia and Li, 2008) (Fig. 2). The lithologies
include a wide range from siltstone and fine–medium-grained sandstone to pebbly sandstone and conglomerate (Zeng et al., 2020) (Fig. 2), and intergranular,
intragranular pores as well as fracture constitute the main reservoir pore
spaces (Nian et al., 2018, 2021; Lai et al., 2019a). The
depositional subfacies evolved from fan delta plains in K1bs3 to
braided delta front subfacies in K1bs2 and K1bs1 members,
and the main depositional microfacies recognized include a distributary
channel, mouth bar and distributary bay (Wang et al., 2013; Lai et al.,
2017a; Nian et al., 2018).
Data and methods
Cores were taken from 18 cored wells, and photos were taken for each species
of core. In addition, almost all the examined cores were slabbed
360∘ to better show the distinct characteristics of core surfaces.
Approximately 200 thin sections were polished to approximately 0.03 mm and
impregnated with blue resin to highlight porosity. Thin sections were also
stained with mixed Alizarin Red S and potassium ferricyanide solution for
differentiating various types of carbonate minerals (calcite, dolomite and
their ferroan equivalents).
Thin sections were firstly examined by optical transmitted light and
subsequently cathodoluminescence (CL) microscopy. The CL observations were
made using a ORTHOPLAN cold cathode device.
SEM (scanning electron microscopy) was used to detect the various types of
clay minerals and recognize the micropores within clay minerals. The
secondary electron images were used to detect the pores and clay minerals
associated with the freshly broken rock surfaces.
Conventional well logs include three lithology logs including calipers
(CAL), gamma ray (GR) and spontaneous potential (SP); three porosity logs
including sonic transic time (AC), compensated neutron log (CNL) and
bulk density (DEN); and deep and shallow lateral resistivity logs (LLD, LLS).
Schlumberger's FMI (Fullbore Formation MicroImager) image logs were used to
obtain the high-resolution (5 mm) borehole images. A series of data
processes including speed correction, centering correction and
normalization were used to generate the static and dynamic images (Lai et
al., 2018). Beddings and natural and induced fractures are manually picked out
on the image logs by fitting sinusoidal waves (Nian et al., 2021; Feng et
al., 2021; Lai et al., 2022).
The lithologies of the Cretaceous Bashijiqike Formation in the Kuqa Depression
include a wide range from conglomerate (Fig. 3a), pebbly sandstone (Fig. 3b),
fine–medium-grained sandstone (Fig. 3c–d), siltstone (Fig. 3e–f) and
mudstone (Fig. 3g–h), indicating a fan-braided deltaic environment (Jia and
Li, 2008; Wang et al., 2013; Lai et al., 2018).
Thin section images showing the pore spaces of Cretaceous
Bashijiqike Formation in Kuqa Depression (Xin et al., 2022). (a) Intergranular pores, Bozi 301, 5843.8 m. (b) Residual intergranular pores with irregular morphology, Bozi 9, 7689.32 m. (c) Framework grain dissolved pores, Bozi 301, 5846.95 m. (d) Intragranular dissolution pores, Keshen 242, 6564.1 m.
(e) Micro-fractures in sandstone with intergranular pore spaces, Bozi 9,
7675.95 m. (f) Micro-fractures in carbonate cemented sandstone, Bozi 22, 6276.85 m.
The pore spaces include residual intergranular pores with irregular
morphology (Fig. 4a, b) and intergranular and intragranular dissolution pores
(Fig. 4c, d) due to dissolved feldspar and rock fragment grains. In some
cases, the coexistence of intergranular pores and intragranular dissolution
pores is common (Fig. 4a–d). Micro-fractures can also constitute an important
pore space (Fig. 4e, f). Micro-fractures can occur in sandstones with evident
intergranular pore spaces (Fig. 4e), and they also can be detected in
carbonate cemented sandstones (Fig. 4f).
Diagenesis type and degree
The types and degree of diagenetic modification as well as the typical
diagenetic minerals in Bashijiqike Formation of the Kuqa Depression are
described in previous studies (Lai et al., 2017a).
