Final Thesis PDF

INVESTIGATION OF EFFECT OF POUR POINT DEPRESSANT ON WAX DEPOSITION AND CRUDE FLOW BEHAVIOUR

INTERIM PROJECT REPORT SUBMITTED IN PARTIAL REQUIREMENT FOR THE DEGREE OF MASTERS IN PETROLEUM ENGINEERING (2015-2017) BY

M Afzal Akthar (15MT000306) Under the guidance of

Dr. Tarun Kumar Naiya to

THE DEPARTMENT OF PETROLEUM ENGINEERING INDIAN INSTITUTE OF TECHNOLOGY (INDIAN SCHOOL OF MINES), DHANBAD-826004 1

List of contents S.No

Title

Page no.

i.

List of figures

3

ii.

List of tables

4

1.

Introduction & Background

5

1.1. Introduction

5

1.2. Effect of wax deposition in pipes

8

1.3. Introduction to Paraffins

9

1.3.1. Paraffins

9

1.3.2. Paraffin Wax Management

2.

3.

4.

1.3.3. Paraffin Wax Mitigation & Prevention Techniques

10

1.3.4. Methods of wax prevention and removal

10

1.3.4.1. Thermal

11

1.3.4.2. Chemical

11

1.3.4.3. Mechanical

12

Literature Survey

15

2.1. Wax deposition

15

2.2. Wax crystallization and Wax-Oil Gel Formation

16

2.3. Pour Point Depressants

17

Experimental Work

21

3.1. Experimental Apparatus

21

3.2. Wax deposition calculations

22

3.3. Pipeline study

23

3.4. Results and discussion

25

3.4.1. Effect of flow rate and temperature on wax deposition

25

3.4.2. Effect of PPD on wax deposition thickness

26

Future work to be done

35 2

List of figures

Fig.No. 1.1.

Title

Page no.

A schematic of the change from onshore to offshore in petroleum production in the late twentieth century

6

1.2.

An example of a pipeline being plugged by wax deposits on the wall

7

1.3.

Areas reported to have wax deposition problems across the world

7

2.1.

Cross Polarized microscope photo of wax oil gel

16

3.1.

Schematic of experimental set-up

24

3.2.

Effect of flow rate on wax deposition in Pipe 1

25

3.3.

Effect of flow rate on wax deposition in Pipe 2

26

3.4.

Effect of PPD concentration on wax deposition at Q = 80 LPM (Pipe 1)

27

3.5.

Effect of PPD concentration on wax deposition at Q = 90 LPM (Pipe 1)

28

3.6.

Effect of PPD concentration on wax deposition at Q = 100 LPM (Pipe 1)

28

3.7

Effect of PPD concentration on wax deposition at Q = 110 LPM (Pipe 1)

29

3.8.

Effect of PPD concentration on wax deposition at Q = 120 LPM (Pipe 1)

29

3.9.

Effect of PPD concentration on wax deposition at Q = 80 LPM (Pipe 2)

30

3.10.

Effect of PPD concentration on wax deposition at Q = 90 LPM (Pipe 2)

30

3.11.

Effect of PPD concentration on wax deposition at Q = 100 LPM (Pipe 2)

31

3.12.

Effect of PPD concentration on wax deposition at Q = 110 LPM (Pipe 2)

31

3.13.

Effect of PPD concentration on wax deposition at Q = 120 LPM (Pipe 2)

32

3

List of tables

Table.No. 3.1.

3.2.

Title Thickness of wax deposited in Pipes 1 and 2 at different temperatures and flow rates

26

Effect of PPD on wax deposition thickness at different temperatures for Pipe 1

1.3.

Page no.

32

Effect of PPD on wax deposition thickness at different temperatures for Pipe 2

33

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1. INTRODUCTION & BACKGROUND

1.1.

