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A Review of Wax-Formation/Mitigation Technologies in the Petroleum Industry Article  in  SPE production & operations · December 2017 DOI: 10.2118/189447-PA

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PO189447 DOI: 10.2118/189447-PA Date: 15-December-17

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A Review of Wax-Formation/Mitigation Technologies in the Petroleum Industry Meagan White, Kelly Pierce, and Tathagata Acharya, California State University, Bakersfield

Summary Wax or paraffin formation in subsea pipelines is a major problem in the upstream petroleum industry, accounting for tremendous economic losses. Researchers have reported that approximately 85% of the world’s oils encounter problems from wax formation (Thota and Onyeanuna 2016). In this manuscript, the authors briefly discuss the mechanism of wax formation in pipelines. Next, a review of various wax-mitigation technologies is provided. The review includes citations of various thermal, chemical, mechanical, biological, and other innovative methods reported by previous researchers and used in the industry. Introduction Flow assurance is a relatively newer term used in the oil and gas industry that refers to the flow of hydrocarbons from the reservoir to the onshore receiving facilities. Flow assurance is especially significant in the subsea oil and gas industry, which involves deepwater drilling. Hydrocarbons are obtained from subsea wells and are transferred to onshore facilities through a network of flowlines, subsea manifolds, platforms, and trunkline. Fig. 1 shows a schematic of a subsea network. Trunkline to onshore Platform

Sea

Flowline Subsea manifold

Well 1

Seabed

Well 2

Fig. 1—Schematic of a subsea oil and gas network.

At large depths, high pressures and temperatures are encountered and the flow-assurance technologies aim at reducing the pressure drop between the reservoir and the onshore facilities. The pressure drop across a well transporting the hydrocarbons is a combination of the following two factors. The first factor is difference in pressure heads, as shown by ðh PReservoir  PWell ¼ g qðyÞdy; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ð1Þ 0

where PReservoir is the reservoir pressure, PWell is the well outlet pressure, g is the acceleration caused by gravity, and q is the density of hydrocarbon as a function of well depth. The second factor is the frictional pressure drop in the well as shown by PReservoir  PWell ¼ f

L qV 2 ; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ð2Þ D 2

where f is the friction factor, L is the measured depth of the well, D is the diameter of the well, q is the density of hydrocarbons, and V is the flow velocity. Pressure drops through wells and subsea flowlines are influenced by several factors: 1. Hydrocarbon composition in wells. Hydrocarbons contained within wells are in a multiphase state. Hydrocarbons in liquid form have larger density than the hydrocarbons in gaseous form. As given by Eqs. 1 and 2, pressure drop across wells is directly proportional to the density of hydrocarbons, and therefore wells with more liquids will give rise to larger pressure drops. 2. Flow velocity in wells. As shown by Eq. 2, pressure drop varies as a square of flow velocity. Therefore, with increasing flow velocity, the pressure drop across a well will increase rapidly.

C 2017 Society of Petroleum Engineers Copyright V

Original SPE manuscript received for review 7 March 2017. Revised manuscript received for review 20 August 2017. Paper (SPE 189447) peer approved 7 September 2017.

