Nanoparticles have been widely used to reduce wellbore instability problems of shale formation. In this paper, nanoparticle-containing water-based drilling fluids (WBDFs) and oil-based drilling fluids (OBDFs) were evaluated by running three new tests including spontaneous imbibition, swelling rate and acoustic transit time. Results showed that, for the WBDFs, nanoparticles leaded to higher plastic viscosity (PV) and yield point (YP), and lower API-filtration. Moreover, because pore throats of shale can be plugged by nanoparticles, imbibition amount, swelling rate, and Young’s-modulus reduction of shale decreased significantly.
Yili Kanga, Jiping Shea, Hao Zhangb, Lijun Youa, Minggu Songa
aState Key Lab of Oil and Gas Reservoir Geology and Exploitation in Southwest Petroleum University, Chengdu, China. bCollege of Energy Resources in Chengdu University of Technology, Chengdu, China
Received 14 January 2016, Accepted 21 March 2016
Higher concentration of nanoparticles can induce better plugging effect. However, for the OBDFs, nanoparticles did not show these positive effects like the nano WBDFs, even leaded to some negative effects such as higher filtration and larger Young’s-modulus reduction. The main reasons are that the silica nanoparticles can easily disperse in the WBDFs, and effectively prevent the filtrate invading into shale by plugging pore throats. But the same silica nanoparticles are difficult to disperse in OBDFs, and do not perform the expected functions. This study indicates that nano WBDFs have great potential to reduce the wellbore instability problems of shale formation.
Drilling through a clay-rich shale formation often results in wellbore instability problems. It has been estimated that shale formations make up more than 75% of all drilled formations, and they account for more than 90% of all expenses associated with wellbore instability problems. The main cause of wellbore instability is drilling-fluid filtrate absorption and subsequent swelling and sloughing of the wellbore . So, in order to reduce the filtrate invasion, the best possible way is to seal off exposed pore throats of shale .
Al-Bazali (2005) measured the shale pore-throat sizes according to the capillary pressure equation, and found that the average pore-throat sizes of a variety of shales range from 10 to 30 nm . As shown in Fig. 1, compared with shale pore-throat sizes, conventional drilling fluid additives, such as bentonite and barite, have much larger particle diameters, ranging from 0.1 to 100 μm . The extremely low permeability and small pore-throat size observed in shale indicate that conventional filtration additives cannot form mud-cakes on shale surface and thus not reduce filtrate invasion , . So, according to the theory of particle bridging, only nanoparticles should be used for plugging shale pore throats , , .
Fig. 1. Particle-size scale .
Previous investigations which based on pressure penetration experiments showed that nano-particles (particle diameters in the nano-meter range) can prevent pressure of drilling fluid from transmitting into the shale formation , , , , . They demonstrated that nanoparticles performed well at plugging the pore throats, and significantly reducing the permeability of the shale. In addition, for the micro-cracks in shale, the nanoparticles alone cannot plug them, but nanoparticles presented a good synergic effect with other materials in drilling fluid , , , .
In conclusion, combination of properly formulated drilling fluid and appropriate nanoparticles are keys of preventing water invasion. OBDFs have been widely used to reduce the wellbore instability problems because OBDF contains a litter water (less than 20 wt%). But recent investigations indicated that OBDFs can still lead to wellbore instability due to filtrate invasion. For example, filtrate invasion into shale can increase lubrication of bedding planes, and generate alkali erosion , , , . These negative effects can lead to reduction of shale strength.
Previous investigations mainly paid close attention to pressure transmission in shale exposed WBDFs, and did not evaluate the applicability of the nanoparticles in OBDFs. In this paper, some new experimental methods, such as spontaneous imbibition, swelling rate, and acoustic transit time test, were adopted to evaluate applicability of the silica nanoparticles in WBDFs and OBDFs. Experimental results can provide some evidences to reduce the wellbore instability problems using nano drilling fluids.
Samples and experimental methods
As shown in Fig. 2, the nanoparticles discussed in this paper were 10–20-nm diameter silica spheres, and were non-modified. They had excellent ion compatibility, temperature stability, and no adverse effect on drilling fluid properties , .