Introduction

Crude oil is a complex mixture of hydrocarbons, consisting of waxes, asphaltenes, resins, aromatics, and naphthenes. Wax deposition has become one of the most common flow assurance problems in the petroleum industry. This phenomenon can result in many problems such as decreased production rates, increased power requirements and failure of facilities. As petroleum resources shift from onshore reservoirs toward offshore subsea production, the industry is currently facing unprecedented challenges to maintain flow assurance for petroleum production, in which the strategy to prevent or mitigate wax deposition has become increasingly costly and complicated. Wax deposition is a critical operational challenge to the oil and gas industry. As early as 1928, wax deposition was reported as an issue that “presents many difficult problems while being produced, transported, and stored” (Reistle, 1932). Wax deposition problems occur in a wide range of locations in the petroleum production chain, including flow lines, surface equipment, and topside facilities, and downstream refineries. In some of the extreme cases, it can also occur in well tubings. The waxy components of crude oils, also known as n-paraffins, represent a group of nalkanes with carbon numbers that are usually greater than 20 (Lee, 2008). These components are normally dissolved in the oil at reservoir conditions where the temperature is relatively high. However, as the crude oil leaves the reservoir and travels toward processing facilities, its temperature can decrease substantially and potentially fall below the wax appearance temperature (WAT) (Berne-Allen & Work, 1938). When the waxy components can precipitate out of the oil and form solids, resulting in slurries in the oil flow that require higher pressure drop for transportation. More importantly, the precipitation of these components on the inner surface of the pipe wall can lead to the formation of wax deposits, which often occurs on the tubing, the pipelines, and the process equipment (Reistle, 1932). In early- to mid-1990s, the problem of wax deposition usually occurred during petroleum production on land or onshore resources (Reistle, 1932). In 1969, it was reported that the cost for wax control in U.S. domestic production amounted annually to $4.5–$5 million (Bilderback & McDougall, 1969). Because of easy access and management for these resources, the problem of onshore wax deposition can be addressed by relatively simple methods, including the optimization of the operating conditions (pipeline size, pressure, etc.). Heating of the pipeline or mechanical removal of the wax deposit was used occasionally and was generally not as prohibitive. It is during the late twentieth century that the problem of wax deposition has become increasingly challenging, as the production of petroleum fluids shifted from onshore resources toward offshore reservoirs around the world. A schematic of this shift is shown in Figure 1.1 (Huang, Senra, Kapoor, & Fogler, 2010). 5

Fig 1.1. A schematic of the change from onshore to offshore in petroleum production in the late twentieth century. (From Huang, Z. et al., AIChE J. 57, 841–851, 2011.)

Taking the United States as an example, large offshore reservoirs that are mainly by the coastlines of Louisiana, Texas, California, and Alaska have quickly become one of the most crucial elements to the United States’ strategic development of energy resources (Economic analysis methodology for the 5-year OCS Oil and Gas Leasing Program for 2012– 2017, 2011). While 20 million bbl of oils were produced from offshore in the Gulf of Mexico in 1995, this number has risen to 1400 million bbl in 2007 (Bai & Bai, 2012). The offshore petroleum fluids are usually transported in long-distance pipelines, which range from tens to hundreds of kilometers before they eventually reach onshore processing facilities (Golczynski & Kempton, 2006). The oil typically comes out of the reservoir at a temperature around 160°F and is cooled significantly as it is transported through the pipes on the ocean floor, where the water temperature is around 40°F. This temperature difference between the oil in the pipeline and the surrounding water on the ocean floor (160°F to 40°F) becomes the driving force that causes the oil in the pipeline to cool down. As the oil temperature decreases, the waxy components can precipitate out of the oil and form deposits on the pipe wall. The problem of wax deposition in the subsea pipeline has caused a series of problems for the flow assurance industry, including increased pressure drop needed for oil transportation and potential blockage of the pipeline. An example of a plugged pipeline due to wax deposition reported by Singh, Venkatesan, Fogler, and Nagarajan (2000) is shown in Figure 2.

6

Figure 1.2. An example of a pipeline being plugged by wax deposits on the wall. (From Singh, P. et al., AIChE J., 46, 1059–1074, 2000.)

The problem of wax deposition has become such a flow assurance concern that its severity must be assessed in the design of nearly every subsea development across the world, including the Gulf of Mexico (Kleinhans, Niesen, & Brown, 2000), the North Slope (Ashford, Blount, Marcou, & Ralph, 1990), the North Sea (Labes-Carrier, Rønningsen, Kolnes, & Leporcher, 2002; Rønningsen, 2012), North Africa (Barry, 1971), Northeast Asia (Bokin, Febrianti, Khabibullin, & Perez, 2010; Ding, Zhang, Li, Zhang, & Yang, 2006), Southern Asia (Agrawal, Khan, Surianarayanan, & Joshi, 1990; Suppiah et al., 2010), and South America (Garcia, 2001). The locations of these oil fields that have been reported to have concerns of wax deposition are highlighted in Figure 1.3.

Figure 1.3 Areas reported to have wax deposition problems across the world

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Significant operational hazards due to wax deposition have been reported over the past few decades. The U.S. Minerals Management Service reported 51 occurrences of severe waxrelated pipeline plugging in the Gulf of Mexico between the years 1992 and 2002 (Zhu, Walker, & Liang, 2008). One of the most severe cases was reported by Elf Aquitaine in which a removal of a wax-related pipeline blockage cost as much as $5 million. The remediation of this blockage resulted in a 40-day shutdown of the pipeline, which added an additional loss of $25 million of deferred revenue (Venkatesan, 2004). The arguably most notorious incidence might be from the Staffa Field, Block 3/8b, UK North Sea, in which the problem of wax deposition, after several unsuccessful attempts for remediation, eventually led to the abandonment of the field and its platform (Gluyas & Underhill, 2003), leading to an estimated loss of as much as $1 billion (Singh, 2000). One of the main approaches to prevent wax deposition in subsea operations is pipeline insulation. However, this solution could greatly increase the the pipe is subjected to wax deposition risk, the most frequently used remediation method is called “pigging,” which uses an inspection gauge with brushes or blades on its surface to scrape off the wax deposits on the wall (Golczynski & Kempton, 2006). Normal production is usually interrupted during the pigging operations, adding to the cost of production. The frequency of pigging can greatly influence the production cost. An estimate of deferred revenue based on a 29-km production pipeline and a production rate of 30,000 bbl/day with an oil price of $20/bbl at the time of the study is shown in Figure 1.4 (Niesen, 2002). It should be noted that the oil price nowadays has increased and thus, the production costs related to pigging will be much higher. As we can see from the above analysis, it is extremely important to have a sufficient and rigorous understanding of the physics and chemistry of wax precipitation/deposition in the pipeline in order to develop economically viable prevention/mitigation strategies. The establishment of such an understanding can be achieved through a series of laboratory characterizations as well as predictive modeling that incorporates the fundamentals of thermodynamics and transport phenomena.

