Elsevier

Ocean Engineering

Volume 122, 1 August 2016, Pages 105-117
Ocean Engineering

A numerical study on water wetting associated with the internal corrosion of oil pipelines

https://doi.org/10.1016/j.oceaneng.2016.06.022Get rights and content

Highlights

  • A refined CFD model is employed to predict the type of wetting in flowlines with reasonable accuracy.

  • As the diameter of pipe increases the probability of water wetting and corrosion risk increases.

  • As the viscosity of oil increases the likelihood of water wetting and corrosion risk decreases.

  • A decrease in oil-water interfacial tension results in a decrease in corrosion risk.

  • The higher the density of oil the less the likelihood of water wetting and corrosion.

Abstract

Long distance pipelines are considered as the vein of the oil and gas industry on land and offshore. A well often produces water along with crude oil. The presence of water as well as dissolved gases such as CO2 and H2S introduces a serious menace of internal corrosion. It is well known that the distribution of water and oil inside the pipeline has a great influence on the corrosion rate. As a matter of fact, internal corrosion occurs when a free layer of water comes in contact with the pipe. Hence, predicting the distribution of water inside the pipe and identifying the continuous phase that directly wet the wall is of foremost importance when dealing with internal corrosion of oil pipelines. The accurate prediction of the distribution of water significantly increases the accuracy of corrosion prediction as well as the confidence regarding the integrity of the pipelines. In spite of all the great efforts toward studying different influential factors associated with the internal corrosion of steel pipelines, a large gap of knowledge is observed in predicting the water wetting. The objective of the present study is to employ a tuned two-fluid model by taking advantage of computational fluid dynamics, that is capable of predicting the distribution of water and the type of wetting (water wetting/oil wetting) at the bottom of the pipe. Furthermore, the effect of different parameters such as pipe diameter, oil density, oil viscosity and interfacial tension on the transition from water wetting to oil wetting is studied.

Introduction

The transmission of multi-phase flows from a well to a main platform or onshore processing units is a major concern for offshore developments. An efficient design, considering the known influential factors, could significantly reduce the capital and operational costs. Crude oil is often transmitted simultaneously with water. In the early stages of a well's lifetime the amount of formation water might be negligible. However, mature wells usually produce significant amount of water. Furthermore, water injection is often used in enhanced oil recovery process.

The internal structure of oil-water interface, known as flow pattern, critically depends on the fluid and flow characteristics as well as the geometry of the pipe. Generally, two phase oil-water flows in horizontal pipes are classified into two major groups and several sub groups. At relatively low velocities the gravitational force is dominant which tends to separate oil and water with a clearly defined interface. This flow pattern is sometimes called stratified flow. However, as the velocity of flow increases the turbulence increases, which in turn, tends to mix two phases. As a result, a dispersed region is observed between two phases. By further increase of flow velocity one of the phases will totally lose its continuity and become dispersed in the continuum of another phase. This flow regime is referred to as dispersed flow (Angeli and Hewitt, 2000a, Xu, 2007).

Apart from the fluid and flow characteristics, the volume fraction of water (water cut) is an important factor that determines the type of flow pattern. At high velocities where we expect to see a dispersed flow, the water cut is a controlling factor that specifies the continuous phase. For a given oil-water flow there is a critical water cut beyond which the water will become the continuous phase. This critical point is often called phase inversion (Angeli and Hewitt, 2000a, Xu, 2007, Lovick and Angeli, 2004a, Kumara et al., 2009, Yusuf et al., 2012).

The distribution of water in oil-water flow has a significant effect on the corrosion rate which is an important factor in offshore field development. The presence of water as well as dissolved gases such as CO2 and H2S introduces a serious hazard of internal corrosion. Any contact of a continuous layer of this corrosive water with the pipe (water wetting) can potentially result in an internal corrosion. While a direct contact of oil with pipe will not cause corrosion. Hence, when dealing with internal corrosion of pipelines, it is essential to predict whether the water phase is continuous or totally dispersed in a continuous oil phase. An accurate prediction of the distribution of water significantly increases the accuracy of corrosion prediction as well as the confidence regarding the integrity of the pipelines. Whereas, an incorrect prediction of water distribution leads to significant mistakes in predicting the corrosion rate. Moreover, selecting an appropriate type of inhibitor and estimating the required amount of inhibitor and corrosion resistant materials require a prior knowledge of water distribution inside the pipe (Nyborg, 2005; Nesic, 2007; Cai et al., 2012; IIman and Kusmono, 2014; Mohd et al., 2015; Papavinasam et al., 2010).

