While drilling into the igneous rock formations of the Shunbei area, problems such as loss of well circulation and borehole collapse occur frequently, seriously hindering the efficient development of oil and gas resources. Aiming to solve this problem, the physicochemical and mechanical properties of igneous rocks are studied through a series of laboratory tests to determine the main factors influencing formation collapse and instability. In addition to the laboratory results, the weak plane effect of fracture mechanics, the seepage effect of drilling fluid, and the hydration effect of the drilling fluid on the borehole wall stability of igneous rock formations are evaluated and analyzed by establishing a mathematical model. The results show that the microfractures in the igneous rock are relatively developed and can be divided into unfilled fractures and calcite-filled fractures. The mechanical strength of the matrix igneous rock is higher than that of the rock samples with microfractures. The compressive strength of calcite-filled and unfilled fracture samples is 1/3-1/4 that of matrix igneous rocks, and immersion in the drilling fluid has little influence on the mechanical strength of igneous rocks. The fracture weak plane effect has the greatest influence on wellbore stability. With the increase of the number of fractures at different angles, the collapse pressure equivalent density of the formation subject to the mechanical weak plane effect increases by 21% compared with that of the homogeneous formation without fractures. The seepage effect of the drilling fluid on borehole stability is secondary, and the equivalent density of the formation collapse pressure increases by 11%. Because of the low content of clay minerals, the hydration effect of the drilling fluid on borehole stability was minimal and the equivalent density of collapse pressure increased by only 2%. During the drilling process, considering the weak plane effect of the microfractures and the seepage effect of the drilling fluid, the drilling fluid density should be controlled at about 1.82 g/cm3. The effective plugging ability and rheological properties of the drilling fluid should be improved for the formation with microfractures. The research results can provide a theoretical basis for the safe and efficient development of igneous reservoirs.
While drilling into the igneous rock formations of the Shunbei area, problems such as loss of well circulation and borehole collapse occur frequently, seriously hindering the efficient development of oil and gas resources. Aiming to solve this problem, the physicochemical and mechanical properties of igneous rocks are studied through a series of laboratory tests to determine the main factors influencing formation collapse and instability. In addition to the laboratory results, the weak plane effect of fracture mechanics, the seepage effect of drilling fluid, and the hydration effect of the drilling fluid on the borehole wall stability of igneous rock formations are evaluated and analyzed by establishing a mathematical model. The results show that the microfractures in the igneous rock are relatively developed and can be divided into unfilled fractures and calcite-filled fractures. The mechanical strength of the matrix igneous rock is higher than that of the rock samples with microfractures. The compressive strength of calcite-filled and unfilled fracture samples is 1/3-1/4 that of matrix igneous rocks, and immersion in the drilling fluid has little influence on the mechanical strength of igneous rocks. The fracture weak plane effect has the greatest influence on wellbore stability. With the increase of the number of fractures at different angles, the collapse pressure equivalent density of the formation subject to the mechanical weak plane effect increases by 21% compared with that of the homogeneous formation without fractures. The seepage effect of the drilling fluid on borehole stability is secondary, and the equivalent density of the formation collapse pressure increases by 11%. Because of the low content of clay minerals, the hydration effect of the drilling fluid on borehole stability was minimal and the equivalent density of collapse pressure increased by only 2%. During the drilling process, considering the weak plane effect of the microfractures and the seepage effect of the drilling fluid, the drilling fluid density should be controlled at about 1.82 g/cm3. The effective plugging ability and rheological properties of the drilling fluid should be improved for the formation with microfractures. The research results can provide a theoretical basis for the safe and efficient development of igneous reservoirs.