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3. Effect of temperature on hydrocarbons. Hydrocarbon compositions that predominantly contain gases are highly influenced by temperatures. With increase in temperature, the gas velocities increase, and as shown by Eq. 2, the pressure drop increases across the well. 4. Measured depth (MD) of wells. As shown by Eq. 2, the pressure drop through a well increases with increasing MD. 5. Friction in wells. Eq. 2 shows that the pressure drop across a well increases with increasing friction factor. 6. Gravity forces. Eq. 1 shows that the pressure drop across a well increases with increasing head, and therefore the gravity forces are extremely significant. 7. Bathymetry. Pressure drop across flowlines is highly influenced by flowline bathymetry. Pipelines with a greater number of bends caused by bathymetry experience larger pressure drops. 8. Valves and process modules. Valves and process modules in flowlines give rise to larger pressure drops. 9. Formation of solid deposits in pipelines. Formation of solid deposits in pipelines in the form of hydrates, asphaltene, and wax chokes the pipelines and creates large pressure drops across them. Wax Formation in Pipelines Wax formation and deposition in subsea crude-oil pipelines are major flow-assurance problems that cause heavy losses to the industry. Severe wax deposition in Lasmo Field, UK, resulted in the abandonment of the entire field, and losses in the region of USD 100 million were incurred (Singh et al. 2000; Nguyen et al. 2001). Waxes are classified as microcrystalline and macrocrystalline waxes (Dorset 2000; Elsharkawy et al. 2000; Kumar et al. 2004). Macrocrystalline or n-paraffin waxes are the principal constituents, which have elongated structures such as rods, plates, and needles (del Carmen Garcia et al. 1998; Kane´ et al. 2002). These typically consist of 20 or more carbon atoms, but waxes containing up to 80 carbon atoms have been reported (Woo et al. 1984). Microcrystalline waxes are composed of iso-paraffin or branched-chain paraffins and naphthenes (Misra et al. 1995; Bacon et al. 2010). These have smaller rounded structures (Bacon et al. 2010). Macrocrystalline waxes constitute approximately 80 to 90% of the total wax content, while the rest are microcrystalline waxes such as branched chain paraffins and naphthenes (Rehan et al. 2016). The mitigation technologies discussed in the present manuscript relate predominantly to macrocrystalline waxes forming in subsea pipelines. Wax or paraffin tends to precipitate when the temperature of the crude oil falls below the wax-appearance temperature (WAT) or cloud point, which is typically between 95 and 130 F (Coberly 1942). When crude oil flows from the wellbore, the pressure drops cause solution gases to liberate. Thus, the temperature drops, the viscosity increases, and the hydrocarbon composition changes. As the temperature reduces to WAT, wax molecules form clusters of chains. However, the crystals grow only when the nuclei reach a critical size, attain stability, and facilitate further attachment. Wax deposition in pipelines is largely influenced by the composition of oil. Wax or saturate composition in oil can be determined through saturate/aromatic/resin/asphaltene (SARA) analysis. The analysis involves dividing a sample of crude oil into the four fractions (saturate, aromatic, resin, and asphaltene) according to their polarizability and polarity. Although the saturate or wax fractions consist of nonpolar materials including linear, branched, and cyclic saturated hydrocarbons, aromatics contain more polarizable material. Finally, resins and asphaltenes have polar substituents (Aske et al. 2001; Fan et al. 2002). SARA analysis is performed using three established methods: gravity-driven chromatography (ASTM), high-pressure liquid chromatographic, and thin-layer chromatography, the details of which are explained elsewhere (Fan et al. 2002). The ASTM method requires a large oil sample for the analysis, and asphaltene is removed from the sample before chromatography is performed. This method is also the slowest and is hard to automate. The high-pressure liquid-chromatographic method is an improvement over the ASTM method because it is faster and less difficult to automate. However, like the ASTM method, it also requires removal of asphaltenes before chromatography can be performed. Finally, the thin-layer chromatography method is the most improved of the three methods, and is the fastest. It also does not require asphaltenes to be separated before chromatographic analysis (Fan et al. 2002). SARA analysis is also useful toward understanding the flow behavior of crude oils. A crude oil is regarded as heavy when its  API value, shown by Eq. 3, is less than 20 (Dusseault 2001): API gravity ¼

141:5  131:5; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ð3Þ Sg

where Sg is specific gravity. Heavy oil is highly viscous and cannot flow easily through the wells. SARA analysis reveals that heavy crude oils contain larger weight percentages of asphaltene and resin compared with conventional oil. Table 1 shows typical composition by weight percentages of conventional and heavy crude oils (Santos et al. 2014). Several research groups studied flowability of crude oils as a function of SARA components. Leontaritis and Mansoori (1988) reported that the resins/asphaltenes ratio determined asphaltene stability and flow behavior of crude oils. A colloidal-instability index has been defined as the ratio of asphaltenes/saturates to asphaltenes/resins, and is used as a similar correlation (Por 1992; Asomaning and Watkinson 1999). A comparative study conducted using SARA analysis between a heavy crude oil and a waxy crude oil showed that the waxy crude oil had a larger percentage of asphaltene, whereas the heavy crude oil had a larger percentage of resin. The study revealed superior stability of waxy emulsions and therefore better flowability of waxy crude oil, with water cut as high as 70% vs. only 50% in heavy crude oil. Formation of stable waxy emulsions would inhibit wax deposition in pipelines (Paso et al. 2009). Composition (wt%) Asphaltene

Resin

Oil Fraction

Conventional oil

0.1–12

3–22

67–97

Heavy oil

11–45

14–39

24–64

Table 1—Composition of conventional and heavy oils (Santos et al. 2014).

