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WAX DEPOSITION PROJECT REPORT SUBMITTED IN PARTIAL FULFILLMENT OF THE REQUIREMENT FOR THE AWARD OF DEGREE

BACHELOR OF TECHNOLOGY in PETROLEUM ENGINEERING

By

ARJIT KUMAR PRINCE Admission Number: 14JE000335 SESSION: 2015-2016

UNDER THE GUIDANCE OF

TARUN KUMAR NAIYA Assistant Professor

DEPARTMENT OF PETROLEUM ENGINEERING

INDIAN SCHOOL OF MINES DHANBAD-826004

Contents 1. Acknowledgement……………………………………………………………………………… ………………………………………. 2. Abstract…………………………………………………………………………………………… …………………………………………. 3. Introduction……………………………………………………………………………………… ………………………………………… 4. Wax deposition and Thixotropy……………………………………………………………………………………… ………….. 5. Wax Deposition Problem in Flow Conditions………………………………………………………………………………. 6. Wax crystallization…………………………………………………………………………………… …………………………………. 7. Mechanism of wax deposition………………………………………………………………………………………… ………….. 8. Factors leading to wax precipitation and deposition……………………………………………………………………. 9. Wax Appearance Temperature (WAT) and Wax Dissolution Temperature (WDT) Measurement…. 10.Why Thixotropic property is important in Wax Deposition………………………………………………………….. 11.Effects of wax deposition in pipes……………………………………………………………………………………………… … 12.Methods of wax prevention and removal…………………………………………………………………………………..... 13.Thixotropic behavior of oil…………………………………………………………………………………………………… ……… 14.Conclusion……………………………………………………………………………………… …………………………………………….

ACKNOWLEDGEMENT Apart from the efforts of me, the success of any project depends largely on the encouragement and guidelines of many others. I take this opportunity to express my gratitude to the people who have been instrumental in the successful completion of this project. I would like to show my greatest appreciation to Prof Tarun Kumar Naiya. I can’t say thank you enough for his tremendous support and help. I feel motivated and encouraged every time I attend his meeting. Without his encouragement and guidance this project would not have materialized. My deep sense of gratitude to my seniors for support and guidance. The guidance and support received from all the members who contributed and who are contributing to this project, was vital for the success of the project. I am grateful for their constant support and help. I would also thank my

Institution and my faculty members without whom this project would have been a distant reality. I also extend my heartfelt thanks to my family and wellwishers.

ABSTRACT Highly waxy crude oils can cause significant problems such as blockage of a pipeline because of the precipitation and deposition of select wax components during the production and transportation of the crude oil. The cost of wax management is enormous and rapidly increasing because of increased oil production in deep sea areas. Wax management costs can be significantly reduced if wax deposition and gelation in pipeline can be accurately predicted. In this research, a rigorous wax deposition model combined with the wax precipitation kinetics in the boundary layer was developed using a computational heat and mass transfer analysis. This model accurately predicted the deposition and aging rates for lab scale and pilot plant scale flow loop tests under laminar and turbulent flows. The model was also extended to make prediction in subsea field pipelines. Studies of wax deposition under turbulent flow conditions showed that the deposition rate is significantly reduced by the precipitation of waxes in the thermal boundary layer. Furthermore, this analysis proved that the convective mass flux is bounded by the Venkatesan-Fogler solubility method as the lower bound and the ChiltonColburn analogy method as the upper bound. The challenging issue of the restart of a gelled subsea pipeline after shut-in period was also studied experimentally and theoretically. The gel inside the pipeline formed during a

stoppage of oil flow must be broken to restart the flow. The gel breaking mechanisms during the restart of a pipeline were investigated and were found to be a function of cooling rate. The existence of a delineation point between cohesive and adhesive failures was found by measuring the gel strengths using various cooling rates. Using a controlled stress rheometer and a cross polarized microscope, we elucidated the phenomena behind the existence of a delineation point between cohesive and adhesive failures. This study has shown that the controlled stress rheometer can predict the restart pressure of a gelled pipeline when the cooling rate is low and breakage occurs adhesively. Finally, we developed a restart model that can predict the relationship between the amount of injection fluid and the pressure applied to the pipeline.

INTRODUCTION Crude oils are a complex mixture of hydrocarbons in which the majorities are saturated alkanes. In some cases, the concentration of high molecular linear alkanes is very high, leading to the appearance of solids when fluids are cooled below a threshold temperature, termed wax appearance temperature (WAT); in these cases, the fluids are typically called waxy oils. The wax fraction of the oil comprises the molecules that are expected to solidify upon temperature decrease and typically contain molecules with alkyl chain length greater than 18 units. The percentage of such hydrocarbons in oils worldwide usually ranges from 1 to 50 % . At reservoir temperatures (70-150 oC) and pressures (50-100 MPa), wax molecules are dissolved in the crude oil. However, as the crude oil flows

through a subsea pipeline resting on the ocean floor at a temperature of 4 oC, the temperature of oil eventually decreases below its cloud point temperature (or wax appearance temperature, WAT) because of the heat losses to the surroundings. The solubility of wax decreases drastically as the temperature decreases and wax molecules start to precipitate out of the crude oil. Because oil reservoirs near the shoreline have become depleted, oil production in deep sea areas has increased significantly. Forecasters expect that, by 2017, oil production from deep sea areas will exceed 8 million barrels per day which is about three times greater than deep sea production in year 2002 (2.4 million barrels per day). Recent advances in the exploration and production technologies in deep sea areas have made deep water drilling economically feasible and the oil industry has drilled subsea oil wells as far as 160 miles away from the shore. As oil wells are developed, wax problems will become more severe and extensive due to the increased transportation lines on the cold ocean floor.

Oil production in deep sea areas The research in this dissertation elucidates the fundamental understanding of problems in the production and transportation of waxy crude oil. More specifically, the flow assurance problems incurred by the precipitation of wax molecules during the production and transportation in the field pipelines can be categorized as: (1) Wax deposition in flow conditions and (2) Wax gelation and restart problem after shut-in period.

