Acidizing flowback optimization for tight sandstone gas reservoirs

Journal of Natural Gas Science and Engineering 24 (2015) 311e316

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Acidizing flowback optimization for tight sandstone gas reservoirs Jinghong Hu a, Hong Liu b, Dan Wu a, Junjing Zhang c, * a

Beijing Key Laboratory of Unconventional Natural Gas Geology Evaluation and Development Engineering, China University of Geosciences, Beijing, China School of Petroleum and Gas Engineering, Chongqing University of Science and Technology, Chongqing, China c ConocoPhillips Company, Houston, TX, USA b

a r t i c l e i n f o

a b s t r a c t

Article history: Received 9 September 2014 Received in revised form 21 March 2015 Accepted 23 March 2015 Available online

The physical properties of Sichuan tight sandstone formations include low porosity and low permeability. Fortunately, micro-fractures are well developed in this area, and the development of a reservoir is thus possible. Acidification can repair reservoir damage and improve single-well production; however, gas well production can change after acidizing: some wells improve, while others decline. After many studies, the flowback system after acidification has been shown to play an important role in determining the acidizing effect. Therefore, optimizing the flowback system after acidification can significantly influence the results of acidizing. A series of velocity sensitivity experiments have been performed, and their results show that the velocity sensitivity is high. Based on fluid mechanics principles, an optimization model of the acid flowback is constructed using experimental results; as a result, the relationship between the pressure drop in the wellhead and the choke size can be calculated, and a reasonable choke during the process of acid flowback can be determined using the methods described in this paper. The results are of great significance in optimizing the flowback system after acidification and also in enhancing the gas production of single wells. © 2015 Elsevier B.V. All rights reserved.

Keywords: Experiment Critical velocity Acidizing Flowback Mathematical model

1. Introduction When the flow rate of a fluid that is compatible with a reservoir's rock is above the critical velocity, the permeability may continue to decrease; this is called the velocity sensitivity effect. During the process of production, drilling, stimulation and water injection, fluids flowing in the reservoir may cause particle migration, blocked pores and a decline in permeability. In different reservoirs, the degree of damage due to particle migration is principally determined by the velocity of the fluids. A reasonable velocity of the fluids is thus a critical parameter to aid the development of reservoirs. The velocity sensitivity is related to the characteristics of the reservoir rock and the fluid properties. Damage to the reservoir will likely occur due to particle migration. The reasons for the velocity sensitivity of reservoirs can be explained better by interface mechanics and percolation mechanics (Shi et al., 2003). Laura K. (1982) showed that the stress and velocity are the primary factors that cause reservoir damage. The purpose of the

* Corresponding author. E-mail address: [email protected] (J. Zhang). http://dx.doi.org/10.1016/j.jngse.2015.03.042 1875-5100/© 2015 Elsevier B.V. All rights reserved.

velocity sensitivity experiments performed in this study is to determine the relationship between the fluid velocity and the change in permeability; to determine the critical velocity; and to evaluate the decline in permeability that is caused by the velocity sensitivity effect. Experiments are the primary method to study the stress-velocity sensitivity. The velocity sensitivity effect will be significantly enhanced as the effective stress increases (Penny and Conway, 1993). A series of experimental results show that a foamy fluid can reduce the damage caused to a reservoir (Penny and Conway, 1991). In recent years, studies on the sensitivity of fractures or crack-porosity carbonate reservoirs primarily focused on the stress sensitivity and the conventional fluid sensitivity (He et al., 2005; Lorenz, 1999; Qanbari, 2012; Li et al., 2007a,b). A group of experiments on stress-velocity sensitivity have been performed in the DaQing Oilfield and the ChangQing Oilfield (Sun et al., 2013). A full diameter core test can describe the real velocity sensitivity more accurately, particularly in reservoirs where the fractures and pores are well developed (Li et al., 2007a,b). The tight sandstone gas reservoir investigated in this study is located in the southern Sichuan Basin; the sandstone in this area is characterized by a low porosity and a low permeability, but microfractures do grow well in this area. However, the gas production of