Wax-deposition mechanisms in pipelines have been studied extensively by researchers. Wax deposition takes place through three stages: wax separation, wax-crystal growth, and wax deposition (Khanifar et al. 2011). During the initial stages of deposition, the concentration of wax crystals in deposits is in the range of 5 to 10 wt%. With the increase in deposition, wax becomes harder, and the yield 2

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stress increases and therefore it becomes more difficult to mitigate the deposits (Kang et al. 2014). Burger et al. (1981) have shown that during startup operations, wax deposition is a consequence of three separate mechanisms through which both dissolved and precipitated wax crystals are transported laterally: molecular diffusion, Brownian motion, and shear dispersion. Molecular Diffusion. This enables the diffusion of dissolved wax constituents. When the temperature of crude oil flowing through the pipeline falls below the WAT, tiny wax crystals are precipitated and liquid oil will be in equilibrium with those solid crystals. The quantity of these crystals that can remain dissolved in liquid oil decreases with decrease in temperature. With crude oil flowing, the temperatures at the walls of the pipeline are lesser than the temperatures at the center of the pipeline. The temperature profile along the wall will create a concentration gradient of dissolved wax and will lead to transportation of wax toward the wall through molecular diffusion, as shown by @G @C ¼ Df  A  ; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ð4Þ @t @y where G is the total solid deposition by molecular diffusion, . Df is the molecular-diffusion coefficient for deposition, A is the surface @C area available, C is the concentration of wax in oil, and is the concentration gradient. Therefore, Eq. 4 can be rewritten as @y . . Wm ¼ qs  A  Df  @C  dT ; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ð5Þ @T dy . @C is the solubility coefficient of wax crystals in oil, qs is where Wm is the rate of wax-crystal . deposition caused by molecular diffusion, @T dT the wax-crystal density, and is the radial-temperature gradient at the wall, which can be evaluated through a heat-transfer analysis. dy Brownian Motion. Brownian motion facilitates lateral transport of already precipitated wax particles. As the thermally excited oil molecules collide with the already precipitated small solid-wax crystals, Brownian movements of wax crystals are created, and with the concentration gradient leads to net transport of these particles toward the pipeline walls. Eq. 6 shows Brownian diffusion: . DB ¼ ðR  TÞ ; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ð6Þ ð6p  l  d  NÞ where DB is the Brownian-diffusion coefficient, R is the gas constant, T is absolute temperature, l is dynamic viscosity, d is the particle diameter, and N is Avogadro’s number. Shear Dispersion. With small solid particles suspended in a liquid in laminar flow, the particles tend to move in the direction of the surrounding liquid. However, mutually induced velocity fields are created that facilitate movements in the transverse directions. In such flows, the particle speed is equal to the streamline speed at the center, and the particles rotate with angular velocity equivalent to onehalf the shear rate. The rotating particles impart circulatory motion to the layer of liquid adjacent to the particle. The drag force on neighboring particles by the rotating liquid causes large temporary displacements. This is called shear dispersion, and is shown by DS ¼

