Characterized as the reversal flow of liquid film into the wellbore, liquid loading is a genuine issue for gas wells as it diminishes the gas production rate. In the event that fluid rate accumulating in the wellbore is excessively high, the gas production rate will decrease fundamentally and for severe instances of accumulation, the operating organization will relinquish the well which will cause immense budgetary misfortunes. Subsequently, so as to maintain a strategic distance from the latter occurring, it is proper for the working organization to anticipate and recognize the liquid loading status of the gas wells in order to utilize viable apparatuses and pathways to avert it. Therefore, to counteract those misfortunes, the forecast of the liquid reversal point is obligatory.

Several researchers studied and established models to predict the loading phenomenon. After thoroughly review those studies, conclusions made on the different models are controversy and their results are conservatives. This paper presents a model where the hypothesis relies on fluid film reversal. The model considers the change from annular flow (fluid film encompassing the gas core) to slug or churn flow to be the grounds of liquid film backflow. Subsequently, from the review of previous literature on vertical wells, it is obvious that the film thickness is more sensitive to the tubing inner diameter, the tubing pressure gradient, the changes of fluid properties, the film and gas gravitational forces. Therefore, it is more rational for the critical gas flow rate to be dependent on those parameters. Subsequently, the momentum balances of both the liquid and gas phase were developed, and a derivation of an expression of the gas void fraction leading to the derivation of the dimensionless liquid film thickness and thus the critical film thickness were obtained. As a result of this modeling, a simplistic practical critical gas velocity and critical gas flow rate correlation which at the same time combines and incorporates the parameters influencing the loading phenomenon are viable for any profundity of the well.

So as to assess the adequacy of this model, evaluation has been performed between the model and some well-known model such as Turner et al. (1969) model, Li et al. (2001) model, Belfroid et al. (2008) model and Liu et al. (2018) model on some of the vertical gas wells of the North-West Xinjiang gas field. The outcome of this evaluation provides an overall 95% prediction and identification precision, outclassing the models quoted above. Thus, the model is the most appropriate to classify and foresee liquid backflow and accumulation in gas wells.

ABSTRACT

The growth characteristics of hydrate film and bubble hydrodynamic behaviors are experimentally studied. An integrated hydrodynamic model of hydrated bubble is developed, considering the interaction of multiple factors. Based on experimental data, methane hydrate film thickness is estimated, and new empirical correlations of bubble deformation ratio and drag coefficient are presented. Using the model, we predict the safe operation cycle for a well in South China Sea. The results indicate that hydrate formation significantly prolongs the safe cycle; however, once hydrate-coated bubbles arrive at the wellhead, hydrate blockage risk will increase, which can provide references for future well-opening operations.

INTRODUCTION

Frequent typhoons in South China Sea pose a serious threat to the offshore drilling safety, thus the urgent measures of offshore platform evacuation to avoid the typhoon must be taken in advance. With the gradual shift of offshore oil and gas exploitation to deep water and ultra-deep water, the temperature of drilling fluid near the mud line is close to sea water temperature, and this low-temperature high-pressure environment is in favor of hydrate formation. During the shut-in period in avoiding the typhoon, although the bottom hole pressure is greater than the formation pressure, the gas in the formation would also invade the wellbore by diffusion and displacement, the gas hydrate will be formed near the subsea wellhead. Hydrate formation significantly influences the ascending migration of gas bubbles and even cause the hydrate blockage risk to the blowout preventer or wellbore. Therefore, understanding the dynamic coupling mechanism of hydrate behaviors and bubble hydrodynamics plays an important role in the accurate prediction of the safe operation cycle.

Under the hydrate stability thermodynamic conditions, hydrate crystals are preferentially formed at the gas-liquid interface and propagates rapidly along the bubble surface, thereby agglomerating into the porous hydrate film with a certain thickness. Correspondingly, the pattern of hydrate growth is also transformed from lateral development controlled by heat transfer to thickening growth limited by mass transfer. However, due to the fact that the growth rate of the former is significantly higher than that of the latter (Tanaka et al., 2009; Liu et al., 2018), hydrate film lateral growth dominates in the rising progress of hydrated bubbles. Moreover, many researchers have experimentally and theoretically studied the ascending movement of gas bubbles without hydrate formation. The results indicate that bubble hydrodynamic behaviors are influenced by multiple factors, involving physical properties of the fluids, the fluid turbulence, bubble geometric shape and so on (Batchelor et al., 1967; Davies et al., 1950; Wallis et al., 1974; Rodrigue et al., 1996; Tomiyama et al., 1998; Tomiyama et al., 2002). As for hydrate-covered bubbles, the data reported in the literatures are relatively few and cannot fully reflect the change rule of rising velocity for full-scale bubbles. Bigalke et al. (2010) measured the rising velocity of methane hydrated bubbles with the bubble size of 0.75∼2 mm in the pressure range of 6∼40 MPa; Sato et al. (2013) investigated the ascending trajectory and surface deformation of hydrated bubbles (3.8∼7.8 mm) in a quiescent water bath. Due to the hydrate density close to that of water, the influence of the gravity of hydrated bubble cannot be neglected (Rehder et al., 2009; Bigalke et al., 2008). Simultaneously, the rigid hydrate shell would also change the mobility of bubble surface, thereby interfering with the moving resistance.

