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Wax precipitation

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Wax components can precipitate from petroleum fluids when the original equilibrium conditions of the reservoir are changed so that the solubility of the waxes is reduced; however, wax precipitation does not necessarily lead to deposition. This page discusses wax precipitation behavior and experimental measurements to predict the tendency of a crude oil to precipitate wax.

Wax precipitation behavior

The reason that wax precipitation doesn't necessarily lead to deposition is that individual wax crystals tend to disperse in the fluid instead of depositing on a surface. If the number of wax crystals becomes large enough or if other nucleating materials such as asphaltenes, formation fines, clay, or corrosion products are present, the crystals may agglomerate into larger particles. These larger particles then may separate out of the fluid and form solid deposits.

Fig. 1[1] shows a typical wax precipitation envelope on a pressure temperature diagram. In contrast to the asphaltene precipitation envelope (APE), the solid/liquid-phase boundary is nearly vertical for waxes, illustrating wax precipitation’s strong dependence on temperature and weak dependence on pressure.

Temperature reduction is the most common cause of wax deposition because wax solubility in hydrocarbon fluids decreases as the temperature is lowered.[2] Reservoir fluid cooling occurs throughout the producing fluid system. Cooling can be caused by oil and gas expansion at the formation face:

  • Through casing perforations, or through other orifices or restrictions
  • By dissolved gas being liberated from solution
  • By radiation of heat from the fluid to the surrounding formation as it flows up the wellbore
  • By transfer of the fluid through low-temperature surface facilities
  • By injection of water or other fluids at temperatures below the reservoir temperature

Pressure changes usually have a very small effect on wax precipitation temperatures and amounts; however, changes in the original equilibrium composition of the fluids can result in a loss of wax solubility. A fairly consistent trend is that the lightest components in a crude oil act as good solvents for waxes. Liberation of solution gas from a crude oil as pressure decreases below the bubblepoint of the fluid has been shown to increase the cloud-point temperature of the oil.[3] This effect also has been observed in synthetic mixtures of methane, decane, and heavy n-alkanes with carbon numbers from 18 to 30[4] and for stock-tank oils mixed with methane and carbon dioxide.[5] This trend has been shown to be reversed in a study of two gas-condensate fluids in which the cloud-point temperature decreases as pressure is reduced below the vapor/liquid-phase boundary and may increase only at very low pressures.[6] The addition of intermediate paraffinic, naphthenic, and aromatic components with carbon numbers from 5 to 10 has been shown experimentally to decrease the cloud-point temperature for two crude oils.[7] Some model predictions contradict these results, indicating an increase in cloud-point temperature when pentane, hexane, or nonane were mixed with stock-tank oils.[5]

Analyzing potential for wax precipitation

There are a number of experimental measurements performed on petroleum fluids to define their tendency to precipitate wax. Measurements of the temperature at which wax precipitation occurs and the amount of wax precipitated are done with stabilized (stock tank) oils and live reservoir fluids. Compositional analysis of the fluids is performed to determine the concentrations of chemical species that can precipitate as waxes. This page describes these types of analyses.

Compositional analysis of petroleum fluids

Petroleum constituents may be broadly classified as belonging to the C6- or the C6+ fraction. The heavy end may be further classified with SARA (saturates, aromatics, resins, and asphaltenes) analysis. Various chromatography methods allow the determination of the mass fractions of single carbon number (SCN) fractions of a fluid. One SCN is composed of all the components with boiling points between consecutive n-alkane boiling points. For example, the C7 SCN is composed of all the components with boiling points between the boiling point of n-C7 and n-C8. These analyses routinely extend up to carbon number 30 and may be done up to a carbon number of 45 or more.

Detailed PNA [paraffinic (P), naphthenic (N), and aromatic (A) fraction] analyses also can be performed. Depending on the details of the analysis, the aromatic fraction may or may not include the resins and asphaltenes. It is also possible to determine the amounts of individual n-alkanes. These types of analyses, although expensive, are especially valuable for wax precipitation modeling because they very accurately define the components of a fluid that will precipitate as wax.

Measurement of wax precipitation data

There are a few basic measurements that characterize a fluid’s tendency to precipitate wax. Lira-Galeana and Hammami[8] reviewed the experimental techniques used to obtain these measurements.

Wax appearance temperature or cloud point

When a liquid solution or melt is lowered to the wax appearance temperature (WAT), the wax molecules form clusters of aligned chains. Once these nuclei reach a critical size, they become stable and further attachment of molecules leads to growth of the crystal. Formation of these nuclei causes the fluid to take on a cloudy appearance, hence the name cloud point. This also is referred to as the wax crystallization temperature or wax appearance point. Determination of a WAT significantly higher than the temperatures expected to be encountered during production indicates the potential for wax deposition problems.