d2  c  C ; . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ð7Þ 10

where d is the particle diameter, Ds is the shear-dispersion coefficient, c is the oil-shear rate at the wall, and C is the concentration of wax out of the solution at the wall. Several researchers have proposed different mathematical models to understand wax deposition. Huang et al. (2011) developed a model, the Michigan wax predictor, to predict the growth, deposition thickness, and wax fraction during wax formation in pipelines. This model applies molecular diffusion as the deposition mechanism for wax formation (Huang et al. 2011). Ridzuan et al. (2017) focused on the development of a mathematical model to predict wax deposition and to determine the relationships between various process variables, such as temperature differential between crude oil and pipeline walls, wax composition in crude oil, cooling rate along the pipelines, and flow rate of hydrocarbons. They also used their experimental apparatus, a rotatable central composite design, to obtain a minimum yield of wax deposition. They used response-surface methodology to evaluate the optimized conditions for minimal wax deposition (Ridzuan et al. 2017). Wax-Formation-Prevention/Removal Techniques Prevention of wax formation in subsea flowlines is of significant interest to the petroleum industry. There are several established methods used in the industry, and several significant technologies in decreasing order of their frequency of application in the field are discussed in the following section. Method a: Mechanical Removal. Mechanical-removal techniques are the oldest wax-removal techniques applied in the industry. The following are some established mechanical-removal techniques. Scrapers and cutters are used in well tubing to remove wax. Using these devices, wax may be removed by scraping from the tubing wall while the well is still producing. Although such methods are economical, one major disadvantage is plugging of perforations within wells as a result of circulation of scraped paraffin through the well annulus. Another disadvantage is associated with wireline scrapers being stuck in wells during post-cleaning operations (Al-Yaari 2011). The efficiency in gas lift wells may be enhanced by using free pistons to remove paraffin from such wells (Al-Yaari 2011). Use of pipeline-inspection gauges (PIGs) is a mechanical method that is the oldest and among the most widely used wax-removal techniques in the field, and has been reported previously (Koshel and Kapoor 1999; Craddock et al. 2007; Shecaira et al. 2011; Goodman and Joshi 2013; Kang et al. 2014). PIGs have been used in the petroleum industry for more than a century, and there are arguments that suggest the acronym “PIG” may also have been derived from the squealing noise they make while traveling through a pipeline (The Pigging Products and Services Association 1995). A PIG is launched from a PIG launcher, which is a section of the pipeline with a larger diameter gradually reducing to the normal diameter of the pipeline. As the PIG is launched, the launching station is closed and the 2017 SPE Production & Operations ID: jaganm Time: 18:31 I Path: S:/PO##/Vol00000/170051/Comp/APPFile/SA-PO##170051

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pressure-driven flow of the hydrocarbon in the pipeline pushes the PIG through to the receiving center. The PIG while traveling can scrape off the wax deposits from the pipeline walls. Fig. 2 shows how a cleaning PIG can operate within a section of a subsea pipeline. Some of the advantages of using PIGs include low labor costs, simplicity of operation, and less downtime because cleaning may be faster compared with some of the other methods. However, retrieving a PIG that is stuck in a pipeline may be very expensive (Fung et al. 2006).

PIG-launching end

A cleaning PIG PIG-receiving end

Wax deposition along walls

Fig. 2—Use of PIGs.