Corrosion accounts for over 25% of failures experienced in oil and gas industry. Among different kinds of corrosion, sweet corrosion (CO2 corrosion) is the most frequent one (Kermani and Harrop, 1996). During the past decades many works have been focused on studying different factors affecting the sweet corrosion rate (Nesic, 2007, Bockris et al., 1961, Gray et al., 1989a, Gray et al., 1989b, Nesic et al., 2003, Nordsveen et al., 2003, Wang et al., 2004, De Waard et al., 1995). Moreover, different models have been proposed to estimate the corrosion rate (De Waard and Lotz, 1993, Nesic et al., 1995, Mohd and Paik, 2013, Norsok, NORSOK Standard M-506, 2005). However, in spite of all the advances, predicting corrosion rate and controlling or mitigating its hazardous effects is still a challenging task. Past studies as well as real field experiences revealed that predicting the internal flow behavior is essential not only for developing a reliable predictive corrosion model but also for eliminating or diminishing the hazardous effects of internal corrosion (Nyborg, 2005, SP0208, N.A.C.E, 2008, Nesic, 2012, Wang and Zhang, 2015).

Due to the higher density of water compared to the oil, the probability of water wetting at the bottom of steel pipe is the highest. Sweet corrosion rate in oil-water flow is dependent on the wetted area by corrosive water. Hence, predicting the onset of oil/water wetting as well as water wetted area is crucial. Furthermore, in case of water wetting, the characteristics of free water layer such as its height, velocity and shear stress with wall are some of the key factors that influence the mass transfer between the pipe and the bulk flow (corrosion rate) (Nesic, 2007, Nesic et al., 2005).

Thus far, few researchers tried to develop models for predicting the onset of oil/water wetting. Wicks and Fraser (1975) stated that as the flow velocity increases more water drop entrainments is observed and there is a critical velocity beyond which all the water phase become dispersed in the oil. They concluded that the critical velocity depends on the pipe diameter. Smith (1987) proposed a simple rule for predicting transition from water wetting to oil wetting condition. Based on the measured corrosion rate of field data they suggested that for water cuts up to 20% and velocities higher than 1 m/s oil wetting will be observed at the bottom of pipe. However, the proposed rule of thumb cannot be applied for different conditions other than the operating condition of the used field data. Adams et al. (1993) also suggested a simple rule for estimating the phase wetting at the bottom of pipe. According to their model for water cuts less than 30% oil wetting is expected. While for water cuts between 30% and 50% oil and water may wet the wall alternatively. For water cuts higher than 50% water wetting is observed irrespective of the pipe diameter, oil property, velocity, etc. However, field experiences contradict these simple rules. The corrosion may occur at water cuts as low as 1% or may be negligible for water cuts as high as 50%. As a matter of fact, the transition water cut for oil wetting depends on many factors and such simple rules cannot predict the transition points quantitatively (Craig, 1998, Li, 2009). De Waard et al. (2001) implemented an empirical water wetting correction to their original corrosion model. The model is based on the API of the oil. However, the model does not take into account the effects of pipe diameter, the viscosity of oil, surface tension, etc. Several other models have been proposed to determine the minimum flow velocity required for transition to oil wetting. However, none of them consider all the influential parameters such as different oil properties, pipe geometry, surface wettabality and water cut. A brief description of these models can be found in (SP0208, N.A.C.E, 2008).

Wang et al. (2014) experimentally suggested that the corrosion in oil-brine mixtures can be significantly retarded by forming a stable water in oil emulsion. This finding emphasizes the importance of predicting the onset of water in oil dispersion.

Apart from these, a great deal of effort was gone to establish mechanistic models for predicting the transition point between water wetting and oil wetting (Cai et al., 2004, Li et al., 2006, Tang et al., 2007, Kee et al., 2014, Nesic et al., 2005). Based on the theoretical works of Hinz (1955) and Brauner (2001), a mechanistic model was proposed for predicting the transition between stratified and dispersed flow (water wetting and oil wetting). A comprehensive comparison of the model with experimental data obtained by various techniques showed a great advance in predicting phase wetting in a quantitative manner. The extensive experimental studies indicated that full water wetting is only observed when a free water layer with 100% water fraction flows at the bottom of pipe. Furthermore, it was observed that fully oil wetting is pragmatic when the volume fraction of dispersed water at the bottom of pipe is not higher than 40%. While, for water volume fractions between 40% and 99% at the bottom of pipe an intermittent wetting was observed in which water and oil may alternatively wet the pipe. The experimental results also revealed that the corrosion rate for intermittent wetting is significantly lower than that in water wetting regime. However, it cannot be neglected like fully oil wetting (Cai et al., 2012, Kee et al., 2016). This mechanistic model has been included in MULTICORP corrosion prediction model. Recently, another mechanistic model has been proposed by (Torres et al., 2016).

