# Fine Depicting of Seepage Barrier for Gas Flooding in the Lower Wuerhe Formation Reservoir of the 8th District in China

Authors: Zhibin Jiang; Hongming Tang; Rui Shen; Xiaoguang Wang; Wei Zhou; Liming Lian; Lisha Qi; Dan Xie; Chuanchuan Qian; Jie Wang; Xiao Liu; Qiyao Liu
Journal: Geofluids
 (2022)

---

## Abstract

The lower Wuerhe formation reservoir of the 8th district is a blocky, ultra-low-permeability gravel reservoir with poor waterflooding development, and it is urgent to attack the gas injection gravity flooding. The barrier property of seepage barriers such as interlayers developed inside the reservoir is very important for the study of gas injection gravity flooding. The mineral composition, pore throat structure, and physical characteristics of the interlayer rocks were studied by X-ray diffraction (XRD) whole-rock analysis and nuclear magnetic resonance (NMR). The gas injection breakthrough pressure of the interlayer was studied by core breakthrough experiment and digital core simulation. Based on the determination of the interlayer criteria, logging was used to interpret and characterize the interlayer. The effects of different types of interlayer combinations on gas injection were studied by combining the physical model and numerical simulation methods. The results showed that the lithology of the interlayer in the lower Wuerhe formation of the 8th district was mainly mud-bearing fine gravel with microporosity, average porosity of 6.1% and permeability of 0.0043 mD. The interlayer gas injection breakthrough pressure and permeability were in a logarithmic linear relationship, and the lower limit of gas injection breakthrough under reservoir conditions was 0.003 mD. Initially, it is difficult to flood the upper remaining oil of the gas injection due to the blockage of the interlayer, while in the middle and late stage, the gas-liquid interface gradually reached stability with the increase in injected gas, which has little impact on the final recovery. These results indicate that it is feasible to carry out gas injection gravity flooding in this reservoir.


---

## Body

## 1. Introduction

Gas flooding technology is considered to be an important technology for sustainable and stable production in the late stage of waterflooding development of low-permeability reservoirs and effective development of unconventional hard-to-recover reservoirs such as tight oil and shale oil [1–3]. During the implementation of gas flooding technology, it is also necessary to focus on the differences between gas flooding and water flooding, such as the limit of activation and seepage patterns [4, 5], and the key technologies such as the fine depicting of gas flooding flow units and dominant channels [6], quantitative evaluation of interlayer barrier, and the effect of residual oil distribution on gas flooding effect [7]. Due to the influence of terrestrial sedimentation, domestic reservoirs usually have a large number of longitudinal interlayers, and in this situation, quantitative evaluation of the interlayer barrier is necessary for gas flooding (especially top gas injection gravity flooding) [8].The current research on the interlayer sealability of gas injection is rarely reported, combined with the characteristics of the interlayer, which is similar to oil and gas reservoir caprock; usually, the most common caprock is mud shale, its porosity and permeability are very low, and the two have similarity around sealability research. In 1966, Smith began to explore the problem of cap sealability and proposed the concept of cap and fault sealability [9]. In 1987, Watts proposed the hydraulic sealability and capillary sealability mechanism, after which a large number of different scholars successively proposed new sealability mechanisms such as hydrocarbon concentration and overpressure, while experimental methods for cap sealability evaluation were established for a variety of sealability mechanisms [10]. In 1995, Li systematically classified capillary sealability mechanisms into physical sealability, hydrocarbon concentration sealability, and overpressure sealability [11]. Fu et al. further analyzed and summarized the sealability mechanism of mud shale caprock; that is, the sealability mechanism is usually considered capillary force sealability where higher discharge pressure prevents hydrocarbon diffusion, pressure sealability where abnormally high pressure prevents hydrocarbon escape, and concentration sealability where high concentration of hydrocarbon prevents hydrocarbon diffusion from the reservoir [12, 13]. The failure and damage of the coal seam can be achieved because of the soil and water loss caused by thermal enhanced methane recovery. During heat injection, the permeability of the coal seam increases with distance from the borehole due to the competition between two-phase flow and temperature. Owing to complex fracture geometry, the fracture permeability evolution presents certain heterogeneity, which is related to fractal dimension, in situ stress, and geothermal well layout [14, 15]. The above researches have some reference value. However, in general, there is still a gap in the research on the sealability of the interlayer, especially from the microscopic sealability mechanism to the macroscopic influence of the interlayer on the gas injection interface and recovery enhancement, which has become a key scientific problem that seriously restricts the application of gas flooding technology in the field [16–21].This paper has taken the lower Wuerhe formation reservoir of the 8th district as the research area and obtained the basic understanding of the type of internal seepage barrier and the lower limit of gas flooding breakthrough in extra-low-permeability gravel reservoir through experimental and digital core simulation methods at the microscopic level and then, on the above basis, studied the effects of gas flooding in the field through geological modeling and numerical simulation at the macroscopic level. This study can provide technical support for the implementation of gas injection and gravity stabilization flooding in the reservoir by combining the microscopic and macroscopic research results to deepen the basic and application understanding of interlayer sealability.


## 2. Experimental Samples

Two sizes of rock samples were used in the experiment, one of which was a full-diameter rock sample and the other was a plunger rock sample of about 2.5 cm in diameter. According to the remarks in Table1, it is known that these rock samples were either taken from the interlayer section or from the reservoir section.Table 1
Basic information of full-diameter rock samples.
Sample numberDiameter (cm)Original length (cm)Original weight (g)RemarksJW32-110.3410.092117.60InterlayerJW32-210.328.501862.70InterlayerJW32-310.358.151837.90InterlayerJW32-410.338.671865.30InterlayerJW32-510.3413.132743.10Interlayer8545-19.4113.392243.60Interlayer8545-29.3913.472336.70Interlayer8545-38.6715.112168.80Interlayer8545-49.3215.092498.90Interlayer8545-59.316.731354.90Interlayer8545-69.1713.822166.90Interlayer8545-79.386.231045.60Interlayer8545-89.4315.702658.40Interlayer8545-99.4116.702712.70Interlayer8545-109.488.651414.70Interlayer8545-119.4616.402728.30Interlayer8545-129.4415.202511.20Interlayer805-16.7313.201085.70Interlayer805-26.6815.801279.90Interlayer805-36.6234.002899.50Interlayer805-46.6313.701154.40Interlayer85095-12.56.1465.91I kind of reservoirBai 864-12.59.60111.01I kind of reservoir85095-22.59.50105.69II kind of reservoirBai 864-22.59.46105.14II kind of reservoir8545-142.59.25103.51III kind of reservoir8545-152.59.50104.28III kind of reservoir8545-172.59.00100.24Interlayer8545-182.59.00102.47InterlayerThe first-size full-diameter rock sample and the second-size plunger rock sample were cut and ground separately, and4.5cm×4.5cm×4.5cm cubic cores (Figure 1) and plunger cores of about 2.5 cm in diameter were drilled, which will be used for subsequent gas injection breakthrough pressure experiments. Several samples were selected from the full-diameter rock samples, and plunger cores with 1 inch in diameter were drilled and cut from them. These standard 1-inch plunger cores will be tested separately for basic experiments such as cast thin section, XRD lithology analysis, high-pressure mercury injection, NMR, and micro-CT scanning.Figure 1
Photos of cubic cores before and after being drilled and cut on full-diameter rock samples.


## 3. Research Methods

For the cores treated above, the experimental flow is shown in Figure2. On the one hand, the porosity and permeability tests are carried out for some cores, and then, the gas injection breakthrough pressure evaluation tests are carried out for them. On the other hand, the mineral distribution and pore structure tests are carried out for other cores. Then, on this basis, the pore network simulation for gas injection sealability is carried out with a digital core model. Finally, the breakthrough pressure of gas injection for the interlayer of the target reservoir is evaluated by comprehensive petrophysical experiment and microphysical simulation.Figure 2
Experimental flow.Some basic test methods involved in the experimental flow above are introduced below.


### 3.1. XRD Lithology Analysis

The equipment for the core XRD lithology analysis experiment is the D8 DISCAPROCK X-ray diffractometer from Bruker, as shown in Figure3. The relevant technical parameters of the instrument are as follows: rated output power is 3 kW, current-voltage stability is better than ±0.005%, light tube type is Cu target, ceramic X-ray tube power is 2.2 kW, scanning mode is θ/θ goniometer, accuracy is 0.0001°, angular reproducibility is 0.0001°, maximum scanning speed is 1500°/min, and 2θ rotation ranges from -10° to 168°.Figure 3
D8 DISCAPROCK X-ray diffractometer.


### 3.2. Conventional Porosity and Permeability Analysis

The equipment for core porosity and gas permeability testing is the core pore permeameter of Jiangsu Tuochuang Scientific Research Instrument Co., Ltd., as shown in Figure4. The core pore permeameter is divided into two parts, namely, the core porosity tester and the core permeability tester. The core porosity tester is designed based on Boyle’s law, which measures the inlet pressure and equilibrium pressure value in the process through the pressure sensor, and firstly, the calibration volume value of the instrument system is measured by a number of standard blocks of known volume, and then, according to the experimental data put into the core test to obtain the skeleton volume and the porosity of the core, the technical parameters of this part are as follows: the applicable core specification is about 2.5 or 3.8 cm in diameter and 3-10 cm in length, the gas source is helium, the test pressure is 0.4 MPa, the power supply voltage is 220 V, the frequency is 50 Hz, and the measurement accuracy is ≤0.5%. The core permeability tester is designed based on Darcy’s law, which makes nitrogen gas flow through the core under a certain pressure and measures the pressure difference and flow rate at both ends of the core after the gas reaches stable flow in the core and calculates the gas permeability of the core through Darcy’s law; the technical parameters of this part are as follows: the applicable core specification is about 2.5 or 3.8 cm in diameter and 3-10 cm in length, the gas source is nitrogen gas, the test pressure is 0.6 MPa, the power supply voltage is 220 V, the frequency is 50 Hz, the permeability measurement ranges from 0.0005 to 10000 mD, and the measurement accuracy is ≤1%.Figure 4
Core conventional pore permeameter.