It is estimated that only about 1% of the world’s total
oil and gas resources are in igneous rock reservoirs.[1] However, with the continuous advancement of oil and gas
exploration and development techniques, there is increasing potential
for the exploration and development of igneous reservoirs.[2] Igneous rock formations are very prone to borehole
instability and collapse, and this greatly increases the cost and
difficulty in drilling. Therefore, it is important to study borehole
stability during the process of drilling into igneous rock formations.Scholars at home and abroad have carried out a series of studies
on wellbore stability in igneous rock formations with relatively developed
fractures. Liu et al. conducted a series of experiments on igneous
rock samples from collapsed strata in the Turpan-Hami area, and the
results showed that clay minerals are widely distributed in igneous
microcracks. The drilling fluid filtrate invades the rock along the
microcracks, which leads to the hydration expansion of clay minerals
and a change in the igneous rock microstructure. Primary and secondary
microcracks can expand and merge into single cracks, which will reduce
the cohesion of the rock along the bedding plane and ultimately lead
to borehole wall instability.[3] Based on
the consideration of the igneous rock structure, Liu et al. constructed
the multidiscontinuity strength criterion and established the collapse
pressure prediction method of igneous rock formation by using the
criterion, so as to analyze the borehole wall stability of igneous
rock formation. The results show that hydration and weak plane effect
are the main factors causing the instability of the borehole wall
in igneous strata, and considering their coupling effect is the key
to establish the borehole wall stability technology.[4] Wang et al. used logging technology and field production
data to study the development types and control factors of igneous
fractures and the influence of fractures on high-quality reservoir
development and high-yield oil and gas production. The research showed
that the rock structure and supergene processes play a particularly
important role in determining the development of fractures in igneous
rocks, and these fractures have a substantial influence on wellbore
stability.[5] Han et al. proposed a safe
operation window of drilling fluid density (SOWDFD) in deep igneous
rock formations based on the leakage statistics of adjacent wells.
The law of leaky formation was revealed through a statistical analysis
of the drilling fluid density of the leaky formation group in an adjacent
igneous well, and finally, an improved SOWDFD for deep igneous formations
was established.[6] Chen et al. used a coupled
numerical analysis method to study the impact of rock mass fractures
in isotropic and anisotropic stress states on wellbore stability.
The study found that both the existence of natural fractures caused
by mud infiltration and the reduction of fracture friction angle have
a significant impact on wellbore stability.[7] Considering the influence of pore pressure propagation, in situ
stress, and wellbore pressure, Ma et al. proposed an analytical method
for predicting wellbore stability in fractured formations by using
the Hoek–Brown criterion. The results showed that the critical
mud weight calculated by the H–B criterion is higher than that
calculated by the Mohr–Coulomb criterion, which improved the
prediction ability of wellbore stability of fractured reservoirs.[8]While drilling into the igneous rock formations
of the Shunbei
area, problems such as lost circulation of the well and borehole collapse
occur frequently, which seriously hinders the efficient development
of field oil and gas resources. To solve this problem, the physicochemical
and mechanical properties of igneous rocks are tested in this study
through laboratory experiments, and the main factors affecting wellbore
stability are determined. A theoretical model for evaluating the borehole
stability in an igneous rock formation is established based on laboratory
experimental results, providing a theoretical basis for the optimization
of drilling engineering parameters for igneous rock formations.
Materials
Mineral Composition
The well block
of Shunbei is located on the northern edge of the Shuntuogole low
uplift and the southern part of the Shaya uplift. The tectonic position
and reservoir-forming conditions are superior, the structure is gentle,
and the stratum undulation is small. Under regional compression, pressure-torsion,
and tensional stresses, the faults have obvious directivity in plane
and are mainly characterized as high-angle strike-slip faults. Taking
the downhole igneous rock of the Ordovician system in the Shunbei
well area as the research object, the mineral composition was tested
using the X-ray diffraction instrument first, and the results are
shown in Table .
Table 1
Composition of Collected Samples
samples no
component
content (wt%)
quartz
feldspar
calcite
pyroxene
siderite
dolomite
clay
1
3.0
70.7
7.2
13.0
0.0
0.0
6.1
2
1.8
80.1
3.5
7.6
2.2
1.80
3.0
3
16.3
49.1
21.8
4.0
3.0
3.0
2.8
4
15.1
56.3
12.8
5.6
1.8
3.2
5.2
5
9.3
61.2
8.5
9.1
0.8
2.8
8.3
The igneous rock is mainly composed
of feldspar, containing a small
amount of quartz and calcite, and the clay mineral content is very
low.
Microstructural Characteristics of Samples
To better understand the rock properties of igneous formation in
the Shunbei region, we performed scanning electron microscopy (SEM)
and super-high magnification lens zoom 3D microscope experimental
analysis of igneous formation rocks in the Shunbei region.[9] It was found that the igneous rock microfractures
are relatively developed and not uniform in direction and that open
fractures and closed calcite-filled fractures coexist by salvaging
the underground cores, as shown in Figure .
Figure 1
Downhole core photos of igneous rocks. (a) Rock
samples without
filling fractures. (b) High-contrast image of (a). (c) Rock samples
with calcite filling fractures.