Wax Deposition and Thixotropy Petroleum (or crude oil) is a widely traded and important commodity in the global economy, and in the context of petroleum production, the rheological response of structured fluids can play a very important role. While in many

cases crude oil itself exhibits highly non-Newtonian flow behavior, there are also other fluids which are of interest to rheologists in the field of petroleum engineering. For example, drilling fluids are often designed in order to exhibit a wide range of complex rheological behaviors, from thixotropy to elastoviscoplastic yield-like behavior at large deformations. Non-Newtonian surfactant solutions are frequently utilized in enhanced oil recovery scenarios in order to maximize output from a particular oil field. In order for these fluids to be of use to the practicing petroleum engineer, a working knowledge of their rheology is required. The problem of understanding the rheology of these fluids is of greater relevance today than ever before. Predictions made in the mid-20th century such as those by Hubbert showed that the production of crude oil within a given region would follow a bell shaped curve which, after peaking, would decrease slowly over time. While Hubbert's peak theory predicts that eventually global production of crude oil will reach a peak, the point in time at which this peak will occur is still unclear – although estimates are typically on the order of several decades. One of the reasons for the peak point being difficult to predict is that modern oil exploration techniques have been uncovering new reserves of petroleum in remote locations. As the technology used to both and these reserves and extract oil in more efficient manners continues to develop, total global production of oil can continue to grow. Hence, a significant segment of the oil industry today is focused solely on developing technology that both allows extraction of crude oil from remote reserves, but also allows more efficient extraction of petroleum from current and future reserves. Complex fluids and smart material systems will feature heavily in these developments. In this context, the rheological characterization of precipitate-containing crude oils is of increased importance. Precipitate-containing oils tend to exhibit highly non-Newtonian flow behavior, due to the inherent microstructure associated with the presence of a number of possible solid phases. The most commonly encountered precipitates are waxes, hydrates (or clathrates) and asphaltenes. In the case of ultra-deep water oil production, precipitates such as waxes may pose significant problems towards the goal of ensuring continuous flow of the fluid from a reserve. In particular, the fluid may experience large drops in temperature due to the cool ambient sea-water and extremely long pipelines (several kilometers) , resulting in a waxy crude oil being cooled to below its wax appearance temperature, denoted by Twa. Once the waxy crude is cooled to below Twa, it may form a viscoelastic gel, and much larger pressure drops are then required in order to ensure the same flow rate. This issue is often so problematic that field workers will insulate and/or heat pipelines to prevent this cooling from occurring

Thixotropy is a time-dependent shear thinning property. Certain gels or fluids that are thick (viscous) under static conditions will flow (become thin, less viscous) over time when shaken, agitated, or otherwise stressed (time dependent viscosity). They then take a fixed time to return to a more viscous state. In more technical language: some non-Newtonian pseudoplastic fluids show a time-dependent change in viscosity; the longer the fluid undergoes shear stress, the lower its viscosity. A thixotropic fluid is a fluid which takes a finite time to attain equilibrium viscosity when introduced to a step change in shear rate. Some thixotropic fluids return to a gel state almost instantly, such as ketchup, and are called pseudo plastic fluids. Others such as yogurt take much longer and can become nearly solid. Many gels and colloids are thixotropic materials, exhibiting a stable form at rest but becoming fluid when agitated. Some fluids are anti-thixotropic: constant shear stress for a time causes an increase in viscosity or even solidification. Constant shear stress can be applied by shaking or mixing. Fluids which exhibit this property are usually called rheopectic. To tackle the situation of wax deposition, we need to understand the problem and for that the properties of the crude oil like viscosity, flocculation, deflocculation, thixotropy, etc must be known along with their dependency on the temperature as the main problem occurs due to the temperature variance. The properties of fluids vary a lot from the gases. Like the property of viscosity; in gases the viscosity increases with increase in temperature while in liquids viscosity decreases with increase in temperature. So, here we can see how differently the two behave in similar conditions. It is not that liquids behave like solids. As for example, solids can resist lower values of shear stress and to bring the solid in motion a minimum value of shear stress is needed. While in liquids a small value of shear stress is enough to bring about the system into motion i.e. it can’t resist the shear stress no matter how small its value is. From these two cases we can conclude that the properties of the liquids are very different than that of solids or gases. So, there properties are needed to be studied separately if we want to control phenomenon like wax deposition. This project is mainly deals with one property of the fluids: thixotropy.

Wax Deposition Problem in Flow Conditions

Wax deposition occurs when paraffin components in crude oil (alkanes with carbon numbers greater than 20) precipitate and deposit on the cold pipeline wall when the inner wall temperature falls below the cloud point temperature (solubility limit). If preventive methods for wax deposition (e.g. insulation of pipeline, injection of wax inhibitor, or combination of both) are not successful, a wax gel layer grows rapidly in thickness and impedes the flow of oil due to the flow restriction. In the Lasmo field in the UK, wax deposition was so severe and frequent that the entire field was abandoned at a cost of over $100,000,000. Once the wax deposit starts to impede the production and transportation due to the flow restriction, corrective methods to remediate the wax deposit are generally necessitated. One of the most commonly used corrective methods used in the fields is pigging. In pigging, a pig (a solid object with the diameter smaller than the inner diameter of the pipe) passes through the pipeline to scrape off the wax deposit. However, the pigging method cannot efficiently be utilized without a proper wax deposition prediction. Successful management of wax deposition will become more important in the future because new explorations and productions are being made farther offshore. The wax deposition management cost to the petroleum production industry is enormous and will increase both in terms of capital costs (e.g. preventive methods) and operating costs (e.g. corrective methods).It is widely recognized that tremendous savings could be realized from accurate wax prediction in offshore systems. Consequently, a fundamental understanding of wax deposition phenomena and a comprehensive wax deposition model based on this fundamental understanding is strongly necessitated in order to overcome the challenges in production and transportation of subsea pipelines.

Wax Gelation and Restart Problem after Shut-in Wax precipitation during oil flow results in wax deposition and flow restriction, wax precipitation during a production shutdown results in problems when attempting to restart the flow. If the transportation in a pipeline is stopped due to a planned maintenance or an emergency situation such as severe weather conditions on the off-shore platforms, the temperature and solubility of wax decreases and wax molecules precipitate out of liquid phase in a static condition. In the absence of flow, the precipitation of wax molecules leads to the formation of a wax-oil gel as shown in the cross-polarized microscope photo of wax.

This restart flow problem is especially challenging when the ambient temperature is below the pour point temperature (ASTM D 5853) or the gelation temperature, which indicates the lowest temperature at which oil is pumpable. In order to prevent this risk and to enhance the restart ability after shut-in, chemical agents which can depress the pour point temperature and/or weaken the strength of the wax-oil gel. When assessing the restart ability, it is necessary to estimate the pressure required to break the plug of wax-oil gel. The pressure required to break the gel and to restart flow is proportional to the strength of the gel (yield stress) and the aspect ratio of the pipeline. Consequently, a fundamental understanding on the wax-oil gel breaking phenomena is needed to overcome the challenges in production and transportation of subsea pipelines.