### 3.3. Pore Structure Characterization

For the characteristics of the interlayer cores, various scale pore structure characterization methods were used, including high-pressure mercury injection, nuclear magnetic scanningT2 distribution, and micro-CT scanning. Among them, the testing equipment of high-pressure mercury injection is the 9500-model automatic mercury injection instrument of American Mike Company, as shown in Figure 5; the prepared core was put into the mercury injection instrument, under the difference between the two ends, a certain volume of mercury will be injected into the tested rock pores, and according to the change of pressure rise and fall and the corresponding change of the rise and fall of the volume of mercury entering the rock, the pore size and distribution curve of the rock can be measured. The entry-exit capillary pressure curves of the rock were plotted, and after further calculation, other pore structure characteristic parameters of the sample can be derived, and the relevant technical parameters of the mercury injection instrument are as follows: the pressure range is 0-30000 psi and the minimum detection pore throat radius is 3.6 nm.Figure 5
The 9500-model automatic mercury injection of American Mike Company.The detection equipment of NMR scanT2 distribution is the core NMR analyzer Meso-MR23 of Suzhou Newmark Analytical Instruments Co., Ltd., as shown in Figure 6. NMR inverse calculates the fluid properties and its content in the pore by observing the signal intensity of hydrogen NMR, and the relevant technical parameters of the NMR analyzer are as follows: the instrument main frequency is 21 MHz, the minimum echo interval is 60 μs, the probe size is 1/1.5 in, and the maximum sample size is 2.54 cm in diameter and 5 cm in length.Figure 6
Core NMR analyzer.The detection equipment for micro-CT scanning of cores is the Phoenix V|tome|xs type micro-CT scanner, as shown in Figure7, X-ray CT is used to penetrate the object with conical X-rays, the image is magnified by different magnifications of the objective lens, and a three-dimensional model is reconstructed from a large number of X-ray attenuation images obtained by 360-degree rotation. The CT images reflect the energy decay of X-rays during penetration, so the 3D CT images can truly reflect the internal pore structure and relative density of the core. The relevant technical parameters of the micro-CT scanner are as follows: the sample size is 1-70 mm in diameter, the voltage is 20-240 kV, the electron beam current is 50-150 μA, and the pixel size is 0.7-40 μm. The pore throat characteristics of the interlayer cores were analyzed by combining the above three methods.Figure 7
V|tome|xs micro-CT scanner.


### 3.4. Numerical Simulation

#### 3.4.1. Conservation of Mass

A generalized conservation equation of mass components and energy in the porous continuum can be written as follows [1]:
(1)∂φ∑αραSαXαi+Rsii∂t=−∑α∇⋅ραXαi⋅−kkrαμα∇Pα−ραg∇z+∑α∇⋅αTα−kkrαμα⋅∇Pα−ραg∇zδij+αLα−αTα⋅−kkrα/μα∇Pα−ραg∇z2−kkrα/μα∇Pα−ραg∇z+φSατdαkδij⋅∇ραXαi+qi,where i is the index for the components, i=1,2,3,⋯,Nc; k=Nc+1 for energy; Mi is the accumulation term of component k; qi is an external source/sink term; Fi is the “flow” term of mass or energy; α is the phase indicator; g is the gas; o is the oil; w is the water; ϕ is the porosity; ρα is the density of phase α; Sα is the saturation of phase α; Xαi is the mass content of component i in phase α; Rsi is the adsorption term of component k on rock solids; αTα,αTα are the transverse and longitudinal dispersion coefficient, respectively; τ is the tortuosity; dαi is the molecular diffusion coefficient of phase α; and δij is the Kronecker delta function (if i=j, then δij=1; otherwise, δij=0).The solution procedure is fully implicit.


#### 3.4.2. Equations of State

The Peng-Robinson equation has been chosen as the equation of state (EOS) in the simulation procedure of the multiphase compositional model.(2)p=RTVi−b−aTVi+ubVi+wb,where p is the pressure of the system (Pa), T is the temperature of the system (K), Vi is the volume of the component i (m3/kmol), and R is the molar gas constant (8.314×103m3·Pa/kmol·K).The RK mixing rule of the vdW type has been chosen in the simulation procedure of hydrocarbon mixture.(3)am=∑i∑jyiyjaiaj1/21−kij,bm=∑iyibi,where am,bm are gravitation and repulsion coefficients of mixture, respectively, and kij is the binary mutual act coefficient of components i and j.The flash equation consists of correlation equations and limiting conditions, which could be derived into the Rachford-Rice equation and solved with the Newton-Raphson method.(4)∑iyi−xi=∑iZiKi−11+NVKi−1=∑iZiKi−1Ki−NLKi−1=0,where yi,xi are molar contents of component i in the vapor phase and liquid phase, respectively; NV,NL are the molar volume of component i in the vapor phase and liquid phase, respectively; Zi is the molar contents of component i; and Ki is the phase equilibrium constant.


#### 3.4.3. Constitutive Relations and Boundary Conditions

To complete the mathematical description of multiphase flow, multicomponent transport, and diffusion in porous media, a generalized mass- and energy-balance equation needs to be supplemented with a number of constitutive equations.To express constraints of physical processes, variables, and parameters, boundary conditions are also necessary to make the governing equations solvable.Saturation of phaseα is constrained on summation of total fluid saturation.
(5)∑αSα=1.Mole fraction of phaseα is constrained on summation of total mole fraction of component i.
(6)∑iXαi=1.The relative permeability and the capillary pressure of a fluid phase in a multiphase system are normally assumed to be functions of fluid saturation.(7)krα=krαSα,pcα=pcαSα.Density and viscosity of a fluid phase are treated as a function of pressure, temperature, and mass compositions.(8)ρα=ραP,T,Xαi,μα=μαP,T,Xαi.Porosity is the effective porosity constrained on a reference porosity at a reference pressure and temperature, whileCr is the compressibility coefficient.
(9)ϕ=ϕ01+CrP−P0.


#### 3.4.4. Parameter Determination and Numerical Simulation Input

In this paper, intersecting numerical simulation software is used to establish a model based on the practical geology data of the test well.The geometric size of the model is700m×1300m×10m with a plane grid step of 50 m and a longitudinal grid step of 10 m; a reservoir porosity is 12.3% with an average horizontal permeability 1.0 mD and the vertical permeability 0.1 mD; the original oil saturation is 56%; the original formation pressure is 13 MPa, and the original formation temperature is 345 K.A 5-point injection-production well pattern is designed to be used with well spacing 130 m; horizontal wells are also selected with a horizontal section length 900 m; half length of the artificial fracture is 150 m, and the total fracturing section is 8; the local grid encryption (LGR) technique is used to develop fine description on grids with fractures; the equivalent conductivity method is used to determine the fracture mesh width (0.1 m) and permeability (200 mD).Dual control is applied in constant liquid volume and bottom hole pressure (>the bubble point pressure) referring to the practical production situation. Development mode of asynchronous periodic even injection and odd production is calculated in simulation of the five-point horizontal well pattern and single horizontal well.


## 3.1. XRD Lithology Analysis

The equipment for the core XRD lithology analysis experiment is the D8 DISCAPROCK X-ray diffractometer from Bruker, as shown in Figure3. The relevant technical parameters of the instrument are as follows: rated output power is 3 kW, current-voltage stability is better than ±0.005%, light tube type is Cu target, ceramic X-ray tube power is 2.2 kW, scanning mode is θ/θ goniometer, accuracy is 0.0001°, angular reproducibility is 0.0001°, maximum scanning speed is 1500°/min, and 2θ rotation ranges from -10° to 168°.Figure 3
D8 DISCAPROCK X-ray diffractometer.


## 3.2. Conventional Porosity and Permeability Analysis

The equipment for core porosity and gas permeability testing is the core pore permeameter of Jiangsu Tuochuang Scientific Research Instrument Co., Ltd., as shown in Figure4. The core pore permeameter is divided into two parts, namely, the core porosity tester and the core permeability tester. The core porosity tester is designed based on Boyle’s law, which measures the inlet pressure and equilibrium pressure value in the process through the pressure sensor, and firstly, the calibration volume value of the instrument system is measured by a number of standard blocks of known volume, and then, according to the experimental data put into the core test to obtain the skeleton volume and the porosity of the core, the technical parameters of this part are as follows: the applicable core specification is about 2.5 or 3.8 cm in diameter and 3-10 cm in length, the gas source is helium, the test pressure is 0.4 MPa, the power supply voltage is 220 V, the frequency is 50 Hz, and the measurement accuracy is ≤0.5%. The core permeability tester is designed based on Darcy’s law, which makes nitrogen gas flow through the core under a certain pressure and measures the pressure difference and flow rate at both ends of the core after the gas reaches stable flow in the core and calculates the gas permeability of the core through Darcy’s law; the technical parameters of this part are as follows: the applicable core specification is about 2.5 or 3.8 cm in diameter and 3-10 cm in length, the gas source is nitrogen gas, the test pressure is 0.6 MPa, the power supply voltage is 220 V, the frequency is 50 Hz, the permeability measurement ranges from 0.0005 to 10000 mD, and the measurement accuracy is ≤1%.Figure 4
Core conventional pore permeameter.