The degree of mechanical compaction varied significantly for the Bashijiqike
sandstones in the Kuqa Depression (Lai et al., 2017a). The sandstones are
buried to a great depth from 5500–8000 m, and compaction is extensive due to
the overburden rocks. The rocks are very heavily compacted, especially the
very fine-grained or poorly sorted rocks (Fig. 5a–b). However, some of the
rocks which are well sorted or abundant in rigid grains can preserve large
amounts of intergranular pores (Fig. 4a–b).
Thin section, CL and SEM images showing the diagenesis type and
degree as well as diagenetic minerals of Cretaceous Bashijiqike Formation in
Kuqa Depression (Xin et al., 2022). (a) Tightly compacted rocks, very fine-grained, Dabei 902, 5097.15 m. (b) Poorly sorted rocks which are tightly compacted, Dabei 1102, 5921.26 m. (c) Intergranular pores preserved in well-sorted rocks, Dabei 14, 6351.16 m. (d) Extensive carbonate cements, Dabei 1101, 5895.76 m. (e) Dolomite cements, Dabei 1101, 5809.35 m. (f) CL images showing the extensive carbonate cements, Dabei 12, 5442.09 m. (g) Dissolution pores due to dissolution of framework grains, Dabei 1102,
5915.51 m. (h) Intergranular and intragranular dissolution pores, Keshen 242, 6564.1 m. (i) Authigenic quartz and illite and smectite mixed layer, Bozi 102, 6758.04 m. (j) Illite and smectite mixed layer filling in the pore spaces, Bozi 102,
6763.16 m.
In addition, the pore-line grain contacts also suggest a limited degree of
compaction, and the cementation is also inhibited (Lai et al., 2019b)
(Fig. 5c). Actually, there are evident dark cement rims (mixed-layer
illite–smectite) on many of the framework grains within these rocks (Fig. 4b, e), and the presence of authigenic mineral rims on framework grains can
inhibit (quartz) cementation into the intergranular pore space (Lai et al.,
2017a).
Diagenetic minerals are mainly carbonates, and they are the most
volumetrically important (Fig. 5d). Carbonate cements, which are in the form
of calcites (Fig. 5d) and dolomites (Fig. 5e), significantly reduce pore
spaces. There are even no evident pore spaces in rocks which are extensively
cemented by carbonates (Fig. 5d, e). The CL images prove the extensive
carbonate cements in the intergranular pore spaces, and they can even
replace framework grains (Fig. 5f).
Dissolution occurred along the framework grain boundary and the
intragranular pore spaces, forming intergranular and intragranular
dissolution pore spaces (Fig. 5g, h). The dissolution degree is also varied
greatly, and significant dissolution is mainly associated with the
fine–medium-grained rocks (Fig. 5g, h). The secondary dissolution pores are
developed due to framework grain (feldspar and rock fragments) dissolution
(Fig. 5g, h).
There are also minor amounts of quartz cements (Fig. 5i) and clay minerals in
the form of an illite and smectite mixed layer (Fig. 5j) in the Bashijiqike
sandstones of the Kuqa Depression (Lai et al., 2017a). The quartz cements occur
as small authigenic quartz crystals (Fig. 5i), while the mixed-layer
illite–smectite clays occur as pore-filling fibrous or webby morphologies
(Fig. 5j).
Compaction, cementation and porosity reduction
Compaction and pore-filling cements will reduce porosity in sandstones
(Houseknecht et al., 1987; Lima and DeRos, 2002; Mansurbeg et al., 2008; Lai
et al., 2015; Haile et al., 2018).
The compactional porosity loss (COPL) is commonly estimated by Eq. (1):
COPL=OP-(100×IGV)-(OP×IGV)(100-IGV),
where OP is the original porosity (the OP values were estimated as 40 %
for fine–medium-grained, well-sorted sandstone), and IGV is the sum of
present intergranular porosity and total cement content (intergranular
porosity before cementation but after compaction) (Houseknecht et al., 1987;
Ozkan et al., 2011; Lai et al., 2015).
The cementational porosity loss (CEPL) can be calculated as Eq. (2)
(Houseknecht et al., 1987; Zhang et al., 2008; Ozkan et al., 2011):
CEPL=(OP-COPL)×CEMIGV,
where OP is the original porosity, COPL is compactional porosity loss and
CEM is the total cement volume percentages of rock volume.
