16.2.1 General

Wax varies in consistency from that of petroleum jelly to hard wax with melting points from near room temperature to more than 100°C. Wax has a density of around 0.8 g/cm³ and a heat capacity of around 0.140 W/(m·K). Paraffinic hydrocarbon fluids can cause a variety of problems in a production system ranging from solids’ stabilized emulsions to a gelled flowline. Although the pipeline is thermal insulated, it will ultimately cool to the ambient temperature given sufficient time in a shutdown condition. Problems caused by wax occur when the fluid cools from reservoir conditions and wax crystals begin to form. Wax is a naturally occurring substance in most crude oils and, depending on its characteristics, it may cause problems. Wax deposition on the pipeline walls increases as the fluid temperature in the pipeline decreases. The deposits accumulate on the pipe walls and over time may result in a drastic reduction of pipeline efficiency. The temperature at which crystals first begin to form is called the cloud point or wax appearance temperature (WAT). At temperatures below the cloud point, crystals begin to form and grow. Crystals may form either in the bulk fluid, forming particles that are transported along with the fluid, or deposit on a cold surface where the crystals will build up and foul the surface. WAT is calculated from a proprietary thermodynamic model calibrated to field data and using input PVT tests and proprietary high-temperature gas chromatography measurements. Systems with pipe wall temperatures below the WAT need a wax management strategy. It is important to note that the WAT indicates the temperature at which deposition will begin, but it does not indicate the amount of wax that will be deposited or the rate at which it will be deposited. Deposition rate measurements should be made in previous studies and will be used in future modeling. The pour point temperature is the temperature at which the oil stops flowing and gels.

Gel formation and deposition are the main problems that wax may cause in a production system. A crude oil gel forms when wax precipitates from the oil and forms a 3D structure spanning the pipe. This does not occur while the oil is flowing because the intermolecular structure is destroyed by shear forces. However, when the oil stops flowing, wax particles will interact, join together, and form a network resulting in a gel structure if enough wax is out of solution.

Wax deposition results in flow restrictions or possibly a blockage of a pipeline. Complete blockage of flow due to deposition is rare. Most pipeline blockages occur when a pig is run through a pipeline after deposition has occurred and a significant deposit has built up. In this situation the pig will continue to scrape wax from the pipe wall and build up a viscous slug or candle in front of the pig. However, if the candle becomes too large there will be insufficient pressure for the pig to move. When this occurs the pig becomes stuck and mechanical intervention to remove the candle will be necessary before the pig can be moved.

In subsea systems, the following issues caused by waxes should be addressed by flow assurance analyses:

16.2.2 Pour Point Temperature

The pour point is an indicator of the temperature at which oil will solidify into a gel. At the pour point, the fluid still “pours” under gravity; at the next lower measurement temperature (3°C lower), the fluid has gelled and does not pour. In environments with ambient and fluid temperatures above the pour point, no pour point strategy is necessary. In environments where the ambient or fluid temperature is at or below the pour point temperature, a specific pour point strategy is required to maintain flow ability of the fluid. So the environmental temperature could be analyzed, in general, such that the analysis was conservative, 100-year extreme minimum seabed temperatures were used along the pipeline route.

The pour point temperature can be measured using ASTM methods and estimated using high-temperature gas chromatography (HTGC) date correlations.

There are currently at least five ASTM pour point protocols, most of which are designed for petroleum products rather than crude oils. The two most widely used are ASTM D97-09 [1] and D5853-09 [2]. In general, these tests require 100 to 250 mL of fluid. ASTM D97 is an older oil-products pour point protocol that requires heating to a prescribed temperature (60°C) and cooling in a series of baths until the oil gels or solidifies. Shell has devised a “mini” D97 pour point that uses a 30-mL sample. The “mini” pour point has been calibrated using the ASTM D97 method. The repeatability (95% confidence limits, same lab) of the D97 pour points (measured on fuel oils) is reported by ASTM to be 5°F (2.8°C); the reproducibility (95% confidence limits, different labs) is 12°F (6.7°C).