Method b: Chemicals as Wax Inhibitors. Use of chemical inhibitors for wax mitigation in the field has been reported by several researchers (Koshel and Kapoor 1999; Craddock et al. 2007; Goodman and Joshi 2013; Kang et al. 2014). Wax inhibitors are added to oils with high wax content to minimize problems associated with transporting oil. There are three types of wax inhibitors: wax-crystal modifiers, detergents, and dispersants. The detergents and dispersants are surface-active agents that primarily keep wax crystals dispersed as separate particles and reduce their ability to interact and adhere to solid surfaces. These surface agents partly function by modifying the surface of the pipeline wall. One example is wetting the pipeline surface by water to prevent adhesion of paraffin. Some surfactants also solubilize the nucleus and prevent paraffin agglomeration (Al-Yaari 2011). Wax-crystal modifiers have structures similar to precipitating wax crystals. They coprecipitate with wax and compete with wax crystals by occupying their positions on the crystal lattice through hydrocarbon chains. Alternatively, they also create hindrances toward the growth of wax crystals. Wax-crystal modifiers are also known as pour-point depressants. The pour point is the minimum temperature at which oil flows freely under its own weight and specified test conditions. The pour-point depressants can alter the growth and surface characteristics of wax crystals. With pour-point depressants, wax crystals have reduced the tendency of forming 3D structures and sticking to metal surfaces such as pipeline walls. Pedersen and Rønningsen (2003) tested 12 different commercial pour-point depressants and concluded that viscosity reduction in crude oils with wax was the highest within the temperature range of 10 to 25 C. Wei (2015) provided a review of several newly developed wax-crystal modifiers such as ethylene-vinyl acetate, polyethylene-poly (ethylene-propylene), poly (ethylene-butene), and poly (maleic anhydride amide co-a-olefin), and concluded that the performance of wax-crystal modifiers was a strong function of their ability to cocrystalize with wax. Therefore, in addition to the structure of the wax-crystal modifier, its composition is also significant. The efficiency of wax-crystal modifiers is increased by using them with solvents (Wei 2015). The disadvantage of using chemical inhibitors is that they must be used before the bulk temperature of crude oil drops below the WAT. Method c: Hot Oiling/Hot Watering. Several thermal methods of wax mitigation, such as hot oiling/watering and thermal coatings (explained later in the subsection Surface Coatings and Thermal Management), have been used in the field (Esaklul et al. 2003; Goodman and Joshi 2013; Kang et al. 2014). Hot oiling or hot watering is the method of injecting hot oil or hot water into wells in an attempt to dewax wellbores. Hot oil or water at 150 to 300 F (approximately 65 to 150 C) is pumped into the casing or tubing to melt waxes (Newberry and Barker 1985). It is one of the most-common methods used in the field. The biggest advantage is perhaps associated with it being a simple method and that it may not require complicated instrumentation. However, the effectiveness of hot oil/water injection depends on the location of wax in the tubing. Because the heat capacity of the injected liquid is much lower than the heat capacity of the well, the liquid starts cooling fast and may not be as effective when paraffin is at larger depths (Mansure and Barker 1993). In addition, hot oil injection may cause formation damage over time, which has been discussed in petroleum literature (Reistle and Blade 1932; Barker 1987; Nanniger and Nanniger 1990; Noll 1992; Newberry and Barker 2000). However, there are various advantages of this method, such as its simplicity of application, low costs, and immediate results (Barker 1987). Method d: Chemical Solvents. Chemical solvents are used when crude oils are highly sensitive to surfactants, and form emulsions or produced water with high concentration of dissolved solid particles. They are useful toward dissolving only a specific weight of wax dependent on molecular weight (MW), pressure, and temperature (Newberry and Barker 1985; Bimuratkyzy and Sagindykov 2016). Some of the commonly used chemical solvents to dissolve wax formations are carbon tetrachloride, carbon disulfide, kerosene, and diesel oil (Al-Yaari 2011; Bimuratkyzy and Sagindykov 2016). The advantage of using chemical solvents is that they are inexpensive and may not require complicated instrumentation. However, this method may be less efficient toward dissolving wax plugs with larger masses. Method e: Exothermic or Fused Chemical Reactions. This technique involves exothermic chemical reactions with controlled heat emission to remove wax deposits in pipelines (Singh and Fogler 1998; Nguyen et al. 2001, 2003, 2004; Nguyen and Fogler 2005). Fused chemical reactions undergo a delay before significant product formation. Nguyen et al. (2001) performed a fused chemical reaction between sodium nitrite and ammonium chloride catalyzed by citric acid encapsulated in polymer-coated gelatin capsules. They suggested that because of the characteristic delay, a highly fused exothermic chemical reaction will produce substantial heat to melt and redissolve wax at the desired location (Nguyen el at. 2001). Using the encapsulation technique, either the catalyst or one of the reactants is encapsulated. Thus, the release of the catalyst into the bulk solution is controlled. Therefore, the exothermic reaction between sodium nitrite and ammonium chloride was delayed by the controlled release of the encapsulated catalyst, which was citric acid. The 4