Wax Crystallization Crystallization generally is the process of separation of solid phase from a homogenous solution, the separated solid phase appearing as crystals. Paraffins (waxes) remain in solution as natural components of crude oil until temperature gets to or below their solubility limit. The separation of wax (solid phase) out of the oil (liquid phase) at favorable prevailing conditions is referred to as wax precipitation or crystallization. Crystallization and precipitation have been used interchangeably in wax deposition studies and will be used to mean the same process in this work. Two types of wax crystals have been distinguished: macro-crystalline wax composed mainly of normal paraffin and micro-crystalline wax from iso-paraffins and naphthenes (cyclo-paraffins). Wax crystal formation involves two stages—nucleation and growth—with nucleation preceding growth stage. As the solubility limit is approached, the kinetic energy of the paraffin molecules is reduced as a result of temperature reduction. Consequent to this reduced kinetic energy, the motion of the wax molecules is hindered, leading to continuous reduction and closure of the space between the molecules. As this process continues, the wax molecules get tangled, forming clusters which grow larger and become stable upon reaching a certain critical size. The critical size is dependent upon the prevailing condition. However, the clusters re-dissolve when critical size is not attained and become unstable. These clusters are referred to as nuclei. Nuclei that achieve critical cluster size will have an increasing number of molecules clinging to them as the prevailing condition remains favorable to crystal formation, leading to an increase in size of formed wax crystals. This process of increase in size is known as wax crystal growth stage. Nucleation

and growth occur simultaneously in the oil system, with one or the other predominating at a time. Sometimes in the literature, deposition is used interchangeably with precipitation, but they are different concepts. Wax deposition is the formation of a layer of the separated solid phase, and the eventual growth of this layer, on a surface in contact with the crude oil. Wax deposition can be formed from an already precipitated solid phase (wax) through mechanisms of shear dispersion, gravity settling, and Brownian motion, or from dissolved wax molecules through a molecular diffusion mechanism. Precipitation does not necessarily lead to deposition, as precipitated wax may not deposit due to other prevailing operating conditions. Thus, precipitation, though an important condition for deposition, is not necessarily sufficient for wax deposition. Singh et al. (2001) reported that there are two stages or steps that are involved in wax deposition: wax gel formation followed by aging of deposited wax gel. Petroleum wax deposits contain some crude oil, water, gums, resins, sand, and asphaltenes, depending on the nature of the particular crude oil, which are entrapped during the crystallization and deposition process. The trapped oil causes diffusion of wax molecules into the gel deposit and counter-diffusion of oil out of the gel deposit, a process that depends on the critical carbon number of the oil. The critical carbon number is unique for different waxy crude oils and depends on the prevailing operating conditions also (Singh et al., 2000). In the gel deposit, the fraction of molecules with carbon numbers greater than the critical carbon number increases, while that of molecules with carbon numbers lower than the critical carbon number decreases. The process of diffusion and counterdiffusion leading to hardening of the gel deposit, increase in size of deposit, and increase in the amount of wax in gel deposit, is called aging, the second stage of wax deposition. Molecular diffusion, therefore, is critical to aging and hardening of wax gel deposits. Wax model Singh et al. (2000) reported that the deposition of wax gel on the pipe/tubing wall follows a process that can be described by the following five steps: 1. Gelation of the waxy oil (or formation of incipient gel layer) on the cold surface. 2. Diffusion of waxes (hydrocarbons with carbon numbers greater than the critical carbon number) towards the gel layer from the bulk oil. 3. Internal diffusion of these molecules through the trapped oil. 4. Precipitation of these molecules through the trapped oil. 5. Counter diffusion of de-waxed oil (hydrocarbons with carbon numbers lower than the critical carbon number) out of the gel deposit layer. Steps 3, 4, and 5 are reported to be responsible for the increase in solid wax content of the wax gel deposit (aging of the wax deposit).

Images showing the effect that various types of precipitates may have on a pipeline cross-section.

Mechanism of Wax Deposition The mechanism of wax deposition is considered here with respect to the lateral transport of waxy residue. Wax deposition is believed to occur as a result of lateral transport by diffusion, shear dispersion, and Brownian diffusion. Gravity settling is believed to be a possible transport mechanism also. Molecular Diffusion- For all flow conditions, oil will be in laminar flow either throughout the pipe or at least in a thin laminar sublayer adjacent to the pipe wall. When the oil is being cooled, there will be a temperature gradient across the laminar sublayer. If temperatures are below the level where solid waxy crystals can be precipitated, then the flowing elements of oil will contain precipitated solid particles, and the liquid phase will be in equilibrium with the solid phase; that is, the liquid will be saturated with dissolved wax

crystals. The temperature profile near the wall will lead to a concentration gradient of dissolved wax, and this dissolved material will be transported toward the wall by molecular diffusion. When this diffusing material reaches the solid/liquid interface, it will be precipitated out of solution. Brownian Diffusion- Small, solid waxy crystals, when suspended in oil, will be bombarded continually by thermally agitated oil molecules. These collisions will lead to small random Brownian movements of the suspended particles. If there is a concentration gradient of these particles, Brownian motion will lead to a net transport, which in nature and mathematical description is similar to diffusion. The possible contribution of Brownian diffusion to wax transport and deposition has been mentioned prominently in USSR literature. Shear Dispersion- When small particles are suspended in a fluid that is in laminar motion, the particles tend to move at the mean speed and in the direction of surrounding fluid. The particle speed is that of streamline at its center, and the particle rotates with an angular velocity which is half the fluid shear rate. If the particles approach a solid boundary, both linear and angular velocities will be reduced. Because of fluid viscosity, rotating particles will impart a circulatory motion to a layer of fluid adjacent to the particle. This rotating fluid region exerts a drag force on neighboring particles. In a shear field, each particle passes and interacts with nearby particles in slower or faster moving streamlines. When only two particles are present, far from a wall and at a very low Reynolds number, these passing encounters result in large temporary displacements. As the particles pass, their trajectories are such that the particles curve around one another and return to their original streamline. Thus, there is no net lateral displacement. If the particle concentration is high, however, then a significant number of multi particle interactions will occur. These multi particle collisions result in net lateral transport and a dispersing of particles. Gravity Settling- Precipitated waxy crystals are denser than the surrounding liquid oil phase. Hence, if particles were non-interacting, they would settle in a gravity field and could be deposited on the bottom of pipes or tanks. For an initially uniform mixture in a vessel, there would be a beginning rate of settling followed by a diminishing rate of deposition, which asymptotically would approach zero at complete settling.

