Method of moderate water injection and its application in ultra-low permeability oil reservoirs of Yanchang Oilfield, NW China

Fig. 1. Correlation curve of imbibition displacement efficiency and displacing speed.

1.3.2. Influencing factors of dynamic imbibition displacement efficiency

In order to analyze the main factors affecting the efficiency of imbibition-displacement, dynamic imbibition experiment between fracture and matrix is conducted. Additionally, the effects of reservoir physical properties, core wettability, water saturation, fluid viscosity and other parameters on dynamic imbibition were compared.

There is a large error to evaluate the properties of ultra-low permeability reservoirs with a single parameter of permeability or porosity, so reservoir quality index ($\sqrt{{K}/{\phi }\;}$) is taken to characterize the effect of reservoir properties on the efficiency of imbibition displacement. In Fig. 2a, the efficiency of imbibition displacement increases as reservoir quality index increases. When the reservoir quality index is less than 0.0327 μm, pore throat connectivity gets worse and original water saturation of pores increases, resulting in the insufficient conditions of imbibition displacement and poor displacement effect. In Fig. 2b, as the wetting index of the core water phase gets larger, the water absorption and drainage capacity get stronger and the efficiency of the imbibition displacement gets higher. From Fig. 2c, we can see that the greater the water saturation results in the smaller capillary pressure, the imbibition is weakened, because the small pores in the matrix have been filled with water mostly, and the probability of injecting water to displace the oil and the connecting range become smaller. It can be seen from Fig. 2d, the greater the oil-water viscosity ratio, the lower the efficiency of imbibition oil displacement, the imbibition is harder to occur because of the high capillary pressure for imbibition due to the high oil-water viscosity ratio.

Fig. 2.

Fig. 2. Effects of reservoir quality index (a), wettability (b), water saturation (c) and oil-water viscosity ratio to the efficiency of imbibition displacement.

1.3.3. Correction of dynamic imbibition speed based on imbibition experiment

The theoretical calculation method of oil-water two-phase imbibition speed can be acquired by referring to the L-W Model. The model requires a horizontal capillary tube with radius of r and length of L, and the original condition is the capillary tube fully filled with non-wetting phase fluid. Imbibition occurs when two phases connecting, non-wetting phase fluid is driven out by wetting phase fluid under capillary pressure.

Analyzing the dynamics of fluids in the capillary tube by using Poiseuille equation, oil-water two-phase fluid movement speed is obtained^[23]:

(2)${{v}_{\text{i}}}=\frac{{{r}^{2}}\left( \Delta p+{{p}_{\text{c}}} \right)}{8\sqrt{{{\left( {{\mu }_{\text{w}}}L \right)}^{2}}-\left( {{\mu }_{\text{w}}}-{{\mu }_{\text{o}}} \right)\left[ \frac{{{r}^{2}}t}{4}\left( \Delta p+{{p}_{\text{c}}} \right)+2{{\mu }_{\text{w}}}L{{L}_{t}}-{{L}_{t}}^{2}\left( {{\mu }_{\text{w}}}-{{\mu }_{\text{o}}} \right) \right]}}$

When the displacement pressure difference is zero, it’s the spontaneous imbibition of the oil-water system, equation (2) can be changed to:

(3)${{v}_{\text{i}}}=\frac{{{r}^{2}}{{p}_{\text{c}}}}{8\sqrt{{{\left( {{\mu }_{\text{w}}}L \right)}^{2}}-\left( {{\mu }_{\text{w}}}-{{\mu }_{\text{o}}} \right)\left[ \frac{{{r}^{2}}t}{4}{{p}_{\text{c}}}+2{{\mu }_{\text{w}}}L{{L}_{t}}-{{L}_{t}}^{2}\left( {{\mu }_{\text{w}}}-{{\mu }_{\text{o}}} \right) \right]}}$

Equation (3) reveals the flow in a single capillary tube, which is a microscale flow, and can be used to simulate reservoir macroscopic oil-water two-phase flow. Through equation (4) to change the capillary radius to a function of porosity and permeability:

(4)$r\text{=}\sqrt{\frac{8K}{\phi }}$

The water film exists in ultra-low permeability reservoirs, capillary pressure can be expressed as:

(5)${{p}_{\text{c}}}\text{=}\frac{2{{\sigma }_{\text{ow}}}}{r}$

By analyzing the dynamic imbibition experiment, the main controling factors of imbibition speed are wettability, reservoir properties, model size, oil-water viscosity and water saturation. Equation (3) takes wettability, reservoir properties, model size and oil-water viscosity into consideration except for water saturation; therefore, by introducing the correction term of water saturation to obtain the expression of oil-water two-phase imbibition speed by fitting experimental data (in Fig. 3) to determine correction factors a and n:

(6)${{v}_{\text{i}}}^{\prime }=\frac{a\sqrt{\frac{K}{\phi }}{{\sigma }_{\text{ow}}}{{\left( 1-{{S}_{\text{w}}} \right)}^{n}}}{\sqrt{{{\left( {{\mu }_{\text{w}}}L \right)}^{2}}-\left( {{\mu }_{\text{w}}}-{{\mu }_{\text{o}}} \right)\left[ \sqrt{\frac{2K}{\phi }}{{\sigma }_{\text{ow}}}t+2{{\mu }_{\text{w}}}L{{L}_{t}}-{{L}_{t}}^{2}\left( {{\mu }_{\text{w}}}-{{\mu }_{\text{o}}} \right) \right]}}$

Fig. 3.

Fig. 3. The contrast between corrected formula of imbibition speed and experimental test results.

2. Numerical simulation of imbibition-displacement

In order to apply the results of laboratory experiments to the practice of field water injection, a new imbibition-displacement numerical simulation method considering the effect of imbibition was built. The displacement and imbibition during waterflooding process are two main restricting factors of recovery, which are reflected in the reservoir as two main parameters^[24,25,26]: fracture permeability and exchange capacity between fractures and matrix. The exchange ability between fractures and matrix is the most important affecting factor in oil recovery and has an important influence on waterflooding effect in low permeability oilfield^[27,28]. Fig. 4 is a physical model schematic of dual-porosity dual-permeability system.

Imbibition flow and non-Darcy flow coexist between matrix and fractures, controlled by the capillary pressure and displacement pressure differential. And Darcy flow exists between fractures.

Fig. 4.

Fig. 4. Schematic of the physical model for the dual-porosity and dual-permeability system.

2.1. Mathematical model of the imbibition-displacement flow

The assumptions are as follows: (1) The fluid flowing in the reservoir is isothermal. (2) Only two phases of oil and water in the reservoir, and oil and water seepage follow the non-Darcy’s law. (3) Oil and water are not miscible. (4) Rock is slightly compressible, considering the capillary pressure in the process of seepage.

2.1.1. Mathematical model of the imbibition-displacement flow in the matrix

For the water phase:

(7)$\pm \frac{\partial }{\partial x}{{\left[ {{\rho }_{\text{w}}}\frac{{K}'{{K}_{\text{rw}}}}{{{\mu }_{\text{w}}}}\left( \frac{\partial {{p}_{\text{w}}}}{\partial x}-{{G}_{\text{w}}} \right) \right]}_{\text{m}}}\pm \frac{\partial }{\partial y}{{\left[ {{\rho }_{\text{w}}}\frac{{K}'{{K}_{\text{rw}}}}{{{\mu }_{\text{w}}}}\left( \frac{\partial {{p}_{\text{w}}}}{\partial y}-{{G}_{\text{w}}} \right) \right]}_{\text{m}}}\pm \\ \frac{\partial }{\partial z}{{\left[ {{\rho }_{\text{w}}}\frac{{K}'{{K}_{\text{rw}}}}{{{\mu }_{\text{w}}}}\left( \frac{\partial {{p}_{\text{w}}}}{\partial z}-{{G}_{\text{w}}} \right) \right]}_{\text{m}}}+{{q}_{\text{wfm}}}+{{q}_{\text{wm}}}=\frac{\partial {{\left( \phi {{\rho }_{\text{w}}}{{S}_{\text{w}}} \right)}_{\text{m}}}}{\partial t}$

For the oil phase:

(8)$\pm \frac{\partial }{\partial x}{{\left[ {{\rho }_{\text{o}}}\frac{{K}'{{K}_{\text{ro}}}}{{{\mu }_{\text{o}}}}\left( \frac{\partial {{p}_{\text{o}}}}{\partial x}-{{G}_{\text{o}}} \right) \right]}_{\text{m}}}\pm \frac{\partial }{\partial y}{{\left[ {{\rho }_{\text{o}}}\frac{{K}'{{K}_{\text{ro}}}}{{{\mu }_{\text{o}}}}\left( \frac{\partial {{p}_{\text{o}}}}{\partial y}-{{G}_{\text{o}}} \right) \right]}_{\text{m}}}\pm \\ \frac{\partial }{\partial z}{{\left[ {{\rho }_{\text{o}}}\frac{{K}'{{K}_{\text{ro}}}}{{{\mu }_{\text{o}}}}\left( \frac{\partial {{p}_{\text{o}}}}{\partial z}-{{G}_{\text{o}}} \right) \right]}_{\text{m}}}+{{q}_{\text{ofm}}}+{{q}_{\text{om}}}=\frac{\partial {{\left( \phi {{\rho }_{\text{o}}}{{S}_{\text{o}}} \right)}_{\text{m}}}}{\partial t}$

Considering the effect of stress sensitivity on matrix permeability:

(9)${{K}_{\text{m}}}^{\prime }={{K}_{\text{m}0}}{{\text{e}}^{-{{\alpha }_{\text{m}}}\left( {{p}_{\text{m}0}}-{{p}_{\text{m}}} \right)}}$

Considering the effect of starting pressure on the matrix:

(10)$\frac{\partial p}{\partial x}-G=\left\{ \begin{matrix} \frac{\partial p}{\partial x}-G\quad \quad \frac{\partial p}{\partial x}>G \\ 0\quad \quad \quad \quad \frac{\partial p}{\partial x}\le G \\ \end{matrix} \right.$

2.1.2. Mathematical model of the imbibition-displacement flow in fracture

For the water phase:

(11)$\pm \frac{\partial }{\partial x}{{\left( {{\rho }_{\text{w}}}\frac{{K}'{{K}_{\text{rw}}}}{{{\mu }_{\text{w}}}}\frac{\partial {{p}_{\text{w}}}}{\partial x} \right)}_{\text{f}}}\pm \frac{\partial }{\partial y}{{\left( {{\rho }_{\text{w}}}\frac{{K}'{{K}_{\text{rw}}}}{{{\mu }_{\text{w}}}}\frac{\partial {{p}_{\text{w}}}}{\partial y} \right)}_{\text{f}}}\pm \\ \frac{\partial }{\partial z}{{\left( {{\rho }_{\text{w}}}\frac{{K}'{{K}_{\text{rw}}}}{{{\mu }_{\text{w}}}}\frac{\partial {{p}_{\text{w}}}}{\partial z} \right)}_{\text{f}}}-{{q}_{\text{wfm}}}+{{q}_{\text{wf}}}=\frac{\partial {{\left( \phi {{\rho }_{\text{w}}}{{S}_{\text{w}}} \right)}_{\text{f}}}}{\partial t}$

For the oil phase:

(12)$\pm \frac{\partial }{\partial x}{{\left( {{\rho }_{\text{o}}}\frac{{K}'{{K}_{\text{ro}}}}{{{\mu }_{\text{o}}}}\frac{\partial {{p}_{\text{o}}}}{\partial x} \right)}_{\text{f}}}\pm \frac{\partial }{\partial y}{{\left( {{\rho }_{\text{o}}}\frac{{K}'{{K}_{\text{ro}}}}{{{\mu }_{\text{o}}}}\frac{\partial {{p}_{\text{o}}}}{\partial y} \right)}_{\text{f}}}\pm \\ \frac{\partial }{\partial z}{{\left( {{\rho }_{\text{o}}}\frac{{K}'{{K}_{\text{ro}}}}{{{\mu }_{\text{o}}}}\frac{\partial {{p}_{\text{o}}}}{\partial z} \right)}_{\text{f}}}-{{q}_{\text{ofm}}}+{{q}_{\text{of}}}=\frac{\partial {{\left( \phi {{\rho }_{\text{o}}}{{S}_{\text{o}}} \right)}_{\text{f}}}}{\partial t}$

Considering the change of fracture permeability:

(13)${{K}_{\text{f}}}^{\prime }={{K}_{\text{f}0}}{{\text{e}}^{-{{\alpha }_{\text{f}}}\left( {{p}_{\text{f}0}}-{{p}_{\text{f}}} \right)}}$

2.1.3. Mathematical model of the fluid exchange

Considering the effect of starting pressure and stress sensitivity, the mathematical models of fluid exchange between matrix and fractures caused by displacement and imbibition are established respectively.