## 3.3. Pore Structure Characterization

For the characteristics of the interlayer cores, various scale pore structure characterization methods were used, including high-pressure mercury injection, nuclear magnetic scanningT2 distribution, and micro-CT scanning. Among them, the testing equipment of high-pressure mercury injection is the 9500-model automatic mercury injection instrument of American Mike Company, as shown in Figure 5; the prepared core was put into the mercury injection instrument, under the difference between the two ends, a certain volume of mercury will be injected into the tested rock pores, and according to the change of pressure rise and fall and the corresponding change of the rise and fall of the volume of mercury entering the rock, the pore size and distribution curve of the rock can be measured. The entry-exit capillary pressure curves of the rock were plotted, and after further calculation, other pore structure characteristic parameters of the sample can be derived, and the relevant technical parameters of the mercury injection instrument are as follows: the pressure range is 0-30000 psi and the minimum detection pore throat radius is 3.6 nm.Figure 5
The 9500-model automatic mercury injection of American Mike Company.The detection equipment of NMR scanT2 distribution is the core NMR analyzer Meso-MR23 of Suzhou Newmark Analytical Instruments Co., Ltd., as shown in Figure 6. NMR inverse calculates the fluid properties and its content in the pore by observing the signal intensity of hydrogen NMR, and the relevant technical parameters of the NMR analyzer are as follows: the instrument main frequency is 21 MHz, the minimum echo interval is 60 μs, the probe size is 1/1.5 in, and the maximum sample size is 2.54 cm in diameter and 5 cm in length.Figure 6
Core NMR analyzer.The detection equipment for micro-CT scanning of cores is the Phoenix V|tome|xs type micro-CT scanner, as shown in Figure7, X-ray CT is used to penetrate the object with conical X-rays, the image is magnified by different magnifications of the objective lens, and a three-dimensional model is reconstructed from a large number of X-ray attenuation images obtained by 360-degree rotation. The CT images reflect the energy decay of X-rays during penetration, so the 3D CT images can truly reflect the internal pore structure and relative density of the core. The relevant technical parameters of the micro-CT scanner are as follows: the sample size is 1-70 mm in diameter, the voltage is 20-240 kV, the electron beam current is 50-150 μA, and the pixel size is 0.7-40 μm. The pore throat characteristics of the interlayer cores were analyzed by combining the above three methods.Figure 7
V|tome|xs micro-CT scanner.


## 3.4. Numerical Simulation

### 3.4.1. Conservation of Mass

A generalized conservation equation of mass components and energy in the porous continuum can be written as follows [1]:
(1)∂φ∑αραSαXαi+Rsii∂t=−∑α∇⋅ραXαi⋅−kkrαμα∇Pα−ραg∇z+∑α∇⋅αTα−kkrαμα⋅∇Pα−ραg∇zδij+αLα−αTα⋅−kkrα/μα∇Pα−ραg∇z2−kkrα/μα∇Pα−ραg∇z+φSατdαkδij⋅∇ραXαi+qi,where i is the index for the components, i=1,2,3,⋯,Nc; k=Nc+1 for energy; Mi is the accumulation term of component k; qi is an external source/sink term; Fi is the “flow” term of mass or energy; α is the phase indicator; g is the gas; o is the oil; w is the water; ϕ is the porosity; ρα is the density of phase α; Sα is the saturation of phase α; Xαi is the mass content of component i in phase α; Rsi is the adsorption term of component k on rock solids; αTα,αTα are the transverse and longitudinal dispersion coefficient, respectively; τ is the tortuosity; dαi is the molecular diffusion coefficient of phase α; and δij is the Kronecker delta function (if i=j, then δij=1; otherwise, δij=0).The solution procedure is fully implicit.


### 3.4.2. Equations of State

The Peng-Robinson equation has been chosen as the equation of state (EOS) in the simulation procedure of the multiphase compositional model.(2)p=RTVi−b−aTVi+ubVi+wb,where p is the pressure of the system (Pa), T is the temperature of the system (K), Vi is the volume of the component i (m3/kmol), and R is the molar gas constant (8.314×103m3·Pa/kmol·K).The RK mixing rule of the vdW type has been chosen in the simulation procedure of hydrocarbon mixture.(3)am=∑i∑jyiyjaiaj1/21−kij,bm=∑iyibi,where am,bm are gravitation and repulsion coefficients of mixture, respectively, and kij is the binary mutual act coefficient of components i and j.The flash equation consists of correlation equations and limiting conditions, which could be derived into the Rachford-Rice equation and solved with the Newton-Raphson method.(4)∑iyi−xi=∑iZiKi−11+NVKi−1=∑iZiKi−1Ki−NLKi−1=0,where yi,xi are molar contents of component i in the vapor phase and liquid phase, respectively; NV,NL are the molar volume of component i in the vapor phase and liquid phase, respectively; Zi is the molar contents of component i; and Ki is the phase equilibrium constant.


### 3.4.3. Constitutive Relations and Boundary Conditions

To complete the mathematical description of multiphase flow, multicomponent transport, and diffusion in porous media, a generalized mass- and energy-balance equation needs to be supplemented with a number of constitutive equations.To express constraints of physical processes, variables, and parameters, boundary conditions are also necessary to make the governing equations solvable.Saturation of phaseα is constrained on summation of total fluid saturation.
(5)∑αSα=1.Mole fraction of phaseα is constrained on summation of total mole fraction of component i.
(6)∑iXαi=1.The relative permeability and the capillary pressure of a fluid phase in a multiphase system are normally assumed to be functions of fluid saturation.(7)krα=krαSα,pcα=pcαSα.Density and viscosity of a fluid phase are treated as a function of pressure, temperature, and mass compositions.(8)ρα=ραP,T,Xαi,μα=μαP,T,Xαi.Porosity is the effective porosity constrained on a reference porosity at a reference pressure and temperature, whileCr is the compressibility coefficient.
(9)ϕ=ϕ01+CrP−P0.


### 3.4.4. Parameter Determination and Numerical Simulation Input

In this paper, intersecting numerical simulation software is used to establish a model based on the practical geology data of the test well.The geometric size of the model is700m×1300m×10m with a plane grid step of 50 m and a longitudinal grid step of 10 m; a reservoir porosity is 12.3% with an average horizontal permeability 1.0 mD and the vertical permeability 0.1 mD; the original oil saturation is 56%; the original formation pressure is 13 MPa, and the original formation temperature is 345 K.A 5-point injection-production well pattern is designed to be used with well spacing 130 m; horizontal wells are also selected with a horizontal section length 900 m; half length of the artificial fracture is 150 m, and the total fracturing section is 8; the local grid encryption (LGR) technique is used to develop fine description on grids with fractures; the equivalent conductivity method is used to determine the fracture mesh width (0.1 m) and permeability (200 mD).Dual control is applied in constant liquid volume and bottom hole pressure (>the bubble point pressure) referring to the practical production situation. Development mode of asynchronous periodic even injection and odd production is calculated in simulation of the five-point horizontal well pattern and single horizontal well.


## 3.4.1. Conservation of Mass

A generalized conservation equation of mass components and energy in the porous continuum can be written as follows [1]:
(1)∂φ∑αραSαXαi+Rsii∂t=−∑α∇⋅ραXαi⋅−kkrαμα∇Pα−ραg∇z+∑α∇⋅αTα−kkrαμα⋅∇Pα−ραg∇zδij+αLα−αTα⋅−kkrα/μα∇Pα−ραg∇z2−kkrα/μα∇Pα−ραg∇z+φSατdαkδij⋅∇ραXαi+qi,where i is the index for the components, i=1,2,3,⋯,Nc; k=Nc+1 for energy; Mi is the accumulation term of component k; qi is an external source/sink term; Fi is the “flow” term of mass or energy; α is the phase indicator; g is the gas; o is the oil; w is the water; ϕ is the porosity; ρα is the density of phase α; Sα is the saturation of phase α; Xαi is the mass content of component i in phase α; Rsi is the adsorption term of component k on rock solids; αTα,αTα are the transverse and longitudinal dispersion coefficient, respectively; τ is the tortuosity; dαi is the molecular diffusion coefficient of phase α; and δij is the Kronecker delta function (if i=j, then δij=1; otherwise, δij=0).The solution procedure is fully implicit.


## 3.4.2. Equations of State

The Peng-Robinson equation has been chosen as the equation of state (EOS) in the simulation procedure of the multiphase compositional model.(2)p=RTVi−b−aTVi+ubVi+wb,where p is the pressure of the system (Pa), T is the temperature of the system (K), Vi is the volume of the component i (m3/kmol), and R is the molar gas constant (8.314×103m3·Pa/kmol·K).The RK mixing rule of the vdW type has been chosen in the simulation procedure of hydrocarbon mixture.(3)am=∑i∑jyiyjaiaj1/21−kij,bm=∑iyibi,where am,bm are gravitation and repulsion coefficients of mixture, respectively, and kij is the binary mutual act coefficient of components i and j.The flash equation consists of correlation equations and limiting conditions, which could be derived into the Rachford-Rice equation and solved with the Newton-Raphson method.(4)∑iyi−xi=∑iZiKi−11+NVKi−1=∑iZiKi−1Ki−NLKi−1=0,where yi,xi are molar contents of component i in the vapor phase and liquid phase, respectively; NV,NL are the molar volume of component i in the vapor phase and liquid phase, respectively; Zi is the molar contents of component i; and Ki is the phase equilibrium constant.