Downhole core photos of igneous rocks. (a) Rock
samples without
filling fractures. (b) High-contrast image of (a). (c) Rock samples
with calcite filling fractures.The mesostructure of the igneous rock was imaged using a stereo
microscope, as shown in Figure .
Figure 2
Stereomicroscope images of igneous rocks.
Stereomicroscope images of igneous rocks.The microfractures in the igneous rocks are relatively developed,
and most of them are open cracks without fillers, with a general width
of 0.1∼1 mm. The microstructure of the core was analyzed by
SEM, as shown in Figure .
Figure 3
SEM photos of igneous rocks (2000× and 500× magnification)
SEM photos of igneous rocks (2000× and 500× magnification)The igneous rock bedrock is relatively dense, but
unfilled fractures
or calcite-filled fractures are more developed. Honeycomb or point
clay minerals are seen between some cracks, and the crack width is
1∼3 μm. The mechanical strength between the fracture
plane mainly depends on the filling materials between the fractures.
The mechanical strength of unfilled or semifilled fractures is small,
and the weak plane effect of fractures reduces the overall mechanical
strength of igneous rocks, which means that the rock in the borehole
wall is susceptible to collapse along the fracture plane. Therefore,
the existence of fractures greatly reduces the strength of igneous
rocks (Liu et al.).[10]
Experimental Section
Experimental Methods
To determine
the main factors affecting the wellbore stability of igneous rock
formation in the Shunbei area, the physicochemical and mechanical
properties of igneous rocks were tested through laboratory experiments,
and a theoretical model for the wellbore stability evaluation of igneous
rock was established according to the results of laboratory experiments.First, the porosity and permeability parameters of downhole igneous
rocks (developed with different fracture occurrence) are tested. The
testing of rock porosity and permeability parameters can be used to
evaluate the seepage capacity of borehole wall rocks and provide basic
parameters for the dynamic change law of seepage field and stress
field between wellbore and formation in the later period. The equipment
used is a tight core gas permeability and porosity meter. Nitrogen
is used as the test medium to simulate formation pressure conditions,
and the porosity and permeability of tight cores are measured based
on Boyle’s law and Darcy’s theorem, respectively.Second, the test of hydration expansion performance of the underground
igneous rock core is carried out. Both the hydration expansion performance
and the rolling recovery rate can be used to evaluate and analyze
the hydration expansion capacity and borehole wall instability mechanism
of borehole wall rocks under downhole pressure.[11−13] The drilling
fluid used to soak the core in the experiment is a water-based drilling
fluid used in the field. The specific formula of the drilling fluid
is as follows: 4% Bentonite + 1% LV-CMC + 1% NH4HPAN + 0.2% Coated
with flocculant + 0.5% COP-HFL/LFL + 0.3% NaOH. The underground rock
core was immersed in the hydration expansion tester with the drilling
fluid for 24 h, and then the hydration expansion performance of underground
igneous rocks was evaluated and analyzed under the on-site drilling
fluid immersion environment.Finally, the mechanical properties
of underground igneous rocks
were tested. Through systematic triaxial mechanical testing, the mechanical
parameters of rocks can be accurately obtained within a downhole pressure
environment. These parameters can be used to evaluate the influence
of different drilling fluid systems, fracture development degree,
and fracture strike on the rock mechanical properties of borehole,
so as to improve the prediction accuracy of borehole stability.[14−16] The experimental equipment of this triaxial rock mechanics test
is RTR—1000 static (dynamic) triaxial rock mechanics servo
test system. The whole set of equipment consists of four parts: a
high-temperature and high-pressure triaxial chamber, a confining pressure
pressurization system, an axial pressurization system, and an automatic
data acquisition and control system. The experimental equipment is
mainly used to test the mechanical properties of standard rock samples:
compressive strength, Young’s modulus, Poisson’s ratio,
friction angle, cohesion, and other parameters. Three types of core
columns (without cracks, with calcite-filled cracks, and with unfilled
cracks) were selected for this test. The diameter of the core columns
was 25 mm, and their length was 50 mm. The rock samples were divided
into two groups, one of which was kept dry, while the other group
was immersed in the drilling fluid for 48 h. The confining pressure
of the triaxial mechanical loading experiment was 20 MPa.
Experimental Results and Discussion
Experimental
Test of Rock Porosity and Permeability
Parameters
The porosity and permeability of the Ordovician
igneous rock mass were characterized using a rock pore-permeability
tester; the test results are shown in Table .