Plot of compactional porosity loss (COPL) and cementational
porosity loss (CEPL) versus depth for the Bashijiqike sandstones.
The calculated results show that COPL ranges from 11.8 % to 39.6 % with
an average of 32.0 %, while CEPL is in the range from 0 % to 27.2 % and
averaged as 5.2 % (Fig. 6). Porosity reduction by mechanical compaction was
more significant than by cementation (Fig. 6). However, COPL shows no evident
relationship with burial depth and can reach as high as 40 % and even shallower, and even in depths deeper than 7500 m, the COPL can be
lower than 20 % (Fig. 6).
Lai et al. (2017a) has unraveled the paragenetic diagenetic history of the
studied rocks, and eogenetic diagenetics mainly include mechanical
compaction, precipitation of calcite cements and grain-coating clays; then
mesogenetic diagenesis contains framework grain dissolution and
precipitation of clay minerals and quartz, while meteoric water of
teleodiagenesis results in dissolution of the framework grains.
Fracture and image log characterization
Natural fractures are important subsurface fluid flow conduits and they play
important roles in hydrocarbon accumulation and production (Khoshbakht et
al., 2009; Zeng, 2010; Lyu et al., 2016, 2017; Laubach et al.,
2019). In terms of fracture attributes (dip angles), natural fractures can
be divided into vertical fractures and high dip angle fractures
(>60∘), medium dip angle fractures (30–60∘), and low-angle fracture (<30∘) and
horizontal fracture from the aspect of image log interpretation.
Additionally, fractures can be classified into open, partly open or closed
fractures in terms of fracture status. Core observations show that the
fine–medium-grained sandstones have the highest abundance of fractures, and
open-filled fractures with various dip angles can occur in the fine–medium-grained sandstones (Fig. 7).
Core photos showing the various attributes and status of fracture. (a) Horizontal fracture, fine-grained sandstones, Bozi 101, 6916.5 m. (b) Low-angle fracture, fine-grained sandstones, Dabei 1401, 6351.4 m. (c) High-angle fracture, fine-grained sandstones, Bozi 3, 5972 m. (d) Multi-set high-angle fracture, medium-grained sandstones, Bozi 301,
5854.2 m. (e) Network fractures, medium-grained sandstones, Dabei 12, 5399.9 m. (f) Low-angle fracture, medium-grained sandstones, Dabei 12, 5403.7 m. (g) Calcite-filling high-angle fracture, fine-grained sandstones, Bozi 104,
6803 m. (h) Fracture-enhanced dissolution, Dabei 14, 6349.6 m. (i) Calcite filling and dissolution along the fracture planes, Dabei 17,
6154.2 m.
Natural fractures can be easily picked out from the image logs as dark
sinusoidal waves in case the drilling muds are conductive (water-based
drilling muds) (Fig. 8) (Ameen et al., 2012; Khoshbakht et al., 2009; Lai et
al., 2019a). The continuity of the sinusoidal waves depend on the filling
degree of fracture surfaces, i.e., the partly to fully closed fractures
(sealed by resistive calcite cements) may show discontinuous to continuous
bright sinusoidal waves on the image logs.
Fractures on the image logs picked out as dark sinusoidal waves.
Dip direction of fractures can be derived from the lowest point of the
sinusoidal waves, while dip angles can be determined by the sine wave
amplitudes (Fig. 8) (Nie et al., 2013; Keeton, et al., 2015; Lai et al.,
2018). Therefore the bedding planes and natural open and closed fractures can
be picked out for the entire log intervals. Then rose diagrams of bedding
planes and open and closed fractures can be drawn (Lai et al., 2021b) (Fig. 9).
In addition, four fracture parameters including fracture aperture (FVAH),
fracture density (FVDC), fracture porosity (FVPA) and fracture length (FVTL)
can be calculated from the image logs (Table 1) (Ameen and Hailwood, 2008;
Khoshbakht et al., 2012; Lai et al., 2021b).
Comprehensive evaluation of natural fractures, induced fractures
and fracture effectiveness using image logs for Dabei 1101.
