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Investigation of drill-in fluids damage and its impact on wellbore stability in Longmaxi shale reservoir
Journal of Petroleum Science and Engineering 159 (2017) 702–709
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Investigation of drill-in fluids damage and its impact on wellbore stability in Longmaxi shale reservoir Xiangchen Li *, Xiaopeng Yan, Yili Kang State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, Sichuan 610500, China
A R T I C L E I N F O
A B S T R A C T
Keywords: Drill-in fluid Formation damage Sealing Hydration Fracture propagation Wellbore stability
The stability of the horizontal long section wellbore is the key factor of restricting the efficient development of shale gas. High clay mineral content and developed microfractures of shale reservoir make the problems of formation damage and horizontal wellbore stability more complex. OBDF (Oil-based drill-in fluid) is widely used to control formation damage and prevent wellbore instability in shale gas wells. However, high cost and serious environmental problem severely restrict the economic development of shale gas. In order to meet the requirement of cost reduction and environmental protection during shale gas drilling operation, drilling horizontal well with WBDF (water-based drill-in fluid) instead of OBDF has become one of the engineering technology problems to be solved urgently. The Longmaxi shale in Sichuan Basin of China and the associated drill-in fluids at the site are the object of our research. Evaluation experiments on liquid damage and sealing capacity of drill-in fluids were conducted to recognize and optimize the properties of oil-based and water-based drill-in fluids in shale reservoir. Combining the methods of particle size distribution, friction coefficient testing, alkali erosion, linear expansion and immersion test, we investigated the effect of drill-in fluids on formation damage and wellbore stability. Results show that the damage degree of OBDF filtrate on shale is more severe than that of WBDF filtrate. Fracture sealing and bi-directional pressure containment capacity of WBDF is also stronger than that of OBDF. Due to the invasion of OBDF with high pH value, the friction strength of the fracture surface decreases and frictional sliding will take place, which can cause the wellbore instability. With the WBDF immersion, microfractures initiate and propagate along the bedding surface for the shale hydrate expansion, and lead to wellbore instability. The results of our analysis suggest that OBDF does not completely solve the problems of formation damage and wellbore instability in shale reservoir, and reinforcing the sealing fracture and inhibiting hydration capacity of WBDF will contribute to its wider application in shale reservoir. This study provides a theoretical guidance for drill-in fluid selection and optimization during the operation of shale gas well drilling.
1. Introduction
wellbore (Hudson et al., 2012; Civan, 2013; You et al., 2016). Shale gas well productivity will be affected only if any one of the gas production stages or gas migration paths were damaged. Shale reservoir is characteristic of high clay content, ultra-low water saturation and developed nano-micro pore network and micro fracture. Due to the long contact time between drill-in fluid and formation during drilling process of horizontal long section, formation damage and wellbore instability problems may occur easily induced by drill-in fluid (Bennion, 2002; Kang et al., 2013), which finally reduced the gas production and migration ability of shale (Bedrikovetsky et al., 2011, 2012; Jiang et al., 2005). OBDF has become the first choice of drilling horizontal long section for its good inhibition, lubrication and wellbore strengthening (Zou et al., 2010; Liu et al., 2010). However, high cost and prominent environmental
Shale gas reservoirs have received great attention in the past decade and have become the focus of petroleum industry. Shale reservoir has extremely low permeability and is difficult to develop economically using traditional methods. Horizontal well with multistage hydraulic fracturing is required for such low-permeability reservoir to create very complex fracture networks and therefore to enhance shale gas well productivity effectively (Guo et al., 2014; Wu et al., 2016). The process of gas production from shale gas reservoir includes three stages such as desorption, diffusion and seepage. And gas migration paths are considered to be multi-scale comprising the combination of matrix pore throat, natural fracture network and hydraulic fracture network connected to
* Corresponding author. E-mail address: [email protected] (X. Li). https://doi.org/10.1016/j.petrol.2017.10.005 Received 16 February 2017; Received in revised form 18 August 2017; Accepted 2 October 2017 Available online 6 October 2017 0920-4105/© 2017 Published by Elsevier B.V.
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Journal of Petroleum Science and Engineering 159 (2017) 702–709
(LIGCO)þ0.6% pH transferred agent (CAUSTIC SODA)þ0.3% fluid loss additive (MIN-PAV LV)þ1.8% anti-sloughing agent (LATIMAGIC)þ2.0% fluid loss additive (SULFATROL)þ3% clay stabilizer (CLAY-TROL)þ3% filming sealing agent (MAX-SHIEID)þ3% accelerated the lubricating agent (LATIRATE)þ barite. Particle size distribution of experimental drill-in fluids were measured by Malvern laser particle size analyzer and filtrate was centrifuged from drill-in fluids with TG16-WS high-speed centrifuge for the subsequent experiments.
issues of OBDF seriously influenced the economic and efficient development of shale gas reservoir. Furthermore, the field application indicates that instability problems were often encountered during horizontal long section and even other complex situations may happen induced by OBDF (Li et al., 2012; Lu et al., 2012a,b). Lost circulation and wellbore instability problems will frequently lead to severe formation damage near wellbore area, what's worse, solid invasion can also be displaced into deep formation during the later fracturing process, which may cause permanent damage in larger area. In view of this, drilling horizontal well with WBDF instead of OBDF has become one of the engineering technology problems to be solved urgently (Xu et al., 2016; Zhang et al., 2016; Rajat and Vikas, 2017). Many valuable works have been achieved about the single factor analysis of the formation damage mechanisms in shale reservoir (Alvarez et al., 2007; Zhang, 2014; Vaz et al., 2010; Albazali, 2011; Dahaghi and Mohaghegh, 2011; Tsar et al., 2012; Frequin et al., 2013; Kalantariasl et al., 2015; Sacramento et al., 2015; Liu et al., 2016a,b). However, the study on formation damage evaluation and mechanisms of drill-in fluids is still not systemic, and the relationship between formation damage and wellbore instability need to be revealed urgently. In order to meet the requirement of cost reduction and environmental protection during shale reservoir drilling operation and to further investigate formation damage mechanisms of different drill-in fluids and its impact on wellbore stability, the Longmaxi shale formation in Sichuan Basin of China and the associated drill-in fluids at the site are the object of our research. In this paper, we conducted a series of evaluation experiments on liquid damage and sealing capacity drill-in fluids and combining methods of particle size distribution, friction coefficient testing, alkali erosion, linear expansion and immersion test were used to investigate the effect of drill-in fluids on formation damage and wellbore stability. Based on the results of experimental measurement and theoretical analysis, optimization route of drill-in fluid in Longmaxi shale was demonstrated.