The channeling flow between matrix and fractures produced by displacement (considering starting pressure gradient and stress sensitivity):

(14)${{Q}_{\text{fm}1}}=\frac{A}{{{l}_{\text{fm}}}}{{K}_{\text{m}}}^{\prime }\frac{{{K}_{\text{r}}}\rho \left( p \right)}{\mu \left( p \right)}\left( {{p}_{\text{m}}}-{{p}_{\text{f}}}-G{{l}_{\text{fm}}} \right)$

The channeling flow between matrix and fractures produced by imbibition:

(15)${{Q}_{\text{fm2}}}=\rho {{v}_{\text{i}}}^{\prime }{{S}_{\text{mf}}}$

The total channeling flow between matrix and fractures:

(16)${{Q}_{\text{fm}}}={{Q}_{\text{fm}1}}\text{+}{{Q}_{\text{fm}2}}$

The above mathematical models can be solved by the numerical method, and the variable data of reservoir pressure, saturation and production with time can be obtained. The traditional IMPES (hidden pressure and apparent saturation) finite difference method is used to solve the model. The calculation is shown in Fig. 5.

Fig. 5.

Fig. 5. Flow chart of the numerical simulation.

2.2. Example analysis

This paper took the Chang 8 reservoir in the south of Yanchang oilfield as an example, numerical simulation analysis of imbibition-displacement is conducted. Geological model is a block central grid. In the x, y, z direction, grid numbers are 100, 100 and 2, grid sizes are 10, 10 and 8 m, respectively. This paper used diamond-shaped inverted nine-point vertical well injection and production well network. The model relative permeability curve is shown in Fig. 6, and the model parameters are summarized in Table 2.

Fig. 6.

Fig. 6. Relative permeability curve of the model.

Table 2 Basic parameters of simulation model.

Parameter	Value	Parameter	Value
Porosity of matrix	4.58%	Reservoir thickness	8 m
Permeability of matrix	0.25× 10^-3 μm²	Oil saturation	58%
Porosity of fracture	0.1%	Density of water	1.01 g/cm³
Permeability of fracture	500× 10^-3 μm²	Oil/water viscosity ratio	3.5
Density of crude oil	0.86 g/cm³	Oil-water inter- facial tension	40 mN/m
Initial formation pressure	12 MPa	Bottom hole pressure of oil well	3.5 MPa
Starting pressure gradient of oil phase	0.04 MPa/m	Starting pressure gra- dient of water phase	0.01 MPa/m
Stress sensitivity coefficient of matrix permeability	0.017 MPa^-1	Sensitivity coeffi- cient of fracture permeability	0.065 MPa^-1
Water flooding volume	10 m³/d

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Fig. 7 shows the effect of imbibition on oil saturation after 15 years of production. It can be seen that the oil saturation of the fracture system decreases continuously without considering imbibition. When the water line is advanced to the bottom of the oil well, the oil saturation of the fracture system is very low, and a large amount of residual oil in matrix is accumululated. The oil saturation in the matrix decreases while the oil saturation in fracture system increases when the effect of imbibition is considered. The reason is that there is a significant difference in the waterflooding development process between ultra-low permeability reservoir and conventional reservoir. Under the effect of imbibition, the crude oil in the matrix flows to the fractures continuously, which makes the oil saturation in the fractures increase and the water saturation decreases.

Fig. 7.

Fig. 7. Effect of imbibition on oil saturation of model.

Fig. 8 shows the effect of imbibition on the daily oil production of a single well. It can be seen that in the early stage of production, the production rate decreases rapidly with and without percolation, which indicated that the fluid flow is mainly fracture seepage. In the later stage of production, when considering the effect of imbibition, production rate remained stable for a long time at a low value. While without the consideration of the effect of imbibition, production rate continuously decreasing until the oil is no longer produced. The average daily oil production of a single well considering imbibition is 0.32 t, and the average daily oil production of a single well without imbibition is only 0.06 t, while the actual average daily oil production of a single well is 0.28 t. The predicted production value of oil wells considering imbibition is more consistent with the actual production data of moderate water injection wells. It is verified that the numerical simulation results of imbibition-displacement in this paper are more in line with the actual development of fractured ultra-low permeability reservoirs, and also shows that imbibition flooding plays an important role in the late stage of water injection development of fractured ultra-low permeability reservoirs.