ASTM D5853 [2] is designed specifically for crude oils and recognizes the potentially strong effect of thermal history on the gelling temperature. Two separate heating and cooling protocols are employed in order to see the effects of two substantially different thermal histories. The minimum pour point protocol requires heating to 105°C and cooling in air for 20 min at room temperature before entering a series of cooling baths. This protocol lowers the measured pour point in two ways: (1) It ensures that all wax is in solution before cooling is started, and (2) it cools relatively quickly, potentially “outrunning” the wax kinetics and reaching a lower temperature before the gel forms. The maximum pour point protocol requires heating to 60°C or less, cooling in air for 24 hr, and a short reheat to 45°C followed by the cooling baths. This protocol raises the measured point by allowing a long time for “seed crystals” to form at room temperature, which in turn decreases the time for gel formation. ASTM D5853 is difficult to adapt to small volumes; therefore, we have no “mini” technique for ASTM D5853. The repeatability of D5853 using crude oils is reported by ASTM to be 6 to 12°F (3.3 to 6.6°C), but the reproducibility is as high as 32 to 40°F (17.8 to 22.2°C).

16.2.3 Wax Formation

The wax deposit is complex in nature, comprised of a range of normal paraffins of different lengths, some branched paraffins, and incorporated oil. The buildup of wax over time can eventually reach a point where flow rates are restricted. Wax deposits in oil production flowlines are primarily comprised of paraffins of C⁷⁺ in length. The deposition of paraffins is controlled by temperature. As the temperature in a system drops, paraffins that are in the liquid phase begin to come out of solution as solids. Wax deposits form at the wall of the pipe where the temperature gradient is at its highest.

In addition to wax deposition, the formation of sufficient wax solids can cause oil to “gel” at sufficiently low temperature during a shutdown of the system. Once this occurs, it is difficult or even impossible to restart flow in the system due to the very high viscosity of the gelled oil. The wax properties of oils have been characterized by cloud point and pour point measurements. The cloud point essentially measures the point at which wax first visibly comes out of solution as oil is cooled at atmospheric pressure. The pour point is the temperature at which the oil ceases to flow when the vessel is inverted for 5 sec. These measurements give a general understanding of the temperatures at which wax deposition will become a problem and when crude oil gelling will become a problem.

The key to wax deposition prediction is a precise analysis of the concentration of the normal paraffins in an oil sample, which is carried out using the HTGC technique. The paraffin composition data are used to construct a thermodynamic model for prediction of wax deposition rates in the flowline as well as for predicting the cloud point and pour point dependence on pressure. The thermodynamic model may be combined with the model of flowline using software such as HYSYS, PIPESIM, or OLGA to predict where wax deposits will occur, how fast wax will accumulate, and the frequency at which the line must be pigged.

In contrast to hydrates, wax deposits slowly and can be controlled by controlling the system temperature and temperature differential at the pipe wall. Cloud points for deepwater GoM crude oils generally fall in the range of 80 to 100°F. If the system is operated at a temperature approximately 10 to 20°F above the cloud point, wax will not deposit. A “rule of thumb” for the deposition temperature that has been frequently used is cloud point + 15°F. Although this can usually be achieved for the wellbore and subsea tree, it is often not possible to operate at this high a temperature in the flowline. The host arrival temperature may be limited due to processing concerns or by the temperature rating of equipment. During late life, the reservoir temperature may have dropped to the point at which host arrival temperatures are substantially below the cloud point leading to significant deposition. Figure 16-1 shows the relationship of temperature and pressure to wax formation. The left side of the curve shows the area where waxes will deposit, whereas the right side of the curve indicates where waxes will not form.

Figure 16-1 Temperature/Pressure Relationships in Formation of Wax

Wax formed in wellbores can only be removed by a process such as coiled tubing, which is prohibitively expensive for subsea wells. As a result, it is important to control the temperature of the well tubing, tree, and other components that cannot be pigged (such as jumpers) above the point at which wax deposition occurs. This critical wax temperature may be chosen as cloud point + 15°F. The flowing wellhead temperatures and pressures from flow assurance analysis are used to check that the tubing and tree remain above this critical wax deposition temperature. The need to prevent wax deposition in the wellbore, tree, and jumpers may set a minimum late life production rate, based on the temperature predictions from flow assurance.