2.3. Experimental methods 2.3.1. Liquid damage evaluation In this paper, vacuum saturation method was adopted to push the drill-in fluid filtrate into the shale, and the permeability damage rate was determined based on the absolute permeability in different conditions, which was obtained through measuring gas permeability under different average pressure difference. The test procedure was as follows: (1) A dried sample was installed in the core holder under 3.0 MPa effective stress and measured the gas permeability at different displacement pressures, and then made absolute permeability as initial permeability by the gas permeability; (2) The sample was placed into the high pressure vessel and vacuumized under 60 C for 2 h till vacuum degree 0.098 MPa; (3) Sample was saturated by drill-in fluid filtrate under vacuum condition; (4) The gas permeability of the fully saturated sample was gotten as in step one above. The damage degree of drill-in fluid filtrate was determined as follows:
Pd ¼ 1 Kf 1 Kf 2
(1)
Where Pd was permeability damage rate, %; Kf1 was the initial permeability, mD; Kf2 was the permeability after filtrate damage, mD. 2.3.2. Sealing capacity evaluation Sealing capacity evaluation was conducted to determine the sealing fracture capacity of drill-in fluids. The equipment can simulate the drillin fluids circulation and shearing flow on borehole face during the drilling process. The schematic diagram was shown in Fig. 1 and the procedure was as the follows: (1) Forward direction permeability (in the direction of the arrow) of fractured sample by formation water was measured at 7 MPa confining pressure; (2) Drill-in fluid was stirred in the fluid container at 150 s1 shearing rate and 70 C; (3) Drill-in fluid was circulated in the inverted flow direction for 60 min under 3.5 MPa flowing; (4) Forward direction permeability was regained by formation water at the different pressure gradients. The permeability recovery rate was determined as follows:
2. Experimental section 2.1. Shale samples Samples were taken from the Longmaxi shale formation in Changning district of Sichuan Basin. Mineral composition of the sample was tested with X0 Pert Pro XRD made by Holland Panalytical company and test results were listed in Table 1, showing that the sample has rather high content of clay minerals. Geochemical test results show that the TOC (Total Organic Carbon) of this shale ranged from 1.9% to 7.3%, with an average of 4.0%. In order to meet the sample requirement of damage evaluation of drill-in fluids, shale samples cored on the direction parallel to the bedding plane with a diameter of 25.4 mm, and their end surfaces were cut smoothly and then preserved in the oven.
Pr ¼ Kw2 =Kw1
(2)
2.2. Drill-in fluids
Where Pr was permeability recovery rate, %; Kw1 was the initial permeability, mD; Kw2 was the regained permeability, mD.
Two typical drill-in fluid systems used in the related experiments were from shale gas well in Changning shale district. And their basic properties are shown in Table 2. The formulation of OBDF: white oilþ2% organic clayþ3% primary emulsion(HEMUL)þ3% coemulsifier (HCOAT)þ1% wetting agent (HWET)þ2% oxidized asphalt (HSEAL)þ 2% micron-sized fluid loss additive(NSEAL)þ4% CaO þ barite. The formulation of WBDF: 0.5% NV-1þ0.6% multifunctional compound (LATI-BASE)þ1% viscosity reducer (DESCO)þ0.8% viscosity reducer
2.3.3. Friction coefficient test Due to high content of brittle minerals and developed bedding plane, frictional sliding along the fracture surface was the main motion pattern of the shale. Friction coefficient between fracture surfaces was tested with self-developed COF-1 friction coefficient tester (Fig. 2). The procedure was as the follows: (1) The sample was cut into two different shapes: one was the specimen sliced on the direction parallel to the bedding with a thickness of 5.0 mm and the other was semi-cylindrical
Table 1 Mineral composition of Longmaxi shale in Changning district of Sichuan Basin. Bulk composition (wt %) Quartz 29.58
Carbonatite 9.33
Relative content of clay mineral (wt %) Feldspar 11.37
Pyrite 4.03
Clay 45.69
703
Illite 68.51
Illite/Smectite 11.14
Chlorite 20.35
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Journal of Petroleum Science and Engineering 159 (2017) 702–709
Table 2 Basic properties of drill-in fluids. Fluid type
Density
Apparent viscosity (mPa.s)
(g/cm3) OBDF WBDF
1.91 1.93
Plastic viscosity
Yield value (Pa)
(mPa.s) 55 65
API filtration
Oil-water ratio
pH value
(ml)
41 29
11 34
0.6 2.4
ES (V)
93/7 0/100
11.5 9.0
735 –
Fig. 1. Schematic diagram of sealing capacity evaluation of drill-in fluids.
Fig. 2. Schematic diagram of COF-1 friction coefficient tester.
sample sliced along the axis, and their surfaces were polished with 80 mesh metallographic sandpaper; (2) The weighted specimen was placed on the left side of semi-cylindrical sample connected to force and displacement transducer; (3) The friction force and displacement data automatically were recorded with data collection system under movement speed of 4.0–5.0 mm/min; (4) The data was saved when the sliced specimen moved to the right edge of semi-cylindrical sample, and the experiment was repeat for three times. The friction coefficient of dry sample was measured after fixing the weight set on the specimen, and the friction coefficient of immersed sample was measured with the drill-in fluid level came up to sample contact interfaces. The friction coefficient was determined as follows:
2.3.4. Immersion test The changing characteristics of shale structure by water-rock interaction could be directly observed through immersion test. The schematic diagram of the immersion test was shown in Fig. 3. The procedure was as follows: (1) Slice with a thickness of 5.0 mm was prepared by the plug parallel to bedding and taken photos after drying them under 60 C for 48 h; (2) The samples were hung in the heat-resistant plastic bottles with a 300 ml drill-in fluid filtrate and immersed them beneath a liquid level of 2 cm; (3) These sealed plastic bottles were placed into a thermostatic water bath; (4) The samples were dried and taken photos after the 1d and 7d-immersion.
μf ¼ Ff 9:8 WN
3. Results
(3) 3.1. Liquid retention damage
Where μf was the friction coefficient between fracture surfaces, dimensionless; Ff was friction force recorded by force transducer, N; WN was the total mass of slice thick sample and weight set, Kg.
Drill-in fluid filtrate is easy to resort due to developed nano-scale pores and high capillary force, which caused serious liquid phase 704
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Journal of Petroleum Science and Engineering 159 (2017) 702–709
Fig. 3. Schematic diagram of immersion test.
trapping damage. The result of wetting contact angle (Fig. 4) displaced that the contact angle of oil-based filtrate with polished shale surface is smaller than that of water-based filtrate. And the invaded oil phase was easier to adhere to the shale surface and difficult to flow back. As we can see from the experiment result of shale imbibition (Fig. 5), imbibition amount of shale generally went up rapidly in the beginning and remained stable with the time increasing. Imbibition amount to oil-based filtrate of the sample came up to 0.55 times PV (porosity volume) after 24-hours spontaneous imbibition, which is larger than that of water-based filtrate with the amount 0.34 times PV. The larger oil imbibition amount and higher oil phase retention capacity are the two key reasons why serious oil phase trapping damage happened frequently while drilling shale formation with OBDF. The permeability damage rate of drill-in fluid filtrate was determined based on the absolute permeability obtained with measuring gas permeability under different average pressure difference (Fig. 6). The damage rate of WBDF filtrate was 66.43%, and the damage rate of OBDF filtrate was 98.05% (Table 3). The result showed that permeability damage induced by OBDF filtrate was more severe than that induced by WBDF filtrate. The gas-measured permeability after interact with WBDF fluid filtrate demonstrated relatively higher slippage effect, indicating that water retention degree reduced with the increase of flowback pressure difference. While the gas-measured permeability of OBDF filtrate interaction varied little with the increase of flowback pressure difference, showing that oil retention degree was more severe.
