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Inhibitory effect of water-based drilling fluid on methane hydrate dissociation
Accepted Manuscript Inhibitory effect of water-based drilling fluid on methane hydrate dissociation Xin Zhao, Zhengsong Qiu, Chao Zhao, Jiangen Xu, Yubin Zhang PII: DOI: Reference:
S0009-2509(19)30089-2 https://doi.org/10.1016/j.ces.2018.12.057 CES 14729
To appear in:
Chemical Engineering Science
Received Date: Revised Date: Accepted Date:
13 September 2018 8 December 2018 31 December 2018
Please cite this article as: X. Zhao, Z. Qiu, C. Zhao, J. Xu, Y. Zhang, Inhibitory effect of water-based drilling fluid on methane hydrate dissociation, Chemical Engineering Science (2019), doi: https://doi.org/10.1016/j.ces. 2018.12.057
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Inhibitory effect of water-based drilling fluid on methane hydrate dissociation Xin Zhao a,b,*, Zhengsong Qiu a,b,*, Chao Zhao a, Jiangen Xu a, Yubin Zhang a a
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, P. R.
China b
Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)),
Ministry of Education, Qingdao 266580, P. R. China Corresponding Author: [email protected] (Xin Zhao); [email protected] (Zhengsong Qiu) Address: No. 66, Changjiang West Road, Huangdao District, Qingdao, Shandong Province, China. Postal Code: 266580
Abstract Hydrate dissociation poses a significant problem during drilling operations in hydrate-bearing sediments. The drilling fluid is in direct contact with hydrates, and understanding its inhibitory effect on hydrate dissociation is important for stabilizing hydrates during drilling operations. In this work, an apparatus was designed for investigating hydrate dissociation in drilling fluids, and the effects of thermodynamic hydrate inhibitors (THIs), polyvinyl pyrrolidone (PVP), and soybean lecithin on hydrate dissociation were studied. The inhibitory effect of a water-based drilling fluid in the presence of the potential hydrate dissociation inhibitors was also studied. An unexpected inhibitory effect occurred with ethylene glycol (EG) at concentrations below 10 wt%, resulting from a range of factors including the dissociation driving force, and mass and heat transfers in the EG solution. PVP and lecithin reduced the hydrate dissociation rate and increased the time required for complete dissociation of hydrates. These can, therefore, be used in water-based drilling fluids to inhibit hydrate dissociation. A combination of 0.1 wt% PVP and 0.5 wt% lecithin was selected as an optimal hydrate dissociation inhibitor, considering its inhibitory effect and compatibility with the drilling fluid. Using EG at a concentration below 10 wt% as a THI instead of NaCl can
also help inhibit hydrate dissociation. The findings of this work provide a basis for the development and design of drilling fluids for drilling in hydrate-bearing sediments. Key words: hydrate dissociation inhibitor; methane hydrate; drilling fluid; inhibitory effect; lecithin
1. Introduction Significant amounts of natural gas hydrates have been identified in marine sediments and permafrost regions around the world, especially in deepwater sediments (Makogon, 2010). Gas hydrates are ice-like compounds formed by the inclusion of gas molecules in clathrates of water molecules under low temperature and high pressure. Although gas hydrates present a large threat to the conventional oil and gas industry, they are also considered as a potential future energy resource (Han et al., 2016). The estimated value of global hydrate resources is 3 × 1015 m3, which is much higher than that of conventional gas (4.04 × 1014 m3) and shale gas (2.044.56 × 1014 m3) resources (Chong et al., 2016; Liu et al., 2017). In recent years, the exploration and development of gas hydrates has been a key focus of the energy industry. Although natural gas hydrates are considered a new type of clean energy resource, the dissociation of hydrates when drilling through hydrate-bearing sediments can cause severe engineering problems, or even marine geological hazards (Sultan et al., 2004; Freij-Ayoub et al., 2007; Khabibullin et al., 2010; Gao et al., 2017; Hardwick and Mathias, 2018). Figure 1 illustrates the engineering problems related to hydrate dissociation in offshore drilling. During drilling operations, the high pressure and low temperature conditions required for hydrate stability can no longer be maintained due to the change in geostatic stress, and the large amount of heat generated from the drill bit cutting and breaking rocks, and the friction between the drilling tool and the wellbore. As a result, gas hydrates surrounding the wellbore dissociate, and the surrounding rocks collapse. In addition, large amounts of gas and water released from hydrate dissociation increase the pore pressure of the hydrate-bearing sediment
formation, decreasing formation strength. The released gas also reduces the density of drilling fluids, and the drilling fluid fails to deliver sufficient support to the wellbore, resulting in instability. The gas released during hydrate dissociation is likely form hydrates again in the low-temperature drilling fluid, especially when the well is shut in, thus plugging the pipeline and blowout preventer (Ning et al., 2013; Wang et al., 2019). Therefore, hydrate dissociation is one of the biggest challenges when drilling through hydrate-bearing sediments. These problems represent a worst-case scenario and may occur rarely. However, operators must still pay special attention to the issue of hydrate dissociation given the severe consequences of this phenomenon.
Fig. 1. Engineering problems caused by hydrate dissociation in offshore drilling.
The drilling fluid is considered the ‘blood’ of drilling engineering (Meng and Qiu, 2018; Zhao et al., 2019). When drilling hydrate-bearing sediment, drilling fluid is extremely important for ensuring safety and efficiency of the process as it is in direct contact with the hydrate-bearing sediments. The temperature, pressure, properties of the drilling fluid are the critical factors for hydrate stability. Theoretically, reducing the temperature and increasing the density of the drilling fluid can increase the stability of gas hydrates. However, increasing the
drilling fluid density promotes the invasion of drilling fluids into the formation and can even fracture the formation. Yet, simply reducing drilling fluid temperature cannot completely prevent hydrate dissociation. For example, in hydrate drilling operations in the Arctic, serious hydrate dissociation problems have occurred even though low-temperature and high-density drilling fluid was used. The drilling fluid density was further increased to stabilize the hydrates, but the column pressure exceeded the fracture pressure of the formation, resulting in lost circulation (Schofield et al., 1997; Torsæter and Cerasi, 2015). The physical and chemical properties of the drilling fluid may also play an important role in inhibiting hydrate dissociation, although these effects have not yet been studied. Research on gas hydrate production and removal of hydrate blockages in pipelines tends to focus on promoting hydrate dissociation, rather than inhibiting hydrate dissociation. Therefore, an understanding of the factors promoting gas hydrate dissociation already exists (Panter et al., 2011; Sohn and Seo, 2017; Shi et al., 2018; Song et al., 2018). In order to increase the gas production rate, some studies have sought to stimulate hydrate dissociation using thermal methods, depressurization, and chemical injection. High concentrations of thermodynamic hydrate inhibitors (THIs) can change the equilibrium conditions of gas hydrate, thus promoting hydrate dissociation (Semenov et al., 2015; Yagasaki et al., 2015; Aminnaji et al., 2017). In order to prevent hydrate blockage, and to remove any blockage within a pipe, some studies have explored the formation and dissociation of gas hydrate in the presence of kinetic hydrate inhibitors (KHIs). The results of these studies have shown that hydrates formed in the presence of some KHIs, including polyvinylcaprolactam, polyvinylpyrrolidone (PVP), and the copolymer of polyvinylpyrrolidone and polyvinylcaprolactam, dissociated at a slower rate than when in pure water (Bruusgaard et al., 2009; Gulbrandsen and Svartaas, 2017a and 2017b; Tang et al., 2018), while hydrates dissociated faster in the presence of antifreeze proteins (Daraboina et al., 2011a and 2011b). However, these studies investigated the
dissociation of hydrates formed in KHI solutions, which are completely different from those found in the sea floor. There are few reports in the literature on the inhibition of hydrate dissociation by drilling fluids. In the hydrate drilling operations in the Arctic, lecithin was added into the drilling fluid to stabilize hydrates (Schofield et al., 1997), but very few experimental data were reported. Kawamura et al. (2003) tested the dissociation time of pellet-shaped methane hydrates in aqueous xanthan solutions, determining that the dissociation rate was lower in the viscous fluid than in water. Fereidounpour and Vatani (2014, 2015) investigated the effects of water-based drilling fluids on hydrate dissociation at 1022 °C, and designed a polyacrylate drilling fluid to improve wellbore stability by reducing the invasion of drilling fluid into the formation. As the exploration and pilot production of gas hydrates in different regions progresses, problems caused by hydrate dissociation will become more prominent. It is therefore increasingly necessary to investigate the effects of drilling fluids on hydrate dissociation. In this work, an apparatus was designed for investigating hydrate dissociation in drilling fluids, and the effects of typical THIs and KHIs on hydrate dissociation were experimentally studied. Additives that could effectively inhibit hydrate dissociation were added to a water-based drilling fluid to investigate the inhibitory effects of the drilling fluid on hydrate dissociation. An idealized hydrate dissociation inhibitor was finally selected based on the experimental results, considering both the inhibitory effect and compatibility of the drilling fluid. The flow chart in Fig. 2 shows an outline of the study. This work provides a basis for the development and design of suitable drilling fluids for the drilling of hydrate-bearing sediments.
Fig. 2. Flow chart that describes the logical structure of this study.
2. Materials and methods 2.1 Materials Sodium dodecyl sulfate (SDS), NaCl, KCl, polyvinyl pyrrolidone (PVP, molecular weight ≈630,000), and ethylene glycol (EG) were purchased from Sinopharm Chemical Reagent Co., Ltd. Soybean lecithin was purchased from Hunan Weixing Biotechnology Co., Ltd. The additives of the water-based drilling fluid included low-viscosity polyanionic cellulose (PAC-LV), amphoteric polymer (FA367), and sulfonated phenolic resin (SMP), and were supplied by China Oilfield Services. Methane hydrates are abundant and widespread in deepwater sea floors (Kang et al., 2013) so methane with a purity ≥ 99.9% was used in the experiments and was purchased from Qingdao Tianyuan Gas Company. Deionized water was prepared in our laboratory. 2.2 Apparatus and procedure 2.2.1 Hydrate formation and dissociation tests An apparatus was designed for investigating hydrate formation and dissociation in drilling fluids, as shown in Fig. 3. The volume of the autoclave was 750 mL, and this large volume reduced the stochastic effect for hydrate nucleation (Del Villano and Kelland, 2011). The
temperature of the autoclave was controlled via a water bath and was measured with two temperature sensors to an accuracy of ± 0.05 °C. The pressure was measured with a pressure sensor to an accuracy of ± 0.01 MPa. The displacement rate of the constant flux pump which was used to inject the drilling fluid into the autoclave ranged from 0 to 10.0 mL/min.