Fig. 8.

Fig. 8. Effect of imbibition on daily oil production in single well.

This paper used the numerical simulation method of imbibition-displacement. The injection-production ratio and daily water injection rate are optimized with the aim of maximizing recovery at 95% water cut (Fig. 9). As shown in Fig. 9a, the recovery rate is the highest when the injection-production ratio is 0.95, which is 17.2%. Compared with the traditional water injection scheme (injection-production ratio is 1.2), the recovery rate is increased 2.9 percentage. According to Fig. 9b, the highest rate of recovery is 17.4% when the daily water injection volume is 7.5 m³.

Fig. 9

Fig. 9 Effect of the injection-production ratio (a) and daily water injection (b) on recovery

3. Moderate water injection mechanism and application

3.1. Moderate water injection mechanism

Both laboratory experiments and numerical simulation show that reasonable control of water injection pressure, water injection intensity and water injection speed can fully exert the effect of imbibition-displacement, and significantly improve the development efficiency of ultra-low permeability reservoirs. This is also the core of the current moderate water injection. The moderate water injection is based on the moderate water injection (controlling the water injection strength and the water injection pressure), and moderately controlling the advancement speed of the water drive front, increasing the oil-water exchange time, and giving full play to the spontaneous imbibition of the capillary to enhance the oil recovery. The main mechanism includes: On one hand, the positive imbibition is effectively utilized, and the water injection intensity and the water injection pressure are controlled to make the front of the water drive as uniform as possible to avoid the occurrence of water breakthrough and water out. On the other hand, through reverse imbibition and exchange and based on the mechanism of water absorption and oil drainage of hydrophilic porous media, reasonable control of water injection displacement speed, more crude oil can be produced from matrix. After large-scale fracturing of ultra-low permeability reservoirs, a high flow conductivity fracture network is formed. Under the pressure of capillary pressure, the wetting phase (water) in the fracture penetrates into the matrix, and the non-wetting phase (oil) in the matrix is replaced to fractures to the bottom of the well by the pressure difference of the injected water.

3.2. Moderate water injection mine application

The well group with the improved injection-production well network in the test area is selected as the moderate water injection test well group, and the diamond-shaped inverted nine-point injection-production well network is conducted. The net pay of the oil layer is 11.2 m, the effective porosity is 5.8%, the permeability is 0.28×10^-3 μm², oil saturation is 58%, and the crude oil density is 0.86 g/cm³.

From the comprehensive production curve (Fig. 10), it can be seen that the studied area started to produce in 2004, and water injection began in 2006. At the early stage of production, no water was injected, and developed with natural attenuation. The production of liquid and crude oil decreased rapidly and the water content increased slowly. From 2006 to 2008, it was the early stage of water injection. The injection-production ratio of the stage was between 1.2 and 1.6. The liquid production of single well was increased, but the water content increased rapidly while the oil production continued to decrease. The main reason was that the injected water rapidly advanced along the fractures, and the efficiency of water injection was not ideal. Water injection has been adjusted during 2009 to 2012, the stage injection-production ratio was gradually changed from 1.45 to 0.96, the water content decreased from 61% to 53%, and the average single well daily oil production changed from 1.27 t to 1.26 t. In 2013, it entered the moderate water injection high-efficiency and stable production period. The injection-production ratio was controlled at 0.95, and the water injection volume was controlled at 7.0-8.0 m³/d. The water injection development showed stable liquid production, stable water content, stable oil production, and stable oil production and water control effect. It can be seen from the evaluation of water injection efficiency (Fig. 11) that after the implementation of moderate water injection, and the waterflooding recovery is predicted to increase significantly, which is expected to reach 20%. It can be seen that the imbibition effect is essential for improving the efficiency of oil displacement in ultra-low permeability reservoirs. Moreover, the moderate water injection technology that fully exerts the imbibition can ensure the continuous high and stable oil production in the ultra-low permeability reservoirs.

Fig. 10.

Fig. 10. Production curve of moderate water injection in test area.

Fig. 11.

Fig. 11. Evaluation of the development effect of moderate water injection in test area.