Image-log-derived fracture parameters for Well Dabei 1101 in the Kuqa Depression.
StrataDepthintervals withfractures (m)Open fractures Closed fractures Number offractureFVDC (1 m-1) FVTL (m) FVAH (mm) FVPA (%) Dip anglesAverage dipDip anglesAverage dipMaxAveMaxAveMaxAveMaxAveK1bs5790–580025–82∘52∘∠ 144∘40–50∘45∘∠ 48∘821.23.21.762.60.120.075801–580245–64∘54∘∠ 234∘654.15.54.97.91.80.210.145803–581339–72∘52∘∠ 142∘123.51.72.82.34.23.90.150.085818–582541–59∘46∘∠ 155∘51.512.11.55.13.20.160.085827–584545–65∘61∘∠ 137∘81.40.92.51.62.51.20.110.065869–588840–73∘53∘∠ 133∘213.51.75.43.58.93.80.320.14K1bx5890–589241–85∘65∘∠ 168∘30–40∘44∘∠ 56∘71.81.543.25.64.50.250.155920–593245–70∘56∘∠ 192∘51.211.31.15.92.90.290.11Dissolution and cementation along the fracture surface
Cementation and dissolution within fractures impact fracture patterns and
properties (Ukar and Laubach, 2016; Laubach et al., 2019; Baqués et al.,
2020). Core observations (including the scanning image of core surfaces) show
that the fractures in Bashijiqike sandstones are highly cemented, and the
presence of fractures improves subsurface fluid flow (Matonti et al., 2017),
and therefore the active fluids rich in Ca2+ will be cemented along the
fracture surfaces (Fig. 10a–c). Neither the high-angle, low-angle or even horizontal fractures are highly cemented (Fig. 10a–c). Cemented subsurface
fractures limit the fluid flow (Laubach et al., 2004; Matonti et al., 2017).
In addition, the presence of fractures enhances dissolution, and the fracture
surfaces can be observed to be enlarged by dissolution (Fig. 10d). In some
cases, the cementation and dissolution can occur simultaneously in a
fracture surface, and the enlarged fracture surfaces can be fully cemented
by the late-stage cements (Fig. 10e). Also, in some cases the mudstones can
fill the fracture spaces (Fig. 10f). Dissolution occurring along the fracture
surfaces can even form vugs (Fig. 10g–h), indicating a high degree of
dissolved framework grains. However, the dissolved fracture surfaces can in
some cases be filled by late-stage carbonate cements (Fig. 10g–h).
Core photos showing the cementation and dissolution along the
fracture surfaces of Cretaceous Bashijiqike Formation in Kuqa Depression. (a) Calcite cemented fracture planes (high angle), Keshen 601. (b) Two calcite veins (high angle), Keshen 506. (c) Horizontal fractures filled by calcite cements, Keshen 506. (d) Dissolution along the fracture plane, enlarged fracture surfaces, Keshen
601, 2-31/57. (e) Large calcite veins, Keshen 506. (f) Mudstone filling in the fracture planes, Keshen 506. (g) Dissolution along the fracture surfaces, forming vugs, Keshen 8003. (h) Cementation and dissolution along the fracture surfaces, Keshen 8003.
Thin section observations also show that the fractures play important roles
in enhancing dissolution and cementation (Fig. 11a–c). Calcite cements are
commonly detected occurring along the fracture planes, and they can partly to
fully fill the fracture spaces (Fig. 11a). Fractures are also important
channels for fluid flow, and consequently the acid-rich fluids will enhance
framework grain dissolution. Therefore, the fracture surfaces are commonly
observed to be dissolved (Fig. 11b). In some cases, both dissolution and
cementation can simultaneously occur along the fracture planes (Fig. 11c).
The calcite cementation fills the fracture spaces and reduces fracture
effectiveness, while dissolution improves the fracture connectivity (Figs. 10 and 11). Actually, most opening-mode subsurface fractures contain some
amount of cement (Laubach et al., 2018; Bruna et al., 2020).