1.2.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:   

High viscosity, which leads to pressure losses High-yield stress for restarting flow 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 8

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.

1.3. Introduction to Paraffins 1.3.1. Paraffins Paraffin precipitation and deposition in flowlines and pipelines is an issue impacting the development of deep-water subsea hydrocarbon reservoirs. The buildup of paraffin deposits decreases the pipeline cross-sectional area, restricts operating capacities, and places additional strain on pumping equipment. Hence it becomes necessary to understand paraffins. Waxes are typically long, linear or branched n-paraffin chains within produced hydrocarbons and primarily consist of paraffin hydrocarbons (C18-C36) and naphthenic hydrocarbons (C30 - C60). Hydrocarbon components of wax can exist in various states of matter (gas, liquid or solid) depending on their temperature and pressure. When the wax freezes, it forms crystals referred to as macrocrystalline wax.Those formed from naphthenes are known as microcrystalline wax. The solid forms of paraffin, called paraffin wax, are from the heaviest molecules from phytane (C20H42 ) to lycopane (C40H82 ). Paraffin wax is a white, odorless solid with a typical melting point between about 115°F and 154°F (46 and 68°C) having a density of around 0.9 g/cm3.Waxes have low thermal conductivity, a high heat capacity, and are insoluble in water. While constant deposition of wax can block production lines, it can also act as insulation due to its low thermal conductivity and high heat capacity, resulting in higher arrival temperatures during steady flowing conditions and longer cooldown times during shutdowns. Paraffin wax is soluble in ether, benzene and certain esters, while being unaffected by most common chemical reagents.

1.3.2. Paraffin Wax Management Paraffin deposition can cause a multitude of operational challenges including:    

Reduction of the internal diameter of the pipelines, which restricts and can ultimately block flow. Increased surface roughness on the pipe wall which causes increased backpressure and reduced throughput. Accumulations that fill process vessels and storage tanks, leading to system upsets and labor/OPEX-intensive cleanup and disposal problems. Interference with valve and instrumentation operation. 9



Increased risk of sticking pigs in the line and interference with the in-line inspection of flowlines and export lines by tools such as gauge pigs, caliper pigs and intelligent pigs.

All of these problems may result in production shutdowns, hazardous conditions, and damage to equipment. Paraffin wax mitigation/prevention can be either preventive or corrective. Preventive practices take steps to avoid paraffin deposits and growth. Corrective practices require the periodic removal of any deposits. A cost/benefit analysis of these solutions should be conducted before the final selection of a paraffin management strategy is made, where a combination of these approaches may be required in order to provide an optimized wax control strategy.

1.3.3. Paraffin Wax Mitigation & Prevention Techniques Some common wax mitigation/prevention techniques are:   

  

Optimized pipeline sizing and layout. Insulating the line to prevent heat loss and maintain flowing temperatures above the WAT. Injection of paraffin inhibitors, dispersants or solvents. Inhibitors need be injected above the WAT to be effective. Solvents can be used on existing wax deposits and dispersants when it is not possible to inject above the WAT. Controlled production of wax deposits by carefully monitoring the wax layer thickness. Use of non-metallic pipe linings and coatings to reduce the frictional drag and thereby reduce the effects of shear dispersion and molecular diffusion. Selection and use of a suitable pig design and periodic pigging of the line.

1.4. 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. 2. 3.

Thermal Chemical Mechanical

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1.4.1. 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. 1.4.2. 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. 11

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. 1.4.3. Mechanical  



Mechanical removal by using progressive pigging programs to remove accumulated deposits while ensuring that the use of an overly-aggressive pig will not result in the pig becoming stuck behind the wax accumulation. 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.