Factors Leading To Wax Precipitation and Deposition

Wax precipitation occurs when the wax molecules contained in the crude oil reach their solubility limit due to change in equilibrium conditions in the crude, resulting in loss of paraffin solubility. The solubility limit is directly dependent on temperature and, as such, is defined by temperature, given other specified conditions. There are other factors that affect the precipitation of wax and thus wax deposition. While some of these factors influence wax precipitation by shifting the solubility limit in terms of temperature upwards/downwards, others provide a favorable environment for deposition to occur. Such factors include oil composition plus available solution gas, and pressure of the oil which affects the amount of gas in solution. Others are flow rate, completion, and pipe or deposition surface roughness.

Temperature -Temperature seems to be the predominant and most critical factor in wax precipitation and deposition due to its direct relationship with the solubility of paraffin. Sadeghazad et al. (1998) reported that temperature and the amount of light constituent are the two most important factors affecting wax precipitation and deposition. Paraffin solubility increases with increasing temperature and decreases with decreasing temperature. In working with food-grade wax in a model oil solvent consisting of mineral oil and kerosene mixed at a ratio of 3:1, Singh et al. (2000) showed the relationship between wax solubility and temperature. Wax precipitates from crude oil when the operating temperature is at or below the WAT (cloud point temperature). It has been reported that wax deposition will not occur until the operating temperature falls to or below the WAT (Erickson et al., 1993). All other factors actually lead to wax deposition when the temperature is already at or below the cloud point. The ambient temperature around the pipe is generally less than the oil temperature in the pipe. Thus, there is loss of heat through the pipe wall to the surroundings because a temperature gradient exists between the bulk oil and the colder pipe wall. This temperature gradient leads to wax deposition when the pipe wall temperature falls below the cloud point. The rate of wax deposition is in direct proportion to the temperature difference between the bulk oil and the pipe wall (Eaton et al., 1976) when bulk oil temperature is fixed. However, Haq (1981) showed that keeping the pipe wall temperature constant at a value below the cloud point of the oil and varying the bulk oil temperature reduce the amount of wax deposited as the temperature difference between the bulk oil and pipe wall increases. The temperature gradient between the cold tubing/pipe wall and the bulk oil initiates a concentration gradient in the paraffin molecule distribution. Paraffin molecules near the pipe wall crystallize out of the oil as wall temperature falls below cloud point, leading to a reduction in the number of dissolved paraffin molecules around the wall inducing a radial concentration gradient. The simple law of diffusion is obeyed then as dissolved paraffin molecules in the oil diffuse towards the wall, causing additional precipitation and further deposition. This leads to increasing wax deposit thickness with time. Cole and Jessen (1960) opined that it is the difference between the cloud point temperature and the temperature of the pipe wall that most importantly determines the rate of wax deposition.

Crude Oil Composition- Crude oil is composed of saturates, aromatics, resins, and asphaltenes (SARA), the distribution of which in a particular crude oil system is shown by the SARA analysis. SARA determines the susceptibility of the crude to deposition of wax solids, and thus the stability of the crude oil. Saturates are flexible in nature, the flexibility being highest in normal paraffins because they are straight chain compounds. The very high flexibility of normal paraffins makes it possible for them to easily cluster and crystallize. The iso-paraffins equally enjoy a high level of flexibility, but form a more unstable wax. Cyclo-paraffins (naphthenes) are least flexible due to their cyclic nature and do not contribute much to wax deposition. These components are in thermodynamic equilibrium at initial reservoir conditions. It is known that aromatics serve as solvents for high molecular weight saturates, which are the sources of paraffin waxes in crude oil while the polar components, especially asphaltenes, induce wax nucleation (Hammami et al., 1999) . Singh et al. (2001) reported, however, that the solubility of paraffins in aromatic, naphthenic, and other organic solvents becomes low at room temperature (low temperatures). Light ends of saturates equally help to keep the high molecular weight heavy ends in solution. The onset of production results in the loss of these light ends, as they are first to leave the reservoir. This alters the original composition of the oil system, resulting in decreased solubility of the paraffin waxes. This loss of solubility could lead to precipitation and deposition of wax. In a model study, Huanquan et al. (1997) reported that increasing the percentage of light end (C5) in a synthetic oil system decreased the cloud point temperature, reducing the chance of wax deposition. Generally, the weight percent of the saturates in the crude oil, the structural distribution of the paraffin components, and the occurrence of other solids like formation fines, corrosion materials, and presence of asphaltenes which could form nucleating sites—all contribute to wax precipitation and deposition. Oils containing high C 30+ (especially normal paraffin C30+) concentrations exhibit high cloud point temperatures (Ferworn et al., 1997). Therefore, knowledge of the oil composition (SARA) gives a fair idea of the wax deposit potential of the crude and, hence, the oil stability. Oil stability has been reported to depend on its solids content and the balance between aromatics and saturates. By SARA analysis, the distribution by weight percent of saturates, aromatics, resins, and asphaltene components, for stable and unstable crude oils, is as follows: Unstable crude: Saturates > Aromatics > Resins > Asphaltenes Stable crude: Aromatics > Saturates > Resins > Asphaltenes This distribution is to be expected since the aromatics keep the heavy paraffin wax in solution, while a crude oil system that displays a large amount of saturates (paraffin) is likely to be unstable (Carbognani et al., 1999) and thus precipitate and deposit wax.