High pour point oils present a potentially serious problem somewhat similar to that for formation of hydrates. Wax formation during shutdown can be sufficient to make line restart difficult or even impossible. Even though temperatures may be well above the pour point during steady-state operation, it is impossible to know when a shutdown may occur.

Wax deposition will occur once the oil has fallen below the cloud point if there is a negative temperature gradient between the bulk oil and a surface. However, the Deepstar research [3] has shown that wax deposition also can occur above the dead oil cloud point in some systems. Therefore, to prevent wax deposition, the system temperature should remain greater than 9°C above the dead oil cloud point. Experimentally the tendency of oil to deposit and the rate of deposition can be measured by placing a cold surface in contact with warm oil. Experimental systems include cold fingers, coaxial shearing cells, and pipe loops. The cold finger consists of a test tube–shaped metal finger cooled by flowing chilled fluid through the finger, and a heated stirred container for an oil sample. The coaxial shearing cell is similar to a cold finger but the finger rotates to create uniform shear on the surface. A pipe loop is a pipe-in-pipe heat exchanger in which the cold fluid is pumped through the shell side and the oil is heated and pumped through the tube side. It might be expected that the pipe loop would be the preferred method due to its geometric similarity to a pipeline. However, if an actual field sample is to be used, none of the methods properly simulate the system since dynamic similitude is impossible to achieve without building a system of the same size. However, each method can be used to measure the wax flux to the surface. With careful analysis the data from any laboratory method can be used to make predictions about field deposition.

As oil cools far below the cloud point it may begin to gel. While the amount of wax out of solution needed to form a gel structure varies considerably, 2% paraffin is used as a useful rule of thumb. The typical method of measuring a crude oil pour point is ASTM D5853-09 shown in Figure 16-2, which specifies the conditioning required for obtaining reproducible values. Because the cooling rate is not controlled in this method, results may vary from lab to lab, but in general the results are accurate to within ±5°F.

Figure 16-2 ASTM D5853 Pour Point Testing [4]

16.2.4 Gel Strength

The pour point is used to determine whether or not a crude oil will form a gel; the gel strength is defined as the shear stress at which gel breaks. The gel strengths measured in a rheometer are typically of the order of 50 dyne/cm². However, the sample in a rheometer will yield uniformly due to the small gap. In a pipe the sample will not yield uniformly. A pressure front will propagate through the oil and the oil near the inlet will yield and begin to flow when a flowline is restarted. Because this problem is not tractable due to the compressibility and non-Newtonian behavior of a crude oil gel, predictions continue to be made from rheometer measurements or short pipe sections.

Start-up pressure predictions can be made using following equation:

(16-1)

where is the pressure drop, is the yield stress, L is the length of the pipe, and D is the diameter of the pipe. Equation (16-1) assumes that the whole flowline is gelled, will yield simultaneously, and that the yield at the wall is the appropriate parameter to consider. This method typically overpredicts the actual restart pressures.

For export pipelines laboratory pour point methods are very good indicators of potential problems since the export pipelines and blowdown flowlines are full of dead crude. If a flowline were not blown down, then the gel situation would improve due to an increase in light components in the oil.

16.2.5 Wax Deposition

The deposition tendency and rate can also be predicted adequately by calculating the rate of molecular diffusion of wax to the wall by the following equation:

(16-2)

where

The radial concentration gradient can easily be calculated if broken into two components by applying the chain rule as shown in following equation:

(16-3)

where T is temperature. The concentration gradient may be calculated from the wax concentrations predicted by a thermodynamic model for a range of temperatures.

16.2.6 Wax Deposition Prediction

Waxes are more difficult to understand than pure solids because they are complex mixtures of solid hydrocarbons that freeze out of crude oils if the temperature is low enough. Waxes are mainly formed from normal paraffins but isoparaffins and naphthenes are also present and some waxes have an appreciable aromatic content. The prediction of wax deposition potentials comprises two parts: the cloud point temperature or wax appearance temperature, and the rate of deposition on the pipe wall. The cloud point is the temperature below which wax crystals will form in oil, and the rate of deposition determines the wax buildup rate and pigging frequency requirement. The cloud point temperature can be satisfactorily predicted using thermodynamic models. These models require detailed hydrocarbon compositions. Figure 16-3 shows the comparison between experimental data and model simulation. The tendency of the pressure effect is accurately predicted.