Fig. 2. SEM image of silica nanoparticles.
Yanchang shale was used in this study. And this shale consists of quartz, feldspar, dolomite, clays and other silicate and carbonate minerals (Table 1). In addition, this shale has the contact angle of 60.5° and 4.5° under contacting with water and oil, respectively. Permeability ranges from 0.00015 to 0.037 mD, porosity ranges from 2.0% to 3.5%, and average pore diameter is 25 nm .
Table 1. Composition of Yanchang shale.
WBDF and OBDF were used in this study. Main additives and properties of these two drilling fluids were listed in Table 2, Table 3.
Table 2. Main additives and properties of WBDF.
Table 3. Main additives and properties of OBDF.
Spontaneous imbibition experiment
Spontaneous imbibition experiments were conducted by testing imbibition amount of shale exposed to different fluids under 25 °C. Dry shale plugs (25.5–25.8 mm diameter and 30–40 mm length), which drilled along the same bedding planes, were suspended below the balance (ESJ200-4B, Shenyang Longteng Electronic Co., Ltd, China), and then immersed in the experimental fluid. Data acquisition system of the spontaneous imbibition instrument can automatically record the imbibition amount variation with time increase.
The swelling of shale was determined using linear swelling instrument (CPZ-2, Qingdao Heng TAIDA Electromechanical Equipment Co., Ltd, China) following the Chinese Oil and Gas Industry Standard SY/T5613-2000 under 25 °C . 10-g Dry shale powders (particle size is less than 150 μm) were put into test container, and compacted using press machine under 4 MPa and maintaining 5 min. Displacement sensor was attached on the top surface of the compacted sample. Then remaining space of the test container was filled with experiment fluid. The swelling rate of sample can be recorded by data acquisition system.
Acoustic transit time experiment
Shale plugs were soaked in drilling fluid for different times under 25 °C. After soaking, sound waves testing system (SCMS-J, Chengdu Haohan Rock-electric Co., Ltd, China) was used to test acoustic transit time of S-wave and P-wave of the soaked shale plugs (Fig. 3). Young’s modulus of shale could be calculated according to the data of S-wave and P-wave .
Fig. 3. Schematic diagram of acoustic transit time testing system.
Results and discussion
Rheology and filtration of nanoparticle-containing drilling fluids
The rheology and filtration parameters of drilling fluids were tested based on API (American Petroleum Institute) standard. The test results were listed in Table 4. It can be seen that the presence of nanoparticles resulted in higher PV and YP of both WBDFs and OBDFs. And the greater concentration of nanoparticles could induce higher PV and YP. The API filtrations of nano WBDFs decreased with the increase of nanoparticle concentration, but the API filtrations of nano OBDFs were slightly larger than that of basic fluid (OBDF). The pH of WBDFs decreased with the increase of nanoparticle concentration, but the pH of OBDFs did not change.
Table 4. Rheology and filtration properties of drilling fluids.
There are three main reasons for above experimental results. Firstly, the addition of nanoparticles results in higher solids content, which can lead to higher PV and YP. Secondly, as shown in Fig. 4, Yan (1995) tested the half-life period of water droplet in the W/O emulsion and oil droplet in the O/W emulsion, respectively . Both emulsions were treated by hydrophilic silica powder. These results indicated that the half-life period of water droplet was smaller than that of oil droplet. It means that hydrophilic silica powder can reduce the stability of W/O emulsion.
The silica nanoparticles are non-modified, and have good water wetting ability . The stability of OBDFs (W/O emulsion) will be decreased when the silica nanoparticles are added in it. Thereby, the silica nanoparticles are difficult to disperse in OBDFs. The API filtrations of OBDFs with nanoparticles are higher than that of basic fluid. Thirdly, silica nanoparticles can react with hydroxyl ions (OH−) in WBDFs according to Eqs. (1), (2), . The concentration of hydroxyl ions can be decreased based on these two reactions, which leads to lower pH value of nano WBDFs. OBDFs contains a little water (15 wt%), and the oil is continuous phase, which indicates that silica nanoparticles are difficult to react with hydroxyl ions. So the pH of nano OBDFs did not change.