Pressure -Pressure, as an important parameter in the exploitation of reservoir fluids, plays a significant role in wax precipitation and deposition. The pressure profile during oil production is such that the reservoir pressure declines with production, and the pressure of the flow stream drops all the way from the reservoir to the surface. The lighter components of the reservoir fluid tend to be the first to leave the reservoir as pressure depletes. This causes an increase in the solute solvent ratio, since the light ends serve as solvent to the wax components. Hence, the solubility of wax is reduced with the loss of these light ends. Brown et al. (1994) studied the effect of pressure on the cloud point of dead oil as well as live oil by measuring cloud point at atmospheric pressure and higher pressures. The wax appearance temperature increases with increase in pressure above the bubble point, at constant composition. This phenomenon implies that increase in pressure in the one-phase liquid region (above bubblepoint pressure) will favor wax deposition. The situation is different below the bubblepoint where there is two-phase existence. Here wax appearance temperature decreases with increase in pressure up to bubble point pressure (Brown et al., 1994) due to dissolution of light ends back into the liquid phase. The WAT increases with increase in pressure for STO, commonly referred to as dead oil (Brown et al., 1994; Karan et al., 2000). Huanquan et al. (1997) reported that the WAT increases with increase in pressure for a fixed component liquid mixture. Other Contributing Factors- Though temperature, composition, and pressure of oil play the most significant role in wax deposition, other factors that have been identified as contributing to wax deposition include flow rate, gas-oil ratio, and pipe/tubing wall roughness. Laboratory investigations have revealed that wax deposition is influenced more by laminar flow than when flow is in the turbulent regime. Increasing flow rate from laminar to turbulent reduces maximum deposition rate and at the same time lowers the temperature at which maximum deposition rate occurs (Hsu et al., 1994), a scenario that is expressed in Figure 2.3. Low flow rates offer the moving oil stream longer residence time in the flow channel. This increased residence time allows more heat loss to the surroundings, leading to a higher chance of the bulk oil temperature falling below the WAT and enough time for wax precipitation and final deposition. Jessen and Howell (1958) believed that when flow is in the laminar regime, wax deposition increases with increase in flow rate. Increase in flow rate in the laminar regime makes more fluid available for wax deposition. However, wax deposition decreases as flow moves to the turbulent regime. Turbulent flow stream exerts a kind of viscous force, which tends to drag or slough the wax deposits from the pipe wall. When this viscous drag exceeds the resistance to shear in the deposits, the wax then sloughs and is lodged back into the liquid. This removal mechanism has a significant impact on the wax deposition rate (Hsu et al., 1994). There is a difference in texture between wax deposited at high flow rates and wax deposited at low flow rates (Jessen and Howell, 1958; Tronov, 1969; Haq, 1981). Paraffin wax deposited at high flow rates appears harder, being more compact and more firmly attached to the deposition surface, the molecules having good cohesion among them. In his study of the effect of deposition surface roughness on paraffin deposition, Hunt (1962) concluded that deposits do not adhere to metals themselves, but are held in place by surface roughness which acts as wax nucleating sites. Jorda (1966) observed that paraffin deposition increases with greater surface roughness. In their wax deposition study with pipes of different materials, Jessen and Howell (1958) concluded that the amount of wax deposited on a smooth surface is less than that deposited on steel. However, Patton and Casad (1970) could not see any correlation between wax deposition and surface roughness, but opined that adhesion bond at a surface should be proportional to the total contact area and therefore related to surface roughness. Gas/oil ratio influences wax deposition in a manner that depends on the pressure regime. Above the bubblepoint, where all gases remain in solution, solution gas helps to keep wax in solution. Luo et al. (2001) reported that wax appearance temperature will be high with low GOR (gas oil ratio), while

Singh et al. (2004) observed that injection of lift gas in a closed loop reduced wax deposition by causing a depression in wax appearance temperature as a function of pressure. High GOR would result in more expansion and subsequent cooling as pressure of the oil system depletes, a situation that can aggravate the wax deposition problem. In a study to reduce waxappearance temperature by injection of diluent lift gas, Singh et al. (2004) noted that good results were not obtained in high GOR wells.

Effect of flow rate on wax deposition rate

Wax Appearance Temperature (WAT) and Wax Dissolution Temperature (WDT) Measurement Wax Crystallization Point The point defining when paraffin separates into solid phase from the bulk oil liquid phase is a very important thermodynamic parameter in wax deposition studies. Sadeghazad et al. (1998) described it as a very important parameter that affects wax precipitation and is basic to the wax deposition problem. It has been reported that rheologically, crude oil is a lowviscosity Newtonian fluid, but exhibits non-Newtonian behavior at low temperature (Leontaritis and Leontaritis, 2003), a phenomenon attributed to paraffin wax solid-phase separation. This point of separation, defined by temperature, happens to be unique for a particular pressure as well as oil composition, and is interchangeably referred to as wax appearance temperature or cloud point. Cloud point temperature has been defined as the temperature at which paraffin wax begins to crystallize from crude oil solution (Kruka et al., 1995; Karan et al., 2000). Monger-McClure (1999) defined measured cloud point as the highest temperature at which wax solids are detected when an oil sample is cooled at a controlled rate. This is different from thermodynamic cloud point (which can be referred to as true cloud point), defined as the highest temperature at which a paraffin wax will exist in a crude oil at a given pressure (Hammami et al., 2003). Whereas true cloud point lies on the solid/liquid-phase envelope, laboratory or experimentally measured cloud point lies within the solid/liquid-phase envelope (Karan et al., 2000). Below WAT a solid phase of wax exists in the crude oil.

As can be seen from figure, the crystallization temperature decreases as pressure increases from zero to the bubblepoint, then increases with pressure above the bubblepoint. Measuring the exact cloud point or WAT has not been easily achievable despite the several techniques available for determining such. The wax appearance temperature is a unique oil property that is dependent upon many factors including oil composition, measurement technique, thermal history of oil, and oil properties relating to crystal nucleation and growth (Hammami et al. 2003). The cooling rate employed during a test affects the result. When oil samples are cooled fast, there seems to be a supercooling problem that tends to depress the measured WAT. Hammami et al. (2003) reported that, in the event of supercooling, the oil is cooled beyond the WAT without wax crystallization. Nucleation sites are then required to initiate wax formation. Where there are no nucleation sites, wax crystallization becomes spontaneous at such a low temperature.

Research has shown that STO WAT results match closely with field experience (Hammami & Raines, 1999). STO WAT gives higher value than live oil WAT of the same crude oil. This is to be expected, as light ends increase the solubility of paraffin molecules (Huanquan et al., 1997), while increase in pressure depresses the WAT below the bubblepoint pressure (Brown et al., 1994). The entire wax deposition process is complex. Karan et al. (2000) reported that a likely reason why STO WAT closely matches field experience could be the difference between bulk oil temperature, which corresponds to field deposition temperature, and tubing wall temperature where actual deposition occurs. Stock tank oil WAT remains relevant in wax deposition studies and in characterizing waxy crude oils partly because of the apparent difficulty in obtaining and handling live oil samples (Karan et al., 2000). The WAT test is the most important and critical among other diagnostic tests carried out on a crude oil sample for wax precipitation and deposition. It indicates whether or not wax precipitation or deposition will be an issue during oil production. Oil composition and properties change at the WAT as wax begins to precipitate. Viscosity and density of the crude increase with an increase in the amount of wax precipitated; therefore, the aim is to ensure that the temperature of the producing oil as it arrives at the surface is above its WAT. Also, the tubing wall temperature should be kept above the oil WAT to avoid deposition by molecular diffusion. The results of STO WAT tests performed using two different techniques—viscometry and CPM—are hereby presented.