Fig. 5. Imbibition amount of shale treated with drill-in fluids.
Fig. 6. Gas-measured permeability of shale before and after drill-in fluid filtrate damage. Table 3 Liquid damage of drill-in fluids filtrate.
3.2. Sealing capacity evaluation The range of sealing fracture width by drill-in fluids was determined by sealing capacity evaluation experiments by steel samples with the different fracture width. The purpose of this experiment was that the maximum sealed fracture width by drill-in fluids was determined without the consideration of fracture surface roughness. As shown in Table 4, the severe lost circulation of OBDF happened at the fracture width of 100 μm, and the severe lost circulation of WBDF occurred when the fracture width reached up to 300 μm. This meant that WBDF has the wider sealing scope and the higher sealing capacity. The result of sealing capacity evaluation for shale samples showed that flowback breakthrough pressure of OBDF was lower than that of
Samples
Initial permeability (mD)
Regained permeability (mD)
Damage rate (%)
Filtrate type
L-1 L-2
0.2567 0.4363
0.0050 0.1421
98.05 64.43
OBDF WBDF
WBDF and OBDF had a higher value of regained permeability recovery rate (Table 5). Thus it can be seen that high quality mud cake with better bi-directional bearing capacity can form on the end face of the shale sample. The likelihood of liquid and solid invasion and wellbore instability damage had dramatically decreased. 4. Discussion 4.1. Sealing capacity of dill-in fluids in shale formation There is a complex pore system including organic and inorganic pores, micro-fractures and natural fractures. The pore structure of samples was observed by SEM. The result shows that minerals existence at the form of layered distribution (Fig. 7a), the development of microfracture (Fig. 7b) and different scale pore (Fig. 7c) is more extensive. Then it is very significant that the fractures and pores are efficiently sealed to prevent solid and liquid of drill-in fluid from intruding into the reservoir. Particle size distribution of drill-in fluids were measured by laser
Fig. 4. Wetting contact angle between drill-in fluids filtrate and shale. 705
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Table 4 Sealing capacity evaluation of drill-in fluids for steel samples with the different fracture width. Working fluid
Samples
Fracture width (μm)
Lost circulation
Flowback pressure difference(MPa)/ Regained permeability recovery rate(%)
1#
50
None
100
Severe
0.5 0 0.07 0
1 0 0.1 0
1.5 0 0.14 53.8
2 0 0.5 81.8
OBDF
2#
0.3 0 0.05 0
3#
50
None
100
None
5#
200
A little
6#
300
Severe
0.1 0 0.1 0 0.5 0 0.5 0
0.2 0 0.2 0 0.1 0 0.1 0
0.25 69.61 0.25 66.93 0.18 70.62 0.18 76.13
0.6 74.37 0.55 75.81 0.7 73.48 0.7 93.33
WBDF
4#
0 0 0 0 0 0 0 0
effect of pressure difference and interact with the minerals of fracture surface. Both WBDF and OBDF can reduce the friction coefficient of fracture surfaces compared with that of dry sample (Fig. 9). However the friction coefficient decline of fracture surface soaked in OBDF was 21.9%, which was bigger than that in WBDF with a value of 12.5%. It showed that friction coefficient was reduced after the interaction between fluid and fracture surfaces. Lubrication film thickness is the key factor affecting the friction coefficient. With the fluid between fracture surfaces, adsorption film have certain bearing capacity due to the orientation arrangement of polar molecules and the cohesive force between molecules, so as to prevent the direct contact of fracture surfaces. The bonding capacity between liquid and solid interfacial and the lubrication film thickness increased with the reduction of contact angel, which signified lower friction coefficient (Yang et al., 2010; Zhou and Wu, 2016; Voronov et al., 2008). As a result of developed bedding plane of shale formation, the invasion of drill-in fluids into the bedding plane was frequently encountered during the drilling operation, which led to the reduction of friction coefficient between fracture surfaces and wellbore instability. Mineral erosion of fracture surface can make fracture width wider and induce fracture propagation, leading to borehole instability (You et al., 2014). Based on the laser scanning results of fracture surface before and after erosion, fracture surface becomes more smooth at the condition of pH ¼ 11 and exposure 12 days (Fig. 10). Both minerals and organic matter of shale are involved in the reaction of alkali erosion leading to the roughness reduction of fracture surface (Kang et al., 2016). The effect of alkali erosion on fracture width is more outstanding under the condition of higher pH value and longer exposure time. This is the one of reasons why lost circulation happens more frequently during drilling progress in shale reservoir. It is worth noting that the sealed fracture may be opened again under the high pH value environment. Even though the fracture is temporarily plugged, the high pH filtrate will continue to erode the shale fracture surface with the growing time. That makes the
Table 5 Sealing capacity evaluation of drill-in fluids for shale samples with the different fracture width. Samples
Fracture width(μm)
Flowback pressure difference(MPa) /Regained permeability recovery rate(%)
Working fluid
L-3
29.99 30.78
0.05 0 0.05 0
0.12 0 0.1 0
0.18 0 0.12 0.07
0.2 47.05 0.44 46.33
OBDF
L-4
0 0 0 0
L-5
22.06 28.86
0.5 0 1.9 7.59
1 0 2.6 6.46
1.4 0.95 2.8 15.70
3.08 2.73 3.2 17.71
WBDF
L-6
0 0 1.3 4.31
particle size analyzer. Water-based drill-in fluid had a bimodal and wider range of particle size distribution (Fig. 8a), while the oil-based drill-in fluid showed narrow range of particle size distribution(Fig. 8b). It showed that WBDF had better sealing capacity for the developed multiscale pore structure of shale. As shown from fracture surface, the invasion depth of WBDF was relative shallow resulting from the formation of temporary sealing zone, in contrast, OBDF invaded the fracture deeply and spread out across the fracture surface. Solid and liquid phase invasion are the two main damaging type of drill-in fluids, and the key factor for formation damage control is to enhance the sealing capacity of the drill-in fluids. The better sealing capacity the drill-in fluids are, the higher bi-directional bearing capacity the sealing zone are, and the easier removal of formation damage will be. In order to achieve high sealing efficiency, it is necessary to predict the fracture width accurately and make good match between solid particle and fracture width.