ABSTRACT

The present work investigate the effect of droplets entrainment on critical gas velocity, using the liquid film reversal model from Barnea (1986), Luo et al. (2014) and Shekhar et al. (2017). Especial attention was given to the onset of liquid loading in gas well. Experimental and field data were considered for model evaluation. Field data were taken from published data (Turner et al., 1969, Belfroid et al., 2008 and Veeken et al., 2010). Experiments were performed at the multiphase laboratory (EPT-NTNU) in an upward inclinable pipe. The test section was 6 m long and 60 mm ID. Inclination angles varied from 30 ͦ to 70 ͦ from horizontal. The fluids used were air and water. Measurements included fluid velocities and reversal point. High-speed video cameras were used to record the flow regime transition (slug to annular) present in the system. Prediction using the film reversal models revealed that the model over-estimate the critical gas velocity compared to results where entrainment is neglected.

1 INTRODUCTION

Most gas wells produce liquid as co-produced fluid during well production. Liquid flows along with the gas core as droplets or liquid film on the tubing wall. At the beginning of the production, the gas rate is sufficient to carry all the produced fluid to the surface. However, the declining on the reservoir pressure, the gas production rate decreases until the current gas velocity is insufficient to lift the liquid to the surface. Once this condition is establish, fraction of the liquid starts to flow counter-current to the gas core and accumulates at the bottom of the well, creating a static column of liquid. This accumulation causes backpressure against the formation, which affect the production capacity of the well, making the well produce at unstable flow condition. If the well keep producing at unstable condition, it may lead to a premature abandonment of the well or in some case to wrong well test calculations due to slugging or churning of the liquid.

ABSTRACT

We consider the apparent roughness and increased pressure drop associated with the presence of a thin liquid film between the gas and the pipe wall in two- and three-phase stratified-annular gas-liquid flow. The main objective is to improve the pressure drop predictions for near-horizontal gas-condensate flows with low liquid loading and high gas flow rate. To support the model development, SINTEF conducted experiments in 8- and 12-inch 2.5-degree upward-inclined pipes at the Tiller test facility in Norway. A model for the film roughness developed in a previous study was generalized to account for the effect of gravity, which limits the film thickness for lower gas rates. Oil droplets are more effectively transported by the turbulence in the gas, so the liquid film on the pipe wall tends to have a lower aqueous fraction than the liquid layer in the bottom of the pipe. In the general case, the model covers all stages from a pure stratified flow at low gas rates to stratified annular flow for intermediate gas rates to (in the case of low liquid loading) pure annular flow at high rates. Model predictions are in good agreement with the SINTEF data.

1 INTRODUCTION

Annular stratified flow often occurs in pipeline transport of gas-condensate fluids at high rates. The key difference between pure stratified flow and annular stratified flow is that the latter includes a thin film of liquid between the gas and the pipe wall, which is held in place by the turbulent fluctuations. The thin film can become very rough, significantly increasing the frictional contribution to the pressure gradient; this is particularly significant for flows with low liquid loading, where other contributions to the pressure gradient are relatively small.

ABSTRACT

In this paper we present a detailed analysis of large scale experimental data from the SINTEF Multiphase Laboratory on high-rate low liquid loading flows. The experimental work [1] was funded by Equinor as part of the Tanzania gas field development project [2] [3] [4], and SINTEF was granted access to use the data for improving the accuracy of the pressure drop predictions in LedaFlow. The experimental results showed that a key element for predicting high-rate low liquid loading flows accurately is to account for the droplets that deposit on the walls in the gas zone, creating a wall film. This wall film can have a profound effect on the hydraulic roughness experienced by the gas, and subsequently the frictional pressure drop. Furthermore, the data showed that this effect was particularly important for high liquid viscosities and in three-phase flows, and simulations showed that LedaFlow had a clear tendency to under-predict the pressure drop in such scenarios. To improve this situation, we used the data to derive a model for predicting this complex phenomenon. This paper summarizes the main parts of the data analysis and the development of the wall film model. We show that by introducing this new model into LedaFlow, we were able to significantly improve the agreement with the measurements.