## 3.4.3. Constitutive Relations and Boundary Conditions

To complete the mathematical description of multiphase flow, multicomponent transport, and diffusion in porous media, a generalized mass- and energy-balance equation needs to be supplemented with a number of constitutive equations.To express constraints of physical processes, variables, and parameters, boundary conditions are also necessary to make the governing equations solvable.Saturation of phaseα is constrained on summation of total fluid saturation.
(5)∑αSα=1.Mole fraction of phaseα is constrained on summation of total mole fraction of component i.
(6)∑iXαi=1.The relative permeability and the capillary pressure of a fluid phase in a multiphase system are normally assumed to be functions of fluid saturation.(7)krα=krαSα,pcα=pcαSα.Density and viscosity of a fluid phase are treated as a function of pressure, temperature, and mass compositions.(8)ρα=ραP,T,Xαi,μα=μαP,T,Xαi.Porosity is the effective porosity constrained on a reference porosity at a reference pressure and temperature, whileCr is the compressibility coefficient.
(9)ϕ=ϕ01+CrP−P0.


## 3.4.4. Parameter Determination and Numerical Simulation Input

In this paper, intersecting numerical simulation software is used to establish a model based on the practical geology data of the test well.The geometric size of the model is700m×1300m×10m with a plane grid step of 50 m and a longitudinal grid step of 10 m; a reservoir porosity is 12.3% with an average horizontal permeability 1.0 mD and the vertical permeability 0.1 mD; the original oil saturation is 56%; the original formation pressure is 13 MPa, and the original formation temperature is 345 K.A 5-point injection-production well pattern is designed to be used with well spacing 130 m; horizontal wells are also selected with a horizontal section length 900 m; half length of the artificial fracture is 150 m, and the total fracturing section is 8; the local grid encryption (LGR) technique is used to develop fine description on grids with fractures; the equivalent conductivity method is used to determine the fracture mesh width (0.1 m) and permeability (200 mD).Dual control is applied in constant liquid volume and bottom hole pressure (>the bubble point pressure) referring to the practical production situation. Development mode of asynchronous periodic even injection and odd production is calculated in simulation of the five-point horizontal well pattern and single horizontal well.


## 4. Results and Analysis

### 4.1. Lithological Characteristics of Interlayers

For the lithological and structural characteristics of the interlayers, core cast thin sections were prepared on several 1-inch diameter plunger cores drilled and cut above cores. In addition, the lithologies of the above 1-inch diameter plunger cores were analyzed by XRD to obtain the whole-rock mineral and clay mineral content distribution of the interlayers, respectively.The identification results (Figure8) of core cast thin sections indicated that the main lithologies of the interlayers were mud-bearing medium gravel, tuff-bearing medium gravel, mud-bearing calcareous fine gravel, and gravel-bearing mud-bearing feldspathic clastic fine sandstone, which were small in thickness and mainly produced in the form of thin interlayer. The rocks were poorly sorted in terms of grain size, with deviations in roundness and predominantly subangular shape. The grains had high gravel content, and the gravel composition was most abundant in mudstone gravel, with sandstone gravel and a small amount of basaltic gravel, which indicated that the rocks were deposited after short distance and rapid transport. The pore spaces between the gravels were mainly filled and cemented by clay minerals and zeolites, followed by calcite cementation, and the pore spaces contained long-engine miscellaneous groups. The overall structural maturity and compositional maturity were low, the content of heterogeneous groups was high, averaging 24%, a small number of gravels were in slight concave-convex contact, there was pressure-soluble action, and multilevel particle filling combined with strong diagenesis leads to extremely poor pore development.Figure 8
Some images of rock thin sections.XRD whole-rock analysis of the interlayer rock samples (Table2) showed that the interlayer cores were dominated by minerals such as quartz, plagioclase, and epidote, with the highest epidote content of 29% on average, followed by quartz at 27%. Meanwhile, these cores generally contain high clay content with an average of 21%, indicating that these interlayers were similar to mud shale caprock although they were not pure mudstone.Table 2
Mineral composition of interlayer cores.
Sample numberMineral content (%)QuartzK-feldsparPlagioclaseCalciteSquare zeoliteClay minerals805-320.95.111.84.635.422.28545-217.725.96.128.222.18545-427.14.812.02.335.518.38545-937.24.69.85.234.19.1JW32-331.614.76.716.230.8JW32-527.313.611.124.423.6Average27.04.814.66.029.021.0The clay minerals almost do not contain kaolinite (Table3). Combined with the mineral evolution law, kaolinite is prone to develop dissolution pores, but the clay minerals in the interlayer of this study were dominated by montmorillonite, illite, and illite-smectite (I/S) mixed layer, so the dissolution pores were not developed in this study.Table 3
Composition of clay minerals in intercalated cores.
Total clay mineral (%)Clay mineral content (%)Monazite (S)Illite-smectite (I/S)Illite (I)Chlorite (C)RelativeAbsoluteRelativeAbsoluteRelativeAbsoluteRelativeAbsolute22.258.012.9429.322.163.013.9378.218.3519.3387.0213.89.1232.190.8686.230.84513.9247.4319.523.6429.9286.6307.121.060.513.440.38.829.76.537.56.7


### 4.2. Physical Properties and Pore Throat Characteristics of the Interlayer

The physical characteristics, pore space, and pore throat structure characteristics of the interlayer were analyzed. Firstly, the physical conditions of the interlayer were analyzed, and all the cores drilled and cut out above were tested for basic porosity and permeability, and the porosity of the interlayer was concentrated between 4% and 8%, with an average of 6.1%, and the permeability was mainly less than 0.005 mD, accounting for 53.1%, with an average of 0.0043 mD (Figure9).Figure 9
Histograms of porosity and permeability of core samples from interlayers.The pore and throat space in the core can be visualized by identifying the thin section of the core cast obtained earlier and the CT scan images of the core.Due to the influence of rock structure and diagenesis, there were very few primary pore spaces, and the pore space was mainly secondary pores and fractures. The main pore types (Figure10) were intragrain (clay minerals in gravel/feldspar/organic matter/mudstone rock fragments) dissolution pores, intragrain seams (cracks inside the grains due to compaction), and gravel edge seams (85%), while intergrain dissolution pores and microfractures and dissolution pores within the mica fillings were occasionally seen (15%). The pores were generally isolated and had very poor connectivity.Figure 10
Microcast thin section images of cores: (a) microcracks around tuff gravel (crack widths 13-531μm); (b) glass shard solution pores; (c) silty mudstone gravel chip; (d) microcracks in filler; (e) mudstone gravel containing silt; (f) cracks in fine siltstone gravel (crack widths 20-51 μm).
(a)(b)(c)(d)(e)(f)CT scans of typical core samples showed insignificant pore development at the microscale (scanning accuracy is about 20 microns), and no significant pore development can be seen at the microscale size. Obvious pores can be seen on submicrofine scan images (scan accuracy is about 0.5μm), indicating that pores in the interlayer were mainly dominated by micropores (Figure 11).Figure 11
CT scan images of rock cores.Finally, the pore throat structure characteristics of the interlayer can be obtained by core NMR scanning and high-pressure mercury injection. NMR testing was performed on several cores drilled from full-diameter rock samples; firstly, the cores were vacuumed and pressurized saturating the simulation of formation brine; then, theT2 distribution was obtained by NMR testing to analyze the pore structure characteristics, after which the cores were centrifuged separately, and the centrifuged cores were subjected to NMR tests performed to analyze the movable and bound water by comparing the T2 spectrum distribution.From the NMR, the main poreT2 values of the compartment samples were between 0.1 and 10 ms, and some samples have a small amount of development between 100 and 300 ms, indicating that the pores of the interlayer rock samples were mainly dominated by micro- and small pores with local development of individual large pores, and the reservoir samples had a considerable proportion of pores between 10 and 500 ms (Figure 12).Figure 12
NMR curves of typical samples.From the high-pressure mercury injection, the discharge flooding pressure of the interlayer samples was higher. It is clear from the median pressure (average 133.9 MPa) that the pressure at 50% inlet mercury saturation was much higher for all samples than for the conventional hypotonic samples, with an average inlet mercury saturation of only 62.9% at an inlet pressure of 200 MPa. The median radius was 0.007μm on average, and the average pore throat radius was 0.045 μm (Table 4). The core pore throat radius was generally less than 0.1 μm, and the main pore throat radius was between 0.001 and 0.05 μm, dominated by nanopores, with 82.7% of pore throats less than 0.1 μm (Figure 13).Table 4
Parameters of high-pressure mercury injection for the interlayer samples.
Well numberPorosity (%)Pd (MPa)P50(MPa)Rmax (μm)R50 (μm)Ri (μm)SHgmax (%)We (%)805-3-26.98.58111.50.0860.0070.01273.545.58545/2/23.90.12188.95.9360.0040.04155.132.18545/4/34.125.95200.70.0280.0040.00751.434.6JW32-3-23.00.58122.91.2720.0060.06463.619.3JW32-5-24.21.09139.60.6780.0050.03266.735.2Average4.76.18133.91.4930.0070.04562.930.9Figure 13
Histogram of pore throat of interlayer core samples.With lots of tests, the selected regional samples belong to the interlay, but they are not shale caprocks. Their porosities are concentrated in 4~8%, and their permeabilities are less than 0.005 mD. The pore throat radius is generally less than 0.1μm. The pore is the nanopore mainly distributed from 0.001 μm to 0.05 μm. The connectivity is very poor as the pore is generally isolated. In summary, these characteristics are similar to those of the shale caprock.