Table 2
Test Results of Igneous
Rock Porosity
and Permeability Parameters
no
length/cm
diameter/cm
porosity
permeability/mD
sample
description
1
4.74
2.5
0.10%
1.1 × 10–4
homogeneous
without cracks
2
4.85
2.5
0.80%
3.08 × 10–3
one fracture was developed, and the calcite was completely
filled between the fractures
3
4.87
2.5
1.20%
4.72 ×
10–3
multiple fractures are developed,
which are completely filled
with calcite
4
4.92
2.5
1.50%
1.52 × 10–2
multiple fractures are developed, which are half-filled
with
calcite
5
4.93
2.5
1.90%
8.14 × 10–2
multiple fractures are developed, which are no filling
It can be seen from Table that the igneous
bedrock is dense and uniform, and the porosity
and permeability of the no cracked rock mass are extremely low, generally
10–4 mD. Fractures and pores substantially increase
the porosity and permeability of the rock mass. The permeability of
the rock with closed calcite-filled fractures is second only to that
of bedrock. As the number of fractures increases, the porosity and
permeability parameters also increase. The porosity and permeability
of rock masses with half-calcite-filled or unfilled fractures are
up to 10 times higher than that of bedrock and fully calcite-filled
rock masses. Under the action of the positive pressure difference
at the bottom of the well, fractures induce the drilling fluid to
preferentially migrate along the fractures to the rock of the borehole
wall. The pore pressure near the borehole wall increases, weakening
the supporting effect of the drilling fluid on the borehole rock.
Seepage of the drilling fluid also leads to a splitting effect on
the rock cracks in the borehole wall, causing the fractures to expand
and crack, which further lubricates the crack surfaces and weakens
the mechanical strength between the cracks (Song and Zhang).[17]
Experimental Test of
Rock Hydration Expansion
Performance Parameters
The hydration expansion performance
and rolling recovery rate of igneous rocks soaked in the field drilling
fluid for 24 h were tested, and the test results are shown in Figure .
Figure 4
Experimental results
of hydration expansion performance of igneous
rocks. (a) Expansion performance test results; (b) rolling recovery
test results.
Experimental results
of hydration expansion performance of igneous
rocks. (a) Expansion performance test results; (b) rolling recovery
test results.The Ordovician igneous rock in
the Shunbei well area has a low
hydration expansion performance, with the expansion strain under the
condition of drilling fluid immersion lower than 1.2%, and the rolling
recovery rate is generally higher than 82%. The experimental results
show that the Ordovician igneous rock is relatively dense and hard,
with a low clay mineral content and weak hydration expansion and dispersion
performance.
Experimental Testing
of Mechanical Properties
The mechanical performance parameters
of the rock samples were
tested, and the experimental results are shown in Table , and the influence of cracks
and the effects of immersion in the drilling fluid on the mechanical
properties of igneous rocks were analyzed.
Table 3
Experimental
Results of Triaxial Mechanics
of Igneous Rocks
experiment condition
no
confining pressure/(MPa)
compressive strength/(MPa)
elasticity modulus/(MPa)
Poisson ratio
core description
dry sample
1
20
189.7
17,094.4
0.16
homogeneous
sample
2
60.05
7481.6
0.15
filling fracture development
3
48.68
4936.1
0.14
no filling fracture development
drilling fluid immersion
4
20
178.6
16,321.5
0.16
homogeneous sample
5
51.3
7060.1
0.15
filling fracture development
6
40.4
4521.3
0.14
no filling fracture development
As can be seen in Table , the compressive strength and elastic modulus
of homogeneous
unfractured igneous rocks are high, while those of both filled and
unfilled fractured rocks are low (1/3∼1/4 of the strength of
homogeneous unfractured igneous rocks). The existence of cracks greatly
affects the mechanical strength of igneous rocks. The strength of
the rock mass with calcite-filled closed fractures is slightly higher
than that of the rock mass with unfilled fractures. Because the clay
mineral content in igneous rocks is very low, immersion in the drilling
fluid has little effect on the mechanical parameters, and the mechanical
strength of the rocks is only slightly reduced after immersion. By
observing the rock sample after the triaxial mechanical test, it can
be seen that igneous rocks containing unfilled or calcite-filled cracks
are damaged by external force, and the rock samples are preferably
damaged along the direction of the crack, and the failure surfaces
almost coincide with the fracture planes. This indicates that the
rock mechanical strength of both open and filled fractures is low,
and failure along the fracture is preferred under the action of a
high external-stress environment. Based on the experimental results,
hydration has little effect on the mechanical properties of igneous
rock and the stability of the borehole wall. The fractures in igneous
rocks are relatively developed, and the mechanical weak plane effect
of the fractures is the main factor affecting borehole wall collapse.