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Table 1 Evaluation standard of the velocity sensitivity. Velocity sensitivity index (%)

5

5e30

30e50

50e70

>70

Sensitivity degree

None

Weak

Mid to weak

Mid to strong

Strong

Table 2 Velocity sensitivity evaluation results of the formation water. Core NO

Depth (m)

Kmax (10
3mm2)

Kmin (10
3mm2)

DK

Sensitivity degree

Remark

#1 #2 #3 #4 #5 #6 #7 #8 #9 #10

3679.06 3358.37 3342.38 3350.23 3467.28 3467.65 3428.73 3540.78 3340.70 3540.69

19.897175 2.103619 33.936314 4.958226 42.040754 29.564354 8.787063 108.456064 2.383921 1.120748

10.780940 1.696637 3.541181 3.796585 30.773832 9.447996 2.968038 87.863140 0.913012 0.571362

45.8 19.3 89.5 23.4 26.8 68.0 66.2 18.9 61.7 49.0

Mid to Weak Strong Weak Weak Mid to Mid to Weak Mid to Mid to

Formation Formation Formation Formation Formation Formation Formation Formation Formation Formation

wells after acidizing has been known to change; the effect of the acidizing flowback is the key factor to determine the final quality of the acidizing process. To optimize the acidizing flowback in this area, experiments and theories are both considered in this paper. First, the range of the critical velocity is obtained by velocity sensitivity experiments under experimental conditions. Second, based on the theory of the similarity principle, a critical velocity model of the acidizing flowback is built, and the critical velocity is calculated. Lastly, a model of the relationship between the pressure drop in the wellhead and the choke size is built based on the principles of fluid mechanics. Considering the effect of the invasion radius of the acidizing construction, a reasonable choke during the process of the acid flowback can be calculated. 2. Velocity sensitivity experiments with formation water 2.1. Evaluation program with formation water 1) Select the cores to use for testing, and then test the cores permeability in air; 2) Each core was saturated with formation water for 48 h in a vacuum;

Fig. 1. Curves of the velocity sensitivity experiments 1e5.

weak

strong strong strong weak

water water water water water water water water water water

3) Slowly adjust the confining pressure to 2 MPa while maintaining the confining pressure above the core upstream pressure; the value must be controlled to 1.5e2 MPa. Then, open the valve on the import side and in the displacement pump; the pump speed should not exceed 1 mL/min. At this time, gas will be displaced to the upstream pipeline of the core and is then discharged from the exhaust valve. When the gas is removed upwards, the pipeline is full of fluids, and the fluids begin to flow from the exhaust valve. The displacement pump or gas source should then be closed. 4) Open the outlet valve of the gripper, and then close the exhaust vent; 5) Measure the permeability of the formation water (KW); 6) During the experiments, set different flow rates (e.g., 0.50, 0.75, 1.0, 2.0, 3.0, 4.0, 5.0, 6.0 mL/min), and measure the formation permeability (Kf) under different flow rates; 7) (Ki
1
Ki)  100%/Ki
1 is used to determine whether the damage to the reservoir due to the velocity sensitivity would occur. When this value is more than 5%, damage will likely occur; this flow velocity can thus be defined as the critical velocity:

Fig. 2. Curves of the velocity sensitivity experiments 6e10.