Thin sections showing the cementation and dissolution along the
fracture surfaces of Cretaceous Bashijiqike Formation in Kuqa Depression (Xin et al., 2022). (a) Calcite cementation along fracture surface, Keshen 242, 6567.51 m,
K1bs. (b) Calcite cementation along fracture surface, Bozi 22, 6323.64 m,
K1bs. (c) Dissolution along fracture plane, Keshen 242, 6568.95 m. (d) Coexistence of cementation and dissolution along fracture surfaces, KS
242, 6446.94 m.
Vuggy fractures, which were formed due to dissolution along the fracture
planes, can also be observed on the image logs, and the fracture surfaces
are evidently enlarged (Fig. 12). These fractures occur as continuous or
discontinuous, conductive, resistive or mixed (partly resistive and partly
conductive) sinusoidal waves on the image logs (Fig. 12) (Lai et al., 2018).
Image logs showing the dissolution along fracture surfaces,
forming vuggy fracture of Bashijiqike Formation in Kuqa Depression.
In situ stress direction and magnitudesIn situ stress direction
Determination of the in situ stress direction is important for
stress-related geo-hazards and reservoir-related issues (Nian et al., 2016).
In situ stress direction can be determined from the induced fractures and
borehole breakouts picked out from image logs (Rajabi et al., 2010; Ameen et
al., 2012; Nian et al., 2016; Lai et al., 2018). Drilling induced fractures
formed as a result of the local stress field around the borehole, and they
are parallel to Shmax (present-day maximum horizontal compressive stress)
(Wilson et al., 2015). Borehole breakouts are wellbore enlargements induced
by in situ stress concentrations and indicates the orientations of the
minimum (Shmin) horizontal stress directions (Bell and Gough, 1979;
Zeng and Li, 2009; Massiot et al., 2015; Nian et al., 2016). The trend of
the drilling induced fractures is approximately NW–SE direction (Fig. 13).
Image logs showing induced fractures indicating the maximum
horizontal stress direction (Shmax) of NW–SE.
In situ stress magnitudes
The calculation of in situ stress magnitude supports petroleum engineers'
decisions about well design, wellbore stability and fracture stimulation
(Zoback et al., 2003; Ju and Wang, 2018; Iqbal et al., 2018; Lai et al.,
2019a). The three mutually orthogonal principal stresses include (1) vertical (overburden) stress (Sv), (2) maximum horizontal stress (Shmax)
and (3) minimum horizontal stress (Shmin) (Zoback et al., 2003; Verweij et
al., 2016; Dixit et al., 2017; Lai et al., 2019a).
The magnitudes of Shmax, Shmin and Sv can be determined by constructing 1-D
MEMs (one-dimensional mechanical Earth models) (Fig. 14) (Zoback et al.,
2003; Tingay et al., 2009; Ju et al., 2017; Lai et al., 2019a). The vertical
stress is caused by the gravity of overburden rocks (Hassani et al., 2017;
Lai et al., 2019a). The magnitude of Sv at a certain depth equals the
weight of overburden rocks, and it can be calculated by Eq. (3) (Verweij et
al., 2016; Lai et al., 2019a).
Sv=∫0Hρgdz,
where H is the burial depth (m), ρ is the bulk density (kg m-3) and g is
9.8 m s-2 (Verweij et al., 2016; Zhang and Zhang, 2017; Ju and Wang,
2018).
In situ stress magnitude determination via well logs (Keshen 8).
Pore pressure (Pp), also is known as formation pressure at a certain depth
(Dixit et al., 2017), can be calculated from sonic well logs using Eaton's
method (Eaton, 1969; Tingay et al., 2009).
Pp=P0-(P0-Pw)(Δtn/Δt)c,
where Pp is the pore pressure (MPa), P0 (Sv) is the overburden
pressure (MPa), Pw is hydrostatic pressure (commonly taken as 9.8 MPa km-1),
Δtn is sonic interval transit time at normal pressure, Δt is sonic transit time and c is the coefficient of compaction (Zhang, 2011;
Ju et al., 2017).