The fracture conductivity of igneous rocks is strong, and the pressure
penetration of the drilling fluid along the fracture further affects
wellbore stability.[18,19]
Calculations
Laboratory tests have shown that the Ordovician igneous bedrock
in the Shunbei well area is very dense, with high rock mechanical
strength and wellbore stability. However, the microfractures of the
igneous rock are very well developed, and the rock mechanical strength
is obviously subject to the weak plane effect of fracture mechanics.
The mechanical strength of rock samples with microfractures is lower
than that of bedrock. Microfractures also provide channels for the
drilling fluid to filter into the formation, which is the main cause
of downhole leakage. To determine the main controlling factors of
borehole collapse instability in the Ordovician igneous formation,
the effect of the in situ stress field, the weak plane effect of rock
microfractures, and the effect of the seepage of drilling fluid on
the borehole wall collapse pressure were evaluated and analyzed. First,
the effect of drilling fluid seepage along microfractures on the pore
pressure distribution and the effective stress of formation near the
borehole wall is evaluated and analyzed.
Influence
of Wellbore-Formation Seepage on
Formation Effective Stress
Establishment of a Gas–Liquid
Two-Phase
Seepage Equation
At present, most igneous reservoirs are
gas reservoirs. Therefore, the establishment of a gas–liquid
two-phase seepage model during the drilling process is considered
to evaluate the influence on wellbore stability. During the drilling
process, the sum of the water-phase saturation and the gas-phase saturation
in the region of borehole formation should be 1:where Sw is the water-phase saturation and Sg is the gas-phase saturation.The capillary
force on
the water-air two-phase interface is calculated as follows:where Pc is the capillary
force, Pw is
the water-phase pressure, and Pg is the
gas-phase pressure (all in MPa).The rock skeleton and the water
near the borehole wall are considered
incompressible, while the gas is compressible in the evaluation of
the water-gas two-phase seepage. The flow of water and gas satisfies
Darcy’s law and the formation pores near the borehole wall
are entirely filled with water and gas. The equations used to describe
the movement of the water and air are as follows:where K0 is the absolute permeability, Krw(Sw) is the water-phase relative permeability, Krg(Sg) is the gas-phase
relative permeability, μw is the water-phase viscosity,
and μg is the gas-phase viscosity.The continuity
equations are as follows:where ρw is
the water density and ρg is the gas density, both
in kg/m3.Because the water is incompressible, ρw is a constant,
while for the compressible gas, ρg is related to
the gas pressure by a constant ratio at a given temperature. Therefore,
the gas pressure can be used to eliminate the gas density value, resulting
in the formula:Substituting eq into eq and eq into eq yields:The initial conditions are:and
the boundary conditions are:where t is the water-phase
intrusion time (s), Sw0 is the initial
water-phase saturation, Pw0 is the initial
water-phase pressure (MPa), Pg0 is the
initial gas-phase pressure (MPa), Pc(Sw0) is the capillary force at initial water
saturation (MPa), Smaxw is the maximum
water saturation, Pmud is the annulus
pressure, (MPa), and Pc(Smaxw) is the capillary force at maximum water saturation
(MPa).Based on the formula established above, the relationship
between
the pressure and radial distance of the water and gas phases at different
times was plotted (Figure ).
Figure 5
Relationships between (a) water-phase pressures and radial distance
for different times and (b) gas-phase pressures and radial distance
for different times.
Relationships between (a) water-phase pressures and radial distance
for different times and (b) gas-phase pressures and radial distance
for different times.As time increases, the
water and gas two-phase pressures increase
near the borehole. As the radial distance increases, the pressures
decrease. Beyond a certain radial distance, the pressures tend to
be constant. Thus, the relationship diagram of the water-phase invasion
distance with immersion time was plotted (Figure ).
Figure 6
Relationship between the water-phase intrusion
distance and time.
Relationship between the water-phase intrusion
distance and time.As time passes, the distance
of the water-phase intrusion into
the formation increases, and the intrusion speed gradually decreases,
eventually reaching a certain depth of invasion where the water no
longer advances.