Wax-Deposition Measurements in the Simulation and Design of Subsea Pipelines: Conventional practices for estimating the amount of deposited wax in pipelines are usually based on predictions made with simulation packages using limited stocktank-oil (STO) deposition data collected under laminar-flow conditions in benchscale flow loops. Such practices are conservative and often lead to non-optimal designs of pipelines and surface facilities. For optimized designs, laboratory-scale deposition measurements made under realistic conditions are required to calibrate flowline models. In this work, a high-pressure deposition cell that operates on the TaylorCouette (TC) flow principle is used to generate more deposition data with live reservoir fluids under turbulent flow similar to the conditions encountered in many flowlines. The analogy between TC flow and pipe flow is explained, and a scalability flow chart for linking the laboratory-scale deposition data from TC configuration to pipe configuration is presented. Through a case study, the scaled-deposition data are then used to tune a wax-deposition model in the OLGA®5 simulation package. Next, the tuned model is applied to predict wax deposition under actual production and transportation conditions. The importance of tuning the deposition models with live fluid data under turbulent-flow conditions is also shown by comparing results obtained from conventional dead-oil low-shear data.

Effect of wax deposition in pipes Crystallization of waxes in crude oils leads to non-Newtonian flow characteristics, including very high yield stresses that are dependent on time and the shear and temperature histories of the fluid. This crystallization may cause three problems: 1. High viscosity, which leads to pressure losses 2. High-yield stress for restarting flow 3. Deposition of wax crystals on surfaces Wax precipitation-induced viscosity increases and wax deposition on pipes are the primary causes of high flowline pressure drops. In turn, these pressure losses lead to low flow rates that make conditions for wax deposition more favorable. In extreme cases, pumping pressure can exceed the limits of the system and stop flow entirely. A related problem is the high-yield stress for restarting flow. When oil is allowed to stand in a pipeline at temperatures below its pour point, a certain pressure is required to break the gel and resume flow. Again, this pressure may be higher than the pressure limits of the pumps and pipelines.

Why Thixotropic property is important in Wax Deposition When designing the pipelines and the pump facilities, engineers usually do a simplified force balance. The assumption is that when the pressure is enough to overcome the yield stress, the restart occurs. The problem is that there is evidence that this calculation is overestimated; therefore, a better rheological modeling of these oils is necessary once they present an “elastoviscoplastic thixotropic” behavior, which is a complex mixture of plasticity, elasticity, and thixotropy. Thixotropy of waxy crude is an important but complex issue in crude oil rheology study. Due to difference between the broken-down structures with the developed structure of fluid system, thixotropy means that apparent viscosity decreases continuously over time under shearing stress, and recovers gradually over time after stress relief. Thixotropy is basic data for shutdown and restart calculation and pumpability evaluation of waxy crude oil pipeline, besides that, safety analysis for running waxy crude oil pipeline needs accurate quantitative description in thixotropic behavior. Proposed mathematical modes described thixotropic fluid properties; domestic and foreign scholars have numerous studies in thixotropic fluid.

Methods of wax prevention and removal Wax can deposit on surfaces in the production system and in the formation. Wax deposition can be prevented or removed by a number of different methods. These methods fall into three main categories: 1. Thermal 2. Chemical 3. Mechanical

Thermal

Because wax precipitation is highly temperature dependent, thermal methods can be highly effective both for preventing and removing wax precipitation problems. Prevention methods include steam- and electrical-heat tracing of flowlines, in conjunction with thermal insulation. Thermal methods for removing wax deposition include: *Hot oiling *Hot watering *Hot water treatments cannot provide the solvency effects that hot oiling can, so surfactants are often added to aid in dispersion of wax in the water phase. Surfactants are discussed under chemical methods. Hot oiling is one of the most popular methods of deposited wax removal. Wax is melted and dissolved by hot oil, which allows it to be circulated from the well and the surface producing system. Hot oil is normally pumped down the casing and up the tubing; however, in flowing wells, the oil may be circulated down the tubing and up the casing. There is evidence that hot oiling can cause permeability damage if melted wax enters the formation. Higher molecular-weight waxes tend to deposit at the high-temperature bottom end of the well. Lower molecular-weight fractions deposit as the temperature decreases up the wellbore. The upper parts of the well receive the most heat during hot oiling. As the oil proceeds down the well, its temperature decreases and the carrying capacity for wax is diminished. Thus, sufficient oil must be used to dissolve and melt the wax at the necessary depths. Chemical The types of chemicals available for paraffin treatment include: *Solvents *Wax crystal modifiers *Dispersants *Surfactants Solvents can be used to treat deposition in production strings and also may be applied to remediate formation damage. Although chlorinated hydrocarbons are excellent solvents for waxes, they generally are not used because of safety and processing difficulties they create in the produced fluid. Hydrocarbon fluids consisting primarily of normal alkanes such as condensate and diesel oil can be used, provided the deposits have low asphaltene content. Aromatic solvents such as toluene and xylene are good solvents for both waxes and asphaltenes. Solvents are mostly used in large batch treatments. Wax crystal modifiers act at the molecular level to reduce the tendency of wax molecules to network and form lattice structures within the oil. Wax crystal modifiers which are used to prevent wax deposition, reduce oil viscosity and lower the wax gel strength are only effective when used continuously. Since they work at the molecular level they are effective in concentrations of parts per million, as