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References 1. Reistle, C. E. (1928). Methods of dealing with paraffin troubles encountered in producing crude oil. 2. Lee, H. S. (2008). Computational and rheological study of wax deposition and gelation in subsea pipelines (Ph.D. thesis). University of Michigan. 3. Berne-Allen, A., Jr., & Work, L. T. (1938). Solubility of refined paraffin waxes in petroleum fractions. Industrial and Engineering Chemistry, 30, 806–812. 4. Reistle, C. E. (1932). Paraffin and gongealing-oil problems. 5. Bilderback, C. A., & McDougall, L. A. (1969). Complete paraffin control in petroleum production. Journal of Petroleum Technology, 21, 1151–1156. 6. Han, S., Huang, Z., Senra, M., Hoffmann, R., & Fogler, H. S. (2010). Method to determine the wax solubility curve in crude oil from centrifugation and high temperature gas chromatography measurements. Energy & Fuels, 24, 1753–1761. 7. Economic analysis methodology for the 5-year OCS Oil and Gas Leasing Program for 20122017. (2011). Washington, DC. 8. Bai, Y., & Bai, Q. (2012). Subsea engineering handbook (1st ed.). Houston, TX: Gulf Professional Publishing. 9. Golczynski, T. S., & Kempton, E. (2006). Understanding wax problems leads to deepwater flow assurance solutions. World Oil, D–7–D–10. 10. Singh, P., Venkatesan, R., Fogler, H. S., & Nagarajan, N. (2000). Formation and aging of incipient thin film wax-oil gels. AIChE Journal, 46, 1059–1074. 11. Ashford, J. D., Blount, C.G., Marcou, J. A., & Ralph, J. M.(1990). Annular packer fluids for paraffin control: Model study and successful field application. SPE Production Engineering, 5, 351–355. 12. Kleinhans, J., Niesen, V., & Brown, T. (2000). Pompano paraffin calibration field trials. In SPE Annual Technical Conference and Exhibition (pp. 1–15). Dallas, TX: Society of Petroleum Engineers. 13. Labes-Carrier, C., Rønningsen, H. P., Kolnes, J., & Leporcher, E. (2002). Wax deposition in North Sea gas condensate and oil systems: Comparison between operational experience and model prediction. In SPE Annual Technical Conference and Exhibition. San Antonio, TX. 14. Barry, E. G. (1971). Pumping non-Newtonian waxy crude oils. Journal of the Institute of Petroleum, 57, 74–85. 15. Bokin, E., Febrianti, F., Khabibullin, E., & Perez, C. E. S. (2010). Flow assurance and sour gas in natural gas production. 16. Agrawal, K. M., Khan, H. U., Surianarayanan, M., & Joshi, G. C. (1990). Wax deposition of Bombay high crude oil under flowing conditions. Fuel, 69, 794–796. 17. Suppiah, S., Ahmad, A., Alderson, C., Akbarzadeh, K., Gao, J., Shorthouse, J., Jamaluddin, A. (2010). Waxy crude production management in a deepwater subsea environment. In SPE Annual Technical Conference and Exhibition (pp. 1–18). Florence, Italy: Society of Petroleum Engineers.

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18. Garcia, M. C. (2001). Paraffin deposition in oil production. In SPE International Symposium on Oilfield Chemistry (pp. 1–7). Houston, TX: Society of Petroleum Engineers. 19. Zhu, T., Walker, J. A., & Liang, J. (2008). Evaluation of wax deposition and its control during production of Alaska North Slope Oils—Final Report. 20. Venkatesan, R. (2004). The deposition and rheology of organic gels (Ph.D. thesis). University of Michigan. 21. Gluyas, J. G., & Underhill, J. R. (2003). The Staffa Field, Block 3/8b, UK North Sea. Geological Society, London, Memoirs, 20, 327–333. 22. Singh, P. (2000). Gel deposition on cold surfaces (Ph.D. thesis). University of Michigan. 23. Erickson, D. D., Niesen, V. G., & Brown, T. S. (1993). Thermodynamic measurement and prediction of paraffin precipitation in crude oil. In SPE Annual Technical Conference and Exhibition (pp. 353–368). Houston, TX: Society of Petroleum Engineers.