Fig. 3. Schematic diagram of the apparatus for gas hydrate dissociation testing.
SDS had been widely used as a promoter of hydrate formation. Solutions (400 mL) with a concentration of 500 mg/L of SDS in deionized water were prepared. After the autoclave was washed with deionized water, the SDS solutions were added into the autoclave, and vacuumed for 15 min to remove most of the air inside. The temperature inside the autoclave was cooled to 2 °C to simulate typical low temperatures found in deepwater sea floors. After the temperature had stabilized, methane was injected, and the autoclave was pressurized to 10 MPa to form methane hydrates. The temperature and pressure were recorded every 30 s. The hydrate formation process was determined to be finished once the temperature and pressure had stabilized once again. In the hydrate dissociation test, 100 mL of the test fluid (cooled to 2 °C) was injected into the autoclave with a constant flux pump. The temperature of the water bath was increased to 15 °C at a rate of 0.5 °C/min to simulate an increasing downhole temperature caused by heat generated from the rock drilling and the friction between the drill tool and the wellbore. As hydrates dissociated, pressure increased; when the pressure change
over 30 min was 0.01 MPa or less, and the temperature change was 0.1 °C or less, the hydrate dissociation process was deemed to have been finished. For each test fluid, at least two parallel experiments were run. 2.2.2 Fluid property measurement The thermal conductivity of deionized water in the presence of different concentrations of PVP and lecithin was measured at 2 °C using a thermal conductivity meter (TC 3000E, XIATECH, China). The rheological properties of drilling fluids were tested at 2 °C by a ZNN-D6 rotational viscometer (Qingdao Haitongda Special Instrument Co. Ltd.). The apparent viscosity (AV), plastic viscosity (PV), and yield point (YP) were calculated from the 600 and 300 r/min readings using the following formulas: Apparent viscosity (AV)= ϕ600/2 (mPa·s)
(1)
Plastic viscosity (PV)= ϕ600- ϕ300 (mPa·s)
(2)
Yield point (YP)= (ϕ300-PV)/2 (Pa)
(3)
The fluid loss (FLAPI) of drilling fluids was tested using a ZNS-2A filtration apparatus (Qingdao Haitongda Special Instrument Co. Ltd.) at 2 °C and 0.7 MPa for 30 min.
3 Results and discussion 3.1 Analysis of hydrate formation In order to ensure the repeatability of the hydrate dissociation tests, the experimental conditions were optimized for hydrate formation. The Peng-Robinson equation which can predict the vapor pressure and volumetric behavior of multicomponent systems was introduced to calculate the methane molecule change. The equation can be expressed as follows (Peng and Robinson, 1976): P
RT a（T） Vm b Vm (Vm b) b(Vm b)
(4)
where P is the system pressure (MPa); T is the temperature (K); Vm is the molar volume
(L/mol); R is the gas constant (8.3145 J·mol-1·K-1); and a and b are the energy parameter (Pa·m6/mol2) and the Van der Waals co-volume parameter (m3/mol), respectively, which can be calculated using equations (5)(7): R 2Tc2 a(T ) = a(Tc ) (T ) 0.45274 (T ) Pc
（T） [1 k (1 Tr0.5 )]2 b 0.07780
RTc Pc
(5)
(6)
(7)
where Tc is the critical temperature (K); Pc is the critical pressure (MPa); Tr is the ratio of the experimental temperature and critical temperature; and k is the function of the acentric factor w, expressed as follows (Stryjek and Vera, 1986): k 0.378893 1.4897153w 0.17131848w2 0.0196554w3
(8)
Finally, the amount of methane molecules can be calculated as follows:
n V / Vm
(9)
Figure 4 shows a typical temperature and pressure curve for the hydrate formation process in deionized water. After a 1 h induction time, the temperature noticeably started increasing coinciding with a sharp pressure drop, indicating the start of hydrate formation. Hydrate formation was not complete until the temperature and pressure remained constant. Several temperature peaks were observed because of the stochastic nature and heterogeneity of hydrate formation. It took approximately 5.6 h for hydrate formation, and the overall pressure drop was about 7 MPa.
Fig. 4. Variations of temperature and pressure as a function of time for hydrate formation.
Eight repeat hydrate formation experiments were conducted to analysis the amount of hydrate produced, which was important for the repeatability of the subsequent hydrate dissociation experiments. Because of the stochastic nature of hydrate nucleation, induction times varied from 0.5 to 1.6 h in these experiments. The hydrate formation process lasted for 5 to 5.7 h, and at the end of which no water was left in the autoclave. The conversion rate of water to methane hydrate was determined to be 57.76% under ideal conditions, meaning there should have been some (unconverted) water in the autoclave. Therefore, the remaining water was likely distributed in the pores of the hydrate bulk, meaning that no continuous water phase existed in the autoclave. In all nine experiments, the total pressure drop for hydrate formation was 7 ± 0.03 MPa and the amount of consumed methane was 2.23 ±0.02 mol. Based on this, same volume of hydrates could be prepared when conducting subsequent dissociation tests with different fluids. 3.2 Analysis of hydrate dissociation in deionized water After the preparation of methane hydrates, the deionized water (cooled to 2 °C) was injected into the autoclave, and the autoclave was then heated. The pressure and temperature versus time curves for hydrate formation and dissociation are shown in Fig. 5. After the hydrate formation process had finished, the cooled deionized water was injected, and the temperature was increased to stimulate hydrate dissociation. As the hydrate
dissociated, methane was released, and the pressure increased. It took 6 h to dissociate the hydrates completely, which was indicated by a stabilized pressure and temperature. Using the same method, hydrate dissociation experiments were conducted in the presence of typical THIs including NaCl, KCl, and EG. The hydrates had completely dissociated over 4 h in the presence of either 10 wt% NaCl or 10 wt% KCl, indicating that the presence of inorganic salts promoted hydrate dissociation (Fig, 6). The results agreed with other studies on stimulating hydrate dissociation using THIs (Yuan et al., 2013; Fereidounpour and Vatani, 2014).
Fig. 5. Variations of temperature and pressure during hydrate formation and dissociation.
Fig. 6. Released methane amount during hydrate dissociation in the presence of THIs.
Inorganic salts promote hydrate dissociation because the addition of salts reduces water activity, and the hydrate equilibrium curve shifts towards lower temperatures and higher
pressures. Therefore, the driving force for hydrate dissociation increases, promoting hydrate dissociation. However, it is surprising that the time required for hydrate dissociation in 10 wt% EG solution was much longer than in water. This result is in contrast with the current viewpoint that THIs can promote hydrate dissociation. The repeat experiments also showed the same results, requiring that this phenomenon be further discussed. 3.3 Effect of EG on hydrate dissociation The hydrate dissociation process was studied in EG solutions at concentrations of 5 wt%, 10 wt%, 15 wt%, 20 wt%, and 30 wt%. The variations of released methane as a function of time are shown in Fig. 7. It was interesting that the addition of 5 wt% EG retarded hydrate dissociation instead of promoting it, as was expected, although the effect was very weak. When the EG concentration increased to 10 wt%, the inhibitory effect on hydrate dissociation was enhanced. In comparison with the hydrate dissociation process in deionized water, the slope of the released gas curve was smaller, and the time required for hydrates to completely dissociate was longer. The presence of 20 wt% EG promoted hydrate dissociation. The dissociation rate is defined as the ratio of the released methane mole number during hydrate dissociation and the time required for hydrates to completely dissociate. Table 1 shows the dissociation rate and the complete dissociation time in the presence of different concentrations of EG. The results show that on an average, it required 6.1 h to completely dissociate the hydrates, and the average hydrate dissociation rate was 0.379 mol/h. The presence of 5 wt% EG slightly inhibited hydrate dissociation, as the complete dissociation time increased from 6.1 h to 6.5 h and the dissociation rate reduced from 0.379 mol/h to 0.351 mol/h. In the presence of 10 wt% EG, the dissociation time increased to 7.6 h and the dissociation rate reduced to 0.311 mol/h, indicating that hydrate dissociation was inhibited. As the concentration was progressively increased, the dissociation rate increased, and 20 wt% EG increased the dissociation rate to 0.407 mol/h. As the concentration of EG was increased to 30
wt%, hydrate dissociation markedly increased. Therefore, at high concentrations, the presence of EG can promote hydrate dissociation rather than inhibit it, which has been confirmed in studies on chemical injection for stimulating hydrate production (Li et al., 2007; Sun et al., 2018). However, the inhibiting effect of EG at low concentrations was surprising. As previous studies have focused on stimulating hydrate dissociation using high concentrations of THIs, very few have reported hydrate dissociation inhibition. As such, there is no adequate explanation for this phenomenon, but it probably results from several factors that contribute to hydrate dissociation.
Fig. 7. Released methane amount in the presence of EG at different concentrations. Table 1 Hydrate dissociation rate and time in the presence of EG. EG concentration (wt%) 0 5 10 15 20 30
Dissociation rate (mol/h) 0.382, 0.4, 0.36, 0.343, 0.411 0.347, 0.373, 0.332 0.345, 0.306, 0.315, 0.277 0.368, 0.407, 0.371 0.418, 0.376, 0.426 0.457, 0.429
Average Dissociation rate (mol/h) 0.379 0.351 0.311 0.382 0.407 0.443
Complete dissociation time (h) 6.2, 5.7, 6.3, 6.8, 5.6 6.6, 6.0, 6.9 6.5, 7.7, 7.4, 8.6 6.3, 5.6, 6.3 5.6, 6.3, 5.3 5.1, 5.5
Average dissociation time (h) 6.1 6.5 7.6 6.1 5.8 5.3
Hydrate dissociation is a process with mass and heat transfers, and the dissociation rate is proportional to the dissociation driving force without considering the heat and mass transfers. In the heating dissociation process, the overtemperature (the difference between the
environmental temperature and the hydrate equilibrium temperature) is the driving force for hydrate dissociation (Goel et al., 2001; English and Phelan, 2009; Li et al., 2015), as shown in Equation (10) (Song et al., 2017). According to the phase equilibrium for gas hydrate in the presence of EG at different concentrations (Fadnes et al., 1998; Hemmingsen et al., 2011), the overtemperature is 12.7 °C in water and the presence of 10 wt% EG reduces the dissociation temperature by 2.4 °C, thus increasing the overtemperature to 15.1 °C. As a result, the thermal driving force increases, thus promoting hydrate dissociation. All THIs can increase the overtemperature, so they are usually used to promote hydrate dissociation to increase the rate of gas production. dn kAs (T -Teq ) 4k rc2 (T -Teq ) dt
(10)
where n is the amount of gas released from hydrate dissociation (mol); t is the hydrate dissociation time (min); k is the dissociation rate constant (mol·min−1·m−2·°C−1); As is the superficial area of the hydrate particle (m2); rc is the radius of the hydrate particle (m); T is the experimental temperature (°C), and Teq is the hydrate equilibrium temperature (°C). The dissociation process is also significantly influenced by the mass and heat transfers that result from the addition of EG. The phase change rate during hydrate dissociation is proportional to the thermal conductivity, as shown in Equation (11) (Hong et al., 2006).