1 INTRODUCTION

Low liquid loading generally refers to flow conditions where the superficial liquid velocity is small compared to the superficial gas velocity. This is a typical scenario for wet gas lines, where the reservoir produces mostly gas, but where changes in the pressure and temperature along the pipe causes condensation of water and hydrocarbons, so that the liquid rate increases with the distance from the well.

ABSTRACT

The corrosion inhibition mechanism of a new yellow metal corrosion inhibitor was studied using multiple characterization techniques including ellipsometry, white light interferometry (WLI), grazing incidence reflection absorption Fourier transform infrared (GIRA-FTIR) spectroscopy, X-ray photoelectron spectroscopy (XPS), electrochemical impedance spectroscopy (EIS) and high-performance liquid chromatography (HPLC). Compared to traditional azole molecules, the novel yellow metal corrosion inhibitor develops a stimuli-responsive film, which would reduce the impact of high levels of halogen on the corrosion of copper and copper alloy surfaces. A tentative structural model describing the improved halogen resistance of copper and copper alloy in the novel yellow metal corrosion inhibitor solution is proposed.

INTRODUCTION

Based on appearance, copper and its alloys (brass, Cu:Ni alloy) are usually called yellow metals. Yellow metals have very good heat transfer efficiency and antimicrobial properties, so they are often chosen as materials for heat exchanger tubes, reactor joints, coolant tubes etc. However, they suffer from corrosion in cooling water in the presence of oxidizing biocides (e.g. bleach and bromine) used to control biofouling. Corrosion is the process that oxidize elemental metal and release metal ion to solution and cause metal oxide deposit on metal surface. There are two types of corrosion, general corrosion and localized corrosion. General corrosion describes the uniform oxidization of metal on surface, and the corrosion products (e.g. iron oxides) built-up on surface can result in loss of heat transfer efficiency and possibly failure of heat exchangers. Localized corrosion refers to accelerated corrosion in specific areas, such as joints, defects, deposits, or area with microbial film. Aggravate localized corrosion (e.g. pitting) can cause leaks in heat exchanger tubes, operational hazards, and shut down of the production process.

To control corrosion, yellow metal heat exchangers in cooling water systems are often treated with filming corrosion inhibitors. The commodity triazole based corrosion inhibitors, such as Tolytriazole (TT) and Benzotriazole (BZT) are most used filming corrosion inhibitors for yellow metals. It inhibits corrosion by chemically adsorbing onto the surface of yellow metals through bonding with copper and forming an inhibitor film that protects metal from corrosion. However, the film formed by triazoles is often broken down by halogen-based biocides (e.g. free chlorine) in cooling systems. In the bulk water, triazoles can also react with halogen-containing biocides and consequently lose its corrosion inhibition capacity. The reaction mechanism of triazole with halogen-based biocides is that halogen-containing biocide (e.g. free chlorine) reacts with the N-H bond on the triazole ring and forms N-Chloro derivative, which is highly unstable intermediate that readily degrades to other small ineffective molecules. Therefore, the inhibition efficacy of triazole is significantly reduced in the presence of halogen-containing biocide due to consumption of triazole in bulk water and rupture of film on metal surface.^1-4

Understanding the effect of injected water salinity is becoming crucial, as it has been shown to have a strong impact on the efficiency of oil recovery process. Various experiments have concluded that carbonate wettability is altered when the water ionic-composition is changed. In this work, a numerical investigation of an oil blob mobilized by water is conducted inside a single pore. The presented model studies the synergy effect of multiphase flow and water salinity at the pore level.

To model the multiphase flow at the pore-scale, the full hydrodynamic Navier-Stokes equations are solved using direct numerical simulation (DNS). The effect of brine ionic-composition is examined through the electric double layer effect. Experimental zeta potential values, published in the literature, of crude oil/water and water/carbonate interfaces have been employed in the model, which capture the water salinity effect.

The simulation results show that the water wetting film surrounding the oil-droplet collapses to an adsorbed nanometer water layer when high salinity water is used. As a result, a large pressure gradient is required to mobilize the oil inside the pore and overcome the attractive surface forces between the oil/water and water/carbonate interfaces. For low-salinity injected water, the carbonate surface becomes more water-wet. The wetting film surrounding the oil blob becomes stable due to the repulsive electric double layer force. Therefore, less energy is required to mobilize the oil blob inside the pore compared to high water salinity. The effect of solid roughness and injected water flow rate are also studied, which show to have a strong impact on the oil displacement efficiency.

The novelty of the numerical method lies in efficiently capturing the nanoscale effect of the electric double layer in pore-scale multiphase flow at the microscale. The simulation results provide fundamental insights on the efficiency of low-salinity waterflooding at the pore level.