### 4.3. Lower Seepage Limit of Gas Injection in the Interlayer

For the lower seepage limit of gas injection in the interlayer, two methods were used here: core gas injection breakthrough pressure evaluation experiment and simulation of pore network for gas injection sealability to conduct a comprehensive analysis. Firstly, refer to the oil and gas industry standard “Rock gas breakthrough pressure determination method” SY/T 5748-2013 to establish the experiment method of the core gas injection breakthrough pressure evaluation; a series of preparatory work needs to be completed for the core before the experiment. The following is an example of a single cubic core (Figure14). First of all, the corresponding cubic core was drilled and cut from the full-diameter rock sample; then, the core was cleaned and dried for backup, after which the gas permeability of the core was tested, and the vertical and horizontal gas permeabilities were measured separately for the cubic core during the preparation process, and the core was evacuated and saturated with formation brine under exerted pressure after the gas permeability test was completed. After that, the core saturated with formation brine was loaded into the holder, and the pressure combination and constant pressure waiting time were set step by step which referred to the standard, and the outlet condition was judged by the bubble monitoring device at the outlet during the experiment. When there is continuous bubble evenly flowing out, the stable value of the pressure gauge at the injection end of the core at this time is the breakthrough pressure of gas injection at the top of the core. In accordance with the above experimental method and the arrangement of the previous samples, the gas injection breakthrough pressure evaluation experiments of single cubic core, 2.5 cm diameter plunger core, and cubic combination core were carried out, respectively.Figure 14
Core preparation processes before the injection breakthrough pressure evaluation experiment.The pore network simulation of gas injection sealability formed a complete simulation program through three aspects of works which were digital scanning of cores, digital core modeling, and digital core simulation of gas injection sealability. Using this simulation program, the pore network simulations with multiple models and multiple boundary conditions of gas injection sealability were carried out, and the simulation results of multiple conditions were collected and analyzed in a comprehensive manner.The corresponding experiments were conducted for various sizes of cores according to the experimental procedure of gas injection breakthrough pressure evaluation, and the detailed experimental results are shown in Tables5–7.Table 5
Experimental results of gas injection sealability evaluation at the top of the cubic cores.
Core numberPorosity (%)Permeability (mD)Breakthrough pressure (MPa)Breakthrough time805-111.40.246510.528’ 27”8545-67.20.004875.7767’ 10”8545-24.80.0049588.9545’ 00”8545-54.80.0045099.5230’ 40”8545-15.30.00171611.1815’ 34”JW32-35.60.0072311.9408’ 02”JW32-14.70.0094481414’ 31”805-37.70.0014115.1946’ 02”805-47.90.0007528.5107’ 00”JW32-44.30.0010935.83121’ 7”Table 6
Experimental results of gas injection sealability evaluation at the top of 1-inch diameter plunger cores.
Core numberPorosity (%)Permeability (mD)Breakthrough pressure (MPa)Breakthrough time85095-112.00.1226180.7109’ 42”Bai 864-17.60.00192234.63118’ 00”85095-29.10.2402940.3120’ 43”Bai 864-29.10.0702716.0658’ 00”8545-146.70.0092827.179’ 40”8545-159.40.0136328.0344’ 24”8545-175.80.00482913.9839’8545-185.30.007844813’ 58”Table 7
Experimental results of gas injection sealability evaluation at the top of the cubic composite core.
Combination numberPorosity (%)Permeability (mD)Breakthrough pressure (MPa)Breakthrough timeCombination 16.80.00238527.2698’ 39”Combination 27.10.00156543.54143’ 00”Combination 35.60.00220437.790’ 00”Combination 47.10.00119122.49101’ 01”The experimental data of the composited cores and the two previous experimental data of different sizes of cores were analyzed together. The average gas permeability and the lowest gas permeability of the composite cores were used as the benchmarks to carry out the experimental data rendezvous, respectively (Figure15). There is a weak negative correlation between breakthrough pressure and gas permeability in double logarithmic coordinates. When the permeability is greater than 10 mD, the breakthrough pressure is lower than 1 MPa. When the permeability is between 4 and 8 mD, the breakthrough pressure changes greatly, ranging from 5.77 to 43.54 MPa. The breakthrough pressure test data points of the combined core are slightly higher than those of the cube core and 1-inch core, but the breakthrough pressure of the combined core is not simply accumulated by the breakthrough pressure of the single cube core. That is, the combined core can be regarded as a larger overall core, indicating that the top gas injection sealing evaluation can choose 1-inch core or cube core to carry out the experiment. The internal pore structure of the core itself is the main controlling factor of gas injection sealing, and the core specification has relatively little effect on gas injection sealing.Figure 15
Double log-linear relationship between breakthrough pressure and permeability in this experiment.The finding of this experiment was consistent with that in the literature (Figure16), where a good pointing relationship exists between the breakthrough pressure of the caprock and its permeability in double logarithmic coordinates when evaluating the sealability of the caprock. The experiment in this study was basically consistent in conducting with the caprock breakthrough pressure experiment, and the consistent experimental analysis results also indicated that the interlayer is similar in nature to the reservoir’s capping layer.Figure 16
Double logarithmic relationship between capping sealability breakthrough pressure and permeability in the literature.About the improvement in the experiment, the core gas injection breakthrough pressure evaluation experiment can also be carried out in the full-diameter natural core in the future. It can further verify that gas injection breakthrough pressure has nothing to do with the core scale. So the understanding obtained by experimental physical simulation can reflect the large scale gas injection breakthrough pressure in the reservoir.Firstly, the pore network lattice model of the digital core was fixed, which was equivalent to the rock skeleton fixed, and the corresponding boundary conditions were changed, which corresponds to the physical process of gas injection sealability which was to change the gas injection pressure. A series of pore network simulations for gas injection sealability were carried out according to the conditions described above, and the simulation results of three boundary conditions which were gas injection pressure of 10, 20, and 30 MPa are shown in Figure17.Figure 17
Simulation results of the fixed digital core model with changed boundary conditions.As can be seen from Figure17, based on the fixed digital core model, the simulation results of low pressure 10 MPa and medium pressure 20 MPa were that the gas was sealed, and the range of gas intrusion in the digital core under medium pressure condition was wider than that at low pressure, while the simulation results of high pressure 30 MPa were that the gas breaks through this digital core. As the gas injection pressure increases, the gas intrusion range in the digital core increases until the gas breaks through the top of the digital core after the intrusion range reaches a certain level. The results of the whole simulation were consistent with the process of the previous physical simulation experiment of gas injection sealability at the top, which both show that it is relatively reasonable to study the physical process of gas injection sealability through the pore network simulation method.


## 4.1. Lithological Characteristics of Interlayers

For the lithological and structural characteristics of the interlayers, core cast thin sections were prepared on several 1-inch diameter plunger cores drilled and cut above cores. In addition, the lithologies of the above 1-inch diameter plunger cores were analyzed by XRD to obtain the whole-rock mineral and clay mineral content distribution of the interlayers, respectively.The identification results (Figure8) of core cast thin sections indicated that the main lithologies of the interlayers were mud-bearing medium gravel, tuff-bearing medium gravel, mud-bearing calcareous fine gravel, and gravel-bearing mud-bearing feldspathic clastic fine sandstone, which were small in thickness and mainly produced in the form of thin interlayer. The rocks were poorly sorted in terms of grain size, with deviations in roundness and predominantly subangular shape. The grains had high gravel content, and the gravel composition was most abundant in mudstone gravel, with sandstone gravel and a small amount of basaltic gravel, which indicated that the rocks were deposited after short distance and rapid transport. The pore spaces between the gravels were mainly filled and cemented by clay minerals and zeolites, followed by calcite cementation, and the pore spaces contained long-engine miscellaneous groups. The overall structural maturity and compositional maturity were low, the content of heterogeneous groups was high, averaging 24%, a small number of gravels were in slight concave-convex contact, there was pressure-soluble action, and multilevel particle filling combined with strong diagenesis leads to extremely poor pore development.Figure 8
Some images of rock thin sections.XRD whole-rock analysis of the interlayer rock samples (Table2) showed that the interlayer cores were dominated by minerals such as quartz, plagioclase, and epidote, with the highest epidote content of 29% on average, followed by quartz at 27%. Meanwhile, these cores generally contain high clay content with an average of 21%, indicating that these interlayers were similar to mud shale caprock although they were not pure mudstone.Table 2
Mineral composition of interlayer cores.
Sample numberMineral content (%)QuartzK-feldsparPlagioclaseCalciteSquare zeoliteClay minerals805-320.95.111.84.635.422.28545-217.725.96.128.222.18545-427.14.812.02.335.518.38545-937.24.69.85.234.19.1JW32-331.614.76.716.230.8JW32-527.313.611.124.423.6Average27.04.814.66.029.021.0The clay minerals almost do not contain kaolinite (Table3). Combined with the mineral evolution law, kaolinite is prone to develop dissolution pores, but the clay minerals in the interlayer of this study were dominated by montmorillonite, illite, and illite-smectite (I/S) mixed layer, so the dissolution pores were not developed in this study.Table 3
Composition of clay minerals in intercalated cores.
Total clay mineral (%)Clay mineral content (%)Monazite (S)Illite-smectite (I/S)Illite (I)Chlorite (C)RelativeAbsoluteRelativeAbsoluteRelativeAbsoluteRelativeAbsolute22.258.012.9429.322.163.013.9378.218.3519.3387.0213.89.1232.190.8686.230.84513.9247.4319.523.6429.9286.6307.121.060.513.440.38.829.76.537.56.7