4. Conclusion

The fractured ultra-low permeability reservoir has imbibition effect, and the imbibition speed is affected by reservoir physical properties, core wettability, water saturation, and fluid viscosity. The mathematical model for determining the speed of imbibition is the core of the numerical simulation of imbibition-displacement. Based on the L-W single-tube model combined with the experimental data of dynamic imbibition speed, the imbibition speed of macroscopic oil-water flow can be obtained. Compared with the effect without imbibition, the numerical simulation prediction index of ultra-low permeability reservoir considering the imbibition is more consistent with the actual production. The effect of the imbibition cannot be ignored in the development of water injection in ultra-low permeability reservoirs. The moderate water injection technology that fully exerts the imbibition has a remarkable effect of stabilizing oil and controlling water cut and can be popularized and applied in hydrophilic ultra-low permeability reservoirs.

Nomenclature

a, n—imbibition speed correction coefficient;

A—contact area, m²;

G—starting pressure gradient, Pa/m;

K—absolute permeability, 10¹² μm²;

K₀—absolute permeability before change, 10¹² μm²;

K_r—relative permeability;

K°— effective permeability, 10¹² μm²;

l_fm—the distance between matrix and fracture, m;

L—capillary length, m;

L_t—oil-water two-phase contact position at t, m;

p—fluid pressure, Pa;

p₀—fluid pressure before change, Pa;

p_c—capillary pressure, Pa;

Δp—displacement pressure difference, Pa;

q_f, q_m—seepage flow of unit volume between fractures, matrixes, kg/(m³·s);

q_fm—flow per unit volume between fracture and matrix, kg/(m³·s);

Q_fm—total flow between fracture and matrix, kg/s;

Q_fm1, Q_fm2—flow between the fracture and the matrix by displacement and turbulence, kg/s;

r—capillary radius, m;

S_fm—seepage exchange area, m²;

S_w—water saturation, f;

t—time, s;

v_i—imbibition speed, m/s;

v_i°—corrected imbibition speed, m/s;

V_i—volume of crude oil produced at different time, m³;

V_o—total volume of crude oil saturated the rock, m³;

x, y, z—cartesian coordinate system, m;

α—stress sensitivity coefficient, Pa^-1;

η—imbibition displacement efficiency, %;

μ——fluid viscosity, Pa·s;

ρ—fluid density, kg/m³;

σ_ow—oil-water interfacial tension, N/m;

ϕ—porosity, f.

Subscripts:

f—fracture;

m—matrix;

o—oil phase;

w—water phase.

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Low permeability sandstone reservoir imbibition law research

Petroleum Geology & Oilfield Development in Daqing, 2003,22(3):50-52.

With the discovery of more and more low permeable oil fields, the objective of petroleum production is concentrated on the development of low permeable oil fields gradually. Due to poor production and injection capacity of low permeable reservoir, imbibition recovery plays important role in the oilfield development. This paper introduces a new kind of imbibition equipment, and by use of it we studied the reverse imbibition law of low permeable core. Using X-Ray' s degree of change checkout apparatus, we studied the core length effect on reverse imbibition performance and ultimate imbibition recovery, as well as the change course of watercut variation for core of different stages during imbibition process. And reach to the following conclusion: adverse imbibition is the main recovery mechanism in fractured low permeable sandstone reservoir; Due to the characteristic of low permeable reservoir, the effectiveness of capillary force is restricted, imbibition is slow, and imbibition recovery is low; the X-Ray' s scanning result shows that imbibition speed is quick at the initial stage of imbibition, and the imbibition speed slows down after imbibition frontline arrives the boundary.

[10]

Aifen

, FAN

Tianyou

, ZHAO

Lin

Experimental study of spontaneous imbibition in low permeability core fractured reservoir

Petroleum Geology and Recovery Efficiency, 2011,18(5):67-77.

DOI:10.1016/S1003-9953(10)60145-4 URL [Cited within: 1]

Low permeability fractured reservoir has a poor recovery by water flooding,there is still a lot of residual oil left in the matrix after water flooding.It is an important mechanism that the oil flows into the fracture from matrix by imbibition,and various influencing factors are still needed to be studied.In this paper,we studied a number of factors,such as wettability,temperature, viscosity,interfacial tension,and so on,which affect the imbibition through spontaneous imbibition experiments in formation water and surfactant solution,based on the natural low permeability core from Chunliang oil production factory.The results show that the temperature is not the direct factor of imbibition,but it can affect the imbibition indirectly by changing the oil viscosity.The main factors affecting spontaneous imbibition are wettability,oil viscosity and interfacial tension.The more hydrophily of the core,the lower the oil viscosity,and the higher imbibition oil recovery.For the water wet core,it is the permeability and interfacial tension which control the imbibition mode.Different permeability levels have different optimal range of interfacial tension values,in which imbibition has the highest recovery.For the water-wet core and weak-water-wet core,the higher the permeability,the lower the optimal interfacial tension.