4.2. Impact of OBDF on wellbore stability OBDF with high pH value is easy to intrude into fractures under the
Fig. 7. SEM of shale pore structure. 706
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Journal of Petroleum Science and Engineering 159 (2017) 702–709
Fig. 8. Particle size distribution of drill-in fluids.
swelling took place eventually (Darley, 1969; Chenevert, 1970; Jellander et al., 1988). Hydration swelling of shale led to the increasing of hydration stress and stress concentration on the top of the crack, which was the key factor for the initiation and propagation of macro-fracture when drilling shale wells by WBDF (Shi et al., 2012; Ghanbari and Dehghanpour, 2015). With the invasion of drill-in fluid filtrate, the likelihood of wellbore instability increased greatly inducing by the hydration swelling of near wellbore shale. To gain the effect of drill-in fluids on shale integrity, OBDF and WBDF filtrates immersion test with no obvious crack shale samples were carried out respectively. An observation on shale samples showed that samples soaked in OBDF filtrate had no fractures on the surface (Fig. 12a–c). After they were soaked in WBDF filtrate for 1 day, a microfracture along the bedding plane was observed on the surface of the sample, and fracture density increased and began to propagate along the bedding planes with the immersion time going by (Fig. 12d–f). As we can speculate from Fig. 12, microfractures may grow in shale formation as a result of physical-chemical interaction between WBDF filtrate and shale. Original hydration force between the crystal layers of illite could be as large as 50 MPa and hardly to induce long-range expansion (Kang et al., 2017). It means that low water content will cause shale hydration with a small strain and a huge stress. This hydration stress lead to the microfracture generation and tensile strength reduction. More water-based filtrate is imbibed into shale than oil-based filtrate under the condition of a long time soaking for new generated fractures. This result is the unanimous consensus on liquid uptake by shale (Singh, 2016). But it seems to contradict the result of imbibition testing in this paper. The reason of this phenomenon is the consideration of testing time in the different engineering backgrounds. If the problem of filtrate invasion is ineffectively solved, it will cause severe formation damage and wellbore instability.
Fig. 9. Variation curve of friction coefficient vs. displacement.
4.3. Impact of WBDF on wellbore stability Due to the high content of clay mineral and rich organic matter, Longmaxi shale has strong interacting potential with working fluids (Deng and Meng, 2003; Qiu et al., 2007). Linear expansion of shale sample with particle sizes under 100# mesh was measured by CPZ-2 dual channel normal pressure and temperature dilatometer. As shown in Fig. 11, linear expansion for OBDF filtrate was only 1.4% and when it came to WBDF filtrate, its value came up to 14.0%. With the invasion of water, double electrical layer would form, resulting from the water molecules and hydration cation adsorption and aggregation on clay layer, and repulsive force and distance between clay increased and hydration
Fig. 10. Laser scanning results of fracture surface before and after alkali erosion. 707
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supporting wellbore can be applied to develop the anti-sloughing water based drill-in fluid. Effective sealing can be technically implemented by developing hydrophobic nanoparticles (<100 nm) with softening and deformation properties in high temperature and high pressure conditions. The development of hydration inhibitor is the key to WBDF in shale reservoir drilling. According to activation theory, if the activity of containing water in clay minerals of shale is accurately determined, saturated organic salt drilling fluid can reach the objective of enhanced hydration inhibition by reducing its activity to a certain value, which is lower than that in clay minerals. But this method cannot be well generalized for its high cost, complex composition, maintenance difficulty and environmental issues. In addition, hydration inhibition capacity can be improved by varying the lattice spacing of clay minerals. With this method, water-soluble polyamine treatment agent with low molecular weight can be chosen to add into the drilling fluid to prevent water molecules from entering the lattice layer by its strong adsorption on clay minerals and by decreasing interlayer spacing of clay minerals. The hydration inhibition capacity of WBDF formulated by this method may catch up with the level of oil based drilling fluid. And its applicability is much better for relatively simple composition, the small dosage of agents, low cost and low difficulty of environment disposal. Some experimental researches and field trials have been done and obtained the predictive effect in Longmaxi shale (Yan et al., 2015; Peng et al., 2017).
Fig. 11. Linear expansion of shale samples in drill-in fluids.
4.4. Optimization route of drill-in fluid in Longmaxi shale Shale gas reservoirs in China put forward higher requirements on exploration, drilling and development due to its complexity and peculiarity (Liu et al., 2016a,b). OBDF had become the first choice of drilling horizontal long section for its good wellbore strengthening capacity in the drilling practice at early stage of shale gas production. However, high cost, security issues and prominent environmental issues of OBDF, especially for later disposal of wasted OBDF and cuttings returned from the bottom hole of the shale gas well, seriously influenced the economic and efficient development of shale gas reservoir. In view of this, drilling horizontal well with anti-sloughing water based drill-in fluid, whose inhibition, sealing capacity and lubricity catch up with the level of OBDF, has become one of the engineering technology problems to be solved urgently and plays a key role in cleaner production and efficient development in shale gas reservoirs. The applied WBDF in site were difficult to fully meet the requirement for drilling engineering in shale reservoir. Based on the geological characteristics and engineering practice experience of shale reservoirs, the combined method of hydration inhibition, effective sealing and
5. Conclusion The following points can be concluded from this work: (1) The stronger wettability and imbibition of OBDF led to the higher formation damage before the sealing zone formation. (2) WBDF from the site had a better sealing and bi-directional bearing capacity for the wider range of particle size distribution. (3) Frictional sliding may cause wellbore instability for the OBDF lubricity and alkali erosion. (4) Hydrate expansion by WBDF is the important factor for the fracture generation and wellbore instability. (5) Reinforcing the capacity of sealing and hydration inhibition is helpful to widely apply WBDF in the shale reservoir.
Fig. 12. Structure characteristics of shale soaked into drill-in fluids. 708
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Acknowledgements