The determination of the Shmin and Shmax magnitudes via well logs can be
calculated based on vertical stress, Poisson's ratio and pore pressure
(Eqs. 5 and 6) (Eaton, 1969; Zhang, 2011; Maleki et al., 2014; Lai et al.,
2019a; Zhang et al., 2019). The Shmin will be equal to the Shmax in
isotropic stratigraphy (Maleki et al., 2014); however, Shmax is not equal to
Shmin in true formation, and the Shmax and Shmin difference (Δσ=Shmax–Shmin) will vary greatly due to the presence of major faults
and active tectonics (Fig. 14) (Maleki et al., 2014; Yeltsov et al., 2014; Ju
and Wang, 2018; Lai et al., 2019a).
5Shmax=ν1-νSv+1-2ν1-ναPp+E1-ν2εH+Eν1-ν2εh,6Shmin=ν1-νSv+1-2ν1-ναPp+E1-ν2εh+Eν1-ν2εH,
where Sv is vertical stress, PP is pore pressure, E (GPa) is Young's
modulus and ν is Poisson's ratio. α is the Biot's
coefficient, which can be obtained using an empirical equation. The εH and εh are the coefficients related to the maximum and minimum
horizontal stress magnitudes (Zhang et al., 2019).
Discussion
In this section, the impact of in situ stress on compaction will be
discussed, and fracture-enhanced dissolution in single wells are linked, and
then the variations of fracture-diagenesis within various structure patterns
are discussed.
In situ stress magnitude determination via well logs and related
thin sections in Well X501.
Compaction and presence of fractures controlled by in situ stress
The horizontal stress difference (Δσ) plays an important
role in reservoir quality and fractures (Lai et al., 2019a). The thin
section at a depth of about 6356 m has abundant intergranular pore spaces,
indicating a limited mechanical compaction experienced by the rocks. The
calculated Δσ is less than 40 MPa, which is much less than
the surrounding rocks (Fig. 15). The thin section at about 6420 m depth also
indicates a limited mechanical compaction, and evident intergranular pores
can be observed. The calculated Δσ is only about 36–39 MPa,
indicating a low in situ stress magnitude. Conversely, the rocks at about
6369 m depth have experienced an extensive in situ stress concentration,
and the Δσ can reach as high as 45 MPa (Fig. 15). The thin
section observation reveals that the rocks have experienced a high degree of
compaction; no evident intergranular pore spaces are observed, and the
grains are tightly compacted (Fig. 15).
Consequently, horizontal stress difference is a good indicator for the
compaction degree (Fig. 15) (Lai et al., 2019a). High values of horizontal
stress difference will result in a high degree of compaction; the
intergranular pore spaces will be low, and the rocks are easily
tightly compacted (Fig. 15). Conversely, rocks associated with low horizontal
stress difference will experience a low degree of compaction, and the
intergranular pore spaces can be preserved (Fig. 15). High-quality reservoirs
are commonly associated with the layers with low horizontal stress
differences (Fig. 15).
Fracture development within the in situ stress field in Well K8.
Note the fractures are related with layers with low horizontal stress
differences.
Dissolution pores along fracture surfaces (Bozi 104).
Presence of fracture enhance dissolution and dissolution pores
is mainly associated with fractures (Bozi 21).
Dissolution pores are mainly associated with fractures, and no
evident dissolution pores in layers without fractures (Dabei 1102).
Natural fractures are also mainly associated with the layers where Δσ is low (Fig. 16) (Lai et al., 2019a). There are six
fractures picked out by image logs in Layer A of Fig. 16, and the related
Δσ value is only 40–42 MPa. Additionally, the Layer C in
Fig. 16 also has six fractures, and the calculated Δσ value is
only 40 MPa. Conversely, the high Δσ layers commonly relate
to the non-fracture (tight matrix rock) intervals (Layer B in Fig. 16).
Fracture and dissolution
Fractures are mainly encountered in fine–medium-grained sandstones, while
the conglomerates and mudstones rarely have fractures (Fig. 7). In addition,
the dissolution pores are also commonly detected in the fine–medium-grained
sandstones; conversely, those very fine-grained rocks or pebbly sandstones
have low content of intergranular pores, and consequently the dissolution
pores are also rarely observed (Fig. 5), since the presence of intergranular
pores will be favorable for the formation of dissolution pores.