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2. LITERATURE SURVEY 2.1. Wax deposition During the early years of the oil industry, easy profits meant that pipeline operators could afford to be ambivalent about wax deposition and there was little incentive to analyse the phenomena. Although the cooling of oil was, self-evidently, the cause of wax deposition, there were few studies of the various parameters that control deposition rate and severity until mitigation of these deposits started to become prohibitively expensive, largely due to the move towards offshore oil recovery. Most of the theoretical models underpinning studies of wax deposition are based on oil-wax equilibria and equations-of-state. Essentially, these models are semi-empirical and require experimental measurements of WAT (Wax Appearance Temperature) to allow their application to specific crude oils. Won[1989] considered wax to be a solid solution of hydrocarbons into which all components of the crude oil could enter. He based oil-wax phase equilibria on the cooling curves of simple hydrocarbon mixtures. Subsequent studies have shown this model to over predict wax deposition when tested against 'real' crude oil samples, Pedersen et al [1991]. Also, WAT obtained from stock tank oils (STO's) has been shown to vary considerably depending on measurement method, Hammami [1997]. This raises the possible danger of an over-predictive model calibrated using inaccurate WAT values. Faroozibadi [1995] proposed that a more accurate model of wax deposition would take into account the range of solidification temperatures for different molecular weight waxes and suggested that they do not form a solid solution, but rather de-mix on solidification. This 'multi-solid' model for wax deposition was tested against the more traditional solid-solution model by Coutinho [2002]. Although Coutinho acknowledged that a 'multi-solid' model was more realistic, the de-mixing of wax on solidification is supported by experimental evidence, he concluded that the solid solution model's simplicity outweighed any limitations imposed by idealisation. Regardless of how idealized solutions are based on phase equilibria, they cannot accurately predict deposition without considering the dynamic environment in which these phase changes occur. Not only must the thermodynamics of deposition be understood but also the kinetics of the process. To this end, experimental studies have analysed mechanisms of wax deposition in flowing pipelines. In a study by Burger et al[1981] a laboratory flow circuit was set up to allow cooling of oil as it was circulated through ~inch pipes. From his observations and measurements of deposition rate Burger proposed mechanisms for deposition and identified controlling factors. The mechanisms for wax deposition he proposed were molecular diffusion, Brownian diffusion, gravity settling and shear dispersion. The controlling factors identified were radial temperature flux, the oil's WAT and the flow velocity and regime. Burger's observations and theoretical predictions are confirmed by later experimental studies by, amongst others, Hamouda and Davidsen [1995] and Creek et al [1998]. All of these experimental studies observed that in addition to the controlling factors affecting deposition 15

rate, they also affected the deposit's physical structure. In terms of removing wax, knowledge of the physical structure of the deposit is equally as important as predicting its deposition rate. The mechanical properties of wax deposits are a function of the distribution of different molecular weight hydrocarbons and the amount of oil entrained within the wax's crystalline structure. Once a deposit establishes itself on a pipe wall these parameters change over time and age hardening takes place. This phenomenon is of particular interest, as imposing time dependency on the deposit's mechanical properties can have a profound impact on remediation issues such as pigging frequency. Singh [2000, 2001] has performed a series of laboratory experiments to develop a model describing the aging and morphological changes in wax deposits. He proposed the existence of a critical carbon number within the wax-oil system above which wax molecules diffuse into the deposit and below which oil diffuses out into the bulk flow. The rate of this diffusion process is controlled by the radial temperature gradient within the deposit and the flow regime in the pipe. Also, in an experimental study, Cordoba and Schall [2001] provided confirmation of this theory, concluding from their own experiments that hardening of the wax deposit occurs due to solvent migration. Again, it is proposed that this solvent migration (or diffusion) occurs due to a temperature gradient between the cool pipe wall and the flowing oil. 2.2. Wax crystallization and Wax-Oil Gel Formation Ararimeh et al.(2011) have provided a critical review on the issue of wax formation in oil pipelines. The characteristics of wax-oil gels depend on the crystal morphology and structures of the crystal networks, which are strong functions of both thermal and shear histories (Singh et al., 2000). The crystallization of wax molecules below the cloud point temperature incurs formation of gels with a complex morphology. As shown in Figure 2.1., the structure of the wax-oil gel is an interlocking of various wax forms such as needles, plates and orthorhombic wax crystals, dependent on the cooling rate (thermal history), wax concentration and shear history (Dirand et al., 1998; Singh et al., 2000).

Fig. 2.1 Cross Polarized microscope photo of wax oil gel (Lee et al., 2007) 16

Cazaux et al. (1998) investigated the gel structure using X-ray diffraction (XRD), Smallangle X-ray scattering (SAXS), a cross-polarized microscopy (CPM) and a controlled stress rheometer (CSR). They reported that the key parameters that determine the structure of waxoil gel are the crystal shape (aspect ratio) and number density of wax crystals, both of which depend on the temperature and cooling rate. Chang et al. (1999) reported that the morphology of the paraffin crystals strongly depends on both the cooling rate and the shear stress applied to the mixture (Kane et al., 2003; Venkatesan et al., 2005). Recently Visintin et al. (2005) and Vignati et al. (2005) reported that waxy gels have the characteristics of colloidal gels and the radius of gyration of the wax-oil gel changes with cooling rate.