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polymeric coating on the capsule had to dissolve before the catalyst was released into the solution and heat was generated. The thickness of the polymeric coating determined the extent of delay of heat release. Another significant example of wax removal using exothermic reactions is the nitrogen-generation system. This is a novel technology to dissolve wax formed in pipelines, which has been developed, field tested, and commercialized by Petrobras Research Center. This method involves introduction of two inorganic salts and organic solvents to a line. Their chemical reaction generates nitrogen and heats the internal sections of a pipeline where wax has formed. The heat is used to dissolve the wax plug. It is then flushed out of the pipeline (Khalil 1996). The disadvantage of using exothermic chemical reactions as a method to mitigate wax formation is related to higher costs because of the requirement of expensive chemicals, catalysts, and polymer coatings. The chemicals used may also be toxic (Sadeghazad and Ghaemi 2003). Finally, exothermic chemical reactions are an indirect method of heat generation compared with direct methods such as hot oiling/watering. Method f: Surface Coatings and Thermal Management. Researchers have also studied the effect of plastic coatings on wax deposition. It was shown that plastic coatings decreased the weights of wax deposits by 30 wt% or more for high-MW wax because of thermal insulation (Patton and Casad 1970). For their experiments, Patton and Casad (1970) studied three different waxes: Cit-Con 350, Shellwax 200, and Cit-Con recrystallized heavy-intermediate wax. The recrystallized heavy-intermediate wax has a much-larger MW than the other two waxes and is representative of the natural paraffin deposits in pipelines (Nathan 1955; Graves and Tuggle 1968). Recently, coating the internal surfaces of a pipeline with a new polymer, ethylene-tetrafluoroethylene (ETFE), has been reported as a useful method to inhibit wax formation. A test was conducted with three different pipes: a pipe with ETFE internal-plastic-pipe coating, a pipe with rigid polyvinyl chloride internal-plastic-pipe coating, and a steel pipe. The ETFE pipe with the least roughness showed the best results (Bagdat and Masoud 2015). Such surface treatments preclude the need for chemical injectors or storage containers for hot water/oil during heating operations. However, mitigation of wax by providing surface coatings may be more expensive than most other methods discussed. Method g: Wax Mitigation by Microbial Treatment. Using microorganisms for wax mitigation, although not very widely used, has been successfully used on some fields of the Mehsana Asset of Oil and Natural Gas Corporation Limited (Biswas et al. 2012). Biosurfactant-producing bacterial cultures have been reported that aid in wax mitigation in pipelines. Strains such as the Pseudomonas species and Actinomyces species have been shown to reduce heavy hydrocarbon fractions and increase C15 to C20 fractions when crude oil was treated with these bacteria. Crude-oil properties were improved by lowering the WAT, thus making pipelines with flowing crude oil less susceptible to wax formation (Etoumi 2007). A bacterial strain, Geobacillus TERI NSM, has been identified that can help degrade crude-oil paraffin at high temperatures. Such bacteria degrade the paraffin under high-temperature, low-oxygen, and low-nutrient conditions while sparing low-carbon-chain paraffin (Sood and Lal 2008). Lazar et al. (1999) studied a special bacterial consortium (SBC1) and reported that they were efficient in preventing and controlling solid- as well as semisolid-paraffin deposition. Although this is an innovative method, microbial treatment may only be used in wells that produce water and where the bottomhole temperature is lower than 200 F. This is because the microbes used require water to survive and may not be able to withstand extremely high temperatures (Towler and Rebbapragada 2004). Method h: Cold Flow. Cold flow is the method of generating a slurry of solid deposits in a controlled way such that they do not adhere to the pipeline walls (Merino-Garcia and Correra 2008). One of the earliest known cold-flow technologies was patented by Coberly (1942). Wax crystals typically form on the walls of a pipeline when the temperature of the wall falls below the WAT or the crystallization temperature of wax. Coberly (1942) suggested that wax deposition may be retarded by reducing the temperature of the oil that contains wax to well below the crystallization temperature. It was also mentioned that by adding fine particles of resin with a melting point greater than the crystallization temperature of wax, the resin particles acted as nucleation sites for wax and would prevent deposition of wax crystals along the pipeline walls (Coberly 1942). Merino-Garcia and Correra (2008) mentioned that the feasibility of cold flow could be validated by eliminating the temperature gradient and cold wall. Fig. 3 shows the cold-flow scheme redrawn by the authors using the work by Merino-Garcia and Correra (2008).

Dissolved wax Precipitated wax

T (bulk)>WAT, only dissolved waxes

T (bulk) = Twater, only dissolved waxes

Fig. 3—Cold-flow scheme (Merino-Garcia and Correra 2008).

Argo et al. (2007) invented a similar cold-flow technology where hydrocarbons containing wax and other solid deposits such as asphaltenes, or any other precipitating solids, could be transported through pipelines (Argo et al. 2007). This technology involves introducing hydrocarbons into a reactor, where they are mixed with a flow of cold fluid with a temperature lower than the crystallization 2017 SPE Production & Operations ID: jaganm Time: 18:31 I Path: S:/PO##/Vol00000/170051/Comp/APPFile/SA-PO##170051

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temperature. Fig. 4 shows a simple schematic of this technology, which is explained here. Warm oil containing dissolved wax enters the reactor. At the same time, cold oil/condensates containing small crystals enter the reactor as shown in Fig. 4. The small crystals in the cold oil may be carbonates, salts, wax, asphaltenes, or any other crystals that can act as nucleation sites. When warm oil is mixed with cold oil, the precipitators precipitate as small crystals on the nucleating sites and are carried by the flowing hydrocarbons without causing deposits or blockages. The extent of subcooling may be maintained either by enough cold liquid or by sufficient heating inside the reactor (Argo et al. 2007).