Coupling observations of thin sections and image logs shows that fractures
are easily dissolved along the fracture surfaces (Fig. 17). In
addition, microscopic observation of thin section reveals that dissolution
pores are also commonly associated with the fractured layers (Fig. 17). In
some cases, the dissolution enlarged pores can be detected, indicating a
high degree of dissolution. Decameter-scale porosity can even be formed in
carbonate rocks due to the fracture-enhanced dissolution in carbonate rocks
(Ukar et al., 2020). Additionally, microfractures are observed to
coexist with the intergranular and intragranular dissolution pores
(Fig. 17). The presence of fractures enhances fluid flow and will improve
grain dissolution in sandstones (Fig. 18). In fractured intervals, the thin
section confirms the presence of intergranular and intragranular dissolution
pores, and the dissolution pores are commonly coexisting with intergranular
pores (Figs. 17 and 18).
Dissolution pores are mainly associated with natural fractures, and vuggy
fracture surfaces can be observed (Fig. 19). Conversely no evident
dissolution pores are observed in layers without fractures (Fig. 19).
Therefore the presence of natural fractures greatly improves fluid flow and
will enhance framework grain dissolution, forming intergranular and
intragranular dissolution pores.
Fracture diagenesis within structure patterns
In foreland fold-and-thrust belts in the Kuqa Depression, the stress is
concentrated (Ju and Wang, 2018; Feng et al., 2018), and large amounts of
fractures are formed (Fig. 20). However, the natural fractures show no
evident relationships with burial depth as picked out by image logs, and
they can form well-connected fluid flow channels (Fig. 20). The deep and
shallow lateral logs (M2Rx, M2R3) show evident separation characteristics in
fractured zones, which implies a favorable flow property (Fig. 20). The
structural position (anticline hinge vs. limb) will affect the horizontal
stress differences, and variations of compaction and fracturing will be
encountered.
Image log interpreted fractures for Well Dabei 1102.
Cross section of Bozi 1-Bozi 101-Bozi 102 and pore spaces as well
as fractures determined from thin section and image logs for Well Bozi 102.
Note the dissolution pores associated with fractures, and no evident
dissolution pores in layers without fractures.
Well Bozi 102: 6760–6879 m depth intervals, 4 mm choke width, 38.41 MPa drawdown pressure. The daily natural gas production is 10 6557 m3.
The Well Bozi 102, which was drilled in an anticline, also shows high
density of natural fractures (Fig. 21). However, there is also no increasing
or decreasing trend of fracture density with burial depth. The fractured
zones also show evident shallow and deep resistivity deviations, indicating
a favorable fluid capacity (Fig. 21). When combining thin section observation
with image logs, it is found that the fractured zones enhance framework
grain dissolution (Fig. 21). The presence of intergranular and intragranular
dissolution pores is mainly associated with the fractured zones (Fig. 21).
Additionally, the fracture surfaces can themselves be dissolved as
interpreted from the image logs, and the dissolution pores will be formed
since the fractures improve fluid flow and enhance grain dissolution
(Fig. 21). Conversely, the layers with no evident dissolution pores are
mainly related to the non-fracture zones (Fig. 21).
Cross section of KS 8 and pore spaces as well as fractures
interpreted from thin section and image logs for Well KS 8.
Note the intergranular pores are associated with low Δσ
layers, and dissolution pores coexist with fractures.
Well KS 8: 6717.0–6903.0 m depth intervals, 8 mm choke width, 89.66 MPa drawdown pressure. The daily natural gas production is 72 6921 m3.
The Well KS 8, which was also drilled at the core part of an anticline, also
shows a high degree of fracture development (Fig. 22). Also, the fractures are
not controlled by burial depth. In the vertical geophysical cross section,
there is an overall increase in Δσ with burial depths
(Fig. 22). The fractured zones are mainly associated with the low Δσ layers; in addition, the rocks with evident intergranular pores
also are characterized by low Δσ values (Fig. 22).
Consequently, high-quality reservoirs with intergranular pores or fractures
are associated with the low Δσ layers (Fig. 22). The
presence of intergranular pores has no evident relationships with
fractures, and they can be elsewhere providing the Δσ values
are low (Fig. 22). However, the layers with evident dissolution pores or
microfractures are mainly corresponding with the fractured zones, and these
fractured zones are also characterized by a low Δσ value
(Fig. 22). Consequently, the in situ stress magnitude is related to the
structure pattern, and low Δσ values are favorable for the
preservation of intergranular pores. The fractured zones will also result in
a low Δσ stress. Dissolution pores are controlled by the
presence of fractures (Fig. 22).