J. Hu et al. / Journal of Natural Gas Science and Engineering 24 (2015) 311e316

313

Table 3 Calculation of the invasion radius. Well NO

Transform methods

Effective thickness/m

Porosity/%

Total injected fluid/m3

Invasion radius/m

No.1 well No.2 well No.3 well No.4 well No.5 well No.6 well No.7 well No.8 well No.9 well No.10 well No.11 well No.12 well No.13 well No.14 well No.15 well No.16 well No.17 well No.18 well No.19 well No.20 well No.21 well No.22 well No.23 well No.24 well No.25 well No.26 well No.27 well No.28 well No.29 well No.30 well No.31 well No.32 well No.33 well

Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Reducing resistance acid þ Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Reducing resistance acid þ Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Reducing resistance acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Composite acid acidizing Retarded hydrochloric acid þ Regeneration mud acid þ Retarded acid þ Antiswelling liquid acidizing Composite acid acidizing Composite acid acidizing

111 177 335.4 14 34 56 55 311 20 30.5 52 24 61.5 74 67 80 52 88 65 59 48 50.2 41 61 83 22 232.49 136 29.5 235.5 69 216 115

2% 7% 3.5% 3.5% 4% 3.5% 4% 5.2% 5.8% 9.55% 6.1% 4% 8.5% 6% 2.55% 3.25% 3% 5.5% 5.5% 3.7% 3.35% 2.9% 2.2% 5.55% 2.75% 0.80% 3.5% 7.50% 5.80% 7.50% 7.50% 2.75% 3%

120.52 166.94 196.3 79.71 119.88 159.77 59.96 343.11 81.88 101.7 201.01 89.2 139.54 170.9 172.7 303.28 160.11 206.5 163.7 180.4 200.5 189.85 169.47 266.03 309.75 78.98 103.4 278.4 80.1 122.88 121.89 181.14 104.37

4.16 2.07 2.31 7.20 5.30 5.10 2.95 2.60 4.74 3.33 4.49 5.44 2.92 3.50 5.67 6.09 5.72 3.69 3.82 5.13 6.30 6.44 7.74 5.00 6.57 11.95 2.01 2.95 3.86 1.49 2.74 3.12 3.10

8.51% 7.60%

60.79 90.97

1.93 1.91

No.34 well No.35 well

61.2 105

3. Critical velocity under the condition of acidizing flowback

Q yE ¼ A4

(1)

where yE is the critical velocity that is experimentally determined in m/s, Q is the flow rate in m3/s, A is the cross sectional area of the core in m2, and F is the porosity of core. 8) Close the displacement pump or gas source to end the experiment. The evaluation standard is shown in Table 1.

2.2. Velocity sensitivity results of the formation water The results of the experiments are shown in Table 2 and Figs. 1 and 2. The relationship between the flow rate and the permeability rate is shown in Figs. 1 and 2. The velocity sensitivity evaluation results using the formation water are shown in Table 2. The velocity sensitivity indices of cores NO1e9 are between 18% and 90%; the velocity sensitivity degree of the cores tend to be weakly moderate to strong; and the critical velocity of the formation water ranges from 0.75 to 5 mL/min. The velocity sensitivity index of core NO10 is 61.7e62.26%; the velocity sensitivity degree tends to be moderate to strong; and the critical velocity of the formation water ranges from 0.75 to 1 mL/min. Therefore, the critical velocity should be considered during the acidizing flowback; if velocity is too large, the velocity sensitivity effect may occur.

Damage due to the velocity sensitivity tends to occur when the flow velocity of the fluid exceeds that available to flow through the clay minerals' microstructure, leading to the shedding of clay minerals and other particles from the pore surface inside the formation. The particles tend to migrate with the fluid and are deposited in the narrow pores, eventually causing a decline in permeability. The formation water is used as the experimental fluid in this experiment, but the fluid of the acidizing flowback is the acid present in the oil field. The properties of these two fluids, such as their viscosities and densities, are quite different. Converting the experimental critical velocity and flow rate into the real values of the acidizing flowback based on the similarity principle, the real critical velocity can be calculated. Models of the velocity and the mechanical stability under different flow patterns are established as follows. The drag force (Tong, 1982) can be described by:

. F ¼ CA1 ry2 2

(2)

Where A1 is the cross sectional area of a particle in m2, C is the drag coefficient, y is the fluid velocity in m/s, r is the fluid density in kg/ m3, and F is the flow drag force in N. The drag coefficient (Tong, 1982) can be approximated as:

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Fig. 3. Relationship between the wellhead pressure and the critical choke size of the flowback. Fig. 5. Relationship between the reservoir porosity and the invasion radius.