Figure 16-3 Comparison of WAT between Experimental Data and Calculation Results at Different Pressures [6]

The prediction of deposition rates depends on a thermodynamic model for the amount of wax in oil and a diffusion rate model [5]. The accuracy of the predictions is not satisfactory at present, but some industrial JIPs (e.g., University of Tulsa) are investigating to improve the accuracy. The wax models used include these:

In the wax prediction process, the pipeline temperature profile for various insulation systems with different flow velocities should be analyzed and compared with the WAT and pour point temperature to identify the location of wax appearance. Also whether the pipeline is buried or not should be considered due to the thermal insulation properties of a buried pipeline.

16.3.1 General

Several methods of wax control and management are practiced by production operations, but the transportation of crude oil over a long distance in subsea system demands significant planning and forethought. The wax management strategy generally is based on one or more of the following methods:

The most common method of wax control is flowline pigging if the wax has formed. The solid deposit is removed by regularly removing the wax layer by the scouring action of the pig. Chemical inhibitors can also help control wax deposition, although these chemicals are not always effective and tend to be expensive. In cases where flowline pigging of the production lines is not practical, particularly for subsea completions, wax deposition is controlled by maintaining fluid temperatures above the cloud point for the whole flowline.

Coiled-tubing technology has become an important means of conducting well cleanup procedures. This technology involves the redirection of well production to fluid collection facilities or flaring operations while the coiled tubing is in the well. Heavy coiled tubing reels are placed at the wellhead by large trucks, the well fluids are diverted, and high-pressure nozzles on the end of the coiled tubing are placed in the well. Tanker trucks filled with solvent provide the high-pressure pumps with fluids that are used to clean the well tubing as the coiled tubing is lowered into the well. The value of this method is apparent in many areas of the world, since certain integrated production companies maintain a fleet of coiled tubing trucks that remain busy a large percentage of the time.

16.3.2 Thermal Insulation

Good thermal insulation can keep the fluid above the cloud point for the whole flowline and thus eliminate wax deposition totally. Although line heaters can be successfully employed from the wellhead to other facilities, the physical nature of the crystallizing waxes has not been changed. This can be a problem once the fluids are sent to storage, where the temperature and fluid movement conditions favor the formation of wax crystals and lead to gels and sludge.

16.3.3 Pigging

The rate of deposition can be reduced by flowline insulation and by the injection of wax dispersant chemicals, which can reduce deposition rates by up to five times. However, it must be emphasized that these chemicals do not completely stop the deposition of wax. Therefore, it is still necessary to physically remove the wax by scouring the flowline. To facilitate pigging, a dual-flowline system with a design that permits pigging must be built. Pigging must be carried out frequently to avoid the buildup of large quantities of wax. If the wax deposit becomes too thick, there will be insufficient pressure to push the pig through the line as the wax accumulates in front of it. Pigging also requires that the subsea oil system be shut down, stabilized by a methanol injection and blowdown, and finally restarted after the pigging has been completed. This entire process may result in the loss of 1 to 3 days of production. The deposition models created based on the fluids analysis work and the flow assurance calculations are the key to establishing pigging intervals that are neither too frequent to be uneconomical or too infrequent to run the risk of sticking the pig in the flowline. OLGA models the “slug” of wax pushed ahead of the pig.

16.3.4 Inhibitor Injection

Chemical inhibition is generally more expensive than mechanical pigging, although the cost comparison depends on pigging frequency requirements, chemical inhibition effectiveness, and many other factors [7]. Chemical inhibitors can reduce deposition rates but rarely can eliminate deposition altogether. Therefore, pigging capabilities still have to be provided as a backup when chemical inhibition is used. The chemicals must match the chemistry of the oil, at the operating conditions, to be effective. Testing of inhibitor effectiveness is absolutely necessary for each application. The tests should be carried out at likely operating conditions. The chemical inhibitors for wax prevention include:

16.4.1 Wax Remediation Methods

16.4.2 Assessment of Wax Problem

The process of assessment for a wax problem can be summarized as follows [10]:

16.4.3 Wax Control Design Philosophies

Wax control guidelines for the subsea devices and flowlines can be summarized as follows [5]:

For the pour point the strategies can be summarized as follows:

In steady and transient states, the strategies can be summarized as follows:

16.5.1 General

Asphaltenes are a class of compounds in crude oil that are black in color and not soluble in n-heptane. Aromatic solvents such as toluene, on the other hand, are good solvents for asphaltenes. From an organic chemistry standpoint, they are large molecules comprised of polyaromatic and heterocyclic aromatic rings, with side branching. Asphaltenes originate with the complex molecules found in living plants and animals, which have only been partially broken down by the action of temperature and pressure over geologic time. Asphaltenes carry the bulk of the inorganic component of crude oil, including sulfur and nitrogen, and metals such as nickel and vanadium. All oils contain a certain amount of asphaltene. Asphaltenes only become a problem during production when they are unstable. Asphaltene stability is a function of the ratio of asphaltenes to stabilizing factors in the crude such as aromatics and resins. The factor having the biggest impact on asphaltene stability is pressure. Asphaltenes may also be destabilized by the addition of acid or certain types of completion fluids and by the high temperatures seen in the crude oil refining process.

In general, asphaltenes cause few operational problems since the majority of asphaltic crude oils have stable asphaltenes. Typically problems only occur downstream due to blending or high heat. Crude oils with unstable asphaltenes suffer from some severe operational problems, most of which are fouling related and affect valves, chokes, filters, and tubing. Asphaltenes become unstable as the pressure of the well decreases and the volume fraction of aliphatic components increases. If the aliphatic fraction of the oil reaches a threshold limit, then asphaltenes begin to flocculate and precipitate. This pressure is called the flocculation point. Figure 16-4 shows the effect of pressure on asphaltene stability. On the left side of the curve, asphaltenes are unstable, whereas to the right side of the curve, asphaltenes are stable.

Figure 16-4 Effect of Pressure on Asphaltene Stability

There are currently no standard design and operating guidelines for the control of asphaltenes in subsea systems. Some experience has been gained from asphaltene control programs used for onshore wells. Approaches have varied from allowing the wellbore to completely plug with asphaltenes, then drilling the material out, to utilizing periodic solvent washes with coiled tubing to remove material. Relatively few operators have chosen to control asphaltene deposition with dispersants, possibly due to the expense of doing so and variable results.

16.5.2 Assessment of Asphaltene Problem

One method of characterizing oil is with a SARA (saturates, aromatics, resins, and asphaltenes) analysis. This method breaks the oil down into four pseudo-components or solubility classes and reports each as a percentage of the total. The four pseudo-components are saturates, aromatics, resins, and asphaltenes. The asphaltene fraction is the most polar fraction and is defined as aromatic soluble and n-alkane insoluble. Asphaltenes are condensed polyaromatic hydrocarbons that are very polar. Whereas wax has a hydrogen-to-carbon ratio of about 2, asphaltenes have a hydrogen-to-carbon mole ratio of around 1.15. The low hydrogen content is illustrated in Figure 16-5, which shows hypothetical asphaltene molecules.

Figure 16-5 Hypothetical Asphaltene Molecules [11]

Asphaltenes have a density of approximately 1.3 g/cm³. In oil production systems the asphaltenes are often found mixed with wax. There are two mechanisms for fouling that occur during formation. The first involves acid; the second is adsorption to formation material. Acidizing is one of the most common well treatments and can cause severe damage to a well with asphaltic crude oil. The acid causes the asphaltenes to precipitate, sludge, and form rigid film emulsions that severely affect permeability, often cutting production by more than 50%. Formation materials, particularly clays, contain metals that may interact with the asphaltenes and cause the chemisorption of the asphaltenes to the clay in the reservoir. A SARA screen, aliphatic hydrocarbon titration, or depressurization of a bottomhole sample is used to determine if asphaltenes are unstable in a given crude. One SARA screen is the colloidal instability index (CII) 4. The CII is the ratio of the unfavorable components to the favorable components of the oil as shown in following equation:

16-4

where S is the percentage of saturates, As is the percentage of asphaltenes, R is the percentage of resins, and Ar is the percentage of aromatics in the oil. If the CII is greater than 1, then the amount of unfavorable components exceeds the amount of favorable components in the system and the asphaltenes are likely to be unstable.