2T 1 T H KL 2 t r r r
(11)
where H is the enthalpy (J/kg); t is time (s); KL is the thermal conductivity (W/m·K); T is the temperature (K); and r is the radial coordinate (m). The concentration of EG can also significantly influence the thermal conductivity and viscosity of the solution, thus influencing heat and mass transfers. Figure 8 shows the thermal conductivity and dynamic viscosity of aqueous solutions containing different concentrations of EG (Handbook-Fundamentals, 2005). As EG concentration increases, the thermal
conductivity decreases, which can hinder hydrate dissociation. At the same time, the addition of EG increases the aqueous solution viscosity, thus increasing the mass transfer resistance and reducing the hydrate dissociation rate.
Fig. 8. Thermal conductivity and dynamic viscosity of EG solution.
It can therefore be inferred that, although the presence of EG at low concentrations (≤ 10 wt%) increases the thermal driving force for hydrate dissociation, the mass and heat transfer resistances increase, and the hydrate dissociation rate reduces as a result of the combined action of these factors. As the EG concentration continues to increase, the influence of the thermal driving force is greater than that of the heat and mass transfers, promoting hydrate dissociation. 3.4 Inhibitory effect of PVP on hydrate dissociation It has been reported that hydrates form slowly in KHI solutions and that these hydrates also dissociate more slowly than in water (Dragomir et al., 2011; Tang et al., 2018). These studies support the notion that for naturally formed methane hydrate-bearing sea floor sediments, the addition of KHIs to drilling fluids may also inhibit hydrate dissociation. It is well known that the addition of a small amount (0.12.0 wt%) of KHIs does not affect hydrate equilibrium conditions (Kelland, 2006; Kang et al., 2014), so hydrate dissociation kinetics were the focus here. PVP is the representative product of the first generation of KHIs, and the effects of PVP at
different concentrations on hydrate dissociation were tested. Figure 9 and Table 2 show the hydrate dissociation process in the presence of 0.1 wt%, 0.25 wt%, 0.5 wt%, 0.75 wt%, and 1.0 wt% PVP. The addition of a low concentration of PVP (0.1 wt%) showed clear a inhibitory effect on hydrate dissociation; the dissociation rate was reduced from 0.379 mol/h to 0.257 mol/h and the time required for complete hydrate dissociating increased from 6.1 h to 9.2 h. As the concentration of PVP was increased from 0.1 wt% to 1.0 wt%, the inhibitory effect increased; when the concentration was 1.0 wt%, the dissociation rate was 0.214 mol/h and the dissociation time was 10.9 h. The released gas curve at high concentrations fluctuated, however, which might have been caused by the heterogeneity of the hydrates formed and the uneven heat and mass transfers in the viscous polymer solution. In comparison with EG, PVP performed much better at inhibiting hydrate dissociation because 0.1 wt% PVP reduced the hydrate dissociation rate by 32.2%, while 10 wt% EG reduced the rate by 17.9%. As a typical KHI, PVP polymer molecules can adsorb onto the hydrate surface through hydrogen bonding. This forms a polymer film on the hydrate surface and fits the five-membered ring into the hydrate cage, hindering cavity completion and thus inhibiting hydrate growth (Kang et al., 2014). In the same way, during hydrate dissociation, PVP can be adsorbed onto the hydrate surface to form a film that can hinder the transfer of water and gas molecules from the hydrate bulk into the liquid phase, thereby slowing hydrate dissociation. In addition, as a type of high molecular weight polymer, the addition of PVP significantly increases the liquid viscosity (Table 2). High viscosity in turn increases the mass transfer resistance. Moreover, the addition of a small amount of PVP did not obviously influence the thermal conductivity of the solution, indicating that PVP does not inhibit hydrate dissociation by influencing heat transfer.
Fig. 9. Released methane amount in the presence of PVP at different concentrations. Table 2 Hydrate dissociation parameters and fluid properties in the presence of PVP. PVP concentration (wt%) 0 0.1 0.25 0.5 0.75 1.0
Dissociation rate (mol/h) 0.382, 0.4, 0.36, 0.343, 0.411 0.254, 0.25, 0.267 0.234, 0.253 0.213, 0.229 0.238, 0.204, 0.226 0.239, 0.212, 0.185, 0.22
Average Dissociation rate (mol/h) 0.379 0.257 0.243 0.221 0.223 0.214
Complete dissociation time (h) 6.2, 5.7, 6.3, 6.8, 5.6 9.3, 9.6, 8.7 10.1, 9.4 10.7, 10.0 9.6, 11.5, 10.2 9.8, 11.0, 12.4, 10.5
Average dissociation time (h) 6.1 9.2 9.8 10.4 10.4 10.9
Thermal conductivity (W·m-1·K-1) 0.572 0.573 0.566 0.568 0.568 0.569
Apparent viscosity (mPa·s) 1.0 1.5 2.0 2.5 3.5 5.0
3.5 Inhibitory effect of lecithin on hydrate dissociation Figure 10 and Table 3 show the hydrate dissociation process in the presence of 0.1 wt%, 0. 25 wt%, 0.5 wt%, 0.75 wt%, and 1.0 wt% lecithin. Overall, lecithin reduced the hydrate dissociation rate and prolonged the time required for hydrates to completely dissociate. Adding 0.1 wt% lecithin into deionized water reduced the dissociation rate from 0.379 mol/h to 0.297 mol/h and increased the dissociation time from 6.1 h to 7.7 h. The inhibitory effect was not, however, as strong as for PVP at similarly low concentrations. However, the inhibitory effect of lecithin was clearly enhanced by increasing the concentration; after the addition of 0.5 wt% lecithin, the complete dissociation time increased by 54% (from 6.1 h to 9.4 h) and the dissociation rate was reduced by 37.2% (from 0.379 mol/h to 0.238 mol/h). The inhibitory effect was strong; when the concentration was increased to 1.0 wt%, the hydrate
dissociation time increased to 10.4 h and the dissociation rate was reduced to 0.216 mol/h. Therefore, using lecithin can effectively inhibit hydrate dissociation when drilling through hydrate-bearing sediments. It should be noted that adding lecithin to water at a concentration greater than 0.5 wt% resulted in foaming when stirred, which is not favored during the preparation of drilling fluids.
Fig. 10. Released methane amount in the presence of lecithin at different concentrations. Table 3 Hydrate dissociation parameters and fluid properties in the presence of lecithin. Lecithin concentration (wt%) 0 0.1 0.25 0.5 0.75 1.0
Dissociation rate (mol/h) 0.382, 0.4, 0.36, 0.343, 0.411 0.27, 0.301, 0.32 0.282, 0.267 0.221, 0.235, 0.257 0.232, 0.202, 0.252 0.219, 0.192, 0.236
Average Dissociation rate (mol/h) 0.379 0.297 0.274 0.238 0.229 0.216
Complete dissociation time (h) 6.2, 5.7, 6.3, 6.8, 5.6 8.1, 7.6, 7.3 8.3, 8.7 10.0, 9.4, 8.9 9.7, 11.0, 8.8 10.2, 11.4, 9.6
Average dissociation time (h) 6.1 7.7 8.5 9.4 9.8 10.4
Thermal conductivity (W·m-1·K-1) 0.572 0.576 0.566 0.570 0.575 0.571
Apparent viscosity (mPa·s) 1.0 1.0 1.5 2.0 2.0 2.5
A study of hydrate formation in the presence of lecithin shows that lecithin does not influence the thermodynamic equilibrium conditions of methane hydrates (Chen et al., 2007). Therefore, the mechanism of inhibiting hydrate dissociation by lecithin should be analyzed from the perspective of its kinetic inhibitory effect. Table 3 shows that the addition of a small amount of lecithin did not measurably influence the fluid thermal conductivity, indicating that lecithin does not influence heat transfer. As the concentration of lecithin was increased, the
fluid viscosity increased gradually, increasing the mass transfer resistance. This effect was not as strong as for PVP, however. Molecular dynamic simulation showed that lecithin molecules adsorb onto the hydrate surface forming a net structure with nearby lecithin molecules, thus hindering the transfer of water and gas molecules from the dissociated hydrate surface to the liquid phase (Wang et al., 2017). The molecular structure of lecithin is shown in Fig. 11. It forms a multilayer vesicle structure in water when the concentration is greater than 4.69 × 10-4 mol/L and each layer is, in reality, a lipid bilayer (Liu et al., 2010). When a large amount of lecithin molecules are adsorbed onto the hydrate surface through hydrogen bonding, the multilayers may effectively hinder the transfer of gas and water molecules, thus inhibiting hydrate dissociation.
Fig. 11. Molecular structure of lecithin.