Influence of Seepage
on the Effective Stress
of the Borehole Wall
Because of the development of microfractures
in the Ordovician igneous rocks, the influence of fluid migration
along the microfractures on the effective stress should be considered
in the evaluation and analysis of wellbore stability.[20]The seepage migration of the drilling fluid along
microfractures will affect the pore pressure near the borehole wall,
which will inevitably change the effective stress distribution in
the borehole wall zone.[21,22] The following formula
can be used to evaluate and analyze the effective stress distribution
near the borehole wall zone:where σr′, σθ′,
and σz′ are the effective radial stress, circumferential stress, and axial
stress, respectively (MPa); σv, σH, and σh are the overburden pressure, maximum horizontal
principal stress, and minimum horizontal principal stress, respectively
(MPa); τrθ, τrz, and τθz are the shear stress components of the formation around
the well (MPa); pw is the liquid column
pressure of the wellbore (MPa); rw is
the borehole radius (m); r is the radius between
any position point around the well and the borehole axis (m); θ
is the well circumference angle (degrees); a is the
effective stress coefficient (dimensionless); andpp(r, t) is the formation
pore pressure at time t when the distance from the
borehole wall is r.Based on the mathematical
formula established above, the effective
stress distribution near the borehole wall zone was evaluated and
analyzed (Figure ).
Figure 7
Distribution
of effective stress near the borehole wall.
Distribution
of effective stress near the borehole wall.As the seepage of the drilling fluid migrates to the formation,
the effective circumferential and radial stresses acting on the rock
of the borehole wall change significantly. The seepage migration of
drilling fluid causes the formation pore pressure to increase. With
more time, the effective circumferential and radial stresses gradually
decrease, and the scope of influence gradually expands. As the radial
distance of fluid intrusion into the formation increases, the effective
stress will eventually be equal to the original formation pressure.
Wellbore Stability Evaluation of Igneous Rock
Formation
Influence of the Weak Plane Effect of Fractures
on Wellbore Stability
Fracture development greatly reduces
the mechanical strength of igneous rocks. Therefore, the weak plane
effect of fractures has a substantial influence on the borehole stability
of an igneous formation.The Jaeger criterion for weak surfaces
is often used to characterize the effect of fractures on the mechanical
properties of rock masses. The strength criterion of weak rock failure
is:[23]with:where σ1 is the maximum horizontal principal stress (MPa), σ3 is the minimum horizontal principal stress (MPa), Cw is the cohesion of the weak plane (MPa), φw is the internal friction angle of the weak plane (degrees),
and δ is the angle between the weak plane normal and the maximum
principal stress (degrees).If the above conditions are not
met, rock failure follows the Mohr–Coulomb
criterion:[24]where C0 represents the rock cohesion (MPa) and φ0 represents the internal friction angle of the rock (degrees).According to the stress field established above and considering
the seepage field, the equation for the collapse pressure of the borehole
is shown below:among them, K = .Based on the in situ stress and rock mechanical
parameters obtained
from the experimental tests, the collapse pressure equivalent density
of igneous formation was evaluated and analyzed, as shown in Figure .
Figure 8
Collapse pressure equivalent
density distribution of igneous strata
(considering in situ stress and mechanical strength of bedrock).
Collapse pressure equivalent
density distribution of igneous strata
(considering in situ stress and mechanical strength of bedrock).When the in situ stress and bedrock mechanical
parameters are considered,
without accounting for factors such as the crack weak plane effect
and the seepage effect, the maximum equivalent density of the collapse
pressure is about 1.42 g/cm3 in the 90° and 270°
directions, namely, the direction of minimum horizontal principal
stress. In the direction of maximum horizontal principal stress, the
equivalent density of collapse pressure is the lowest, with a value
of about 0.58 g/cm3.As can be seen from the salvaged
cores, the Ordovician igneous
microfractures are relatively well developed in the Shunbei well area,
and the directions and angles of microfracture development (the angle
between the normal direction of the microfracture plane and the direction
of the maximum horizontal principal stress) are not uniform. A schematic
diagram of igneous strata with relatively developed microfractures
was drawn (Figure ).
Figure 9
Schematic diagram of igneous formation with microfracture development.