To conclude, there are complicated compaction, multiple fracturing, and
cementation and dissolution along the fractured zones, and a comprehensive
structural diagenesis analysis by integrating geological and continuous
petrophysical well log data will provide insights into the distribution of
intergranular pores, dissolution pores and fracture developments. The
comprehensive structural diagenesis analysis helps us better understand the
structural and diagenetic processes and reduces the uncertainty in
reservoir quality prediction of ultra-deep sandstones.
Conclusions
Relationships between thrust faults and fault-related folds and diagenesis
in the Kuqa Depression are investigated, and the following conclusions can be
drawn.
The pore spaces in the Lower Cretaceous Bashijiqike Formation consist of
residual intergranular pores and intergranular and intragranular dissolution
pores. The sandstones experienced a high degree of mechanical compaction,
and the compaction is limited in well-sorted rocks or rocks abundant in
rigid grains. The most volumetrically important diagenetic minerals are
carbonates (in the form of calcites and dolomites). Dissolution degree is
varied, and intergranular and intragranular pore spaces are formed.
Natural fracture attitude and status are characterized by image logs, and
fracture parameters including fracture porosity, fracture density, fracture
length and fracture aperture are calculated. Special attention is paid to the
dissolution along the fracture planes. There are abundant natural fractures
cemented by carbonate cements. Neither the high-angle, low-angle or even horizontal fractures are highly cemented. Cementation along the fracture
surfaces limits fluid flow. In addition, core and image log observation
reveal that fracture enhances dissolution, and the fracture planes are
enlarged by dissolution. The cementation and dissolution can occur
simultaneously in a fracture surface in some cases, and the enlarged
fracture surfaces can be fully cemented by late-stage cements.
The magnitudes of vertical stress Sv, maximum horizontal stress (Shmax) and
minimum horizontal stress (Shmin) are calculated by constructing
one-dimensional mechanical Earth models. The horizontal stress difference
(Δσ) determines the compaction degree, and rocks associated
with low horizontal stress difference experienced a low degree of
compaction, and the intergranular pore spaces can be preserved.
Additionally, natural fractures are also mainly associated with the low
Δσ layers.
Dissolution pores are mainly associated with fractured zones since the
presence of fractures enhances fluid flow. The presence of intergranular
and intragranular dissolution pores is mainly associated with the fractured
zones. The high-quality reservoirs with intergranular pores or fractures are
associated with low Δσ layers. Structural diagenesis which
integrates diagenesis with fracture, in situ stress and structure patterns
provides new insights into the reservoir quality evaluation of ultra-deep
sandstones in the Kuqa Depression.
Data availability
The data used to support the findings of this study are available from the
corresponding author upon request.
Author contributions
JL, DL and GW contributed to the conceptualization, methodology and software.
YA, HL and DC contributed to data curation and writing and preparing the original draft. KC and YX contributed to the visualization and investigation. DL and GW contributed to software and validation. JL and GW contributed to writing, reviewing and editing.
Competing interests
The contact author has declared that neither they nor their co-authors have any competing interests.
Disclaimer
Publisher’s note: Copernicus Publications remains neutral with regard to jurisdictional claims in published maps and institutional affiliations.
Acknowledgements
This work is financially supported by National Natural Science Foundation of
China (grant no. 41872133), Natural Science Foundation of Beijing (grant no. 8204069) and
Science Foundation of China University of Petroleum, Beijing (grant no.
2462021YXZZ003). We thank the PetroChina Tarim Oilfield Company for their
technical input.
Financial support
This work is financially supported by National Natural Science Foundation of China (grant no. 41872133, 42002133), Natural Science Foundation of Beijing (grant no. 8204069) and Science Foundation of China University of Petroleum, Beijing (grant no. 2462021YXZZ003). We thank the PetroChina Tarim Oilfield Company for their technical input.
Review statement
This paper was edited by Maria Mutti and reviewed by Sven Maerz and Sara Elliott.
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