Numerical modeling for drilling fluid invasion into hydrate-bearing sediments and effects of permeability

Highlights

• A cylindrical numerical model was established to study the drilling fluid invasion.

• Water and gas generated from hydrate dissociation gradually migrate outward.

• The ‘secondary hydrate’ may form during the drilling fluid invasion process.

• High intrinsic permeability facilitates the drilling fluid invasion.

• Parameters of permeability models determine the reliable of simulated results.

Abstract

Drilling fluid invasion into hydrate-bearing sediments could induce hydrate dissociation and complicate heat and mass transfer around wellbore, and further affect mechanical strength of hydrate-bearing sediments and accurateness of wellbore logging interpretations. In this study, a cylindrical numerical model was established to study the characteristics of drilling fluid invasion into hydrate-bearing sediments and the effects of permeability on this process. The distributions of temperature, pressure, saturation, and salinity of pore water around wellbore at different time were obtained. The pressure and temperature around wellbore gradually increase, and the hydrate around wellbore dissociates with the high-temperature drilling fluid invasion. Meantime, water and gas generated from hydrate dissociation gradually migrate outward and then form ‘secondary hydrate’ in some areas outside wellbore. Dissociation and formation of hydrate can sharply change the salinity of pore water around wellbore. The drilling fluid invasion and hydrate dissociation ranges become larger when the intrinsic permeability is higher. The salinity in sediments decreases sharply while the dilution range is narrow when drilling fluid invasion into hydrate-bearing sediments with low permeability. In addition, the permeability decline exponent of the Masuda model has a significant influence on drilling fluid invasion. However, the Corey exponents of the relative permeability model only have a limited influence on drilling fluid invasion into hydrate-bearing sediments with low intrinsic permeability (e.g., 5.5 mD), while they have a noticeable influence on hydrate-bearing sediments with high intrinsic permeability (e.g., 75 mD).

Introduction

Clathrate hydrate typically forms when small ‘guest’ molecules, such as methane molecules or carbon dioxide molecules, contact water molecules under a suitable temperature and pressure condition (Sloan, 2003). In nature, the ‘guest’ molecules trapped by water cavities are mainly methane molecules, which are the main component of natural gas. Natural gas hydrate (NGH) has been discovered both in onshore and offshore environments all over the world (Sloan and Koh, 2007). Although estimates of the amount of natural gas contained in NGH are considerably different, many studies estimated that carbon mass contained in NGH is approximately 10¹⁶ kg (Pooladi-Darvish, 2004). Therefore, NGH has been considered as a potential source of natural gas for energy supply (Collett, 2002). Moreover, it has become a research focus to find effective technologies for extracting natural gas from NGH economically (Boswell, 2007).

The drilling technology is a necessary and useful method to identify target regions of NGH and exploit its hydrocarbon content (Jiang et al., 2011). However, because NGH is a kind of metastable minerals, a series of risks, including drilling operation disasters, marine geological disasters, and environmental disasters, may occur during the drilling process. Formation and dissociation of hydrate depend on pressure and temperature, salinity of reservoir water, and characteristics of porous medium in which hydrate is formed (Makogon, 2010). Increasing temperature or decreasing pressure can both induce hydrate dissociation. Besides, salt, as a thermodynamic inhibitor, can cause the phase equilibrium curve to shift toward destabilization, which enhances dissociation (Ning et al., 2013a). Dissociation of NGH in hydrate-bearing sediments could cause gas volume expansion, changes in pore pressure and formation strength, etc. (Kwon et al., 2013). Meanwhile, a large amount of natural gas generated from NGH dissociation inrushes into drilling fluid and then may form hydrate again under an appropriate temperature and pressure condition (McConnell et al., 2012). Formation of hydrate inside pipes and valves could impact the flow of drilling fluid and block pipes and blowout preventer stacks (Zhang et al., 2017a,). In order to avoid sharp hydrate dissociation during the drilling process, a practical way is to maintain wellbore pressure at a higher level than pore pressure (Ning et al., 2008), which would cause drilling fluid invasion into sediments. If drilling fluid temperature is higher than the hydrate equilibrium temperature under given salinity and pressure conditions of hydrate-bearing sediments, the temperature of sediments around wellbore will increase with drilling fluid invasion. Besides, in order to prevent hydrate formation in drilling fluid, water-based drilling fluid systems containing a specified concentration of salts are commonly used when drilling in NGH-bearing sediments (Jiang et al., 2011). Thus, drilling fluid with high temperature, heat generated from the friction, and thermodynamic inhibitors in drilling fluid jointly lead to hydrate dissociation around wellbore during the drilling fluid invasion process.