[11]

PEI

Bailin

, PEN

Kezong

, HUANG

Aibin

A new method of measuring imbibition curves

Journal of Southwestern Petroleum Institute, 1994,16(4):46-50.

DOI:10.3863/j.issn.1000-2634.2008.06.042 URL [Cited within: 1]

In view of the great errors in the measurment of imbibition curves,this paper presents a new method of improving the accuracy of the measurement of imbibition curves,and also in troduces its principle,experiment and data analysis.

[12]

PENG

Yuqiang

, HE

Shunli

, GUO

Shangping

, et al.

Effect of injection rate on spontaneous imbibition of sandstone

XinJiang Petroleum Geology, 2010,31(4):399-401.

DOI:10.3724/SP.J.1077.2010.01195 URL [Cited within: 1]

The effect of brine injection rate on spontaneous imbibition behavior and recovery of sandstone is studied, and the ultimate recovery comparison between static imbibition and dynamic imbibition is conducted. The results show that with the increase of brine injection rate, the dynamic imbibition recovery increases and decreases, rapidly, and then tends to be stable, with mono-peak variation in oil recovery and brine injection rate. The fact that dynamic imbibition recovery is lower than static one indicates that spontaneous imbibition of sandstone needs enough time to full exert capillary imbibition in low permeability reservoir. So the injection rate should be low, and measures including intermittent and cyclic injection and production should be adopted in order to increase the spontaneous imbibition recovery.

[13]

WANG

Rui

, YUE

Xiangan

Influence of pressure sensitivity on imbibition for low permeability reservoir rocks.

Journal of Southwest Petroleum University (Science & Technology Edition), 2008,30(6):173-175.

Mechanisms of cyclic water injection are analyzed by combining rock pressure sensitivity experiment and imbibition experiment in view of the characteristics of much remaining oil in the matrixes of fractured low permeability reservoir.Imbibition experiment of different permeability cores and different pressure drops,pressure sensitivity experiment of permeability are studied and compared.The results show that,imbibition recovery ratio firstly increases and then decreases with the increasing of permeability,permeability loss of core is mainly in the early stage of effective pressure increase,influence of pressure drop degree and speed on imbibition recovery ratio takes on the trend of firstly decreasing then increasing,pressure sensitivity is mainly at the smaller pressure drop degree,and the pressure difference caused by pressure fluctuation plays roles mainly at the bigger pressure drop degree and speed in the process of cyclic water injection.

[14]

WANG

Rui

, YUE

Xiangan

, LI

Yiyong

, et al.

Experimental study on the imbibition under the conditions of different scales

Petroleum Geology & Oilfield Development in Daqing, 2012,31(2):112-115.

[15]

KEIJZER P P

, DE VRIES A

Imbibition of surfactant solutions. SPE 20222-PA

1993.

[16]

Xiaoyu

, PU

Chunsheng

, HUANG

Hai

, et al.

Micro-influencing mechanism of permeability on spontaneous imbibition recovery for tight sandstone reservoirs

Petroleum Exploration and Development, 2017,44(6):948-954.

DOI:10.1016/S1876-3804(17)30107-6 URL [Cited within: 1]

The upper part of the 4 th member of Paleogene Shahejie Formation in Bonan sag, Bohai Bay Basin, East China was taken as the study object. Conventional core analysis, casting and conventional thin section inspection, scanning electron microscope observation, particle size analysis and fluid inclusion analysis were carried out on cores, and the data from these analyses and tests was used to find out the evolution of diagenetic environment of the saline lacustrine basin and the main factors controlling the deep formation of high quality reservoirs. The diagenetic environment of the saline lacustrine basin experienced alkali and acid alternation. In the early alkali diagenetic environment, large amounts of carbonate cement filled the primary pores, making the reservoir porosity reduce sharply from 37.3% to 18.77%, meanwhile, keeping the primary pores from compaction, and retaining the dissolution space. In the middle-late stage of acid diagenetic environment, early carbonate cement was dissolved, resulting in rise of reservoir porosity by 10.59%, and thus the formation of the deep high quality reservoirs. The distribution of high quality deep reservoirs is controlled by the development of gypsum salt rock, source rock, fracture system and sedimentary body distribution jointly. Deeply buried high quality reservoirs in the upper part of the 4 th member of the Shahejie Formation in Bonan sag are nearshore subaqueous fan-end sandstone and some fan-medium fine conglomerate buried at 3 400-4 400 m in the north steep slope.