2.3. Pour Point Depressants

A variety of chemicals are available to pipeline operators that are generally referred to as Flow Improvers. One group of chemicals that fit into this category are wax inhibitors or Pour Point Depressants (PPDs). Inhibitors must be matched to the composition of the crude oil, and as composition may vary from one well to another (even from the same reservoir) and will also vary over time, periodic sampling and testing is necessary to ensure the chemical's effectiveness. The problem is exacerbated where a number of wellheads feed into a common riser and process facility, as is often the case in offshore production. Laboratory studies of the effectiveness of chemical inhibitors by the California Institute of Technology and Chevron Texaco revealed even greater concerns [Wang et al, 2003]. They found that in some instances the deposition of low molecular weight paraffins (>C34) was reduced but the amount of high molecular weight paraffins actually increased. Given the general correlation between molecular weight and strength, this is a most undesirable outcome. PPDs have been used which contain oil soluble long chain alkyl group and a polar moiety in the molecular structure. The long chain alkyl group insert into wax crystal and polar moiety exist on the wax surface and reduces wax crystal size.(El-Gamal et al.,1998; Holder and Winkler,1965). They contain crystal modifiers that prevent the formation of large wax molecules by bonding to the wax crystal and hindering further growth. These polymers need to be added to the crude oil before the wax begins to crystallize but are not universally effective, Garcia (1998, 2000), Chanda et al (1998). Inhibitors must be matched to the composition of the crude oil, and as composition may vary from one well to another (even from the same reservoir) and will also vary over time, periodic sampling and testing is necessary to ensure the chemical's effectiveness. The problem is exacerbated where a number of wellheads feed into a common riser and process facility, as is often the case in offshore production. Many theoretical and experimental studies have been put forward to explain the action mechanism of PPD for the control of wax crystallization.

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The most extensively used flow improver for fuel oils are ethylene-vinyl acetate copolymer (M.G. Botros (1997), J.C. Chen, (1985), N.A. Kidd (1982), S. IInyckyj, B. Charles (1962), M.J. Wisotsky, H.N. Miller (1972).) alkyl ester of unsaturated carboxylic acid-olefin copolymer(M.G. Botros (1997), H. Pieter, H. Rodolf (1973)), maleic anhydride alkyl ester of unsaturated carboxylic acid copolymer(L.M. Dong, S.W.Xie (1996), K. Liao, Y. Zhai (1999)). The crystalline lattice structure of wax gels with and without PPD had been studied by Srivastava et al. using XRD It was suggested that paraffin crystallized with a predominantly orthorhombic structure in isolated petroleum waxes. When forming gels in solvents, the lattice structure of wax changed to the hexagonal form. The pour point depressant additive hastened the development of hexagonal planes, the additive molecules seemed to provide the necessary energy to paraffin molecules to crystallize in this high energy form. The similar phenomenon was found by Zhang fusheng when he studied the interactions between wax and PPD using the infrared spectrometric (Vignati et al.(2005)). In general, inhibition of wax crystallization has been considered to occur in the presence of PPD by nucleation, co-crystallization or adsorption. It is generally believed that the PPD function by disrupting or preventing the formation of three-dimensional wax networks, leaving the amount of crystalline wax unaffected. However, based on the study of Srivastava(1992) and Zhang fusheng (1995) as well as the relation between the wax crystal structure and its thermodynamic properties, it can be concluded that the PPD can have an effect on the amount of crystallized wax. The paper dealt with high speed centrifuge and gas chromatography methods to study the effect of PPD on the amount and composition of wax precipitated from solutions. Differential scanning calorimetry and X-ray diffraction were used to study the blends of pour point depressant with paraffin wax to gain a better understanding of their interactions. S. IInyckyj and C. O. Cole (1976) thought that the response of fuels to flow improvers could be substantially improved by utilizing a dual functioning flow improver's composition, which is a combination of two different wax modifying compounds. One of these functions acts as a wax growth arrester while another acts as nucleating agent. In the past years, works have been directed to the combination of two or three compounds as flow improvers (N. Feldman (1980), N. Feldman, J.J. Habeeb (1992), S. IInyckyj (1979)) These additives were a combination of the conventional flow improvers and wax dispersants. The structure and composition of wax dispersants is similar to conventional flow improver in some feature, but different in others. They often possess highly polar functional groups. This polarity may reach a surfactant character, which is considered as the basic prerequisite for the dispersant potential. Polar nitrogen containing polymers can function as wax dispersants and flow improvers simultaneously in one component additive. Pour point is widely used to evaluate the low temperature flowability of crude oil, there are many factors affecting the flowability behavior of crude oil such as its chemical composition, temperature and the current, as well as previous thermal history. 18