Several aliphatic hydrocarbon titrations are available that can be used to assess the stability of asphaltenes in a dead crude oil. One method in particular involves the continuous addition of an aliphatic titrant to oil and the measurement of the optical density of the solution. In this method the precipitation point of asphaltenes is detected by monitoring changes in transmission of an infrared laser. The instrument is referred to as the asphaltene precipitation detection unit (APDU). As the hydrocarbon is added to the oil, the optical density decreases and the laser transmittance through the sample increases. At the point when enough titrant has been added to the sample that asphaltenes become unstable and precipitate, the optical density drops dramatically. This point is called the APDU number, which is defined as the ratio of the volume of titrant to the initial mass of crude oil.

Depressurization of a live bottomhole sample provides the most direct measurement of asphaltene stability for production systems. During depressurization, the live oil flocculation point or the pressure at which asphaltenes begin to precipitate in the system is determined by monitoring the transmittance of an infrared laser that passes through the sample. Onset of flocculation will produce a noticeable reduction of light transmittance. If oil has a flocculation point, then the asphaltenes are unstable at pressures between the flocculation points to just below the bubble point. Many oils are unstable only near the bubble point, which has led many engineers to believe that problems only occur at the bubble point. However, some oils have an instability window of several thousand pounds per square inch. Figure 16-6 depicts an asphaltene solubility curve. The onset or flocculation point, saturation pressure, asphaltene saturation point, and reservoir fluid asphaltene concentration are indicted with dashed lines, whereas the unstable region is indicated by a shaded area between the asphaltene saturation point and the solubility curve. As shown on the curve the region of instability is from 2600 to 3800 psi.

Figure 16-6 Asphaltene Solubility Curve as a Function Pressure [11]

16.5.3 Asphaltene Formation

Asphaltene solids are typically black coal-like substances. They tend to be sticky, making them difficult to remove from surfaces. In addition, asphaltene solids tend to stabilize water/oil emulsions, complicating oil separation and water treatment at the host. It is felt that asphaltenes will be a problem for a relatively small fraction of deepwater projects. Current research efforts have focused on improving screening tests for asphaltene and figuring out how screening test results relate to field problems. Three screening tools are used. The first is a test known as the P-value test, which involves the titration of crude oil with cetane, the normal paraffin with a carbon chain length of 16. Additions of normal paraffins tend to destabilize asphaltenes in the crude oil. The stability of the oil increases with the amount of cetane that can be added before visible amounts of asphaltenes come out of solution. The SARA screen test examines the stability of asphaltenes by determining the concentration of the primary components of crude oil, saturated hydrocarbons, aromatics, resins, and asphaltenes. The ratio of saturates to aromatics and asphaltenes to resins is computed and used to determine the stability of the oil. The PVT screen utilizes two values available from a PVT analysis, the in situ density and the degree of undersaturation (difference between reservoir pressure and bubble point) to make a general assessment of asphaltene stability. In general, increasing under saturation and decreasing in situ density are associated with decreasing asphaltene stability.

16.5.4 Asphaltene Deposition

After the bubble point has been reached, the mass of precipitated asphaltenes and the mass of asphaltenes deposited in the cell are measured. These two measurements provide a means to assess the likelihood of problems due to deposition. We have observed that only a small percentage of total asphaltenes adheres to a surface during an experiment. Based on these observations we would expect only about 5% of the total asphaltenes to play a role in asphaltene deposition. The mass of deposited asphaltenes can be used to predict the mass of deposition in a production system. Although this number is likely to be an overestimate, it is a good number for design purposes and for contingency planning.

Asphaltene problems occur infrequently offshore, but can have serious consequences on project economics. Because asphaltene deposition is most likely as the produced fluid passes through the bubble point, the deposition often occurs in the tubing. Subsea systems designed to mitigate asphaltene problems generally rely on bottomhole injection of an inhibitor with provision to solvent treat the wellbore when required. In the absence of inhibitors, monthly tubing cleanouts are not uncommon onshore. This frequency would be intolerable in a subsea system, making effective inhibitors essential to the design of the project.