C ¼ kk=ðryd=mÞt

(3)

where kk and t are constant coefficients, d is the particle diameter in m2, and m is the fluid viscosity in Pa.s. The Reynolds number (NRe) can be calculated as：

NRe ¼ rdy=m

(4)

FE ¼ FA

(5)

FE ¼

kk=ðrE yE d=mE Þt A1 rE y2E 2

(6)

FA ¼

kk=ðrA yA d=mA Þt A1 rA y2A 2

(7)

Substituting formula (6) and (7) into formula (5) yields: When NRe  2: kk ¼ 24, t ¼ 1 When 2 < NRe  500: kk ¼ 18.5, t ¼ 0.6 When NRe  500: kk ¼ 0.44, t ¼ 0 If the reservoir particles can be carried, the drag force must reach a constant value. Based on the principle of similarity, the drag force should be equal when the experimental conditions and the acidizing construction are considered. Combining formulae (2) and (3), a mechanical balance formula is built as follows:

Fig. 4. Relationship between the acid viscosity and the critical choke size of the flowback.

2
t 2
t mtE r1
t ¼ mtA r1
t E yE A yA

(8)

Based on the flow pattern of the acidizing flowback considered in this study: kk ¼ 18.5, t ¼ 0.6 The critical velocity of acidizing flowback is thus:

yA ¼

1:4 0:6 r0:4 E yE mE

m0:6 r0:4 A A

!5 7

(9)

Fig. 6. Relationship between the reservoir effective thickness and the invasion radius.

J. Hu et al. / Journal of Natural Gas Science and Engineering 24 (2015) 311e316

where FE is the flow drag force that is determined experimentally in N, FA is the flow drag force of the acidizing process in N, rE is the density of the flowback fluid that is determined experimentally in kg/m3, rA is the density of the flowback fluid of the acidizing process in kg/m3, yA is the critical velocity of the acidizing process in m/ s, mE is the fluid viscosity that is determined experimentally in Pa.s, and mA is the fluid viscosity of the acidizing process in Pa.s. The core diameter is 2.5 cm; the critical velocities that were determined experimentally for the formation water on cores NO1e9 range from 2.54  10
5 to 1.69  10
4 m/s; and the critical velocities that were determined experimentally for the formation water on core NO10 range from 2.54  10
5 to 3.39  10
5 m/s. The density of the formation water in the laboratory was 1.0  103 kg/m3; the viscosity was 1.0 mPa s; the density of acid was 1.15  103 kg/m3; the viscosity of acid was 20 mPa s; and the inside diameter of drainpipe was 0.062 m. Based on formula (9), the acid critical velocity of cores NO1e9 range from 5.5  10
5 to 3.78  10
4 m/s; the viscosity of the flowback acid can influence the critical flow; and the acid critical velocities of core NO10 range from 5.5  10
5 to 7.6  10
4 m/s. The viscosity of the acid thus influences the critical flow rate.

4. System optimization of acidizing flowback and blowout control For the process of acidizing flowback, acid primarily flows through the perforations, back to the wellbore, and then to the ground. The perforation diameter and the number of perforations are likely to directly affect the flowback flow rate. The maximum flow rate to the wellbore can be calculated as:

qmax ¼ hAp yA ¼ hAp ymax ¼ 2prhymax

(10)

where qmax is the maximum critical flow rate of flowback in m3/s, h is the reservoir thickness in m, Ap is the flow area of the flowback acid in m2, ymax is the critical velocity of the acid flowback in m/s, and r is the invasion radius of the acid liquid moving into the reservoir in m. When the critical flow rate of the acid that flows back into the wellbore is determined, the choke size can be calculated depending on the instantaneous pressure in the acid flowback process. For the wellhead and blowout choke, Bernoulli's equation applies:

y2 y2 p po y22 þ 1 ¼ þ þx 2 rg 2g rg 2g 2g

(11)

where:

y1 ¼

qmax pR2

(12)