References 1. Won, K W. Thermodynamic calculation of cloud point temperatures and wax phase compositions of refined hydrocarbon mixtures, Fluid Phase Equilibria Volume 53, December, Pages 377-396 (1989). 2. Pedersen, K S, Skovborg, P and Ronningsen, H P. Wax precipitation from North Sea crude oils. 4. Thermodynamic modelling, Energy & Fuels, 5, 924 (1991). 3. Hammami, Ahmed. Paraffin Deposition from crude oils: Comparison of laboratory results to field data, Paper presented at SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5th- 8th October, Paper No. SPE 38776 (1997). 4. Coutinho, Joao A P; Edmonds, Beryl; Moorwood, Tony; Szczepanski, Richard and 5. Zhang, Xiaohong. Reliable wax predictions for Flow Assurance, Presented at the SPE 13th European Petroleum Conference, Aberdeen, UK 29-31 October (2002). 6. Burger, ED; Perkins, T K; Streigler, J H. Studies of Wax Deposition in the Trans Alaska Pipeline, Journal of Petroleum Technology, June, 1075-1086 (1981). 7. Hamouda and Davidsen. An approach for simulation of paraffin deposition in pipelines as a function of flow characteristics with a reference to Tees ide Oil Pipeline, Paper presented at the Society of Petroleum Engineers' International Symposium on Oilfield Chemistry, San Antonio, TX, U.S.A., 14-17 February 1995 (1995). 8. Creek, J L; Hans, Jacob Lund; Brill, James P; Volk, Mike. Wax deposition in single phase flow, Fluid Phase Equilibria, Vol 158-160, Elsevier, 801-811 (1999). 9. Singh, Probjot; Venkatesan, Ramachandran; Fogler, H Scott; Nagarajan N R. Morphological Evolution of Thick Wax Deposits, AIChE Journal, Vol47, No 1, January, 6- 18 (2001 ). 10. Cordoba, A J and Schall, C A. Application of a heat transfer method to determine wax deposition in a hydrocarbon binary mixture, Fuel Vol. 80, 1285-1291 (200 1 ). 11. Cordoba, A J and Schall, C A. Solvent migration in a paraffin deposit, Fuel Vol. 80, 1279-1284 (2001). 12. Ararimeh , D P Chakrabarti, Angelus Pilgrim, M.K.S. Sastry. Wax Formation in oil pipelines: A critical review, International Journal of Multiphase Flow 37 (2011) 671694. 13. Dirand, M., V. Chevallier, E. Provost, M. Bouroukba, and D. Petitjean, “Multicomponent Paraffin Waxes and Petroleum Solid Deposits: Structural and Thermodynamic State,” Fuel 77, 1253 (1998). 14. Singh, P., R. Venkatesan, H.S. Fogler, and N.R. Nagarajan, “Formation and Aging of Incipient Thin Film Wax-Oil Gels,” AIChE J. 46, 1059 (2000) 15. Lee, H.S., P. Singh, W.H. Thomason, and H.S. Fogler, “Waxy Oil Gel Breaking Mechanisms: Adhesive versus Cohesive Failure,” Energy and Fuel, (2007) 16. Cazaux, G., L. Barre, and F. Brucy, 1998 SPE Annual Technical Conference and Exhibition, New Orleans, 27 (1998). 17. Chang, C., D.V. Boger, and Q.D. Nguyen, “Yielding of Waxy Crude Oils”, Ind. Eng. Chem. Res. 37, 1551 (1998)

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18. Kane, M., M. Djabourov, J.L. Volle, J.P. Lechaire, and G. Frebourg, “Morphology of Paraffin Crystals in Waxy Crude Oils Cooled in Quiescent Conditions and under Flow,” Fuel 82(2), 127 (2003) 19. Venkatesan, R., N.R. Nagarajan, K. Paso, Y.B. Yi, A.M. Sastry, and H.S. Fogler, “The Strength of Paraffin Gels Formed under Static and Flow Conditions,” Chem. Eng. Sci. 60(13), 3587-3598 (2005) 20. Visintin, R.F.G., R. Lapasin, E. Vignati, P. D'Antona, and T.P. Lockhart, “Rheological Behavior and Structural Interpretation of Waxy Crude Oil Gels,” Langmuir 21(14), 6240-6249 (2005) 21. Vignati, E., R. Piazza, R.F.G. Visintin, R. Lapasin, P. D'Antona, and T.P. Lockhart, “Wax Crystallization and Aggregation in a Model Crude Oil,” J. of Phys.: Condens. Matter 17(45), 3651-3660 (2005) 22. Holder, G.A., Winkler, J., 1965. Wax crystallization from distillate fuels. J. Inst. Petrol.51, 228–252. 23. I.E. El-Gamal, A.M. Atta, A.M. Al-Sabbagh, Fuel 76 (14/15) (1997) 1471–1478. 24. Garcia, Maria del Carmen; Carbognani, Lante; Urbina, Argelia; Orea, Miguel. Paraffin deposition in oil production. Oil composition and paraffin inhibitors activity, Journal of Petroleum Science and Technology, Vol. 16, Issue 9-10, Oct/Nov, 10011021 (1998). 25. Chanda, D et al. Combined effect of asphaltenes and flow improvers on the rheological behaviour of Indian waxy crude oil, Fuel, vol.77, No. 11, 1163-1167 (1998). 26. Wang, Kang-Shi; Wu, Chien-Hou; Creek, Jefferson L; Shuler, Patrick J; Tang,Yongchun. Evaluation of effects of selected wax inhibitors on paraffin deposition, Petroleum Science and Technology, Volume 21, Issue 4 (2003). 27. M.G. Botros (1997). U.S. Patent 5,681,359, October 28, 1997. 28. J.C. Chen, (1985). U.S. Patent 4,512,775, April 23, 1985. 29. N.A. Kidd (1982). U.S. Patent 4,362,533, December 7, 1982. 30. S. IInyckyj, B. Charles (1962). U.S. Patent 3,048,479, August 7, 1962. 31. S. IInyckyj, C.O. Cole (1976). U.S. Patent 3,961,916, June 8, 1976. 32. M.J. Wisotsky, H.N. Miller (1972). U.S. Patent 3,638,349, February 1, 1972. 33. H. Pieter, H. Rodolf (1973). U.S. Patent 3,726,653, April 10, 1973. 34. L.-M. Dong, S.-W. Xie, Acta Petroeli Sinica Chinese (Petroleum Processing Section) 12 (4) (1996) 66. 35. K. Liao, Y. Zhai Pet, Sci. Technol. 17 (1&2) (1999) 51. 36. J. Zhang, Ch. Wu, W. Li, Y. Wang, H. Cao, DFT and MM calculation: the performance mechanism of pour point depressants study, Fuel 83 (2004) 315–326. 37. Srivastava SP, Tandon RS, Verma PS, Saxena AK, Joshi GC, Phatak SD. Crystallization behavior of n-paraffins in Bombay-High middle-distribution wax/gel. Fuel 1992;71:533–7. 38. S. IInyckyj, C.O. Cole (1976). U.S. Patent 3,961,916, June 8, 1976. 39. S. IInyckyj (1979). U.S. Patent 4,147,520, April 3, 1979 40. N. Feldman, J.J. Habeeb (1992). U.S. Patent 5,094,666, March 10, 1992. 20