## 4.2. Physical Properties and Pore Throat Characteristics of the Interlayer

The physical characteristics, pore space, and pore throat structure characteristics of the interlayer were analyzed. Firstly, the physical conditions of the interlayer were analyzed, and all the cores drilled and cut out above were tested for basic porosity and permeability, and the porosity of the interlayer was concentrated between 4% and 8%, with an average of 6.1%, and the permeability was mainly less than 0.005 mD, accounting for 53.1%, with an average of 0.0043 mD (Figure9).Figure 9
Histograms of porosity and permeability of core samples from interlayers.The pore and throat space in the core can be visualized by identifying the thin section of the core cast obtained earlier and the CT scan images of the core.Due to the influence of rock structure and diagenesis, there were very few primary pore spaces, and the pore space was mainly secondary pores and fractures. The main pore types (Figure10) were intragrain (clay minerals in gravel/feldspar/organic matter/mudstone rock fragments) dissolution pores, intragrain seams (cracks inside the grains due to compaction), and gravel edge seams (85%), while intergrain dissolution pores and microfractures and dissolution pores within the mica fillings were occasionally seen (15%). The pores were generally isolated and had very poor connectivity.Figure 10
Microcast thin section images of cores: (a) microcracks around tuff gravel (crack widths 13-531μm); (b) glass shard solution pores; (c) silty mudstone gravel chip; (d) microcracks in filler; (e) mudstone gravel containing silt; (f) cracks in fine siltstone gravel (crack widths 20-51 μm).
(a)(b)(c)(d)(e)(f)CT scans of typical core samples showed insignificant pore development at the microscale (scanning accuracy is about 20 microns), and no significant pore development can be seen at the microscale size. Obvious pores can be seen on submicrofine scan images (scan accuracy is about 0.5μm), indicating that pores in the interlayer were mainly dominated by micropores (Figure 11).Figure 11
CT scan images of rock cores.Finally, the pore throat structure characteristics of the interlayer can be obtained by core NMR scanning and high-pressure mercury injection. NMR testing was performed on several cores drilled from full-diameter rock samples; firstly, the cores were vacuumed and pressurized saturating the simulation of formation brine; then, theT2 distribution was obtained by NMR testing to analyze the pore structure characteristics, after which the cores were centrifuged separately, and the centrifuged cores were subjected to NMR tests performed to analyze the movable and bound water by comparing the T2 spectrum distribution.From the NMR, the main poreT2 values of the compartment samples were between 0.1 and 10 ms, and some samples have a small amount of development between 100 and 300 ms, indicating that the pores of the interlayer rock samples were mainly dominated by micro- and small pores with local development of individual large pores, and the reservoir samples had a considerable proportion of pores between 10 and 500 ms (Figure 12).Figure 12
NMR curves of typical samples.From the high-pressure mercury injection, the discharge flooding pressure of the interlayer samples was higher. It is clear from the median pressure (average 133.9 MPa) that the pressure at 50% inlet mercury saturation was much higher for all samples than for the conventional hypotonic samples, with an average inlet mercury saturation of only 62.9% at an inlet pressure of 200 MPa. The median radius was 0.007μm on average, and the average pore throat radius was 0.045 μm (Table 4). The core pore throat radius was generally less than 0.1 μm, and the main pore throat radius was between 0.001 and 0.05 μm, dominated by nanopores, with 82.7% of pore throats less than 0.1 μm (Figure 13).Table 4
Parameters of high-pressure mercury injection for the interlayer samples.
Well numberPorosity (%)Pd (MPa)P50(MPa)Rmax (μm)R50 (μm)Ri (μm)SHgmax (%)We (%)805-3-26.98.58111.50.0860.0070.01273.545.58545/2/23.90.12188.95.9360.0040.04155.132.18545/4/34.125.95200.70.0280.0040.00751.434.6JW32-3-23.00.58122.91.2720.0060.06463.619.3JW32-5-24.21.09139.60.6780.0050.03266.735.2Average4.76.18133.91.4930.0070.04562.930.9Figure 13
Histogram of pore throat of interlayer core samples.With lots of tests, the selected regional samples belong to the interlay, but they are not shale caprocks. Their porosities are concentrated in 4~8%, and their permeabilities are less than 0.005 mD. The pore throat radius is generally less than 0.1μm. The pore is the nanopore mainly distributed from 0.001 μm to 0.05 μm. The connectivity is very poor as the pore is generally isolated. In summary, these characteristics are similar to those of the shale caprock.


## 4.3. Lower Seepage Limit of Gas Injection in the Interlayer

For the lower seepage limit of gas injection in the interlayer, two methods were used here: core gas injection breakthrough pressure evaluation experiment and simulation of pore network for gas injection sealability to conduct a comprehensive analysis. Firstly, refer to the oil and gas industry standard “Rock gas breakthrough pressure determination method” SY/T 5748-2013 to establish the experiment method of the core gas injection breakthrough pressure evaluation; a series of preparatory work needs to be completed for the core before the experiment. The following is an example of a single cubic core (Figure14). First of all, the corresponding cubic core was drilled and cut from the full-diameter rock sample; then, the core was cleaned and dried for backup, after which the gas permeability of the core was tested, and the vertical and horizontal gas permeabilities were measured separately for the cubic core during the preparation process, and the core was evacuated and saturated with formation brine under exerted pressure after the gas permeability test was completed. After that, the core saturated with formation brine was loaded into the holder, and the pressure combination and constant pressure waiting time were set step by step which referred to the standard, and the outlet condition was judged by the bubble monitoring device at the outlet during the experiment. When there is continuous bubble evenly flowing out, the stable value of the pressure gauge at the injection end of the core at this time is the breakthrough pressure of gas injection at the top of the core. In accordance with the above experimental method and the arrangement of the previous samples, the gas injection breakthrough pressure evaluation experiments of single cubic core, 2.5 cm diameter plunger core, and cubic combination core were carried out, respectively.Figure 14
Core preparation processes before the injection breakthrough pressure evaluation experiment.The pore network simulation of gas injection sealability formed a complete simulation program through three aspects of works which were digital scanning of cores, digital core modeling, and digital core simulation of gas injection sealability. Using this simulation program, the pore network simulations with multiple models and multiple boundary conditions of gas injection sealability were carried out, and the simulation results of multiple conditions were collected and analyzed in a comprehensive manner.The corresponding experiments were conducted for various sizes of cores according to the experimental procedure of gas injection breakthrough pressure evaluation, and the detailed experimental results are shown in Tables5–7.Table 5
Experimental results of gas injection sealability evaluation at the top of the cubic cores.
Core numberPorosity (%)Permeability (mD)Breakthrough pressure (MPa)Breakthrough time805-111.40.246510.528’ 27”8545-67.20.004875.7767’ 10”8545-24.80.0049588.9545’ 00”8545-54.80.0045099.5230’ 40”8545-15.30.00171611.1815’ 34”JW32-35.60.0072311.9408’ 02”JW32-14.70.0094481414’ 31”805-37.70.0014115.1946’ 02”805-47.90.0007528.5107’ 00”JW32-44.30.0010935.83121’ 7”Table 6
Experimental results of gas injection sealability evaluation at the top of 1-inch diameter plunger cores.
Core numberPorosity (%)Permeability (mD)Breakthrough pressure (MPa)Breakthrough time85095-112.00.1226180.7109’ 42”Bai 864-17.60.00192234.63118’ 00”85095-29.10.2402940.3120’ 43”Bai 864-29.10.0702716.0658’ 00”8545-146.70.0092827.179’ 40”8545-159.40.0136328.0344’ 24”8545-175.80.00482913.9839’8545-185.30.007844813’ 58”Table 7
Experimental results of gas injection sealability evaluation at the top of the cubic composite core.
Combination numberPorosity (%)Permeability (mD)Breakthrough pressure (MPa)Breakthrough timeCombination 16.80.00238527.2698’ 39”Combination 27.10.00156543.54143’ 00”Combination 35.60.00220437.790’ 00”Combination 47.10.00119122.49101’ 01”The experimental data of the composited cores and the two previous experimental data of different sizes of cores were analyzed together. The average gas permeability and the lowest gas permeability of the composite cores were used as the benchmarks to carry out the experimental data rendezvous, respectively (Figure15). There is a weak negative correlation between breakthrough pressure and gas permeability in double logarithmic coordinates. When the permeability is greater than 10 mD, the breakthrough pressure is lower than 1 MPa. When the permeability is between 4 and 8 mD, the breakthrough pressure changes greatly, ranging from 5.77 to 43.54 MPa. The breakthrough pressure test data points of the combined core are slightly higher than those of the cube core and 1-inch core, but the breakthrough pressure of the combined core is not simply accumulated by the breakthrough pressure of the single cube core. That is, the combined core can be regarded as a larger overall core, indicating that the top gas injection sealing evaluation can choose 1-inch core or cube core to carry out the experiment. The internal pore structure of the core itself is the main controlling factor of gas injection sealing, and the core specification has relatively little effect on gas injection sealing.Figure 15
Double log-linear relationship between breakthrough pressure and permeability in this experiment.The finding of this experiment was consistent with that in the literature (Figure16), where a good pointing relationship exists between the breakthrough pressure of the caprock and its permeability in double logarithmic coordinates when evaluating the sealability of the caprock. The experiment in this study was basically consistent in conducting with the caprock breakthrough pressure experiment, and the consistent experimental analysis results also indicated that the interlayer is similar in nature to the reservoir’s capping layer.Figure 16
Double logarithmic relationship between capping sealability breakthrough pressure and permeability in the literature.About the improvement in the experiment, the core gas injection breakthrough pressure evaluation experiment can also be carried out in the full-diameter natural core in the future. It can further verify that gas injection breakthrough pressure has nothing to do with the core scale. So the understanding obtained by experimental physical simulation can reflect the large scale gas injection breakthrough pressure in the reservoir.Firstly, the pore network lattice model of the digital core was fixed, which was equivalent to the rock skeleton fixed, and the corresponding boundary conditions were changed, which corresponds to the physical process of gas injection sealability which was to change the gas injection pressure. A series of pore network simulations for gas injection sealability were carried out according to the conditions described above, and the simulation results of three boundary conditions which were gas injection pressure of 10, 20, and 30 MPa are shown in Figure17.Figure 17
Simulation results of the fixed digital core model with changed boundary conditions.As can be seen from Figure17, based on the fixed digital core model, the simulation results of low pressure 10 MPa and medium pressure 20 MPa were that the gas was sealed, and the range of gas intrusion in the digital core under medium pressure condition was wider than that at low pressure, while the simulation results of high pressure 30 MPa were that the gas breaks through this digital core. As the gas injection pressure increases, the gas intrusion range in the digital core increases until the gas breaks through the top of the digital core after the intrusion range reaches a certain level. The results of the whole simulation were consistent with the process of the previous physical simulation experiment of gas injection sealability at the top, which both show that it is relatively reasonable to study the physical process of gas injection sealability through the pore network simulation method.