Sediment properties, such as permeability, pore pressure, and mechanical strength, will significantly change during the drilling fluid invasion process because drilling fluid invasion can lead to hydrate dissociation and formation. Hydrate dissociation and formation, coupled with high salinity drilling fluid invasion, will change the hydrate distribution patterns and the salinity of pore water in hydrate-bearing sediments, which could further affect the resistivity of hydrate-bearing sediments. The significant resistivity change caused by the drilling fluid invasion increases difficulties in the identification of hydrate zones, and even leads to erroneous results (Tian et al., 2010). Therefore, it is crucial to understand the dynamic process of drilling fluid invasion and evaluate its influence on NGH-bearing sediments, which is of great significance for predicting wellbore stability and improving the accurateness of well logging identification and evaluation.

The research of drilling fluid invasion mainly relies on mathematical models. Many scholars have developed mathematical models to investigate the drilling fluid invasion problems in conventional oil/gas formations (Bilardo et al., 1996; Chi et al., 2004; Windarto et al., 2012; Zhao et al., 2019). The changes in some parameters, such as drilling fluid invasion depth, salinity of pore water, and water saturation in sediments during the drilling fluid invasion process, were evaluated. These models mainly consist of the Darcy law and the law of mass conservation of oil-water two-phases or gas-oil two-phases flow. Some factors also were taken into account as well, such as mud cake thickness, flow rates of drilling fluid, and solid particle invasion. However, although the research on the mechanism of multiphase flow in sediments is relatively mature in these works, temperature change during the drilling fluid invasion process is not taken into account. Compared to the drilling fluid invasion process in conventional oil/gas formations, the drilling fluid invasion into hydrate-bearing sediments could cause more complicated heat and mass transfer accompanied by hydrate dissociation or formation.

At present, the effects of drilling fluid properties, such as drilling fluid temperature and pressure, on hydrate dissociation around wellbore have been researched through numerical models. Freij-Ayoub et al. (2007) investigated—by modeling five cases—the effects of drilling a wellbore in hydrate-bearing sediments and the impact of the drilling fluid temperature and density on changes in stresses and pore pressure within the surrounding sediments. Khabibullin et al. (2011) found the main parameters affecting hydrate dissociation are drilling fluid temperature and bottom hole pressure. Golmohammadi and Nakhaee (2015) built a cylindrical model to simulate hydrate dissociation during drilling through hydrate-bearing sediments. The effects of wellbore pressure and temperature on the moving velocity and location of dissociation front and rates of produced released gas were studied. Gao et al. (2017) simulated the temperature distributions of the wellbore and sediments when circulating the drilling fluid at different temperatures, flow rates, and so forth. The results show that the risks of hydrate dissociation increases as the drilling fluid temperature and flow rate increase. Yu et al. (2017) also found—by using a two-dimensional numerical model that considers the temperature distribution in the wellbore, the heat transfers from drilling fluid to hydrate-bearing sediments, the dynamics of hydrate dissociation, and gas-water two phases flow in hydrate-bearing sediments—that reducing the inlet temperature of drilling fluid could make the dissociated gas flow under control. Sun et al. (2018) analyzed the wellbore stability problem during the drilling process by coupling FLAC3D and TOUGH + HYDRATE. The results show that increasing the temperature and salinity of drilling fluid implies that more free gas will be generated near the wellbore. Zhang et al. (2018) considered the coupling effect of seepage of drilling fluid into hydrate-bearing sediments, heat conduction between drilling fluid and the sediments, hydrate dissociation, and transformation of the sediment framework. The influences of drilling fluid temperature, densities, and soaking time on the instability of hydrate-bearing sediments were calculated and analyzed via the numerical model. Recent research (Wei et al., 2019) provides some prevention strategies for drilling risks, based on sensitivity analyses of drilling parameters, including increasing the drilling fluid circulation rate, reducing the drilling fluid temperature, and increasing the drilling fluid density lower limit.