3.6 Performance evaluation of a water-based drilling fluid containing lecithin and PVP In order to meet the requirements of deepwater drilling which is a challenging, high-risk, high-reward operation, the drilling fluid has to maintain stable rheological and filtration properties, and should inhibit hydrate formation under low temperature and high pressure conditions in order to avoid downhole problems. When drilling through hydrate-bearing sediments, it is required that the drilling fluid can effectively inhibit hydrate dissociation. In this work, the water-based drilling fluid designed for deepwater drilling was selected for testing; its basic formulation is shown in Table 4. Table 4 Basic formulation of water-based drilling fluid for deepwater drilling. Component Bentonite FA367 PAC-LV
Concentration (wt%) 2.0 0.25 0.5
Function Filtrate reducer and viscosifier Viscosifer and encapsulator Filtrate reducer
SMP KCl NaCl
2.0 5.0 10.0
Filtrate reducer Shale inhibitor Hydrate inhibitor
3.6.1 Compatibility between PVP/ lecithin and deepwater drilling fluid Additives need to be compatible with the drilling fluids (Jin et al., 2017). Table 5 and Table 6 show the basic properties of the drilling fluid containing different concentrations of PVP and lecithin. Apparently, the addition of PVP (a high molecular weight polymer) has a significant influence on the rheological property of the drilling fluid at 2 °C. The gel strength (Gel), yield point, and viscosity of the drilling fluid substantially increased following the addition of 0.1 wt% PVP. Increasing the concentration of PVP led to an increase in rheological parameters; the rheological parameters of the drilling fluid were increased by two and three times when 0.5 wt% and 1.0 wt% PVP were added, respectively. Filtration loss was reduced as the concentration of PVP was increased as the polymer could increase the viscosity of the filtrate and thus help form the filter cake along the borehole walls. In deepwater drilling operations, high rheology of the drilling fluid is not favored because it can lead to high equivalent circulating density, causing severe lost circulation (Zhao et al., 2017). Therefore, considering both inhibitory effects on hydrate dissociation and influences on the drilling fluid rheology, 0.1 wt% PVP was selected as the optimal hydrate dissociation inhibitor for the deepwater drilling fluid to balance desired hydrate dissociation effects and engineering requirements. In comparison with PVP, lecithin is a type of surfactant and had a much smaller impact on the rheological properties of the drilling fluid. As the concentration of lecithin was increased from 0.1 wt% to 1.0 wt%, the rheological parameters of the drilling fluid slightly increased and the filtrate loss was also slightly reduced. The addition of 1.0 wt% lecithin increased the PV of the drilling fluid from 15 mPa·s to 22 mPa·s and increased the YP from 8 Pa to 9 Pa. Therefore, the addition of 0.11.0 wt% lecithin would not significantly impact the rheological
and filtration properties of the drilling fluid, although its foaming characteristics present a serious problem at higher concentrations. Considering the inhibitory effect on hydrate dissociation and compatibility with the drilling fluid, 0.5 wt% lecithin was selected as the optimal hydrate dissociation inhibitor. Table 5 Influence of PVP on the basic properties of the drilling fluid. Concentration (wt%) 0 0.1 0.25 0.5 0.75 1.0
AV (mPa·s) 23 32 41.5 58 61 72
PV (mPa·s) 15 22 28 36 37 46
YP (Pa) 8 10 13.5 22 24 26
Gel (Pa) 1.5/2.5 3/5 4/6.5 5/7.5 5/7.5 5.5/8.5
FLAPI (mL) 6.2 5.8 5.1 4.9 4.6 4.1
pH 9 9 9 9 9 9
Table 6 Influence of lecithin on the basic properties of the drilling fluid. Concentration (wt%) 0 0.1 0.25 0.5 0.75 1.0
AV (mPa·s) 23 23.5 26 27.5 28.5 31
PV (mPa·s) 15 15 18 19 20 22
YP (Pa) 8 8.5 8 8.5 8.5 9
Gel (Pa) 1.5/2.5 2/3.5 2/3.5 2/4 2/3.5 2.5/4
FLAPI (mL) 6.2 5.6 5.7 5.7 5.4 5.2
pH 9 9 9 9 9 9
3.6.2 Inhibitory effect of deepwater drilling fluid on hydrate dissociation The water-based drilling fluid typically used in deepwater drilling was tested to evaluate its hydrate inhibitory performance. The thermal conductivity of the drilling fluid was 0.577 W/(m·K) at 2 °C. In this study, 0.1 wt% PVP, 0.5 wt% lecithin, and their mixtures were added to the water-based drilling fluid to evaluate their effect on hydrate inhibition. The results are shown in Fig. 12 and Table 7. When only the typical deepwater drilling fluid was used in the experiment, 8.0 h was required for complete dissociation of hydrates in the drilling fluid, which occurred at a rate 0.310 mol/h. In comparison with hydrate dissociation in deionized water, the hydrates dissociated more slowly in the drilling fluid, although the drilling fluid contained NaCl and
KCl which are promoters of hydrate dissociation. This is due to the drilling fluid being a multicomponent system, and the additives in the drilling fluid can influence hydrate dissociation. The polymeric additives FA-367 and PAC-LV can significantly increase the viscosity of the drilling fluid, thus hindering mass transfer. At the same time, these additives may also directly interact with hydrates, such as by adsorbing onto the hydrate surface, thus inhibiting hydrate dissociation. Therefore, the inhibitory effect of the drilling fluid resulted from the combined action of these different components. In the drilling fluid containing 0.1 wt% PVP, the hydrates dissociated more slowly than in the absence of PVP, but the inhibitory effect was generally weak. In the drilling fluid containing 0.5 wt% lecithin, the hydrate dissociation rate was 0.171 mol/h and the time required for hydrates to completely dissociate was 13.2 h, indicating a strong inhibitory effect. When 0.1 wt% PVP and 0.5 wt% lecithin were used in combination as a hydrate dissociation inhibitor in the drilling fluid, the inhibitory performance was very strong; the hydrate dissociation rate was 0.154 mol/h, which was half that in the drilling fluid, and the time required for complete dissociation of the hydrates was up to 14.8 h. The hydrate dissociation rate was further reduced to 0.133 mol/h when a combination of 0.5 wt% PVP and 0.5 wt% lecithin was used, but the higher concentration of PVP may increase the viscosity of the drilling fluid. The hydrate dissociation temperature was also analyzed. As the water-based drilling fluid contained 10 wt% NaCl and 5 wt% KCl, the theoretical hydrate dissociation temperature was lower than 2 °C under the experimental pressure and without considering the effects of other additives. Therefore, the hydrates would begin dissociating immediately upon contact with the drilling fluid. However, water-based drilling fluids are multi-component systems composed of a mixture of water, solids, organic materials, and salts, and the temperature at which the hydrate dissociation rate started to sharply increase was used to investigate the effect of drilling fluids on hydrate dissociation. It was found that towards the
beginning of the dissociation process, hydrate started dissociating rapidly in the drilling fluid, and the dissociation temperature was 2.0 °C. The addition of 0.1 wt% PVP did not effectively increase dissociation temperature. In comparison, when 0.5 wt% lecithin was used, the hydrates did not dissociate rapidly until the temperature was increased to 3.7 °C. A combination of PVP and lecithin showed better inhibitory performance; in the presence of 0.1 wt% PVP and 0.5 wt% lecithin, the rapid hydrate dissociation temperature was 5.05 °C, and was further increased to 6.20 °C when 0.5 wt% PVP and 0.5 wt% lecithin were used. Therefore, a combination of PVP and lecithin can serve as a good hydrate dissociation inhibitor. Considering that EG is a THI, and that it also inhibits hydrate dissociation at a concentration below 10 wt%, NaCl was replaced by EG in the drilling fluid. The red curve in Fig. 12 shows that using this approach for deepwater drilling fluid can reduce the hydrate dissociation rate.
Fig. 12. Released methane amount during hydrate dissociation in drilling fluids. Table 7 Average hydrate dissociation rate and time in drilling fluids. Inhibitor
Dissociation temperature (°C)
None
2.00
0.1 wt% PVP
2.20
Dissociation rate (mol/h) 0.299, 0.336, 0.273, 0.331 0.252, 0.219, 0.204
Average Dissociation rate (mol/h)
Complete dissociation time (h)
Average dissociation time (h)
0.310
8.3, 7.3, 9.1, 7.4
8.0
0.225
9.4, 11.0, 11.6
10.7
0.5 wt% lecithin 0.1 wt% PVP and 0.5 wt% lecithin 0.5 wt% PVP and 0.5 wt% lecithin 10 wt% EG instead of 10 wt% NaCl
3.70 5.05 6.20 2.25
0.174, 0.18, 0.159 0.151, 0.143, 0.166 0.139, 0.126 0.243, 0.217, 0.212
0.171 0.154 0.133 0.224
13.4, 12.3, 13.8 15.0, 15.9, 13.5 16.1, 17.3 9.5, 11.0, 11.2
13.2 14.8 16.7 10.6
Based on the experimental results, when drilling through hydrate-bearing sediments, using a combination of 0.1 wt% PVP and 0.5 wt% lecithin can effectively inhibit hydrate dissociation and will not significantly impact the basic properties of the drilling fluid. The concentrations of PVP and lecithin can be further increased to meet requirements for greater inhibition of hydrate dissociation, but compatibilities need to be considered. In addition, the use of a low concentration of EG as a THI instead of NaCl can also be helpful.
4. Conclusions Hydrate dissociation experiments were conducted using different drilling fluid additives to select the hydrate dissociation inhibitor for drilling through hydrate-bearing sediments. As expected, THIs, NaCl, and KCl promoted hydrate dissociation. It was surprising, however, that as a THI, EG can slightly inhibit hydrate dissociation at concentrations below 10 wt%. This might be the result of several interacting factors such as the dissociation driving force, and mass and heat transfer features in the EG solution. At higher concentrations EG can promote hydrate dissociation. PVP can reduce the hydrate dissociation rate and delay the time required for hydrates to completely dissociate. A concentration of 0.1 wt% PVP showed a clear inhibitory effect. Lecithin also inhibited hydrate dissociation. The addition of 0.5 wt% lecithin increased the dissociation time by up to 54%. The adsorption of multilayer lecithin vesicles onto the hydrate is most likely the main inhibitory mechanism. Therefore, the addition of PVP and lecithin can help water-based drilling fluids to inhibit hydrate dissociation. A combination of 0.1 wt% PVP and 0.5 wt% lecithin is selected as an optimal hydrate dissociation inhibitor for drilling hydrate-bearing sediments when considering both inhibitory effect and compatibility with the drilling fluid. Using EG at concentrations below 10 wt% as a
THI instead of NaCl can also help inhibit hydrate dissociation. Considering that drilling fluids are multi-component systems, the effects of different components on hydrate dissociation need to be studied further to identify or develop better hydrate dissociation inhibitors.
Acknowledgments This work was supported by the National Natural Science Foundation of China (No. 51804331), the Shandong Provincial Natural Science Foundation (No. ZR2017BEE036), and the Fundamental Research Funds for the Central Universities (No. 18CX02032A).
Conflicts of Interest The authors declare no conflict of interest.
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Highlights (1) The inhibitory effect of drilling fluids on hydrate dissociation was studied. (2) An unexpected inhibitory effect occurred with EG at concentrations below 10 wt%. (3) PVP and lecithin could inhibit hydrate dissociation. (4) A combination of PVP and lecithin was selected as a hydrate dissociation inhibitor.