[17]

MENG

Qingbang

, LIU

Huiqing

, WANG

Jing

, et al.

Imbibition law of naturally fractured reservoirs

Fault Block Oil & Gas Field, 2014,21(3):330-334.

To study the effect of imbibition on the naturally fractured reservoirs and improve the development performances, a typical geological model for the naturally fractured reservoirs was established. The influence of capillary pressure, uniformity of the pore, relative permeability curve, matrix permeability, fracture permeability, oil viscosity and matrix oil saturation on imbibition, which is divided into static and dynamic state, was studied by means of numerical simulation and the formula was fitted between imbibition rate and influence factors. For static state, a linear relationship is obtained between imbibition rate and capillary pressure, matrix permeability, residual oil saturation to water and relative permeability of oil at the irreducible water saturation, an exponent relationship is obtained between imbibition rate and irreducible water saturation, and a power exponent relationship is obtained between imbibition rate and oil viscosity. For dynamic state, the different development mode is proposed for the reservoirs with different wettability.

[18]

WANG

Jialu

, LIU

Yuzhang

, CHWN

Maoqian

, et al.

Experimental study on dynamic imbibition mechanism of low permeability reservoirs

Petroleum Exploration and Development, 2009,36(1):86-90.

[19]

WANG

Xiangzeng

Development technology in low permeability reservoir. Beijing: Petroleum Industry Press, 2012.

[20]

WANG

Jing

, LIU

Huiqing

, XIA

Jing

, et al.

Mechanism simulation of oil displacement by imbibition in fractured reservoirs

Petroleum Exploration and Development, 2017,44(5):761-770.

DOI:10.1016/S1876-3804(17)30091-5 URL [Cited within: 1]

The mechanism model of both static and dynamic imbibition considering capillary pressure and gravity was presented based on the imbibition mechanisms and seepage theory.The validation of the model was performed using published experiment data.Then,this model was employed to study the impacts of oil viscosity,matrix permeability,core size,interface tension,and displacement rate on imbibitions.The results show that,the recovery decreases as oil viscosity increases,and the initial imbibition rate is much faster for lower viscosity oil.Imbibitions recovery is positively related to matrix permeability,the differences of oil recovery for low-permeability to tight oil reservoirs are obvious.Imbibitions effect is negatively related to core size.If the interface tension is low,imbibitions cannot occur without consideration of gravity.But it can occur even in very low interface tension scenario with consideration of gravity.On the whole,the recovery first increases and then decreases as the interface tension decreases.The gravity and capillary play different roles at different ranges of interface tension.There exists an optimal value range of displacement rate in fractured reservoir,which should be optimized with a sufficient oil production rate to achieve higher recovery.

[21]

FANG

Wenchao

, JIANG

Hanqiao

, LI

Junjian

, et al.

A numerical simulation model for multi-scale flow in tight oil reservoirs

Petroleum Exploration and Development, 2017,44(3):415-422.

[22]

YANG

Zhengming

Porous flow mechanics for low permeability reservoirs and its application

Beijing: University of Chinese Academy of Sciences, 2004.

[23]

QIN

Jishun

, LI

Aifen

Reservoir physics. Dongying: University of Petroleum Press, 2003.

[24]

SCHECHTER D

, ZHOU

, ORR

F M J

Capillary imbibition and gravity segregation in low IFT systems

SPE 22594, 1991.

[25]

KEWEN

, ROLAND

Characterization of spontaneous water imbibition into gas-saturated rocks

SPE 62552, 2000.

[26]

CIL

, REIS J

, MILLER M

, et al.

An examination of countercurrent capillary imbibition recovery from single matrix blocks and recovery predictions by analytical matrix fracture transfer functions

SPE 49005, 1998.