Schematic diagram of igneous formation with microfracture development.In combination with eq. –18, the influence
of multiple
fractures with different angles between the normal direction of the
microfracture plane and the direction of the maximum horizontal principal
stress on wellbore stability in igneous formations is evaluated and
analyzed, and the results are shown in Figure .
Figure 10
Collapse pressure equivalent density distribution
of igneous strata
with different fracture occurrence.
Collapse pressure equivalent density distribution
of igneous strata
with different fracture occurrence.The equivalent density of the collapse pressure is about 1.4 g/cm3 without considering drilling fluid seepage and the weak plane
effect. As the number of fractures increases, the weak plane effect
of the microfractures more strongly influences the equivalent density
of the collapse pressure around the igneous formation. When the angle
between the normal direction of a fracture and the maximum horizontal
principal stress is 30°, the equivalent density of the collapse
pressure is relatively low. When the angle between the normal direction
of a fracture and the maximum horizontal principal stress is 90°,
the equivalent density of the formation collapse pressure is as large
as 1.72 g/cm3, and the borehole wall is most likely to
collapse. The effects on wellbore stability from the development of
single fractures around the borehole depend strongly on the development
angle of the fracture. As the number of fractures at different angles
increases, the maximum values of the collapse pressure equivalent
density curves generated by the various angles merge to form the top
curve. The trend of the curve is similar to that of the collapse pressure
equivalent density distribution curve of homogeneous formation calculated
with the Mohr–Coulomb criterion. It can therefore be inferred
that, when there are sufficient disordered fractures around the borehole
and the formation is very fragmented, and the rock mechanics parameters
of the fractured formation can be obtained through experimental testing;
the corresponding equivalent density of the formation collapse pressure
can be calculated according to the Mohr–Coulomb criterion.An evaluation and analysis of the increase in the equivalent density
of the formation collapse pressure due to the weak plane effect caused
by multiple fractures with different development angles around the
borehole were performed (Figure ).
Figure 11
Influence of the weak plane effect of fracture on collapse
pressure
equivalent density of igneous formation.
Influence of the weak plane effect of fracture on collapse
pressure
equivalent density of igneous formation.The weak plane effect of the fractures has a substantial impact
on the equivalent density of the collapse pressure of igneous strata
around the well. The effect is dependent on the angle between the
normal direction of the microfracture plane and the direction of the
maximum horizontal principal stress. At 65° and 245°, the
maximum value of the collapse pressure equivalent density of the igneous
formation is 1.72 g/cm3. Accounting for the weak plane
effect of the fractures causes an increase of 21% in the calculated
collapse pressure equivalent density of igneous strata, demonstrating
the obvious impact of the presence of fractures.
Effect of Drilling Fluid Hydration on Wellbore
Stability
Laboratory tests show that igneous bedrock contains
a small amount (2∼8%) of clay. The influence of the hydration
effect on the collapse pressure equivalent density of igneous strata
was comparatively analyzed (Figure ).
Figure 12
Influence of the hydration effect on collapse pressure
equivalent
density of igneous formation.
Influence of the hydration effect on collapse pressure
equivalent
density of igneous formation.The equivalent density of the collapse pressure of igneous strata
increases slightly when the hydration effect is considered. The equivalent
density of the formation collapse pressure increased to 1.45 g/cm3, an increase of 2% compared with the equivalent density of
formation collapse pressure considering only the ground stress and
the bedrock mechanical strength.
Influence
of the Seepage Effect of the Drilling
Fluid on Wellbore Stability
The weak plane effect of relatively
developed microfractures in igneous rock formations reduces wellbore
stability. Simultaneously, when the igneous rock formation is drilled
out, the drilling fluid migrates along the microfractures under the
action of the positive bottomhole differential pressure, which leads
to an increase in pore pressure near the borehole wall and weakening
the effective support of the drilling fluid on the borehole wall,
and further reducing wellbore stability in the igneous rock formation
(Cui et al.).[25] Therefore, the seepage
migration of the drilling fluid along microfractures is also a key
factor affecting borehole stability in igneous formations. Based on
the laboratory test results, the influence of drilling fluid seepage
migration along microfractures on borehole wall stability was evaluated
and analyzed (Figure ).
Figure 13
Influence of the seepage effect of the drilling fluid on wellbore
stability of igneous formation. (a) Without considering the weak plane
effect of fracture. (b) Considering the weak plane effect of fracture.