## 5. Discussion

### 5.1. Interlayer Isolation Mechanism

In the part of microscopic perspective, in order to better analyze the physical phenomenon process of gas injection sealability by means of pore network simulation, the digital core models were combined with the core micro-CT scan images to carry out the corresponding simulation of gas injection sealability, which was equivalent to changing the rock skeleton and carrying out simulation of gas injection sealability for different digital pore network models. In the pore network simulation, the boundary conditions were simulated by gradually increasing the gas injection pressure, where the first gas injection pressure point referred to the initial pressure of the top gas injection sealing physical simulation experiment, after which each gas injection pressure point was increased by 0.1 MPa on the basis of the previous pressure point. By simulating the gas injection pressure corresponding to each variable condition, judge whether the corresponding digital core model breaks through; if not, simulate and judge the next gas injection pressure point according to the pressure interval of 0.1 MPa, until the simulation result is gas breakthrough; then, the gas injection pressure point is the breakthrough pressure of the digital core model. The rendezvous analysis (Figure18) of the simulated data showed that the breakthrough pressure of gas injection sealability obtained by means of pore network simulation still showed a good linear relationship with gas permeability in double logarithmic coordinates, and this characterization method of gas injection sealability in the interlayer was highly consistent with the previous physical simulation experiment of gas injection sealability at the top.Figure 18
Intersection of permeability and gas injection breakthrough pressure: (a) core experiment; (b) digital core simulation.
(a)(b)The formation fracture pressure in the gas injection test area of the lower Wuerhe group reservoir in zone 8 is 42 MPa, and 90% of the fracture pressure is the maximum injection pressure, from which it is calculated that the bottom flow pressure should be less than 38 MPa, and the maximum pressure difference of gas injection is determined to be 15-20 MPa by combining the current formation pressure in the test area from 0.5 m of the intercalation layer, from which it is concluded that the intercalation layer with gas measurement permeability less than 0.003 mD can play an effective role in this reservoir (Figure19). It can play an effective blocking role in this reservoir (Figure 19).Figure 19
Pore network simulation to analyze the mechanism of gas injection sealability from the pore throat perspective.Considering the consistency of the process and results of the physical simulation experiment of top gas injection sealability with the process and results of the pore network simulation of gas injection sealability, the mechanism of the physical phenomenon of gas injection sealability was analyzed from the pore throat perspective in the pore network simulation. The digital core simulation of gas injection sealability based on the characteristic pore network was carried out, and the simulation study was based on gas-liquid two-phase flow, and the capillary barrier effect of gas-liquid (Jamin effect) (Figure19) was considered the main mechanism of the interlayer sealability from the pore throat perspective. When the pore channel in the rock sample is small, the gas-liquid flow in the capillary tube will have a small capillary resistance, and when the integrated capillary resistance of the whole pore network is larger than the gas injection pressure, the gas is blocked from penetrating, and this explanation also corresponds to the previous experimental results at the core scale. At the same time, this capillary barrier effect is reflected in the specific simulation process, where part of the gas-liquid interface in the digital core model will jump back and forth in the corresponding pore channel, showing that the existing boundary conditions like the gas injection pressure cannot overcome the capillary resistance reflected in the digital core model as a whole.The research work above is aimed at the interlayer. Also, there may be a problem to evaluate gas injection breakthrough pressure for the low-permeability reservoir; in particular, it is likely to cause multiphase flow when the fluid saturation state is complicated. This is a limitation for this research work.


### 5.2. Effects of the Well Type and Shot Hole Location on the Gas-Liquid Interface

In the practical engineering application, the interlayer below the lower limit of permeability can be treated as a dead grid in the reservoir numerical simulation model through the analysis of the sealing mechanism of the interlayer. Thus, the influence of the interlayer on the gas-liquid interface is analyzed in the numerical simulation model.In the macroscopic aspect, firstly, the micromechanism analysis and the analysis of the lower seepage limit of gas injection were integrated to delineate the interlayer on the geological model, while the numerical simulation analysis was carried out by combining the influence of the interlayer on the gas-liquid interface analyzed by the physical model experiment. Combined with the practical understanding of the mine site, the interlayer and well type jointly affect the underground gas injection transport pattern and gas-liquid interface stability. In general, the spatial distribution pattern of the combination of the interlayer and well network types have the following common patterns (Figure20), and injection wells generally use two types of wells, which were vertical or horizontal well type, which differ only in injection capacity and have little effect on underground gas transport, so no distinction was made between injection well types. The combination of two types of well, which were vertical injection and horizontal injection, and eight types of seepage barriers in relation to the injection well shot hole location were subdivided (Table 8) [22–24].Figure 20
Schematic diagram of vertical injection and vertical production (a) and vertical injection and horizontal production (b) modes.
(a)(b)Table 8
Relationship between different combinations of well types, seepage barriers, and injection well shot hole locations.
Injection and production well typeNumberInterlayer type and extension distanceLocation relationship between the interlayer and shot holes of injection and production wellsVertical injection and vertical productionASingle interlayer, 1/2 well spacingProduction well shot hole is located below the interlayerBSingle interlayer, 3/4 well spacingProduction well shot hole is located below the interlayerCSingle interlayer, 3/4 well spacingGas injection well shot hole is located above the interlayerDMultiple interlayers, space stackingProduction well shot hole is located below the interlayerVertical injection and horizontal productionESingle interlayer, 3/4 well spacingHorizontal section is far from the interlayerFSingle interlayer, 3/4 well spacingHorizontal section is close to the interlayerGMultiple interlayers, 3/4 well spacingClose longitudinal distance between interlayersHMultiple interlayers, 3/4 well spacingLong longitudinal distance between interlayers


#### 5.2.1. Vertical Injection and Vertical Production Mode

In the early stage, the interlayer had an impact on the stability of the gas-liquid interface, and part of the remaining oil above the interlayer could not be flooded to the wellbore, which made it difficult to effectively replace the remaining oil at the top of the interlayer. In the middle and later stages, with the increase in gas injection, the reservoir above the gas-liquid interface was basically gradually replaced effectively, including the remaining oil at the top of the interlayer, and finally, the gas-liquid interface remained balanced and stable (Figure21) [25–31].Figure 21
Variation of the gas-liquid interface of four combined relationships in vertical injection and vertical production mode.


#### 5.2.2. Vertical Injection and Horizontal Production Mode

In the early stage, the gas-liquid interface was influenced by the interlayer, and the injected gas partially bypassed the interlayer to repel the remaining oil above the horizontal section, while partially it was difficult to displace the remaining oil above the interlayer to the wellbore due to the obstruction of the interlayer; in the middle and late stages, the gas-liquid interface gradually reached equilibrium and stability with the increase in the gas injection volume (Figure22).Figure 22
Variation of the gas-liquid interface in four combined relationships under vertical injection and horizontal production mode.On the whole, the advantage of the research work above is to have a good understanding of the gas injection sealing mechanism of the interlayer in combination with several methods with different scales, including micropore network simulation, core physical simulation experiment, and reservoir numerical simulation. Its disadvantage is that the understanding is still slightly weak in the combination with the macroapplication of reservoir gas injection.