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The research presented in this paper was financially supported by the Nation Basic Research Program of China (973 programs, No. 2013CB228003), Key Fund Project of Sichuan Provincial Department of Education (No. 16ZA0077) and Sichuan Provincial Research Group of Unconventional Formation Damage Control (No. 2016TD0016). These supports are gratefully acknowledged. References Alvarez, A.C., Hime, G., Dan, M., 2007. The inverse problem of determining the filtration function and permeability reduction in flow of water with particles in porous media. Transp. Porous Media 70 (1), 43–62. Albazali, T.M., 2011. The consequences of using concentrated salt solutions for mitigating wellbore instability in shales. J. Petroleum Sci. Eng. 80 (1), 94–101. Bennion, D.B., 2002. An overview of formation damage mechanisms causing a reduction in the productivity and injectivity of oil and gas producing formations. J. Can. Petroleum Technol. 41 (11), 29–36. Bedrikovetsky, P., Siqueira, F.D., Furtado, C.A., Souza, A.L., 2011. Modified particle detachment model for colloidal transport in porous media. Transp. Porous Media 86 (2), 353–383. Bedrikovetski, P., Vaz, A., Machado, F., Zeinijahromi, A., 2012. Skin due to fines Mobilization,Migration,and straining during steady-state oil production. Petroleum Sci. Technol. 30 (15), 1539–1547. Chenevert, M.E., 1970. Shale alteration by water adsorption. J. petroleum Technol. 22 (1), 141–148. Civan, F., 2013. Comparison of control volume analysis and porous media averaging for formulation of porous media transport. Model. Simul. Fluid Dyn. Porous Media 27–53. Darley, H., 1969. A laboratory investigation of borehole stability. J. Petroleum Technol. 21 (7), 883–892. Dahaghi, A.K., Mohaghegh, S.D., 2011. Numerical simulation and multiple realizations for sensitivity study of shale gas reservoirs. In: Paper SPE 141058 Presented at the SPE Production and Operations Symposium, 27–29 March, Oklahoma City, Oklahoma, USA. Deng, H., Meng, Y., 2003. Shale stability coupling with mechanics and chemistry. Pet. Drill. Tech. 31 (1), 33–36. Frequin, D., Bedrikovetsk, Y.P., Zitha, P.L.J., 2013. CT scan study of the leak-off of oilbased drill-in fluids into saturated media. In: Paper SPE 165193 Presented at the SPE European Formation Damage Conference & Exhibition, 5–7 June, Noordwijk, The Netherlands. Guo, T., Zhang, S., Qu, Z., Zhou, T., Xiao, Y., Gao, J., 2014. Experimental study of hydraulic fracturing for shale by stimulated reservoir volume. Fuel 128 (14), 373–380. Ghanbari, E., Dehghanpour, H., 2015. Impact of rock fabric on water imbibition and salt diffusion in gas shales. Int. J.Coal Geol. 138, 55–67. Hudson, J.D., Civan, F., Michel, G., Devegowda, D., Sigal, R., 2012. Modeling multipleporosity transport in gas-bearing shale formations. In: Paper SPE 153535 Presented at the SPE Latin America and Caribbean Petroleum Engineering Conference, 16–18 April, Mexico City, Mexico. Jellander, R., Marcelja, S., Quirk, J., 1988. Attractive double-layer interactions between calcium clay particles. J. Colloid Interface Sci. 126 (1), 194–211. Jiang, G., Hu, C., Xong, Y., Song, Y., 2005. Rary blocking drilling and completion fluid for reservoir protection. Drill. Prod. Technol. 28 (5), 101–104. Kalantariasl, A., Farajzadeh, R., You, Z., Bedrikovetsky, P., 2015. Non-uniform external filter cake in long injection wells. Industrial Eng. Chem. Res. 54 (11), 3051–3061. Kang, Y.L., Yang, B., You, L.J., Chen, Q., Yu, Y., 2013. Damage evaluation of oil-based drill-in fluids to shale reservoirs. Nat. Gas. Ind. 33 (12), 99–104. Kang, Y.L., She, J.P., Zhang, H., You, L.J., Yu, Y.F., Song, M.G., 2016. Alkali erosion of shale by high-pH fluid: reaction kinetic behaviors and engineering responses. J. Nat. Gas Sci. Eng. 29, 201–210. Kang, Y.L., Yang, B., Li, X.C., Yang, J., You, L.J., Chen, Q., 2017. Quantitative characterization of micro forces in shale hydration and field application. Petroleum Explor. Dev. 44 (2), 328–335.
709
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Investigation of drill-in fluids damage and its impact on wellbore stability in Longmaxi shale reservoir Xiangchen Li *, Xiaopeng Yan, Yili Kang State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, Sichuan 610500, China
A R T I C L E I N F O
A B S T R A C T
Keywords: Drill-in fluid Formation damage Sealing Hydration Fracture propagation Wellbore stability
The stability of the horizontal long section wellbore is the key factor of restricting the efficient development of shale gas. High clay mineral content and developed microfractures of shale reservoir make the problems of formation damage and horizontal wellbore stability more complex. OBDF (Oil-based drill-in fluid) is widely used to control formation damage and prevent wellbore instability in shale gas wells. However, high cost and serious environmental problem severely restrict the economic development of shale gas. In order to meet the requirement of cost reduction and environmental protection during shale gas drilling operation, drilling horizontal well with WBDF (water-based drill-in fluid) instead of OBDF has become one of the engineering technology problems to be solved urgently. The Longmaxi shale in Sichuan Basin of China and the associated drill-in fluids at the site are the object of our research. Evaluation experiments on liquid damage and sealing capacity of drill-in fluids were conducted to recognize and optimize the properties of oil-based and water-based drill-in fluids in shale reservoir. Combining the methods of particle size distribution, friction coefficient testing, alkali erosion, linear expansion and immersion test, we investigated the effect of drill-in fluids on formation damage and wellbore stability. Results show that the damage degree of OBDF filtrate on shale is more severe than that of WBDF filtrate. Fracture sealing and bi-directional pressure containment capacity of WBDF is also stronger than that of OBDF. Due to the invasion of OBDF with high pH value, the friction strength of the fracture surface decreases and frictional sliding will take place, which can cause the wellbore instability. With the WBDF immersion, microfractures initiate and propagate along the bedding surface for the shale hydrate expansion, and lead to wellbore instability. The results of our analysis suggest that OBDF does not completely solve the problems of formation damage and wellbore instability in shale reservoir, and reinforcing the sealing fracture and inhibiting hydration capacity of WBDF will contribute to its wider application in shale reservoir. This study provides a theoretical guidance for drill-in fluid selection and optimization during the operation of shale gas well drilling.
1. Introduction
wellbore (Hudson et al., 2012; Civan, 2013; You et al., 2016). Shale gas well productivity will be affected only if any one of the gas production stages or gas migration paths were damaged. Shale reservoir is characteristic of high clay content, ultra-low water saturation and developed nano-micro pore network and micro fracture. Due to the long contact time between drill-in fluid and formation during drilling process of horizontal long section, formation damage and wellbore instability problems may occur easily induced by drill-in fluid (Bennion, 2002; Kang et al., 2013), which finally reduced the gas production and migration ability of shale (Bedrikovetsky et al., 2011, 2012; Jiang et al., 2005). OBDF has become the first choice of drilling horizontal long section for its good inhibition, lubrication and wellbore strengthening (Zou et al., 2010; Liu et al., 2010). However, high cost and prominent environmental
Shale gas reservoirs have received great attention in the past decade and have become the focus of petroleum industry. Shale reservoir has extremely low permeability and is difficult to develop economically using traditional methods. Horizontal well with multistage hydraulic fracturing is required for such low-permeability reservoir to create very complex fracture networks and therefore to enhance shale gas well productivity effectively (Guo et al., 2014; Wu et al., 2016). The process of gas production from shale gas reservoir includes three stages such as desorption, diffusion and seepage. And gas migration paths are considered to be multi-scale comprising the combination of matrix pore throat, natural fracture network and hydraulic fracture network connected to
* Corresponding author. E-mail address: [email protected] (X. Li). https://doi.org/10.1016/j.petrol.2017.10.005 Received 16 February 2017; Received in revised form 18 August 2017; Accepted 2 October 2017 Available online 6 October 2017 0920-4105/© 2017 Published by Elsevier B.V.