opposed to hot oil or solvents, which must be applied in large volumes. Wax crystal modifiers have a high-molecular-weight and as a result they have high pour points, so their use can be limited in cold climates. Dispersants are a type of surfactants that helps disperse the wax crystals into the produced oil or water. This dispersing of the wax crystals into the produce oil or water helps prevents deposition of the wax and also have a positive effect on the viscosity and gel strength. Dispersants can help break up deposited wax into particles small enough to be carried in the oil stream. To prevent wax deposition dispersants must be used continuously. To remediate deposited wax, dispersants can be used continuously or in batch treatments. Dispersants generally have a very low pour point making their use suitable for cold climates. These chemicals are used in low concentrations and can be formulated in both aqueous and hydrocarbon solutions, making them relatively safe and inexpensive. Surfactants are a general class of chemicals that are most often used to clean vessels, tanks, pipes, machinery or any place where wax may deposit. Surfactants or dispersants can also be used in combination with hot oil and water treatments. Mechanical Scrapers and cutters are used extensively to remove wax deposits from tubing because they can be economical and result in minimal formation damage. Scrapers may be attached to wireline units, or they may be attached to sucker rods to remove wax as the well is pumped. Deposits in surface pipelines can be removed by forcing soluble or insoluble pigs through the lines. Soluble pigs may be composed of naphthalene or microcrystalline wax. Insoluble pigs are made of plastic or hard rubber. Another method of mechanical intervention to prevent deposition is the use of plastic or coated pipe. Low-friction surfaces make it more difficult for wax crystals to adhere to the pipe walls. Deposition will still occur if conditions are highly favorable for wax precipitation, and deposits will grow at the same rate as for other pipes once an initial layer of material has been laid down; therefore, the pipe and coating system must be capable of withstanding one of the other methods of wax removal.

Thixotropic behavior of oil 5 % crude oil sample EXPERIMENT DATA

1, 1

Target Shear Shear Shear Torque Temperat Stress Rate Viscos Rate Time Nm ure °C Pa 1/s ity Pas 1/s s 1.39E0.339 0.099 06 40.8 1 04 3.424 0.1 10.03

1, 2 1, 3 1, 4 1, 5 1, 6 1, 7 1, 8 1, 9 1, 10 1, 11 1, 12 1, 13 1, 14 1, 15 1, 16 1, 17 1, 18 1, 19 1, 20 1, 21 1, 22 1, 23 1, 24 1, 25 1, 26

0.0001 43 0.0002 72 0.0004 02 0.0005 34 0.0006 68 0.0007 9 0.0009 14 0.0010 43 0.0011 7 0.0013 03 0.0014 37 0.0015 63 0.0016 98 0.0018 37 0.0019 76 0.0021 12 0.0022 51 0.0023 92 0.0025 33 0.0026 73 0.0028 19 0.0029 86 0.0031 08 0.0032 85 0.0034 15

40.8

34.98

26.6

1.315

26.76

20.1

40.7

66.44

53.15

1.25

53.43

30.18

40.8

98.31

79.71

1.234

80.09

40.28

40.8

130.4

106.2

1.228

106.8

50.35

40.7

163.3

132.8

1.23

133.4

60.43

40.8

193.1

159.3

1.212

160.1

70.5

40.8

223.5

185.8

1.203

186.7

80.58

40.7

255

212.4

1.201

213.4

90.67

40.7

285.9

238.9

1.197

240.1

100.8

40.8

318.6

265.4

1.2

266.7

110.8

40.7

351.3

292

1.203

293.4

120.9

40.7

382.1

318.5

1.2

320.1

131

40.8

415.2

345.1

1.203

346.7

141.1

40.7

449

371.6

1.208

373.4

151.1

40.7

483

398.1

1.213

400.1

161.2

40.7

516.3

424.7

1.216

426.7

171.3

40.7

550.2

451.2

1.22

453.4

181.4

40.7

584.7

477.7

1.224

480

191.5

40.7

619.3

504.3

1.228

506.7

201.5

40.7

653.4

530.8

1.231

533.4

211.6

40.7

689.2

557.4

1.237

560

221.7

40.7

729.9

583.9

1.25

586.7

231.8

40.7

759.7

610.4

1.245

613.4

241.9

40.6

803.1

637

1.261

640

251.9

40.7

834.9

663.5

1.258

666.7

262

1, 27 1, 28 1, 29 1, 30 1, 31 1, 32 1, 33 1, 34 1, 35 1, 36 1, 37 1, 38 1, 39 1, 40 1, 41 1, 42 1, 43 1, 44 1, 45 1, 46 1, 47 1, 48 1, 49 1, 50 1, 51 1, 52

0.0036 12 0.0038 54 0.0039 89 0.0040 28 0.0041 54 0.0040 78 0.0039 19 0.0037 97 0.0037 43 0.0036 12 0.0034 64 0.0033 72 0.0032 52 0.0031 19 0.003 0.0028 71 0.0027 42 0.0026 08 0.0024 76 0.0023 35 0.0021 94 0.0020 54 0.0019 02 0.0017 6 0.0016 18 0.0014

40.7

883.1

690

1.28

693.4

272.1

40.6

942.1

716.5

1.315

720

282.2

40.7

975.2

743.1

1.312

746.7

292.3

40.6

984.7

769.6

1.28

773.3

302.3

40.7

1016

796.2

1.276

800

312.4

40.6

997

769.7

1.295

773.3

322.5

40.6

958.1

743.1

1.289

746.7

332.6

40.7

928.3

716.5

1.296

720

342.7

40.6

915

690

1.326

693.4

352.7

40.6

883

663.5

1.331

666.7

362.8

40.7

846.8

637

1.329

640

372.9

40.6

824.4

610.4

1.351

613.4

383

40.6

794.9

583.8

1.361

586.7

393.1

40.6 40.6

762.4 733.4

557.3 530.8

1.368 1.382

560 533.4

403.1 413.2

40.6

701.7

504.2

1.392

506.7

423.3

40.6

670.3

477.7

1.403

480

433.3

40.6

637.6

451.2

1.413

453.4

443.5

40.6

605.3

424.7

1.425

426.7

453.5

40.5

570.8

398.1

1.434

400.1

463.6

40.6

536.4

371.6

1.444

373.4

473.7

40.5

502.2

345.1

1.456

346.7

483.7

40.6

464.9

318.5

1.46

320.1

493.8

40.5

430.3

292

1.474

293.4

503.9

40.5 40.6

395.5 355.4

265.4 238.9

1.49 1.488

266.7 240.1

514 524.1

1, 53

54 0.0013 05

40.5

319

212.4

1.502

213.4

534.1

10% crude oil sample EXPERIMENT DATA

1, 1 1, 2 1, 3 1, 4 1, 5 1, 6 1, 7 1, 8 1, 9

Target Shear Shear Shear Torque Temperat Stress Rate Viscos Rate Time Nm ure °C Pa 1/s ity Pas 1/s s 1.27E0.031 0.098 0.316 07 39.9 11 38 2 0.1 10.03 0.0001 52 39.9 37.25 26.6 1.4 26.76 20.1 0.0002 98 39.8 72.78 53.14 1.37 53.43 30.18 0.0004 44 39.8 108.6 79.71 1.363 80.09 40.29 0.0005 89 39.8 144 106.2 1.355 106.8 50.36 0.0007 33 39.7 179.2 132.8 1.349 133.4 60.43 0.0008 72 39.7 213.1 159.3 1.337 160.1 70.5 0.0010 15 39.6 248.1 185.8 1.335 186.7 80.58 0.0011 46 39.7 280.2 212.4 1.319 213.4 90.68