To our knowledge, only Ning et al., 2013a, Ning et al., 2013b researched the dynamic behaviors of the drilling fluid invasion into oceanic gas hydrate-bearing sediments. Effects of drilling fluid properties (including drilling fluid densities, drilling temperatures, drilling salinities) and geophysical properties of sediments (including intrinsic permeability, porosity, initial hydrate saturation) on the invasion of drilling fluid into hydrate-bearing sediments have been investigated with the aid of numerical simulator TOUGH + HYDRATE. Besides, Chen et al. (2019) experimentally simulated the hydrate-bearing sediments with drilling fluid invasion under different wellbore pressures. The results show that a higher wellbore pressure can promote the drilling fluid invasion, but its effect is limited by the distance from the wellbore.

Although several researchers have studied the interactions between the wellbore and hydrate-bearing sediments, most of these works relate to the research of hydrate exploitation and hydrate drilling risks. The drilling fluid invasion process in hydrate-bearing sediments is affected by not only heat and mass transfer mechanism in porous medium, but also hydrate phase transition, which can change the structures and permeability of sediments, making the drilling fluid invasion problem becomes more complex to predict (Ning et al., 2012). Compared with existing numerical models of hydrate exploitation, numerical models of drilling fluid invasion have some specific features, including that the influence range is small, that the duration is short, and that the fluid flow has an opposite direction to fluid flow directions of natural gas production. Processes and mechanisms of phase change, multiphase flow, and heat transfer in hydrate-bearing sediments during the drilling fluid invasion process are still unclear. According to previous results, geophysical properties of hydrate-bearing sediments significantly affect the drilling fluid invasion into hydrate-bearing sediments, especially permeability (Ning et al., 2013a). The permeability of sediments could significantly influence the dynamic processes of drilling fluid invasion into conventional oil/gas formations (Chi et al., 2004; Salazar and Torres-Verdín, 2008). However, at present, there is limited research that focuses on the effects of permeability on the drilling fluid invasion into hydrate-bearing sediments. Permeability is one of the fundamental geophysical properties of hydrate-bearing sediments and is also one of the critical parameters of multiphase flow in porous media (Moridis, 2002). Particle sizes, pore distributions, and particle specific surface all have a significant influence on the permeability of hydrate-bearing sediments (Li et al., 2017). Therefore, the permeability varies significantly in different hydrate-bearing sediments. For example, it is estimated that the permeability of the Messoyakha gas field located in Siberian permafrost ranges from 10 to 1000 mD (Graver et al., 2008). While in ocean areas, many hydrate-bearing sediments have relatively low intrinsic permeability. For example, the permeability of hydrate-bearing sediments in the Shenhu area in the South China Sea is usually lower than 10 mD (Li et al., 2018). On the other hand, research on permeability models (the absolute permeability model and relative permeability model) of hydrate-bearing sediments is still immature. Therefore, there are several uncertain parameters of permeability models involved in numerical models. In this study, a numerical model in cylindrical coordinates was established to investigate the dynamic behaviors of the drilling fluid invasion into hydrate-bearing sediments, and effects of permeability and its models on the drilling fluid invasion process were also analyzed. The results of this study can help in guiding drilling and have great significance for understanding the problem of drilling fluid invasion into hydrate-bearing sediments.