Fig. 4. Half-life curves of water droplet and oil droplet on the oil/water interface under hydrophilic silica powder treating .
Effect of nanoparticles on imbibition amount
Spontaneous imbibition is an important way of filtrate invasion into shale. Imbibition amounts of shale exposed six filtrates of drilling fluids were tested. The filtrates were obtained by using API filter tester (ZNS-5A, Qingdao Sen Xin Electromechanical Equipment Co., Ltd, China). WBDF filtrate and OBDF filtrate were basic fluids. Basic parameters of shale samples were listed in Table 5.
Table 5. Basic parameters of shale samples.
As shown in Fig. 5, the imbibition amount of basic fluid (WBDF filtrate) was the largest. But when the nanoparticles were added into it, the imbibition amount of WBDF filtrate decreased significantly compared with basic fluid. To be detailed, compared with that of basic fluid, when the concentration of nanoparticles was 5 wt%, the total imbibition amount decreased by 42.8%, and decreased by 68.0% when the concentration of nanoparticles was 10 wt%. These results show that the addition of nanoparticles can decrease the imbibition amount of shale. And the reduction of imbibition amount becomes more remarkable as the nanoparticle concentration rises. In addition, for the three fluids, the imbibition amount increased fast in the initial period, and then gradually tended to be constant.
Fig. 5. Relationship between imbibition amount and time for WBDF filtrates with and without nanoparticles.
For the basic fluid, the imbibition amount increased fast before 12 h, however, for the nanoparticle-containing WBDF filtrates, the imbibition amount increased fast only before 1 h, which indicates that nanoparticles can quickly plug shale pore throats. Crack propagation characteristics of shale samples can also prove some evidence. As shown in Fig. 6, sample 2-4-D, which absorbed the WBDF filtrates, generated one micro-crack on shale surface. When the concentration of nanoparticles is 5 wt%, the length of micro-crack on sample 3-7-C was shorter than that of sample 2-4-D. No micro-cracks were observed on the shale surface when the concentration of nanoparticles increased to 10 wt%.
Fig. 6. Crack propagation characteristics of shale samples after absorbing WBDF filtrates.
In order to further confirm the mechanism of reduction of imbibition amount, SEM (Quanta 450, FEI, USA) were used to visualize the type of plugging that was taking place. Fig. 7 was obtained using a shale sample (sample 3-11-B) that had been previously tested with nanoparticle-containing WBDF filtrate (10 wt%). SEM analysis of shale surface showed that shale has a wide range of pore throats, and the nanoparticles plugged primarily the ones that fit that size (Fig. 7a). However, it is easy seen that the group of nanoparticles can in some cases aggregate together to plug on larger pore throats (Fig. 7b). These results demonstrate that the nanoparticles can plug the pore throats of shale.
Fig. 7. SEM images of shale surface (a) nanoparticles within shale and (b) aggregate of nanoparticles plugging a pore throat.
As shown in Fig. 8, it can be seen that there were three main characteristics for the imbibition curves. Firstly, because of strong oil wettability of shale (wetting angle of 4.5°), imbibition amount increased rapidly in the initial period (before 5 min), and then tended to be constant. Secondly, imbibition amounts were almost the same before 3 h for the three filtrates, which indicates that nanoparticles in OBDF filtrate cannot play plugging effect. Thirdly, the total imbibition amounts of nanoparticle-containing filtrates were higher than that of basic fluid (OBDF filtrate) because of crack propagation , .
As shown in Fig. 6, these three samples generated cracks after imbibition. Sample 3-12-A generated two micro-cracks on shale surface (Fig. 9a), but the two micro-cracks did not propagate along the bedding plane. So the imbibition amount did not increase significantly after 3 h. Sample 3-4-B generated one crack propagated along the bedding plane on shale surface (Fig. 9b). Therefore, curve B produced an upward inflection at the third hour. Similarly, the curve C produced two upward inflections at the fourth and twelfth hour respectively due to two cracks propagation of sample 3-1-B (Fig. 9c).
Fig. 8. Relationship between imbibition amount and time for OBDF filtrates with and without nanoparticles.
Fig. 9. Crack propagation characteristics of shale samples after absorbing OBDF filtrates.