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(LIGCO)þ0.6% pH transferred agent (CAUSTIC SODA)þ0.3% fluid loss additive (MIN-PAV LV)þ1.8% anti-sloughing agent (LATIMAGIC)þ2.0% fluid loss additive (SULFATROL)þ3% clay stabilizer (CLAY-TROL)þ3% filming sealing agent (MAX-SHIEID)þ3% accelerated the lubricating agent (LATIRATE)þ barite. Particle size distribution of experimental drill-in fluids were measured by Malvern laser particle size analyzer and filtrate was centrifuged from drill-in fluids with TG16-WS high-speed centrifuge for the subsequent experiments.
issues of OBDF seriously influenced the economic and efficient development of shale gas reservoir. Furthermore, the field application indicates that instability problems were often encountered during horizontal long section and even other complex situations may happen induced by OBDF (Li et al., 2012; Lu et al., 2012a,b). Lost circulation and wellbore instability problems will frequently lead to severe formation damage near wellbore area, what's worse, solid invasion can also be displaced into deep formation during the later fracturing process, which may cause permanent damage in larger area. In view of this, drilling horizontal well with WBDF instead of OBDF has become one of the engineering technology problems to be solved urgently (Xu et al., 2016; Zhang et al., 2016; Rajat and Vikas, 2017). Many valuable works have been achieved about the single factor analysis of the formation damage mechanisms in shale reservoir (Alvarez et al., 2007; Zhang, 2014; Vaz et al., 2010; Albazali, 2011; Dahaghi and Mohaghegh, 2011; Tsar et al., 2012; Frequin et al., 2013; Kalantariasl et al., 2015; Sacramento et al., 2015; Liu et al., 2016a,b). However, the study on formation damage evaluation and mechanisms of drill-in fluids is still not systemic, and the relationship between formation damage and wellbore instability need to be revealed urgently. In order to meet the requirement of cost reduction and environmental protection during shale reservoir drilling operation and to further investigate formation damage mechanisms of different drill-in fluids and its impact on wellbore stability, the Longmaxi shale formation in Sichuan Basin of China and the associated drill-in fluids at the site are the object of our research. In this paper, we conducted a series of evaluation experiments on liquid damage and sealing capacity drill-in fluids and combining methods of particle size distribution, friction coefficient testing, alkali erosion, linear expansion and immersion test were used to investigate the effect of drill-in fluids on formation damage and wellbore stability. Based on the results of experimental measurement and theoretical analysis, optimization route of drill-in fluid in Longmaxi shale was demonstrated.
2.3. Experimental methods 2.3.1. Liquid damage evaluation In this paper, vacuum saturation method was adopted to push the drill-in fluid filtrate into the shale, and the permeability damage rate was determined based on the absolute permeability in different conditions, which was obtained through measuring gas permeability under different average pressure difference. The test procedure was as follows: (1) A dried sample was installed in the core holder under 3.0 MPa effective stress and measured the gas permeability at different displacement pressures, and then made absolute permeability as initial permeability by the gas permeability; (2) The sample was placed into the high pressure vessel and vacuumized under 60 C for 2 h till vacuum degree 0.098 MPa; (3) Sample was saturated by drill-in fluid filtrate under vacuum condition; (4) The gas permeability of the fully saturated sample was gotten as in step one above. The damage degree of drill-in fluid filtrate was determined as follows:
Pd ¼ 1 Kf 1 Kf 2
(1)
Where Pd was permeability damage rate, %; Kf1 was the initial permeability, mD; Kf2 was the permeability after filtrate damage, mD. 2.3.2. Sealing capacity evaluation Sealing capacity evaluation was conducted to determine the sealing fracture capacity of drill-in fluids. The equipment can simulate the drillin fluids circulation and shearing flow on borehole face during the drilling process. The schematic diagram was shown in Fig. 1 and the procedure was as the follows: (1) Forward direction permeability (in the direction of the arrow) of fractured sample by formation water was measured at 7 MPa confining pressure; (2) Drill-in fluid was stirred in the fluid container at 150 s1 shearing rate and 70 C; (3) Drill-in fluid was circulated in the inverted flow direction for 60 min under 3.5 MPa flowing; (4) Forward direction permeability was regained by formation water at the different pressure gradients. The permeability recovery rate was determined as follows:
2. Experimental section 2.1. Shale samples Samples were taken from the Longmaxi shale formation in Changning district of Sichuan Basin. Mineral composition of the sample was tested with X0 Pert Pro XRD made by Holland Panalytical company and test results were listed in Table 1, showing that the sample has rather high content of clay minerals. Geochemical test results show that the TOC (Total Organic Carbon) of this shale ranged from 1.9% to 7.3%, with an average of 4.0%. In order to meet the sample requirement of damage evaluation of drill-in fluids, shale samples cored on the direction parallel to the bedding plane with a diameter of 25.4 mm, and their end surfaces were cut smoothly and then preserved in the oven.
Pr ¼ Kw2 =Kw1
(2)
2.2. Drill-in fluids
Where Pr was permeability recovery rate, %; Kw1 was the initial permeability, mD; Kw2 was the regained permeability, mD.
Two typical drill-in fluid systems used in the related experiments were from shale gas well in Changning shale district. And their basic properties are shown in Table 2. The formulation of OBDF: white oilþ2% organic clayþ3% primary emulsion(HEMUL)þ3% coemulsifier (HCOAT)þ1% wetting agent (HWET)þ2% oxidized asphalt (HSEAL)þ 2% micron-sized fluid loss additive(NSEAL)þ4% CaO þ barite. The formulation of WBDF: 0.5% NV-1þ0.6% multifunctional compound (LATI-BASE)þ1% viscosity reducer (DESCO)þ0.8% viscosity reducer
2.3.3. Friction coefficient test Due to high content of brittle minerals and developed bedding plane, frictional sliding along the fracture surface was the main motion pattern of the shale. Friction coefficient between fracture surfaces was tested with self-developed COF-1 friction coefficient tester (Fig. 2). The procedure was as the follows: (1) The sample was cut into two different shapes: one was the specimen sliced on the direction parallel to the bedding with a thickness of 5.0 mm and the other was semi-cylindrical
Table 1 Mineral composition of Longmaxi shale in Changning district of Sichuan Basin. Bulk composition (wt %) Quartz 29.58
Carbonatite 9.33
Relative content of clay mineral (wt %) Feldspar 11.37
Pyrite 4.03
Clay 45.69
703
Illite 68.51
Illite/Smectite 11.14
Chlorite 20.35
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Journal of Petroleum Science and Engineering 159 (2017) 702–709
Table 2 Basic properties of drill-in fluids. Fluid type
Density
Apparent viscosity (mPa.s)
(g/cm3) OBDF WBDF
1.91 1.93
Plastic viscosity
Yield value (Pa)
(mPa.s) 55 65
API filtration
Oil-water ratio
pH value
(ml)
41 29
11 34
0.6 2.4
ES (V)
93/7 0/100
11.5 9.0
735 –
Fig. 1. Schematic diagram of sealing capacity evaluation of drill-in fluids.
Fig. 2. Schematic diagram of COF-1 friction coefficient tester.
sample sliced along the axis, and their surfaces were polished with 80 mesh metallographic sandpaper; (2) The weighted specimen was placed on the left side of semi-cylindrical sample connected to force and displacement transducer; (3) The friction force and displacement data automatically were recorded with data collection system under movement speed of 4.0–5.0 mm/min; (4) The data was saved when the sliced specimen moved to the right edge of semi-cylindrical sample, and the experiment was repeat for three times. The friction coefficient of dry sample was measured after fixing the weight set on the specimen, and the friction coefficient of immersed sample was measured with the drill-in fluid level came up to sample contact interfaces. The friction coefficient was determined as follows:
2.3.4. Immersion test The changing characteristics of shale structure by water-rock interaction could be directly observed through immersion test. The schematic diagram of the immersion test was shown in Fig. 3. The procedure was as follows: (1) Slice with a thickness of 5.0 mm was prepared by the plug parallel to bedding and taken photos after drying them under 60 C for 48 h; (2) The samples were hung in the heat-resistant plastic bottles with a 300 ml drill-in fluid filtrate and immersed them beneath a liquid level of 2 cm; (3) These sealed plastic bottles were placed into a thermostatic water bath; (4) The samples were dried and taken photos after the 1d and 7d-immersion.