1, 10 1, 11 1, 12 1, 13 1, 14 1, 15 1, 16 1, 17 1, 18 1, 19 1, 20 1, 21 1, 22 1, 23 1, 24 1, 25 1, 26 1, 27 1, 28 1, 29 1, 30 1, 31 1, 32 1, 33 1, 34

0.0012 77 0.0014 11 0.0015 35 0.0016 67 0.0017 93 0.0019 14 0.0020 36 0.0021 52 0.0022 71 0.0023 83 0.0024 9 0.0026 13 0.0027 21 0.0028 29 0.0029 78 0.0031 29 0.0032 03 0.0033 14 0.0034 8 0.0036 46 0.0036 48 0.0037 39 0.0036 34 0.0034 53 0.0033 05

39.8

312.1

238.9

1.306

240.1

100.8

39.8

344.9

265.5

1.299

266.7

110.8

39.9

375.2

292

1.285

293.4

120.9

39.9

407.5

318.5

1.279

320.1

131

39.9

438.3

345.1

1.27

346.7

141.1

40

467.9

371.6

1.259

373.4

151.2

40

497.8

398.1

1.25

400.1

161.2

40.1

526.1

424.7

1.239

426.7

171.3

40.2

555.1

451.2

1.23

453.4

181.4

40.2

582.7

477.7

1.22

480

191.5

40.3

608.8

504.2

1.207

506.7

201.6

40.3

638.7

530.8

1.203

533.4

211.6

40.4

665.1

557.4

1.193

560

221.7

40.4

691.7

583.9

1.185

586.7

231.8

40.4

728

610.4

1.193

613.4

241.9

40.3

764.9

637

1.201

640

251.9

40.4

782.9

663.5

1.18

666.7

262

40.4

810.2

690

1.174

693.4

272.1

40.4

850.7

716.5

1.187

720

282.2

40.4

891.3

743.1

1.2

746.7

292.3

40.4

891.7

769.6

1.159

773.3

302.3

40.4

914.1

796.1

1.148

800

312.4

40.4

888.3

769.6

1.154

773.3

322.5

40.4

844

743.1

1.136

746.7

332.6

40.3

807.9

716.5

1.127

720

342.7

1, 35 1, 36 1, 37 1, 38 1, 39 1, 40 1, 41 1, 42 1, 43 1, 44 1, 45 1, 46 1, 47 1, 48 1, 49 1, 50 1, 51 1, 52 1, 53 1, 54 1, 55 1, 56 1, 57 1, 58 1, 59

0.0032 75 0.0031 94 0.0030 31 0.0029 11 0.0027 96 0.0026 76 0.0025 41 0.0024 25 0.0023 03 0.0021 69 0.0020 55 0.0019 34 0.0018 02 0.0016 81 0.0015 55 0.0014 27 0.0013 04 0.0011 78 0.0010 49 0.0009 18 0.0007 92 0.0006 61 0.0005 29 0.0003 98 0.0002 64

40.4

800.6

690

1.16

693.4

352.7

40.4

780.9

663.5

1.177

666.7

362.8

40.4

741

637

1.163

640

372.9

40.4

711.7

610.4

1.166

613.4

383

40.4

683.5

583.9

1.171

586.7

393.1

40.3

654.1

557.3

1.174

560

403.1

40.4

621.2

530.8

1.17

533.4

413.2

40.4

592.7

504.3

1.175

506.7

423.3

40.3

563

477.7

1.178

480

433.4

40.4

530.4

451.2

1.175

453.4

443.5

40.4

502.4

424.7

1.183

426.7

453.5

40.3

472.7

398.1

1.187

400.1

463.6

40.3

440.4

371.6

1.185

373.4

473.7

40.3

410.9

345.1

1.191

346.7

483.8

40.3

380.3

318.5

1.194

320.1

493.9

40.3

348.9

292

1.195

293.4

503.9

40.3

318.7

265.4

1.201

266.7

514

40.3

288

238.9

1.206

240.1

524.1

40.3

256.5

212.4

1.208

213.4

534.1

40.3

224.4

185.8

1.208

186.7

544.2

40.3

193.5

159.3

1.215

160.1

554.3

40.3

161.5

132.8

1.216

133.4

564.4

40.3

129.4

106.2

1.218

106.8

574.5

40.3

97.2

79.71

1.219

80.09

584.5

40.2

64.64

53.15

1.216

53.43

594.6

1, 60

0.0001 32

40.3

1, 61

-1.41E08

40.3

32.33 0.003 44

26.59

1.216

26.76

604.7

0.096 91

0.035 49

0.1

614.8

Analysis

For gelled waxy crudes oil, the thixotropic behavior of hysteresis loop which is formed under cyclic loading of linear increasing and decreasing shear rate is studied. Hysteresis loop area could represent the strength of thixotropic properties. With increasing of the rate of share rate sweep, the area of hysteresis loop increased. The area of second hysteresis loop is much smaller than first one, and began a slow decline from the third hysteresis loop. Areas of each hysteresis loops were decreased with increasing temperature, but it was different in decline rate—the lower the temperature, the greater the rate of decline. The maximum rate of decrease is the first hysteresis loop with exponential decline, and remaining hysteresis hoops approximately decrease linearly.

Conclusion Wax deposition and wax gelation problems can cause severe flow assurance problems for operators in deep water installations. To help combat these issues, laboratory measurements are required to develop an understanding of fluid characteristics and temperature requirements. Intelligent data interpretation of these measurements can provide rules of thumb and accurate models for establishing pigging and treating programs. Modeling can also provide key indicators for profiling pipeline temperature and wax buildup. These tools can

greatly assist the operator in making economic decisions and exploring multiple design operations. Current modelling technology includes real time, online pipeline monitoring and advisory systems that help manage a myriad of flow assurance issues. A number of operators worldwide have developed such system.

References 1. 2. 3. 4. 5. 6.

www.petrowiki.org www.woodgroup.com www.onepetro.org www.wikipedia.com web.mit.edu/chrisd/Public/chevron/main.pdf web.mit.edu/nnf/publications/GHM216.pdf