S0009-2509(19)30089-2 https://doi.org/10.1016/j.ces.2018.12.057 CES 14729
To appear in:
Chemical Engineering Science
Received Date: Revised Date: Accepted Date:
13 September 2018 8 December 2018 31 December 2018
Please cite this article as: X. Zhao, Z. Qiu, C. Zhao, J. Xu, Y. Zhang, Inhibitory effect of water-based drilling fluid on methane hydrate dissociation, Chemical Engineering Science (2019), doi: https://doi.org/10.1016/j.ces. 2018.12.057
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Inhibitory effect of water-based drilling fluid on methane hydrate dissociation Xin Zhao a,b,*, Zhengsong Qiu a,b,*, Chao Zhao a, Jiangen Xu a, Yubin Zhang a a
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, P. R.
China b
Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)),
Ministry of Education, Qingdao 266580, P. R. China Corresponding Author: [email protected] (Xin Zhao); [email protected] (Zhengsong Qiu) Address: No. 66, Changjiang West Road, Huangdao District, Qingdao, Shandong Province, China. Postal Code: 266580
Abstract Hydrate dissociation poses a significant problem during drilling operations in hydrate-bearing sediments. The drilling fluid is in direct contact with hydrates, and understanding its inhibitory effect on hydrate dissociation is important for stabilizing hydrates during drilling operations. In this work, an apparatus was designed for investigating hydrate dissociation in drilling fluids, and the effects of thermodynamic hydrate inhibitors (THIs), polyvinyl pyrrolidone (PVP), and soybean lecithin on hydrate dissociation were studied. The inhibitory effect of a water-based drilling fluid in the presence of the potential hydrate dissociation inhibitors was also studied. An unexpected inhibitory effect occurred with ethylene glycol (EG) at concentrations below 10 wt%, resulting from a range of factors including the dissociation driving force, and mass and heat transfers in the EG solution. PVP and lecithin reduced the hydrate dissociation rate and increased the time required for complete dissociation of hydrates. These can, therefore, be used in water-based drilling fluids to inhibit hydrate dissociation. A combination of 0.1 wt% PVP and 0.5 wt% lecithin was selected as an optimal hydrate dissociation inhibitor, considering its inhibitory effect and compatibility with the drilling fluid. Using EG at a concentration below 10 wt% as a THI instead of NaCl can
also help inhibit hydrate dissociation. The findings of this work provide a basis for the development and design of drilling fluids for drilling in hydrate-bearing sediments. Key words: hydrate dissociation inhibitor; methane hydrate; drilling fluid; inhibitory effect; lecithin
1. Introduction Significant amounts of natural gas hydrates have been identified in marine sediments and permafrost regions around the world, especially in deepwater sediments (Makogon, 2010). Gas hydrates are ice-like compounds formed by the inclusion of gas molecules in clathrates of water molecules under low temperature and high pressure. Although gas hydrates present a large threat to the conventional oil and gas industry, they are also considered as a potential future energy resource (Han et al., 2016). The estimated value of global hydrate resources is 3 × 1015 m3, which is much higher than that of conventional gas (4.04 × 1014 m3) and shale gas (2.044.56 × 1014 m3) resources (Chong et al., 2016; Liu et al., 2017). In recent years, the exploration and development of gas hydrates has been a key focus of the energy industry. Although natural gas hydrates are considered a new type of clean energy resource, the dissociation of hydrates when drilling through hydrate-bearing sediments can cause severe engineering problems, or even marine geological hazards (Sultan et al., 2004; Freij-Ayoub et al., 2007; Khabibullin et al., 2010; Gao et al., 2017; Hardwick and Mathias, 2018). Figure 1 illustrates the engineering problems related to hydrate dissociation in offshore drilling. During drilling operations, the high pressure and low temperature conditions required for hydrate stability can no longer be maintained due to the change in geostatic stress, and the large amount of heat generated from the drill bit cutting and breaking rocks, and the friction between the drilling tool and the wellbore. As a result, gas hydrates surrounding the wellbore dissociate, and the surrounding rocks collapse. In addition, large amounts of gas and water released from hydrate dissociation increase the pore pressure of the hydrate-bearing sediment
formation, decreasing formation strength. The released gas also reduces the density of drilling fluids, and the drilling fluid fails to deliver sufficient support to the wellbore, resulting in instability. The gas released during hydrate dissociation is likely form hydrates again in the low-temperature drilling fluid, especially when the well is shut in, thus plugging the pipeline and blowout preventer (Ning et al., 2013; Wang et al., 2019). Therefore, hydrate dissociation is one of the biggest challenges when drilling through hydrate-bearing sediments. These problems represent a worst-case scenario and may occur rarely. However, operators must still pay special attention to the issue of hydrate dissociation given the severe consequences of this phenomenon.
Fig. 1. Engineering problems caused by hydrate dissociation in offshore drilling.
The drilling fluid is considered the ‘blood’ of drilling engineering (Meng and Qiu, 2018; Zhao et al., 2019). When drilling hydrate-bearing sediment, drilling fluid is extremely important for ensuring safety and efficiency of the process as it is in direct contact with the hydrate-bearing sediments. The temperature, pressure, properties of the drilling fluid are the critical factors for hydrate stability. Theoretically, reducing the temperature and increasing the density of the drilling fluid can increase the stability of gas hydrates. However, increasing the
drilling fluid density promotes the invasion of drilling fluids into the formation and can even fracture the formation. Yet, simply reducing drilling fluid temperature cannot completely prevent hydrate dissociation. For example, in hydrate drilling operations in the Arctic, serious hydrate dissociation problems have occurred even though low-temperature and high-density drilling fluid was used. The drilling fluid density was further increased to stabilize the hydrates, but the column pressure exceeded the fracture pressure of the formation, resulting in lost circulation (Schofield et al., 1997; Torsæter and Cerasi, 2015). The physical and chemical properties of the drilling fluid may also play an important role in inhibiting hydrate dissociation, although these effects have not yet been studied. Research on gas hydrate production and removal of hydrate blockages in pipelines tends to focus on promoting hydrate dissociation, rather than inhibiting hydrate dissociation. Therefore, an understanding of the factors promoting gas hydrate dissociation already exists (Panter et al., 2011; Sohn and Seo, 2017; Shi et al., 2018; Song et al., 2018). In order to increase the gas production rate, some studies have sought to stimulate hydrate dissociation using thermal methods, depressurization, and chemical injection. High concentrations of thermodynamic hydrate inhibitors (THIs) can change the equilibrium conditions of gas hydrate, thus promoting hydrate dissociation (Semenov et al., 2015; Yagasaki et al., 2015; Aminnaji et al., 2017). In order to prevent hydrate blockage, and to remove any blockage within a pipe, some studies have explored the formation and dissociation of gas hydrate in the presence of kinetic hydrate inhibitors (KHIs). The results of these studies have shown that hydrates formed in the presence of some KHIs, including polyvinylcaprolactam, polyvinylpyrrolidone (PVP), and the copolymer of polyvinylpyrrolidone and polyvinylcaprolactam, dissociated at a slower rate than when in pure water (Bruusgaard et al., 2009; Gulbrandsen and Svartaas, 2017a and 2017b; Tang et al., 2018), while hydrates dissociated faster in the presence of antifreeze proteins (Daraboina et al., 2011a and 2011b). However, these studies investigated the
dissociation of hydrates formed in KHI solutions, which are completely different from those found in the sea floor. There are few reports in the literature on the inhibition of hydrate dissociation by drilling fluids. In the hydrate drilling operations in the Arctic, lecithin was added into the drilling fluid to stabilize hydrates (Schofield et al., 1997), but very few experimental data were reported. Kawamura et al. (2003) tested the dissociation time of pellet-shaped methane hydrates in aqueous xanthan solutions, determining that the dissociation rate was lower in the viscous fluid than in water. Fereidounpour and Vatani (2014, 2015) investigated the effects of water-based drilling fluids on hydrate dissociation at 1022 °C, and designed a polyacrylate drilling fluid to improve wellbore stability by reducing the invasion of drilling fluid into the formation. As the exploration and pilot production of gas hydrates in different regions progresses, problems caused by hydrate dissociation will become more prominent. It is therefore increasingly necessary to investigate the effects of drilling fluids on hydrate dissociation. In this work, an apparatus was designed for investigating hydrate dissociation in drilling fluids, and the effects of typical THIs and KHIs on hydrate dissociation were experimentally studied. Additives that could effectively inhibit hydrate dissociation were added to a water-based drilling fluid to investigate the inhibitory effects of the drilling fluid on hydrate dissociation. An idealized hydrate dissociation inhibitor was finally selected based on the experimental results, considering both the inhibitory effect and compatibility of the drilling fluid. The flow chart in Fig. 2 shows an outline of the study. This work provides a basis for the development and design of suitable drilling fluids for the drilling of hydrate-bearing sediments.
Fig. 2. Flow chart that describes the logical structure of this study.
2. Materials and methods 2.1 Materials Sodium dodecyl sulfate (SDS), NaCl, KCl, polyvinyl pyrrolidone (PVP, molecular weight ≈630,000), and ethylene glycol (EG) were purchased from Sinopharm Chemical Reagent Co., Ltd. Soybean lecithin was purchased from Hunan Weixing Biotechnology Co., Ltd. The additives of the water-based drilling fluid included low-viscosity polyanionic cellulose (PAC-LV), amphoteric polymer (FA367), and sulfonated phenolic resin (SMP), and were supplied by China Oilfield Services. Methane hydrates are abundant and widespread in deepwater sea floors (Kang et al., 2013) so methane with a purity ≥ 99.9% was used in the experiments and was purchased from Qingdao Tianyuan Gas Company. Deionized water was prepared in our laboratory. 2.2 Apparatus and procedure 2.2.1 Hydrate formation and dissociation tests An apparatus was designed for investigating hydrate formation and dissociation in drilling fluids, as shown in Fig. 3. The volume of the autoclave was 750 mL, and this large volume reduced the stochastic effect for hydrate nucleation (Del Villano and Kelland, 2011). The
temperature of the autoclave was controlled via a water bath and was measured with two temperature sensors to an accuracy of ± 0.05 °C. The pressure was measured with a pressure sensor to an accuracy of ± 0.01 MPa. The displacement rate of the constant flux pump which was used to inject the drilling fluid into the autoclave ranged from 0 to 10.0 mL/min.