Warm oil containing precipitators enter the reactor

Reactor where mixing takes place

Pipeline carrying hydrocarbons to a downstream location

Cold oil containing nucleation sites is introduced into the reactor Fig. 4—Cold-flow method for transporting hydrocarbons containing wax (Argo et al. 2007).

However, the cold-flow technology has not been implemented by the industry for field use. It has been a research and development project that has progressed to the stages of laboratory prototypes and pilot testing. Method i: Cold-Oil Recirculation. C-FER Technologies in Edmonton, Canada, have proposed the recirculation of cold oil to reduce the temperature of crude oil and thus inhibit wax formation on pipeline walls (Al-Yaari 2011). Fig. 5 shows the apparatus from Al-Yaari (2011) redrawn by the authors. Nenniger and Nenniger (2005) reported a method of using cold, unheated oil for recirculation and for stimulating heavy-oil production. However, this method may not be suitable when wax has already solidified on the walls of pipelines.

Chilled oil

Dissolved wax

Precipitated wax Fig. 5—Cold-oil recirculation (Al-Yaari 2011).

Method j: Choke Cooling. Knowles (1987) developed a technology where a stream of gas and waxy oil was suddenly cooled by letting it pass through a choke to form wax/oil slurry. The slurry could be transported through pipelines without wax deposition along the pipeline walls. Fig. 6 shows a conceptual representation of the apparatus redrawn by the authors using the work by Knowles (1987). However, creating the choke geometry may be expensive, and the method may not be effective when wax plugs already exist in a pipeline. A breakaway wax plug traveling with a high velocity may damage the choke region of the pipeline. Flow direction

Gas

Dissolved wax

Precipitated wax

Fig. 6—Choke cooling (Merino-Garcia and Correra 2008).

Method k: The Wax Eater. Using this technology by Kellogg, Brown, and Root and Halliburton, hot oil enters a flow loop when the ambient temperature is much lower and is maintained at lower than WAT. This encourages the formation of wax in oil but also reduces the oil temperature to approximately the seabed temperature (Benson 2000; Kalpakci et al. 2000; Fung et al. 2003). Thus, the wax dispersed in oil does not move toward the walls to accumulate there. The amount of recirculating fluid must be greater than the amount of oil that enters the flow loop (Merino-Garcia and Correra 2008). Fig. 7 shows the wax eater reproduced by the authors using the published work by previous researchers (Merino-Garcia and Correra 2008; Al-Yaari 2011). Like cold-flow technologies, the wax eater has not been used in the field yet. Method l: Magnetic-Fluid Conditioning. This is a novel technology in which a fluid exposed to a magnetic field causes changes in solids that are being carried or precipitated from that fluid. When the fluids in pipelines are directed across powerful magnetic fields, 6

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the growth of wax crystals is altered and therefore the formation of solids is inhibited. Magnetic conditioning is useful toward preventing clogging caused by wax and other solid deposits in wells and pipelines carrying oil. There are several patents that have been derived from this technology (Harms et al. 1991; Jones 1992; Corney 1993; Stanley 1998). However, this method will be more expensive than the conventional methods used because of its requirement of complicated instrumentation to maintain the magnetic field.

Cold slurry

Hot oil

Low ambient temperature = 3–4°C

Fig. 7—The wax eater (Merino-Garcia and Correra 2008).