3. EXPERIMENTAL WORK In this study, the effects of various parameters on pressure drop reduction and ultimately wax deposition thickness achieved by addition of 200-1000 ppm PPD has been investigated. In order to make a comprehensive analysis of various operating parameters such as temperature, oil flow rate, pipe diameter and concentration of PPD, some experiments have been carried out with several concentrations of PPD at four different operating temperatures. A flow loop apparatus was designed to determine the effect of temperature, flow rate and PPD addition on wax deposition. The apparatus is shown schematically in figure 3.1.

3.1. Experimental Apparatus Experimental Setup: The experimental setup consists of a oil bath with 30L capacity which is equipped with temperature control system and mechanical stirrer, a stainless steel double-pipe heater, a chilling/ heating circulator, a centrifuge pump variable drive, valves for regulating the flow of crude oil, and thermocouples for temperature reading and a pipeline. Test section: The test section consists of two horizontal independent stainless steel pipes (SS-304) of 0.0508 m (2 inches) and 0.0254 m (1 inch) diameter and 2.5 meters length. The whole length of the pipeline and exposed surfaces are completely insulated to minimise heat loss. Pressure transducers were fitted at both the ends of the pipeline to measure the pressure drop. Flow meters were placed at the outlet of each pipeline. Valves were operated for varying flow rates in the test section. Both, oil flow and water in oil as dispersed flow were kept in circulated mode until the loop reached its stabilization condition for a particular flow rate and temperature. Data acquisition: The data acquisition section consists of pressure transducers, flow meters, temperature sensors connected to a control panel where the input data can be controlled as per requirement. Gear pump was used to circulate waxy crude oil from the oil bath through the pipeline test sections. Waxy crude oil and the coolant (water) temperatures were adjusted at the desired values by controlling the bath and the chilling circulator temperatures. Volumetric flow meters were used to measure flow rates of waxy crude oil. The water bath was heated and the water was flowed through the jackets of the two test sections to liquefy remove all the fluid that remains in the pipe after termination of an experiment.

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3.2. Wax deposition calculations The method of calculating wax deposition is based on the concept that wax deposition in a pipe section reduces the hydraulic diameter of the flowing fluid inside the pipe, resulting in an increase in friction pressure drop over the pipe section. The friction pressure drop across a section of pipe with wax deposited inside can be calculated using the Equation 3.1 𝐿 𝜌

∆p𝑓 = 4𝑓 d

2

4𝑄 2

(𝜋d2 ) .............................(3.1)

where ∆p𝑓 is the pressure drop L is the length of the pipe section D is the hydraulic diameter or effective inside diameter Q is the volumetric flow rate ρ is the fluid density f is the fanning factor

A waxy crude oil often behave as a non- Newtonian fluid when temperature becomes lower than the cloud point and wax crystals are present in the crude oil. However, when the wax content is low, e.g. less than 5% by weight, this non-Newtonian behavior is not appreciated and the crude oil can be treated as Newtonian fluid. But in this case the wax content of the crude oil in study is 11.3 which is very high and will contain good amount of asphaltenes and wax crystals. The friction factor in Equation 4.1 can be estimated from Equation 3.2 with the help of Equation 3.3. −n 𝑓 = 𝑐N𝑅𝑒

NRe =

4𝜌𝑄 𝜋µ𝑑

..................................(4.2) .................................(4.3)

where µ is the apparent viscosity of the crude oil c=16, n=1 for laminar flow and c = 0.046, n = 0.2 for turbulent flow. Laminar flow exists when NRe