Fig. 3. Schematic diagram of the apparatus for gas hydrate dissociation testing.
SDS had been widely used as a promoter of hydrate formation. Solutions (400 mL) with a concentration of 500 mg/L of SDS in deionized water were prepared. After the autoclave was washed with deionized water, the SDS solutions were added into the autoclave, and vacuumed for 15 min to remove most of the air inside. The temperature inside the autoclave was cooled to 2 °C to simulate typical low temperatures found in deepwater sea floors. After the temperature had stabilized, methane was injected, and the autoclave was pressurized to 10 MPa to form methane hydrates. The temperature and pressure were recorded every 30 s. The hydrate formation process was determined to be finished once the temperature and pressure had stabilized once again. In the hydrate dissociation test, 100 mL of the test fluid (cooled to 2 °C) was injected into the autoclave with a constant flux pump. The temperature of the water bath was increased to 15 °C at a rate of 0.5 °C/min to simulate an increasing downhole temperature caused by heat generated from the rock drilling and the friction between the drill tool and the wellbore. As hydrates dissociated, pressure increased; when the pressure change
over 30 min was 0.01 MPa or less, and the temperature change was 0.1 °C or less, the hydrate dissociation process was deemed to have been finished. For each test fluid, at least two parallel experiments were run. 2.2.2 Fluid property measurement The thermal conductivity of deionized water in the presence of different concentrations of PVP and lecithin was measured at 2 °C using a thermal conductivity meter (TC 3000E, XIATECH, China). The rheological properties of drilling fluids were tested at 2 °C by a ZNN-D6 rotational viscometer (Qingdao Haitongda Special Instrument Co. Ltd.). The apparent viscosity (AV), plastic viscosity (PV), and yield point (YP) were calculated from the 600 and 300 r/min readings using the following formulas: Apparent viscosity (AV)= ϕ600/2 (mPa·s)
(1)
Plastic viscosity (PV)= ϕ600- ϕ300 (mPa·s)
(2)
Yield point (YP)= (ϕ300-PV)/2 (Pa)
(3)
The fluid loss (FLAPI) of drilling fluids was tested using a ZNS-2A filtration apparatus (Qingdao Haitongda Special Instrument Co. Ltd.) at 2 °C and 0.7 MPa for 30 min.
3 Results and discussion 3.1 Analysis of hydrate formation In order to ensure the repeatability of the hydrate dissociation tests, the experimental conditions were optimized for hydrate formation. The Peng-Robinson equation which can predict the vapor pressure and volumetric behavior of multicomponent systems was introduced to calculate the methane molecule change. The equation can be expressed as follows (Peng and Robinson, 1976): P
RT a（T） Vm b Vm (Vm b) b(Vm b)
(4)
where P is the system pressure (MPa); T is the temperature (K); Vm is the molar volume
(L/mol); R is the gas constant (8.3145 J·mol-1·K-1); and a and b are the energy parameter (Pa·m6/mol2) and the Van der Waals co-volume parameter (m3/mol), respectively, which can be calculated using equations (5)(7): R 2Tc2 a(T ) = a(Tc ) (T ) 0.45274 (T ) Pc
（T） [1 k (1 Tr0.5 )]2 b 0.07780
RTc Pc
(5)
(6)
(7)
where Tc is the critical temperature (K); Pc is the critical pressure (MPa); Tr is the ratio of the experimental temperature and critical temperature; and k is the function of the acentric factor w, expressed as follows (Stryjek and Vera, 1986): k 0.378893 1.4897153w 0.17131848w2 0.0196554w3
(8)
Finally, the amount of methane molecules can be calculated as follows:
n V / Vm
(9)
Figure 4 shows a typical temperature and pressure curve for the hydrate formation process in deionized water. After a 1 h induction time, the temperature noticeably started increasing coinciding with a sharp pressure drop, indicating the start of hydrate formation. Hydrate formation was not complete until the temperature and pressure remained constant. Several temperature peaks were observed because of the stochastic nature and heterogeneity of hydrate formation. It took approximately 5.6 h for hydrate formation, and the overall pressure drop was about 7 MPa.
Fig. 4. Variations of temperature and pressure as a function of time for hydrate formation.
Eight repeat hydrate formation experiments were conducted to analysis the amount of hydrate produced, which was important for the repeatability of the subsequent hydrate dissociation experiments. Because of the stochastic nature of hydrate nucleation, induction times varied from 0.5 to 1.6 h in these experiments. The hydrate formation process lasted for 5 to 5.7 h, and at the end of which no water was left in the autoclave. The conversion rate of water to methane hydrate was determined to be 57.76% under ideal conditions, meaning there should have been some (unconverted) water in the autoclave. Therefore, the remaining water was likely distributed in the pores of the hydrate bulk, meaning that no continuous water phase existed in the autoclave. In all nine experiments, the total pressure drop for hydrate formation was 7 ± 0.03 MPa and the amount of consumed methane was 2.23 ±0.02 mol. Based on this, same volume of hydrates could be prepared when conducting subsequent dissociation tests with different fluids. 3.2 Analysis of hydrate dissociation in deionized water After the preparation of methane hydrates, the deionized water (cooled to 2 °C) was injected into the autoclave, and the autoclave was then heated. The pressure and temperature versus time curves for hydrate formation and dissociation are shown in Fig. 5. After the hydrate formation process had finished, the cooled deionized water was injected, and the temperature was increased to stimulate hydrate dissociation. As the hydrate
dissociated, methane was released, and the pressure increased. It took 6 h to dissociate the hydrates completely, which was indicated by a stabilized pressure and temperature. Using the same method, hydrate dissociation experiments were conducted in the presence of typical THIs including NaCl, KCl, and EG. The hydrates had completely dissociated over 4 h in the presence of either 10 wt% NaCl or 10 wt% KCl, indicating that the presence of inorganic salts promoted hydrate dissociation (Fig, 6). The results agreed with other studies on stimulating hydrate dissociation using THIs (Yuan et al., 2013; Fereidounpour and Vatani, 2014).
Fig. 5. Variations of temperature and pressure during hydrate formation and dissociation.
Fig. 6. Released methane amount during hydrate dissociation in the presence of THIs.
Inorganic salts promote hydrate dissociation because the addition of salts reduces water activity, and the hydrate equilibrium curve shifts towards lower temperatures and higher
pressures. Therefore, the driving force for hydrate dissociation increases, promoting hydrate dissociation. However, it is surprising that the time required for hydrate dissociation in 10 wt% EG solution was much longer than in water. This result is in contrast with the current viewpoint that THIs can promote hydrate dissociation. The repeat experiments also showed the same results, requiring that this phenomenon be further discussed. 3.3 Effect of EG on hydrate dissociation The hydrate dissociation process was studied in EG solutions at concentrations of 5 wt%, 10 wt%, 15 wt%, 20 wt%, and 30 wt%. The variations of released methane as a function of time are shown in Fig. 7. It was interesting that the addition of 5 wt% EG retarded hydrate dissociation instead of promoting it, as was expected, although the effect was very weak. When the EG concentration increased to 10 wt%, the inhibitory effect on hydrate dissociation was enhanced. In comparison with the hydrate dissociation process in deionized water, the slope of the released gas curve was smaller, and the time required for hydrates to completely dissociate was longer. The presence of 20 wt% EG promoted hydrate dissociation. The dissociation rate is defined as the ratio of the released methane mole number during hydrate dissociation and the time required for hydrates to completely dissociate. Table 1 shows the dissociation rate and the complete dissociation time in the presence of different concentrations of EG. The results show that on an average, it required 6.1 h to completely dissociate the hydrates, and the average hydrate dissociation rate was 0.379 mol/h. The presence of 5 wt% EG slightly inhibited hydrate dissociation, as the complete dissociation time increased from 6.1 h to 6.5 h and the dissociation rate reduced from 0.379 mol/h to 0.351 mol/h. In the presence of 10 wt% EG, the dissociation time increased to 7.6 h and the dissociation rate reduced to 0.311 mol/h, indicating that hydrate dissociation was inhibited. As the concentration was progressively increased, the dissociation rate increased, and 20 wt% EG increased the dissociation rate to 0.407 mol/h. As the concentration of EG was increased to 30
wt%, hydrate dissociation markedly increased. Therefore, at high concentrations, the presence of EG can promote hydrate dissociation rather than inhibit it, which has been confirmed in studies on chemical injection for stimulating hydrate production (Li et al., 2007; Sun et al., 2018). However, the inhibiting effect of EG at low concentrations was surprising. As previous studies have focused on stimulating hydrate dissociation using high concentrations of THIs, very few have reported hydrate dissociation inhibition. As such, there is no adequate explanation for this phenomenon, but it probably results from several factors that contribute to hydrate dissociation.
Fig. 7. Released methane amount in the presence of EG at different concentrations. Table 1 Hydrate dissociation rate and time in the presence of EG. EG concentration (wt%) 0 5 10 15 20 30
Dissociation rate (mol/h) 0.382, 0.4, 0.36, 0.343, 0.411 0.347, 0.373, 0.332 0.345, 0.306, 0.315, 0.277 0.368, 0.407, 0.371 0.418, 0.376, 0.426 0.457, 0.429
Average Dissociation rate (mol/h) 0.379 0.351 0.311 0.382 0.407 0.443
Complete dissociation time (h) 6.2, 5.7, 6.3, 6.8, 5.6 6.6, 6.0, 6.9 6.5, 7.7, 7.4, 8.6 6.3, 5.6, 6.3 5.6, 6.3, 5.3 5.1, 5.5
Average dissociation time (h) 6.1 6.5 7.6 6.1 5.8 5.3
Hydrate dissociation is a process with mass and heat transfers, and the dissociation rate is proportional to the dissociation driving force without considering the heat and mass transfers. In the heating dissociation process, the overtemperature (the difference between the
environmental temperature and the hydrate equilibrium temperature) is the driving force for hydrate dissociation (Goel et al., 2001; English and Phelan, 2009; Li et al., 2015), as shown in Equation (10) (Song et al., 2017). According to the phase equilibrium for gas hydrate in the presence of EG at different concentrations (Fadnes et al., 1998; Hemmingsen et al., 2011), the overtemperature is 12.7 °C in water and the presence of 10 wt% EG reduces the dissociation temperature by 2.4 °C, thus increasing the overtemperature to 15.1 °C. As a result, the thermal driving force increases, thus promoting hydrate dissociation. All THIs can increase the overtemperature, so they are usually used to promote hydrate dissociation to increase the rate of gas production. dn kAs (T -Teq ) 4k rc2 (T -Teq ) dt
(10)
where n is the amount of gas released from hydrate dissociation (mol); t is the hydrate dissociation time (min); k is the dissociation rate constant (mol·min−1·m−2·°C−1); As is the superficial area of the hydrate particle (m2); rc is the radius of the hydrate particle (m); T is the experimental temperature (°C), and Teq is the hydrate equilibrium temperature (°C). The dissociation process is also significantly influenced by the mass and heat transfers that result from the addition of EG. The phase change rate during hydrate dissociation is proportional to the thermal conductivity, as shown in Equation (11) (Hong et al., 2006).