A survey of corrosion prediction models that are widely being used in industry indicates that many of them do not take any effect of oil/water wetting into account. Among them NORSOK M-506, Cassandra developed by BP, KSC, Tulsa model and Oli model are notable. While few of them such as Hydrocor developed at Shell and Corplus developed at Total use simple oil wetting models. Furthermore, few corrosion models have been coupled with multiphase flow predictive tools such as OLGA. An overview of water wetting transition models in different corrosion models can be found in (Nyborg, 2010).

Aforementioned background clearly reveals the importance of modeling two-phase oil water flow. In order to enhance the confidence in corrosion prediction more advanced multiphase models need to be adopted along with the corrosion models. Due to the complex nature of oil-water flow all the influential factors affecting the phase distributions inside the pipes should be taken into account and neglecting any of them may result in remarkable mistakes. Hence, using advanced computational fluid dynamics (CFD) models is essential for predicting the main features of two-phase oil-water flows. A proper setting of a CFD model can provide phase distributions and velocity profiles with high resolutions that significantly reduces the uncertainties in corrosion modeling.

In spite of the importance of predicting flow patterns in oil-water flows, numerical studies on this topic have been reported considerably less. Thus far, few researchers tried to model different flow patterns of oil-water flows. Gao et al. (2003) and Al-Yaari, Abu-Sharkh (2011) used volume of fluid (VOF) model for modeling the stratified flows. Walvekar et al. (2009), Monzon (2006), Parvini et al. (2010), Hamad et al. (2013) and Pouraria et al. (2013) employed Eulerian–Eulerian approach for modeling dispersed oil-water flows. Furthermore, the application of Eulerian-Lagrangian approach for modeling dispersed oil-water flow was reported by Burlutsky, Turangan (2015). Pouraria et al. (2016) used Eulerian–Eulerian model for predicting different flow patterns in horizontal oil-water flow.

An Eulerian–Eulerian approach is capable of modeling both dispersed and stratified flows. Hence, it can be used for predicting all the flow patterns provided the appropriate closure models regarding the interfacial forces are implemented in the CFD code. These models have been successfully utilized for simulating different flow patterns of gas-liquid and liquid-liquid flows (Yao et al., 2004, Prosperetti and Tryggvason, 2007, Bestion, 2014, Sathe et al., 2010, Yamoah et al., 2015, Pouraria et al., 2016).

The objective of the present study is to use an Eulerian–Eulerian CFD model for predicting the type of wetting inside a horizontal pipeline transmitting two-phase oil-water flow. The main focus of the present study lays on low water cuts, below phase inversion point, where the water may be dispersed or continuous. The capability of the model in predicting the type of flow patterns as well as predicting the onset of oil/water wetting is examined by making a comparison with experimental data. Furthermore, the effect of different parameters such as pipe diameter, oil density, oil viscosity and interfacial tension on the transition from water wetting to oil wetting is studied.

Section snippets

Governing equations

Numerical simulations were carried out using the two-fluid Eulerian–Eulerian model. This modeling is based on ensemble-averaged mass and momentum equations for each phase (Ishi, 1975, Lahey and Drew, 2001). The momentum and continuity equations are solved for both phases that share the same pressure field. In order to couple two phases appropriate closure laws corresponding for interfacial forces should be provided.

For an incompressible flow without mass transfer between phases, the continuity

Geometry and boundary conditions

In order to verify the accuracy of the CFD model a comprehensive comparison with experimental data is essential. Hence, numerical simulations were first carried out for flow conditions and geometry configurations with available experimental data. Table 1 shows a brief description of the geometry of pipe and fluid properties that were used in the experiment (Elseth, 2001). Numerical simulations were performed for a horizontal pipe with internal diameter and lengths of 0.056 m and 15 m,

Results and discussions

Numerical simulations were first performed for oil-water flows in a horizontal pipe with the internal diameter of 0.056 cm. Fig. 2, Fig. 3, Fig. 4, Fig. 5, Fig. 6, Fig. 7 show the distributions of water volume fraction across the pipe cross section as obtained by the CFD model and the experimental data reported by (Elseth, 2001). Fig. 2, Fig. 3, Fig. 4 show the water distribution for input water cut of 0.1 and for three different velocities. As seen in Fig. 2(a), at low velocity of 1 m/s a free

Conclusions

Numerical simulation of two-phase oil-water flow was carried out by taking advantage of the Eulerian–Eulerian approach. The standard k-ε model was adopted to account for the turbulence effects. The accuracy of the results was examined by making a comparison with available experimental data.

According to the present numerical results the multi-phase CFD model could predict the characteristics of oil-water flow and the types of wetting with reasonable accuracy. The numerical model was used to

Acknowledgments

This research was undertaken at the Lloyd's Register Foundation Research Centre of Excellence at Pusan National University. Lloyd's Register Foundation (LRF), a UK registered charity and sole shareholder of Lloyd's Register Group Ltd, invests in science, engineering and technology for public benefit, worldwide.

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