μf ¼ Ff 9:8 WN
3. Results
(3) 3.1. Liquid retention damage
Where μf was the friction coefficient between fracture surfaces, dimensionless; Ff was friction force recorded by force transducer, N; WN was the total mass of slice thick sample and weight set, Kg.
Drill-in fluid filtrate is easy to resort due to developed nano-scale pores and high capillary force, which caused serious liquid phase 704
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Journal of Petroleum Science and Engineering 159 (2017) 702–709
Fig. 3. Schematic diagram of immersion test.
trapping damage. The result of wetting contact angle (Fig. 4) displaced that the contact angle of oil-based filtrate with polished shale surface is smaller than that of water-based filtrate. And the invaded oil phase was easier to adhere to the shale surface and difficult to flow back. As we can see from the experiment result of shale imbibition (Fig. 5), imbibition amount of shale generally went up rapidly in the beginning and remained stable with the time increasing. Imbibition amount to oil-based filtrate of the sample came up to 0.55 times PV (porosity volume) after 24-hours spontaneous imbibition, which is larger than that of water-based filtrate with the amount 0.34 times PV. The larger oil imbibition amount and higher oil phase retention capacity are the two key reasons why serious oil phase trapping damage happened frequently while drilling shale formation with OBDF. The permeability damage rate of drill-in fluid filtrate was determined based on the absolute permeability obtained with measuring gas permeability under different average pressure difference (Fig. 6). The damage rate of WBDF filtrate was 66.43%, and the damage rate of OBDF filtrate was 98.05% (Table 3). The result showed that permeability damage induced by OBDF filtrate was more severe than that induced by WBDF filtrate. The gas-measured permeability after interact with WBDF fluid filtrate demonstrated relatively higher slippage effect, indicating that water retention degree reduced with the increase of flowback pressure difference. While the gas-measured permeability of OBDF filtrate interaction varied little with the increase of flowback pressure difference, showing that oil retention degree was more severe.
Fig. 5. Imbibition amount of shale treated with drill-in fluids.
Fig. 6. Gas-measured permeability of shale before and after drill-in fluid filtrate damage. Table 3 Liquid damage of drill-in fluids filtrate.
3.2. Sealing capacity evaluation The range of sealing fracture width by drill-in fluids was determined by sealing capacity evaluation experiments by steel samples with the different fracture width. The purpose of this experiment was that the maximum sealed fracture width by drill-in fluids was determined without the consideration of fracture surface roughness. As shown in Table 4, the severe lost circulation of OBDF happened at the fracture width of 100 μm, and the severe lost circulation of WBDF occurred when the fracture width reached up to 300 μm. This meant that WBDF has the wider sealing scope and the higher sealing capacity. The result of sealing capacity evaluation for shale samples showed that flowback breakthrough pressure of OBDF was lower than that of
Samples
Initial permeability (mD)
Regained permeability (mD)
Damage rate (%)
Filtrate type
L-1 L-2
0.2567 0.4363
0.0050 0.1421
98.05 64.43
OBDF WBDF
WBDF and OBDF had a higher value of regained permeability recovery rate (Table 5). Thus it can be seen that high quality mud cake with better bi-directional bearing capacity can form on the end face of the shale sample. The likelihood of liquid and solid invasion and wellbore instability damage had dramatically decreased. 4. Discussion 4.1. Sealing capacity of dill-in fluids in shale formation There is a complex pore system including organic and inorganic pores, micro-fractures and natural fractures. The pore structure of samples was observed by SEM. The result shows that minerals existence at the form of layered distribution (Fig. 7a), the development of microfracture (Fig. 7b) and different scale pore (Fig. 7c) is more extensive. Then it is very significant that the fractures and pores are efficiently sealed to prevent solid and liquid of drill-in fluid from intruding into the reservoir. Particle size distribution of drill-in fluids were measured by laser
Fig. 4. Wetting contact angle between drill-in fluids filtrate and shale. 705
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Journal of Petroleum Science and Engineering 159 (2017) 702–709
Table 4 Sealing capacity evaluation of drill-in fluids for steel samples with the different fracture width. Working fluid
Samples
Fracture width (μm)
Lost circulation
Flowback pressure difference(MPa)/ Regained permeability recovery rate(%)
1#
50
None
100
Severe
0.5 0 0.07 0
1 0 0.1 0
1.5 0 0.14 53.8
2 0 0.5 81.8
OBDF
2#
0.3 0 0.05 0
3#
50
None
100
None
5#
200
A little
6#
300
Severe
0.1 0 0.1 0 0.5 0 0.5 0
0.2 0 0.2 0 0.1 0 0.1 0
0.25 69.61 0.25 66.93 0.18 70.62 0.18 76.13
0.6 74.37 0.55 75.81 0.7 73.48 0.7 93.33
WBDF
4#
0 0 0 0 0 0 0 0
effect of pressure difference and interact with the minerals of fracture surface. Both WBDF and OBDF can reduce the friction coefficient of fracture surfaces compared with that of dry sample (Fig. 9). However the friction coefficient decline of fracture surface soaked in OBDF was 21.9%, which was bigger than that in WBDF with a value of 12.5%. It showed that friction coefficient was reduced after the interaction between fluid and fracture surfaces. Lubrication film thickness is the key factor affecting the friction coefficient. With the fluid between fracture surfaces, adsorption film have certain bearing capacity due to the orientation arrangement of polar molecules and the cohesive force between molecules, so as to prevent the direct contact of fracture surfaces. The bonding capacity between liquid and solid interfacial and the lubrication film thickness increased with the reduction of contact angel, which signified lower friction coefficient (Yang et al., 2010; Zhou and Wu, 2016; Voronov et al., 2008). As a result of developed bedding plane of shale formation, the invasion of drill-in fluids into the bedding plane was frequently encountered during the drilling operation, which led to the reduction of friction coefficient between fracture surfaces and wellbore instability. Mineral erosion of fracture surface can make fracture width wider and induce fracture propagation, leading to borehole instability (You et al., 2014). Based on the laser scanning results of fracture surface before and after erosion, fracture surface becomes more smooth at the condition of pH ¼ 11 and exposure 12 days (Fig. 10). Both minerals and organic matter of shale are involved in the reaction of alkali erosion leading to the roughness reduction of fracture surface (Kang et al., 2016). The effect of alkali erosion on fracture width is more outstanding under the condition of higher pH value and longer exposure time. This is the one of reasons why lost circulation happens more frequently during drilling progress in shale reservoir. It is worth noting that the sealed fracture may be opened again under the high pH value environment. Even though the fracture is temporarily plugged, the high pH filtrate will continue to erode the shale fracture surface with the growing time. That makes the
Table 5 Sealing capacity evaluation of drill-in fluids for shale samples with the different fracture width. Samples
Fracture width(μm)
Flowback pressure difference(MPa) /Regained permeability recovery rate(%)
Working fluid
L-3
29.99 30.78
0.05 0 0.05 0
0.12 0 0.1 0
0.18 0 0.12 0.07
0.2 47.05 0.44 46.33
OBDF
L-4
0 0 0 0
L-5
22.06 28.86
0.5 0 1.9 7.59
1 0 2.6 6.46
1.4 0.95 2.8 15.70
3.08 2.73 3.2 17.71
WBDF
L-6
0 0 1.3 4.31
particle size analyzer. Water-based drill-in fluid had a bimodal and wider range of particle size distribution (Fig. 8a), while the oil-based drill-in fluid showed narrow range of particle size distribution(Fig. 8b). It showed that WBDF had better sealing capacity for the developed multiscale pore structure of shale. As shown from fracture surface, the invasion depth of WBDF was relative shallow resulting from the formation of temporary sealing zone, in contrast, OBDF invaded the fracture deeply and spread out across the fracture surface. Solid and liquid phase invasion are the two main damaging type of drill-in fluids, and the key factor for formation damage control is to enhance the sealing capacity of the drill-in fluids. The better sealing capacity the drill-in fluids are, the higher bi-directional bearing capacity the sealing zone are, and the easier removal of formation damage will be. In order to achieve high sealing efficiency, it is necessary to predict the fracture width accurately and make good match between solid particle and fracture width.