Influence of the seepage effect of the drilling fluid on wellbore
stability of igneous formation. (a) Without considering the weak plane
effect of fracture. (b) Considering the weak plane effect of fracture.It can be seen from Figure that drilling fluid seepage along microfractures
increases
the collapse pressure of igneous formations and decreases the stability
of the borehole wall. The maximum collapse pressure equivalent density
of the igneous formation is 1.58 g/cm3 in the 90°
and 270° directions when considering only the drilling fluid
seepage effect, an increase of 11% compared with the collapse pressure
equivalent density of the bedrock. When both the weak plane effect
of the fractures and the seepage effect of drilling fluids are considered,
the collapse pressure equivalent density of igneous rock formations
is further increased. In the directions of 65° and 245°,
the collapse pressure equivalent density of igneous rock formations
has a maximum value of 1.811 g/cm3, a relative increase
of 27.5%. The existence of fractures and the seepage of the drilling
fluid along microfractures substantially increase the collapse pressure
equivalent density.The theoretical calculation and analysis
have shown that wellbore
stability in the Ordovician igneous formation in the Shunbei well
area is the result of the combined influence of multiple factors with
different ranges of influence. The order of the influence range of
these factors is the weak plane effect of microfractures + the seepage
effect of drilling fluid (27.5%) > the fracture weak plane effect
(21%) > the drilling fluid seepage effect (11%) > the clay hydration
effect (2%). Therefore, the main controlling factors affecting the
Ordovician igneous rock formation in the Shunbei well area are the
weak plane effect of the fractures and the seepage effect of the drilling
fluid.The physical, chemical, and mechanical performance parameters
of
the Ordovician downhole igneous rock in the Shunbei well area were
tested experimentally, and a theoretical model was established to
evaluate the stability of the igneous rock formation. The weak plane
effect of the fractures in the igneous rock and the effect of drilling
fluid seepage increase the equivalent density of the borehole wall
collapse pressure up to about 1.811 g/cm3, making it necessary
to optimize the drilling fluid density to meet the stability requirements
for the borehole wall. Wellbore stability is better when drilling
along the direction of the maximum horizontal principal stress. Downhole
imaging logging is recommended to determine the width and density
of microfractures in the downhole pressure environment and the particle
size and gradation of the plugging material to select the appropriate
drilling fluid. The optimized design of drilling fluid rheology and
the improvement of rock carrying capacity can prevent rocks from falling
off the borehole wall and accumulating at the bottom of the well,
which can prevent downhole resistance.
Conclusions
Through experimental tests and theoretical analysis,
the microscopic
fabric, the physical and chemical properties, and the rock mechanical
parameters of the Ordovician underground igneous rocks in the Shunbei
well area were studied. The mechanisms of collapse and instability
of the igneous rock formation and the main control factors for the
instability were determined. An evaluation model for wellbore stability
in igneous rock formations was established, and the following conclusions
and understandings were obtained:The Ordovician igneous rocks in the
Shunbei well area are mainly feldspar, with a small amount of quartz
and calcite and a low clay mineral content. The Ordovician igneous
rocks in the Shunbei well area are relatively well developed with
open fractures and calcite half-filled and fully filled fractures.The Ordovician igneous
rocks in the
Shunbei well area demonstrate weak hydration and expansion ability
and high rolling recovery. The igneous rock bedrock has high rock
mechanical strength, while the rock samples with developed microcracks
have low mechanical strength. Immersion in the drilling fluid has
little effect on the mechanical strength of igneous rock, and the
effects of hydration have little influence on wellbore stability in
igneous rock formations.The Ordovician igneous rock formation
in the Shunbei well area has relatively developed microfractures,
with the weak plane effect of the fractures increasing the formation
collapse pressure equivalent density to 1.72 g/cm3, which
seriously affects the stability of the borehole wall. The seepage
migration of fluid between microfractures weakens the effective support
of the drilling fluid for the borehole wall, leading to an increase
of stratum collapse pressure and the deterioration of the borehole
wall stability.Considering
the weak plane effect
of the igneous microfractures and the seepage effect of the drilling
fluid, the well trajectory should be optimized and the drilling fluid
density should be controlled at about 1.82 g/cm3 during
the actual drilling process. At the same time, the effective plugging
ability of the drilling fluid should be improved and the rheological
property of the drilling fluid should be optimized so as to improve
the rock-carrying ability of the drilling fluid in the drilling process
of microfracture formation.
Figure 1
Figure 2
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Figure 4
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Figure 7
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Figure 11
Figure 12
Figure 13