In a simple operation, the following formula applies:

y1 r2 ¼ z y2 R 2

!!1

(14)

4

1 1þx

2g p
po g y21

þ1

where rz is the critical choke size of the flowback in m; R is the inner diameter of the wellbore in m; x is the local resistance coefficient (dimensionless), which is considered to be 0.5 here; p is the wellhead pressure in Pa; po is the standard atmospheric pressure in Pa; y2 is the fluid velocity in the wellhead in m/s; y1 is the fluid velocity in the wellbore in m/s; ymax is the maximum flow rate into the wellbore in formation in m/s; and g is the acceleration due to gravity in m/s2. 5. Applications Based on the volume balance principle, the extruded acid is moved into the reservoir to repair the damage to the reservoir that near the wellbore; the acid invasion radii have been calculated to be between 1.91 m and 11.95 m, as shown in Table 3, across the 35 wells in the study area. These results can contribute to the calculation of the flowback critical velocity and the displacement rate of reservoir. Fig. 3 shows that the critical velocity of the acid flowback increases with decreasing wellhead pressure: the more acid that enters the reservoir, the larger the critical choke size of the blowout control flowback is required to be. The reason for this is that the critical velocity is a constant value, and a larger choke can be adopted with increasing acid volume. Fig. 3 could be used by field engineers as follows. First, the volume of the acidizing operation should be known. Second, the volume balance principle is used to calculate the invasion radius. Lastly, the choke size can be chosen based on the wellhead pressure. Fig. 4 shows how different acid viscosities influence the critical choke size of the flowback. The choke size may decrease with increasing acid viscosity because a higher viscosity requires more energy to transport micro-particles during the flowback process. To prevent the velocity sensitivity effect and subsequent reservoir damage, a smaller choke must be selected. Therefore, the acid viscosity is also important under the same wellhead pressure. A lower acid viscosity allows a larger bigger choke size to be used and can improve the effect of acidizing flowback. The relationships between the reservoir parameters (i.e., porosity, effective thickness) and the invasion radius are shown in Figs. 5 and 6; the invasion radius may decrease with increasing porosity and effective thickness. The reason for this is that the reservoir porosity and effective thickness are two key parameters to evaluate the reservoir, and a poor reservoir requires a larger acidizing operation, which can increase the invasion radius. 6. Conclusions

The continuity equation is:

y1 pR2 ¼ y2 prz2

R

rz ¼

315

(13)

Combining formulae (11) and (13), the critical choke size is obtained:

(1) Through experimental studies of the velocity sensitivity and similarity principles, it is shown that if the diameter of the choke cannot be suitably chosen, the flowback velocity of the acid fluid may increase, and the velocity sensitivity phenomenon may occur in this gas field. Thus, a reasonable velocity and choke size should be studied during the process of acidizing flowback. (2) A critical choke model of the flowback process is constructed using the material balance and fluid mechanics principles. The critical choke sizes that correspond to different wellhead pressures can be calculated by combining the critical

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J. Hu et al. / Journal of Natural Gas Science and Engineering 24 (2015) 311e316

velocities of the flowback experiments; this can provide the theoretical and technical information for field engineers to optimize flowback operations. (3) A poor reservoir typically requires a larger acidizing operation, which can increase the invasion radius of the acid fluid in the oil field. The flowback process should thus be controlled rigorously to prevent secondary pollution in the reservoir. (4) A set of optimized system methods after acidizing have been established based on the experiments and mathematical models. Different blowout control choke sizes can be chosen based on the wellhead pressure, and engineers can change the choke size with different wellhead pressures to improve the effects of acidizing. Acknowledgments The authors would like to acknowledge the support provided by the National Natural Science Foundation of China (51304174) and the PLN1301 of the State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation (Southwest Petroleum University) and the Fundamental Research Funds for the Central Universities.

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