4.2. Impact of OBDF on wellbore stability OBDF with high pH value is easy to intrude into fractures under the
Fig. 7. SEM of shale pore structure. 706
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Fig. 8. Particle size distribution of drill-in fluids.
swelling took place eventually (Darley, 1969; Chenevert, 1970; Jellander et al., 1988). Hydration swelling of shale led to the increasing of hydration stress and stress concentration on the top of the crack, which was the key factor for the initiation and propagation of macro-fracture when drilling shale wells by WBDF (Shi et al., 2012; Ghanbari and Dehghanpour, 2015). With the invasion of drill-in fluid filtrate, the likelihood of wellbore instability increased greatly inducing by the hydration swelling of near wellbore shale. To gain the effect of drill-in fluids on shale integrity, OBDF and WBDF filtrates immersion test with no obvious crack shale samples were carried out respectively. An observation on shale samples showed that samples soaked in OBDF filtrate had no fractures on the surface (Fig. 12a–c). After they were soaked in WBDF filtrate for 1 day, a microfracture along the bedding plane was observed on the surface of the sample, and fracture density increased and began to propagate along the bedding planes with the immersion time going by (Fig. 12d–f). As we can speculate from Fig. 12, microfractures may grow in shale formation as a result of physical-chemical interaction between WBDF filtrate and shale. Original hydration force between the crystal layers of illite could be as large as 50 MPa and hardly to induce long-range expansion (Kang et al., 2017). It means that low water content will cause shale hydration with a small strain and a huge stress. This hydration stress lead to the microfracture generation and tensile strength reduction. More water-based filtrate is imbibed into shale than oil-based filtrate under the condition of a long time soaking for new generated fractures. This result is the unanimous consensus on liquid uptake by shale (Singh, 2016). But it seems to contradict the result of imbibition testing in this paper. The reason of this phenomenon is the consideration of testing time in the different engineering backgrounds. If the problem of filtrate invasion is ineffectively solved, it will cause severe formation damage and wellbore instability.
Fig. 9. Variation curve of friction coefficient vs. displacement.
4.3. Impact of WBDF on wellbore stability Due to the high content of clay mineral and rich organic matter, Longmaxi shale has strong interacting potential with working fluids (Deng and Meng, 2003; Qiu et al., 2007). Linear expansion of shale sample with particle sizes under 100# mesh was measured by CPZ-2 dual channel normal pressure and temperature dilatometer. As shown in Fig. 11, linear expansion for OBDF filtrate was only 1.4% and when it came to WBDF filtrate, its value came up to 14.0%. With the invasion of water, double electrical layer would form, resulting from the water molecules and hydration cation adsorption and aggregation on clay layer, and repulsive force and distance between clay increased and hydration
Fig. 10. Laser scanning results of fracture surface before and after alkali erosion. 707
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supporting wellbore can be applied to develop the anti-sloughing water based drill-in fluid. Effective sealing can be technically implemented by developing hydrophobic nanoparticles (<100 nm) with softening and deformation properties in high temperature and high pressure conditions. The development of hydration inhibitor is the key to WBDF in shale reservoir drilling. According to activation theory, if the activity of containing water in clay minerals of shale is accurately determined, saturated organic salt drilling fluid can reach the objective of enhanced hydration inhibition by reducing its activity to a certain value, which is lower than that in clay minerals. But this method cannot be well generalized for its high cost, complex composition, maintenance difficulty and environmental issues. In addition, hydration inhibition capacity can be improved by varying the lattice spacing of clay minerals. With this method, water-soluble polyamine treatment agent with low molecular weight can be chosen to add into the drilling fluid to prevent water molecules from entering the lattice layer by its strong adsorption on clay minerals and by decreasing interlayer spacing of clay minerals. The hydration inhibition capacity of WBDF formulated by this method may catch up with the level of oil based drilling fluid. And its applicability is much better for relatively simple composition, the small dosage of agents, low cost and low difficulty of environment disposal. Some experimental researches and field trials have been done and obtained the predictive effect in Longmaxi shale (Yan et al., 2015; Peng et al., 2017).
Fig. 11. Linear expansion of shale samples in drill-in fluids.
4.4. Optimization route of drill-in fluid in Longmaxi shale Shale gas reservoirs in China put forward higher requirements on exploration, drilling and development due to its complexity and peculiarity (Liu et al., 2016a,b). OBDF had become the first choice of drilling horizontal long section for its good wellbore strengthening capacity in the drilling practice at early stage of shale gas production. However, high cost, security issues and prominent environmental issues of OBDF, especially for later disposal of wasted OBDF and cuttings returned from the bottom hole of the shale gas well, seriously influenced the economic and efficient development of shale gas reservoir. In view of this, drilling horizontal well with anti-sloughing water based drill-in fluid, whose inhibition, sealing capacity and lubricity catch up with the level of OBDF, has become one of the engineering technology problems to be solved urgently and plays a key role in cleaner production and efficient development in shale gas reservoirs. The applied WBDF in site were difficult to fully meet the requirement for drilling engineering in shale reservoir. Based on the geological characteristics and engineering practice experience of shale reservoirs, the combined method of hydration inhibition, effective sealing and
5. Conclusion The following points can be concluded from this work: (1) The stronger wettability and imbibition of OBDF led to the higher formation damage before the sealing zone formation. (2) WBDF from the site had a better sealing and bi-directional bearing capacity for the wider range of particle size distribution. (3) Frictional sliding may cause wellbore instability for the OBDF lubricity and alkali erosion. (4) Hydrate expansion by WBDF is the important factor for the fracture generation and wellbore instability. (5) Reinforcing the capacity of sealing and hydration inhibition is helpful to widely apply WBDF in the shale reservoir.
Fig. 12. Structure characteristics of shale soaked into drill-in fluids. 708
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Acknowledgements
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