Conclusion Wax begins depositing on the pipeline walls using a combination of various mechanisms such as molecular diffusion, Brownian motion, and shear dispersion (Burger et al. 1981). The authors have attempted to provide the petroleum-engineering and flow-assurance community with an overview of different wax-deposition-prevention/inhibition technologies and believe this article may be used by early career engineers and researchers in the industry. Various wax-deposition-mitigation techniques are reviewed such as mechanical methods (scraping and using PIGs and free pistons), thermal methods (hot oiling/watering, cold-flow techniques, thermal coating), using chemicals (pour-point depressants, fused-chemical reactions, and chemical solvents), using microorganisms, magnetic-fluid conditioning, and the wax eater. Although many of these technologies have been used in the field, the authors have not found such applications of methods such as cold flow, choke cooling, the wax eater, and magnetic-fluid conditioning. For each wax-mitigation method discussed, using their understanding, the authors have created Table 2 to show an apparent technology-readiness level (TRL) derived from the US Department of Energy’s classification (Sanchez 2011).

Subsection

Wax-Mitigation Method

TRL

a

Mechanical removal

TRL 9

b

Chemical inhibitors

TRL 9

c

Hot oiling

TRL 9

d

Chemical solvents

TRL 9

e

Exothermic chemical reactions

TRL 8/9

f

Surface coatings and thermal management

TRL 9

g

Microbial treatment

TRL 9

h

Cold flow

TRL 6/7

i

Cold-oil recirculation

TRL 6

j

Choke cooling

TRL 6

k

Wax eater

TRL 6/7

l

Magnetic-fluid conditioning

TRL 6

Table 2—TRL for each wax-mitigation method.

Because the mechanical methods of wax removal are most popular, the authors believe one area of future research may be focused toward developing expendable and inexpensive mechanical-removal tools or PIGs that may be flushed away along with wax plugs. Thermal treatment is another area that requires more research into developing inexpensive passive heating mechanisms. Finally, microbial treatments may be more useful if technologies are developed for their usage at much-higher temperatures and in wells with no water. Nomenclature A ¼ area available for deposition C ¼ concentration of wax in oil d ¼ particle diameter D ¼ well diameter DB ¼ Brownian-diffusion coefficient Df ¼ diffusion coefficient 2017 SPE Production & Operations ID: jaganm Time: 18:31 I Path: S:/PO##/Vol00000/170051/Comp/APPFile/SA-PO##170051

7

Ds f G L N PReservoir PWell R T V c l qðyÞ qs

¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼ ¼

shear-dispersion coefficient friction factor solid deposition measured depth of the well Avogadro’s number reservoir pressure well pressure gas constant temperature flow velocity oil-shear rate at the wall dynamic viscosity hydrocarbon density as a function of vertical depth wax-crystal density

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Stanley, D. 1998. Magnetic Fluid Conditioner. US Patent No. 5,783,074. The Pigging Products & Services Association. 1995. An Introduction to Pipeline Pigging. Houston: Gulf Professional Publishing. Thota, S. T. and Onyeanuna, C. C. 2016. Mitigation of Wax in Oil Pipelines. Int. J. Eng. Res. Rev. 4 (4): 39–47. Towler, B. F. and Rebbapragada, S. 2004. Mitigation of Paraffin Wax Deposition in Cretaceous Crude Oils of Wyoming. J. Pet. Sci. Eng. 45 (1–2): 11–19. https://doi.org/10.1016/j.petrol.2004.05.006. Wei, B. 2015. Recent Advances on Mitigating Wax Problem Using Polymeric Wax Crystal Modifier. J. Petrol. Explor. Prod. Technol. 5 (4): 391–401. https://doi.org/10.1007/s13202-014-0146-6. Woo, G. T., Garbis, S. J., and Gray, T. C. 1984. Long-Term Control of Paraffin Deposition. Presented at the SPE Annual Technical Conference and Exhibition, Houston, 16–19 September. SPE-13126-MS. https://doi.org/10.2118/13126-MS. Meagan White is a bachelor’s degree student in her senior year of studying engineering science at California State University, Bakersfield. Her current research interests are in the fields of flow assurance, thermodynamics, and multiphase flows. Kelly Pierce is a bachelor’s degree student in her junior year of studying engineering at California State University, Bakersfield. Her current research interests are in the fields of thermodynamics, subsea-fluid dynamics, and flow assurance. Tathagata Acharya is a lecturer of engineering at California State University, Bakersfield. He has spent more than 2 years in the upstream oil and gas industry working as a research engineer. Acharya’s current research interests are in the fields of flow assurance, thermodynamics, computational fluid dynamics, and multiphase flows. He holds master’s and PhD degrees in mechanical engineering from Louisiana State University, with a specialization in thermal and fluid sciences.

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