2T 1 T H KL 2 t r r r
(11)
where H is the enthalpy (J/kg); t is time (s); KL is the thermal conductivity (W/m·K); T is the temperature (K); and r is the radial coordinate (m). The concentration of EG can also significantly influence the thermal conductivity and viscosity of the solution, thus influencing heat and mass transfers. Figure 8 shows the thermal conductivity and dynamic viscosity of aqueous solutions containing different concentrations of EG (Handbook-Fundamentals, 2005). As EG concentration increases, the thermal
conductivity decreases, which can hinder hydrate dissociation. At the same time, the addition of EG increases the aqueous solution viscosity, thus increasing the mass transfer resistance and reducing the hydrate dissociation rate.
Fig. 8. Thermal conductivity and dynamic viscosity of EG solution.
It can therefore be inferred that, although the presence of EG at low concentrations (≤ 10 wt%) increases the thermal driving force for hydrate dissociation, the mass and heat transfer resistances increase, and the hydrate dissociation rate reduces as a result of the combined action of these factors. As the EG concentration continues to increase, the influence of the thermal driving force is greater than that of the heat and mass transfers, promoting hydrate dissociation. 3.4 Inhibitory effect of PVP on hydrate dissociation It has been reported that hydrates form slowly in KHI solutions and that these hydrates also dissociate more slowly than in water (Dragomir et al., 2011; Tang et al., 2018). These studies support the notion that for naturally formed methane hydrate-bearing sea floor sediments, the addition of KHIs to drilling fluids may also inhibit hydrate dissociation. It is well known that the addition of a small amount (0.12.0 wt%) of KHIs does not affect hydrate equilibrium conditions (Kelland, 2006; Kang et al., 2014), so hydrate dissociation kinetics were the focus here. PVP is the representative product of the first generation of KHIs, and the effects of PVP at
different concentrations on hydrate dissociation were tested. Figure 9 and Table 2 show the hydrate dissociation process in the presence of 0.1 wt%, 0.25 wt%, 0.5 wt%, 0.75 wt%, and 1.0 wt% PVP. The addition of a low concentration of PVP (0.1 wt%) showed clear a inhibitory effect on hydrate dissociation; the dissociation rate was reduced from 0.379 mol/h to 0.257 mol/h and the time required for complete hydrate dissociating increased from 6.1 h to 9.2 h. As the concentration of PVP was increased from 0.1 wt% to 1.0 wt%, the inhibitory effect increased; when the concentration was 1.0 wt%, the dissociation rate was 0.214 mol/h and the dissociation time was 10.9 h. The released gas curve at high concentrations fluctuated, however, which might have been caused by the heterogeneity of the hydrates formed and the uneven heat and mass transfers in the viscous polymer solution. In comparison with EG, PVP performed much better at inhibiting hydrate dissociation because 0.1 wt% PVP reduced the hydrate dissociation rate by 32.2%, while 10 wt% EG reduced the rate by 17.9%. As a typical KHI, PVP polymer molecules can adsorb onto the hydrate surface through hydrogen bonding. This forms a polymer film on the hydrate surface and fits the five-membered ring into the hydrate cage, hindering cavity completion and thus inhibiting hydrate growth (Kang et al., 2014). In the same way, during hydrate dissociation, PVP can be adsorbed onto the hydrate surface to form a film that can hinder the transfer of water and gas molecules from the hydrate bulk into the liquid phase, thereby slowing hydrate dissociation. In addition, as a type of high molecular weight polymer, the addition of PVP significantly increases the liquid viscosity (Table 2). High viscosity in turn increases the mass transfer resistance. Moreover, the addition of a small amount of PVP did not obviously influence the thermal conductivity of the solution, indicating that PVP does not inhibit hydrate dissociation by influencing heat transfer.
Fig. 9. Released methane amount in the presence of PVP at different concentrations. Table 2 Hydrate dissociation parameters and fluid properties in the presence of PVP. PVP concentration (wt%) 0 0.1 0.25 0.5 0.75 1.0
Dissociation rate (mol/h) 0.382, 0.4, 0.36, 0.343, 0.411 0.254, 0.25, 0.267 0.234, 0.253 0.213, 0.229 0.238, 0.204, 0.226 0.239, 0.212, 0.185, 0.22
Average Dissociation rate (mol/h) 0.379 0.257 0.243 0.221 0.223 0.214
Complete dissociation time (h) 6.2, 5.7, 6.3, 6.8, 5.6 9.3, 9.6, 8.7 10.1, 9.4 10.7, 10.0 9.6, 11.5, 10.2 9.8, 11.0, 12.4, 10.5
Average dissociation time (h) 6.1 9.2 9.8 10.4 10.4 10.9
Thermal conductivity (W·m-1·K-1) 0.572 0.573 0.566 0.568 0.568 0.569
Apparent viscosity (mPa·s) 1.0 1.5 2.0 2.5 3.5 5.0
3.5 Inhibitory effect of lecithin on hydrate dissociation Figure 10 and Table 3 show the hydrate dissociation process in the presence of 0.1 wt%, 0. 25 wt%, 0.5 wt%, 0.75 wt%, and 1.0 wt% lecithin. Overall, lecithin reduced the hydrate dissociation rate and prolonged the time required for hydrates to completely dissociate. Adding 0.1 wt% lecithin into deionized water reduced the dissociation rate from 0.379 mol/h to 0.297 mol/h and increased the dissociation time from 6.1 h to 7.7 h. The inhibitory effect was not, however, as strong as for PVP at similarly low concentrations. However, the inhibitory effect of lecithin was clearly enhanced by increasing the concentration; after the addition of 0.5 wt% lecithin, the complete dissociation time increased by 54% (from 6.1 h to 9.4 h) and the dissociation rate was reduced by 37.2% (from 0.379 mol/h to 0.238 mol/h). The inhibitory effect was strong; when the concentration was increased to 1.0 wt%, the hydrate
dissociation time increased to 10.4 h and the dissociation rate was reduced to 0.216 mol/h. Therefore, using lecithin can effectively inhibit hydrate dissociation when drilling through hydrate-bearing sediments. It should be noted that adding lecithin to water at a concentration greater than 0.5 wt% resulted in foaming when stirred, which is not favored during the preparation of drilling fluids.
Fig. 10. Released methane amount in the presence of lecithin at different concentrations. Table 3 Hydrate dissociation parameters and fluid properties in the presence of lecithin. Lecithin concentration (wt%) 0 0.1 0.25 0.5 0.75 1.0
Dissociation rate (mol/h) 0.382, 0.4, 0.36, 0.343, 0.411 0.27, 0.301, 0.32 0.282, 0.267 0.221, 0.235, 0.257 0.232, 0.202, 0.252 0.219, 0.192, 0.236
Average Dissociation rate (mol/h) 0.379 0.297 0.274 0.238 0.229 0.216
Complete dissociation time (h) 6.2, 5.7, 6.3, 6.8, 5.6 8.1, 7.6, 7.3 8.3, 8.7 10.0, 9.4, 8.9 9.7, 11.0, 8.8 10.2, 11.4, 9.6
Average dissociation time (h) 6.1 7.7 8.5 9.4 9.8 10.4
Thermal conductivity (W·m-1·K-1) 0.572 0.576 0.566 0.570 0.575 0.571
Apparent viscosity (mPa·s) 1.0 1.0 1.5 2.0 2.0 2.5
A study of hydrate formation in the presence of lecithin shows that lecithin does not influence the thermodynamic equilibrium conditions of methane hydrates (Chen et al., 2007). Therefore, the mechanism of inhibiting hydrate dissociation by lecithin should be analyzed from the perspective of its kinetic inhibitory effect. Table 3 shows that the addition of a small amount of lecithin did not measurably influence the fluid thermal conductivity, indicating that lecithin does not influence heat transfer. As the concentration of lecithin was increased, the
fluid viscosity increased gradually, increasing the mass transfer resistance. This effect was not as strong as for PVP, however. Molecular dynamic simulation showed that lecithin molecules adsorb onto the hydrate surface forming a net structure with nearby lecithin molecules, thus hindering the transfer of water and gas molecules from the dissociated hydrate surface to the liquid phase (Wang et al., 2017). The molecular structure of lecithin is shown in Fig. 11. It forms a multilayer vesicle structure in water when the concentration is greater than 4.69 × 10-4 mol/L and each layer is, in reality, a lipid bilayer (Liu et al., 2010). When a large amount of lecithin molecules are adsorbed onto the hydrate surface through hydrogen bonding, the multilayers may effectively hinder the transfer of gas and water molecules, thus inhibiting hydrate dissociation.
Fig. 11. Molecular structure of lecithin.