## 5.1. Interlayer Isolation Mechanism

In the part of microscopic perspective, in order to better analyze the physical phenomenon process of gas injection sealability by means of pore network simulation, the digital core models were combined with the core micro-CT scan images to carry out the corresponding simulation of gas injection sealability, which was equivalent to changing the rock skeleton and carrying out simulation of gas injection sealability for different digital pore network models. In the pore network simulation, the boundary conditions were simulated by gradually increasing the gas injection pressure, where the first gas injection pressure point referred to the initial pressure of the top gas injection sealing physical simulation experiment, after which each gas injection pressure point was increased by 0.1 MPa on the basis of the previous pressure point. By simulating the gas injection pressure corresponding to each variable condition, judge whether the corresponding digital core model breaks through; if not, simulate and judge the next gas injection pressure point according to the pressure interval of 0.1 MPa, until the simulation result is gas breakthrough; then, the gas injection pressure point is the breakthrough pressure of the digital core model. The rendezvous analysis (Figure18) of the simulated data showed that the breakthrough pressure of gas injection sealability obtained by means of pore network simulation still showed a good linear relationship with gas permeability in double logarithmic coordinates, and this characterization method of gas injection sealability in the interlayer was highly consistent with the previous physical simulation experiment of gas injection sealability at the top.Figure 18
Intersection of permeability and gas injection breakthrough pressure: (a) core experiment; (b) digital core simulation.
(a)(b)The formation fracture pressure in the gas injection test area of the lower Wuerhe group reservoir in zone 8 is 42 MPa, and 90% of the fracture pressure is the maximum injection pressure, from which it is calculated that the bottom flow pressure should be less than 38 MPa, and the maximum pressure difference of gas injection is determined to be 15-20 MPa by combining the current formation pressure in the test area from 0.5 m of the intercalation layer, from which it is concluded that the intercalation layer with gas measurement permeability less than 0.003 mD can play an effective role in this reservoir (Figure19). It can play an effective blocking role in this reservoir (Figure 19).Figure 19
Pore network simulation to analyze the mechanism of gas injection sealability from the pore throat perspective.Considering the consistency of the process and results of the physical simulation experiment of top gas injection sealability with the process and results of the pore network simulation of gas injection sealability, the mechanism of the physical phenomenon of gas injection sealability was analyzed from the pore throat perspective in the pore network simulation. The digital core simulation of gas injection sealability based on the characteristic pore network was carried out, and the simulation study was based on gas-liquid two-phase flow, and the capillary barrier effect of gas-liquid (Jamin effect) (Figure19) was considered the main mechanism of the interlayer sealability from the pore throat perspective. When the pore channel in the rock sample is small, the gas-liquid flow in the capillary tube will have a small capillary resistance, and when the integrated capillary resistance of the whole pore network is larger than the gas injection pressure, the gas is blocked from penetrating, and this explanation also corresponds to the previous experimental results at the core scale. At the same time, this capillary barrier effect is reflected in the specific simulation process, where part of the gas-liquid interface in the digital core model will jump back and forth in the corresponding pore channel, showing that the existing boundary conditions like the gas injection pressure cannot overcome the capillary resistance reflected in the digital core model as a whole.The research work above is aimed at the interlayer. Also, there may be a problem to evaluate gas injection breakthrough pressure for the low-permeability reservoir; in particular, it is likely to cause multiphase flow when the fluid saturation state is complicated. This is a limitation for this research work.


## 5.2. Effects of the Well Type and Shot Hole Location on the Gas-Liquid Interface

In the practical engineering application, the interlayer below the lower limit of permeability can be treated as a dead grid in the reservoir numerical simulation model through the analysis of the sealing mechanism of the interlayer. Thus, the influence of the interlayer on the gas-liquid interface is analyzed in the numerical simulation model.In the macroscopic aspect, firstly, the micromechanism analysis and the analysis of the lower seepage limit of gas injection were integrated to delineate the interlayer on the geological model, while the numerical simulation analysis was carried out by combining the influence of the interlayer on the gas-liquid interface analyzed by the physical model experiment. Combined with the practical understanding of the mine site, the interlayer and well type jointly affect the underground gas injection transport pattern and gas-liquid interface stability. In general, the spatial distribution pattern of the combination of the interlayer and well network types have the following common patterns (Figure20), and injection wells generally use two types of wells, which were vertical or horizontal well type, which differ only in injection capacity and have little effect on underground gas transport, so no distinction was made between injection well types. The combination of two types of well, which were vertical injection and horizontal injection, and eight types of seepage barriers in relation to the injection well shot hole location were subdivided (Table 8) [22–24].Figure 20
Schematic diagram of vertical injection and vertical production (a) and vertical injection and horizontal production (b) modes.
(a)(b)Table 8
Relationship between different combinations of well types, seepage barriers, and injection well shot hole locations.
Injection and production well typeNumberInterlayer type and extension distanceLocation relationship between the interlayer and shot holes of injection and production wellsVertical injection and vertical productionASingle interlayer, 1/2 well spacingProduction well shot hole is located below the interlayerBSingle interlayer, 3/4 well spacingProduction well shot hole is located below the interlayerCSingle interlayer, 3/4 well spacingGas injection well shot hole is located above the interlayerDMultiple interlayers, space stackingProduction well shot hole is located below the interlayerVertical injection and horizontal productionESingle interlayer, 3/4 well spacingHorizontal section is far from the interlayerFSingle interlayer, 3/4 well spacingHorizontal section is close to the interlayerGMultiple interlayers, 3/4 well spacingClose longitudinal distance between interlayersHMultiple interlayers, 3/4 well spacingLong longitudinal distance between interlayers


### 5.2.1. Vertical Injection and Vertical Production Mode

In the early stage, the interlayer had an impact on the stability of the gas-liquid interface, and part of the remaining oil above the interlayer could not be flooded to the wellbore, which made it difficult to effectively replace the remaining oil at the top of the interlayer. In the middle and later stages, with the increase in gas injection, the reservoir above the gas-liquid interface was basically gradually replaced effectively, including the remaining oil at the top of the interlayer, and finally, the gas-liquid interface remained balanced and stable (Figure21) [25–31].Figure 21
Variation of the gas-liquid interface of four combined relationships in vertical injection and vertical production mode.


### 5.2.2. Vertical Injection and Horizontal Production Mode

In the early stage, the gas-liquid interface was influenced by the interlayer, and the injected gas partially bypassed the interlayer to repel the remaining oil above the horizontal section, while partially it was difficult to displace the remaining oil above the interlayer to the wellbore due to the obstruction of the interlayer; in the middle and late stages, the gas-liquid interface gradually reached equilibrium and stability with the increase in the gas injection volume (Figure22).Figure 22
Variation of the gas-liquid interface in four combined relationships under vertical injection and horizontal production mode.On the whole, the advantage of the research work above is to have a good understanding of the gas injection sealing mechanism of the interlayer in combination with several methods with different scales, including micropore network simulation, core physical simulation experiment, and reservoir numerical simulation. Its disadvantage is that the understanding is still slightly weak in the combination with the macroapplication of reservoir gas injection.


## 5.2.1. Vertical Injection and Vertical Production Mode

In the early stage, the interlayer had an impact on the stability of the gas-liquid interface, and part of the remaining oil above the interlayer could not be flooded to the wellbore, which made it difficult to effectively replace the remaining oil at the top of the interlayer. In the middle and later stages, with the increase in gas injection, the reservoir above the gas-liquid interface was basically gradually replaced effectively, including the remaining oil at the top of the interlayer, and finally, the gas-liquid interface remained balanced and stable (Figure21) [25–31].Figure 21
Variation of the gas-liquid interface of four combined relationships in vertical injection and vertical production mode.


## 5.2.2. Vertical Injection and Horizontal Production Mode

In the early stage, the gas-liquid interface was influenced by the interlayer, and the injected gas partially bypassed the interlayer to repel the remaining oil above the horizontal section, while partially it was difficult to displace the remaining oil above the interlayer to the wellbore due to the obstruction of the interlayer; in the middle and late stages, the gas-liquid interface gradually reached equilibrium and stability with the increase in the gas injection volume (Figure22).Figure 22
Variation of the gas-liquid interface in four combined relationships under vertical injection and horizontal production mode.On the whole, the advantage of the research work above is to have a good understanding of the gas injection sealing mechanism of the interlayer in combination with several methods with different scales, including micropore network simulation, core physical simulation experiment, and reservoir numerical simulation. Its disadvantage is that the understanding is still slightly weak in the combination with the macroapplication of reservoir gas injection.


## 6. Conclusions

(1)
The lithology, mineral composition, pore throat, and physical characteristics of the interlayer were described in detail by using a combination of cast thin section, XRD, NMR, CT, high-pressure mercury injection, and conventional physical analysis, and the lithology of the interlayer was determined to be mainly mud-bearing medium gravel, mud-calcareous fine gravel, and mud-bearing rock chip medium/fine sandstone, with pores mainly microporous, with an average porosity of 6.1% and an average permeability of 0.0043 mD(2)
Through the combination of core breakthrough experiments and digital core simulations, it was determined that the gas injection breakthrough pressure of the interlayer was in a double log-linear relationship with the permeability, and the lower limit of gas injection of the interlayer in the target ultra-low-permeability gravel reservoir was 0.003 mD(3)
By combining the conventional interlayer identification criteria with the lower permeability limit of gas injection breakthrough, the gas injection limit of the interlayer in this area was determined to bePor≤7.0% and K≤0.003mD(4)
Using physical and numerical models to determine the effect of different types of seepage barrier combinations and different well-type combinations on gas injection, the initial seepage barrier has a greater impact on the gas-liquid interface, partly due to the difficulty in flooding the remaining oil above due to the blockage, and the gas-liquid interface gradually reached stability with the increase in gas injection in the middle and late stages, which had little impact on the final oil recovery



---

*Source: 9529001-2022-06-18.xml*