Double layer Expansion (DLE) is proposed as one of the mechanisms responsible for Improved Oil Recovery (IOR) during Low Salinity Water Flooding (LSWF). This expansion is triggered by the overlap between the diffuse double layers. We performed molecular simulation to study this phenomenon where both kaolinite and montmorillonite are used as substrates contacting water with varying concentration of monovalent and divalent ions. Our results, and several molecular simulations, have confirmed that the location of the adsorption planes is independent of the ionic strength. However, the potential developed on these surfaces and how it decays depends on both the ionic strength and ion nature. A shrinkage is observed in the double layer for the case of low salinity, supported by both film thickness estimations and interaction energy analysis. This shrinkage, which contradicts the prevailing assumption, is consistent with molecular simulation studies, and casts some doubts on the efficiency of DLE as a mechanism for explaining IOR observed during LSWF. This brings into question the role of double layer expansion in enhancing oil recovery, and raises the need to investigate other mechanisms that could be responsible for the experimental and field observations made in this area.

ABSTRACT

Internal corrosion can occur in the natural gas transmission pipelines when aqueous electrolytes are present. The presence of water results from the condensation of wet gas or liquid water from upstream plant upsets. Dissolved contaminants such as salts, CO₂, and H₂S make the electrolyte more corrosive. The ability to monitor internal corrosion in natural gas transmission pipelines before it occurs could have a significant impact on preventing methane leaks as well as catastrophic events resulting from corrosion. A recent concept for early corrosion on-set detection involves the use of proxy materials integrated with the optical fiber sensor platform that corrode at a rate which provides insight into the conditions for which pipeline corrosion is expected to occur. Successful realization of this class of sensors requires a detailed understanding of the corrosion behavior of relevant thin film systems. In support of this goal, Fe thin film of different thicknesses (25, 50, 100 nm) on quartz substrates were tested in CO₂ saturated 3.5%wt. NaCl solutions at 30 °C. The effects of CO₂ and thickness on the corrosion of Fe thin films were studied using optical transmission technique and in situ electrochemical method. The increase in light transmission corresponded to the corrosion of Fe thin films. CO₂ accelerated the corrosion of Fe thin films due to the lower pH and promoted corrosion reactions, resulting in a faster increase of light transmission over time than without CO₂. While the corrosion rate (CR) increased with the film thickness, the CR of Fe thin films were of the same order of magnitude with the API 5L X65 bulk pipeline material, verifying that Fe thin films can serve as a corrosion proxy when integrated with the optical fiber based sensing platform.

INTRODUCTION

Internal corrosion can occur in the natural gas transmission pipelines when aqueous electrolytes are present. Inside the pipelines, electrochemical corrosion takes place in the water phase condensed from wet gas or liquid water from upstream plant upsets. The inherently existing corrosive gases such as CO₂ and H₂S could dissolve in the water forming corrosive electrolytes.¹ Over the last 30 years, internal corrosion accounts for 61% of the incidents caused by corrosion in natural gas transmission and gathering pipeline incidents, according to Pipeline and Hazardous Materials Safety Administration (PHMSA) database. Natural gas consists of nearly 33% of the energy consumption in the United States in 2016 according to the U.S. Energy Information Administration (EIA).² The natural gas delivery system includes 528,000 km (328,000) miles of natural gas transmission and gathering pipelines.³ Therefore, it is important to monitor corrosion inside the gas pipelines to mitigate corrosion and ensure the structure integrity. Of particular interest is an ability to identify localized conditions which are known to initiate internal corrosion before the onset of significant pipeline corrosion occurs.

Summary

Analysis of the experimental data for liquid-entrainment rate, forces exerted on liquid droplet, and secondary flow occurring in the gas core show that the liquid is mainly carried in the form of film in the inclined annular flow. Therefore, it is more reasonable to establish a mathematical model from the bottom-film reversal than from the droplet reversal.

In this study, a new analytical model is developed from force balance of the bottom film of the inclined tubing after studying the bottom-film thickness and gas/liquid interfacial friction factor to reveal the liquid-loading mechanism. Furthermore, a new Belfroid-like empirical model is proposed that is based on the calculation results of a wide range of flowing parameters from the new analytical model to predict the liquid-loading status of gas wells. The new empirical model introduces a coefficient C_d,p,uSL,T to consider how the fluid properties under downhole flow condition affect the critical gas velocity. C_d,p,uSL,T in the new empirical model increases with the pipe diameter, liquid velocity, and flowing pressure, and decreases with the flowing temperature.

The new analytical model, having an average error of 8.45%, agrees well with the published experimental data, and it also performs well in predicting the pressure gradient at liquid unloading condition. The new empirical model could be applied for the prediction of real field operations and has been validated with an accuracy rate of 95% against data newly collected from 60 horizontal wells. The new work can accurately and easily judge the liquid-loading status, and it also reveals how the fluid properties under downhole flowing condition affect the liquid loading.