3.6 Performance evaluation of a water-based drilling fluid containing lecithin and PVP In order to meet the requirements of deepwater drilling which is a challenging, high-risk, high-reward operation, the drilling fluid has to maintain stable rheological and filtration properties, and should inhibit hydrate formation under low temperature and high pressure conditions in order to avoid downhole problems. When drilling through hydrate-bearing sediments, it is required that the drilling fluid can effectively inhibit hydrate dissociation. In this work, the water-based drilling fluid designed for deepwater drilling was selected for testing; its basic formulation is shown in Table 4. Table 4 Basic formulation of water-based drilling fluid for deepwater drilling. Component Bentonite FA367 PAC-LV
Concentration (wt%) 2.0 0.25 0.5
Function Filtrate reducer and viscosifier Viscosifer and encapsulator Filtrate reducer
SMP KCl NaCl
2.0 5.0 10.0
Filtrate reducer Shale inhibitor Hydrate inhibitor
3.6.1 Compatibility between PVP/ lecithin and deepwater drilling fluid Additives need to be compatible with the drilling fluids (Jin et al., 2017). Table 5 and Table 6 show the basic properties of the drilling fluid containing different concentrations of PVP and lecithin. Apparently, the addition of PVP (a high molecular weight polymer) has a significant influence on the rheological property of the drilling fluid at 2 °C. The gel strength (Gel), yield point, and viscosity of the drilling fluid substantially increased following the addition of 0.1 wt% PVP. Increasing the concentration of PVP led to an increase in rheological parameters; the rheological parameters of the drilling fluid were increased by two and three times when 0.5 wt% and 1.0 wt% PVP were added, respectively. Filtration loss was reduced as the concentration of PVP was increased as the polymer could increase the viscosity of the filtrate and thus help form the filter cake along the borehole walls. In deepwater drilling operations, high rheology of the drilling fluid is not favored because it can lead to high equivalent circulating density, causing severe lost circulation (Zhao et al., 2017). Therefore, considering both inhibitory effects on hydrate dissociation and influences on the drilling fluid rheology, 0.1 wt% PVP was selected as the optimal hydrate dissociation inhibitor for the deepwater drilling fluid to balance desired hydrate dissociation effects and engineering requirements. In comparison with PVP, lecithin is a type of surfactant and had a much smaller impact on the rheological properties of the drilling fluid. As the concentration of lecithin was increased from 0.1 wt% to 1.0 wt%, the rheological parameters of the drilling fluid slightly increased and the filtrate loss was also slightly reduced. The addition of 1.0 wt% lecithin increased the PV of the drilling fluid from 15 mPa·s to 22 mPa·s and increased the YP from 8 Pa to 9 Pa. Therefore, the addition of 0.11.0 wt% lecithin would not significantly impact the rheological
and filtration properties of the drilling fluid, although its foaming characteristics present a serious problem at higher concentrations. Considering the inhibitory effect on hydrate dissociation and compatibility with the drilling fluid, 0.5 wt% lecithin was selected as the optimal hydrate dissociation inhibitor. Table 5 Influence of PVP on the basic properties of the drilling fluid. Concentration (wt%) 0 0.1 0.25 0.5 0.75 1.0
AV (mPa·s) 23 32 41.5 58 61 72
PV (mPa·s) 15 22 28 36 37 46
YP (Pa) 8 10 13.5 22 24 26
Gel (Pa) 1.5/2.5 3/5 4/6.5 5/7.5 5/7.5 5.5/8.5
FLAPI (mL) 6.2 5.8 5.1 4.9 4.6 4.1
pH 9 9 9 9 9 9
Table 6 Influence of lecithin on the basic properties of the drilling fluid. Concentration (wt%) 0 0.1 0.25 0.5 0.75 1.0
AV (mPa·s) 23 23.5 26 27.5 28.5 31
PV (mPa·s) 15 15 18 19 20 22
YP (Pa) 8 8.5 8 8.5 8.5 9
Gel (Pa) 1.5/2.5 2/3.5 2/3.5 2/4 2/3.5 2.5/4
FLAPI (mL) 6.2 5.6 5.7 5.7 5.4 5.2
pH 9 9 9 9 9 9
3.6.2 Inhibitory effect of deepwater drilling fluid on hydrate dissociation The water-based drilling fluid typically used in deepwater drilling was tested to evaluate its hydrate inhibitory performance. The thermal conductivity of the drilling fluid was 0.577 W/(m·K) at 2 °C. In this study, 0.1 wt% PVP, 0.5 wt% lecithin, and their mixtures were added to the water-based drilling fluid to evaluate their effect on hydrate inhibition. The results are shown in Fig. 12 and Table 7. When only the typical deepwater drilling fluid was used in the experiment, 8.0 h was required for complete dissociation of hydrates in the drilling fluid, which occurred at a rate 0.310 mol/h. In comparison with hydrate dissociation in deionized water, the hydrates dissociated more slowly in the drilling fluid, although the drilling fluid contained NaCl and
KCl which are promoters of hydrate dissociation. This is due to the drilling fluid being a multicomponent system, and the additives in the drilling fluid can influence hydrate dissociation. The polymeric additives FA-367 and PAC-LV can significantly increase the viscosity of the drilling fluid, thus hindering mass transfer. At the same time, these additives may also directly interact with hydrates, such as by adsorbing onto the hydrate surface, thus inhibiting hydrate dissociation. Therefore, the inhibitory effect of the drilling fluid resulted from the combined action of these different components. In the drilling fluid containing 0.1 wt% PVP, the hydrates dissociated more slowly than in the absence of PVP, but the inhibitory effect was generally weak. In the drilling fluid containing 0.5 wt% lecithin, the hydrate dissociation rate was 0.171 mol/h and the time required for hydrates to completely dissociate was 13.2 h, indicating a strong inhibitory effect. When 0.1 wt% PVP and 0.5 wt% lecithin were used in combination as a hydrate dissociation inhibitor in the drilling fluid, the inhibitory performance was very strong; the hydrate dissociation rate was 0.154 mol/h, which was half that in the drilling fluid, and the time required for complete dissociation of the hydrates was up to 14.8 h. The hydrate dissociation rate was further reduced to 0.133 mol/h when a combination of 0.5 wt% PVP and 0.5 wt% lecithin was used, but the higher concentration of PVP may increase the viscosity of the drilling fluid. The hydrate dissociation temperature was also analyzed. As the water-based drilling fluid contained 10 wt% NaCl and 5 wt% KCl, the theoretical hydrate dissociation temperature was lower than 2 °C under the experimental pressure and without considering the effects of other additives. Therefore, the hydrates would begin dissociating immediately upon contact with the drilling fluid. However, water-based drilling fluids are multi-component systems composed of a mixture of water, solids, organic materials, and salts, and the temperature at which the hydrate dissociation rate started to sharply increase was used to investigate the effect of drilling fluids on hydrate dissociation. It was found that towards the
beginning of the dissociation process, hydrate started dissociating rapidly in the drilling fluid, and the dissociation temperature was 2.0 °C. The addition of 0.1 wt% PVP did not effectively increase dissociation temperature. In comparison, when 0.5 wt% lecithin was used, the hydrates did not dissociate rapidly until the temperature was increased to 3.7 °C. A combination of PVP and lecithin showed better inhibitory performance; in the presence of 0.1 wt% PVP and 0.5 wt% lecithin, the rapid hydrate dissociation temperature was 5.05 °C, and was further increased to 6.20 °C when 0.5 wt% PVP and 0.5 wt% lecithin were used. Therefore, a combination of PVP and lecithin can serve as a good hydrate dissociation inhibitor. Considering that EG is a THI, and that it also inhibits hydrate dissociation at a concentration below 10 wt%, NaCl was replaced by EG in the drilling fluid. The red curve in Fig. 12 shows that using this approach for deepwater drilling fluid can reduce the hydrate dissociation rate.
Fig. 12. Released methane amount during hydrate dissociation in drilling fluids. Table 7 Average hydrate dissociation rate and time in drilling fluids. Inhibitor
Dissociation temperature (°C)
None
2.00
0.1 wt% PVP
2.20
Dissociation rate (mol/h) 0.299, 0.336, 0.273, 0.331 0.252, 0.219, 0.204
Average Dissociation rate (mol/h)
Complete dissociation time (h)
Average dissociation time (h)
0.310
8.3, 7.3, 9.1, 7.4
8.0
0.225
9.4, 11.0, 11.6
10.7
0.5 wt% lecithin 0.1 wt% PVP and 0.5 wt% lecithin 0.5 wt% PVP and 0.5 wt% lecithin 10 wt% EG instead of 10 wt% NaCl
3.70 5.05 6.20 2.25
0.174, 0.18, 0.159 0.151, 0.143, 0.166 0.139, 0.126 0.243, 0.217, 0.212
0.171 0.154 0.133 0.224
13.4, 12.3, 13.8 15.0, 15.9, 13.5 16.1, 17.3 9.5, 11.0, 11.2
13.2 14.8 16.7 10.6
Based on the experimental results, when drilling through hydrate-bearing sediments, using a combination of 0.1 wt% PVP and 0.5 wt% lecithin can effectively inhibit hydrate dissociation and will not significantly impact the basic properties of the drilling fluid. The concentrations of PVP and lecithin can be further increased to meet requirements for greater inhibition of hydrate dissociation, but compatibilities need to be considered. In addition, the use of a low concentration of EG as a THI instead of NaCl can also be helpful.
4. Conclusions Hydrate dissociation experiments were conducted using different drilling fluid additives to select the hydrate dissociation inhibitor for drilling through hydrate-bearing sediments. As expected, THIs, NaCl, and KCl promoted hydrate dissociation. It was surprising, however, that as a THI, EG can slightly inhibit hydrate dissociation at concentrations below 10 wt%. This might be the result of several interacting factors such as the dissociation driving force, and mass and heat transfer features in the EG solution. At higher concentrations EG can promote hydrate dissociation. PVP can reduce the hydrate dissociation rate and delay the time required for hydrates to completely dissociate. A concentration of 0.1 wt% PVP showed a clear inhibitory effect. Lecithin also inhibited hydrate dissociation. The addition of 0.5 wt% lecithin increased the dissociation time by up to 54%. The adsorption of multilayer lecithin vesicles onto the hydrate is most likely the main inhibitory mechanism. Therefore, the addition of PVP and lecithin can help water-based drilling fluids to inhibit hydrate dissociation. A combination of 0.1 wt% PVP and 0.5 wt% lecithin is selected as an optimal hydrate dissociation inhibitor for drilling hydrate-bearing sediments when considering both inhibitory effect and compatibility with the drilling fluid. Using EG at concentrations below 10 wt% as a
THI instead of NaCl can also help inhibit hydrate dissociation. Considering that drilling fluids are multi-component systems, the effects of different components on hydrate dissociation need to be studied further to identify or develop better hydrate dissociation inhibitors.
Acknowledgments This work was supported by the National Natural Science Foundation of China (No. 51804331), the Shandong Provincial Natural Science Foundation (No. ZR2017BEE036), and the Fundamental Research Funds for the Central Universities (No. 18CX02032A).
Conflicts of Interest The authors declare no conflict of interest.
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Highlights (1) The inhibitory effect of drilling fluids on hydrate dissociation was studied. (2) An unexpected inhibitory effect occurred with EG at concentrations below 10 wt%. (3) PVP and lecithin could inhibit hydrate dissociation. (4) A combination of PVP and lecithin was selected as a hydrate dissociation inhibitor.