The WAT depends on which technique is used for the analysis. For example, a microscopy method allows for observation of much smaller wax crystals than a visual technique with the unaided eye. The following techniques are used to determine the WAT.

  • American Society for Testing and Materials (ASTM) visual methods. Oil in a glass jar is submerged in a cooling bath. As the temperature of the bath is lowered, the temperature at which the fluid’s cloudiness is first observed is determined to be the cloud point.
  • Cold finger. A temperature-controlled rod is inserted in a gently heated oil sample. The WAT is determined as the temperature at which wax begins to adhere to the rod.
  • Viscometry methods. Viscometric techniques rely on detection of changes in rheological properties of an oil as wax precipitates. A break in the curve of viscosity plotted vs. temperature is taken as the WAT.
  • Differential-scanning calorimetry. This method detects the latent heat of fusion released on crystallization. Although there can be some uncertainty in interpretation of the results, differential-scanning calorimetry has been widely used for WAT determination and also can provide data on the heat capacities and heats of fusion or transition associated with liquid/solid and solid/solid phase transitions.
  • Cross-polarized microscopy. In this technique, a microscope with a temperature-controlled "hot stage" is used to view an oil sample that is being cooled at a constant rate. The use of a polarized light source and polarized objectives on the microscope allow the wax crystals to show up as bright spots on a black background. This technique usually provides the highest WAT value for dead oils.
  • Light transmittance. The experimental apparatus for this method consists of a PVT cell with a light source and a light power receiver mounted on opposite sides of the cell. When wax crystals appear in the fluid, the amount of light transmitted is reduced dramatically, and the WAT can be seen as a sharp drop in a plot of light power received vs. temperature. This method can be used at high pressure and, therefore, can be applied to live reservoir fluids as well as stock-tank oils.
  • Ultrasonics. Similar to the light-transmittance technique, an ultrasonic signal is sent through the fluid sample and received at a transducer. The velocity of the ultrasonic wave depends on the density of the medium; thus, the transit time for the wave will change at the WAT.

Wax dissolution temperature

The wax dissolution temperature is defined as the temperature at which all precipitated wax has been dissolved on heating the oil. The experimental techniques most often used for determining wax dissolution temperature are differential-scanning calorimetry and cross-polar microscopy.

Pour-point temperature

The pour-point temperature is the lowest temperature at which the oil is mobile. This is usually identified as the stock-tank-oil gelation temperature. The ASTM pour-point test, similar to the ASTM cloud point tests, involves placing a sample of the fluid in a jar and cooling it in a temperature-controlled bath. At each 3°C temperature step, the sample is tested by tipping the jar to determine if the oil is still mobile.

Quantification of wax precipitation

None of the tests used to determine the WAT provide data on the amount of solid precipitated at a temperature below the WAT. Experimental techniques to determine the amount of precipitated wax are described next.

Bulk-filtration apparatus

In this simple experiment, oil in a cylinder is equilibrated at the desired conditions of pressure, temperature, and possibly, solvent concentration.

The entire contents of the cylinder, including oil and any solids that may have precipitated, are ejected through a filter. The solids collected in the filter then may be analyzed for amount and chemical composition. This technique is time consuming and expensive but has the advantage of providing samples of the precipitated solid for analysis.

Pulsed nuclear magnetic resonance (NMR)

Pedersen et al.[9] used an NMR apparatus to determine the amount of precipitated solids as a function of temperature for 17 crude oils. The experimental NMR signals for each oil were compared with calibrated samples of polyethylene in wax-free oil. Although this technique does not allow for chemical analysis of the deposited solids, results are obtained much more quickly than with the bulk-filtration apparatus.


  1. 1.0 1.1 Leontaritis, K.J. 1996. The Asphaltene and Wax Deposition Envelopes. Fuel Sci. Technol. Int. 14 (1-2): 13-39.
  2. Allen, T.O. and Roberts, A.P. 1982. Production Operations, second edition, Vol. 2. Tulsa, Oklahoma: Oil and Gas Consultants International.
  3. Allen, T.O. and Roberts, A.P. 1982. Production Operations, second edition, Vol. 2. Tulsa, Oklahoma: Oil and Gas Consultants International.
  4. Daridon, J.L., Xans, P., and Montel, F. 1996. Phase boundary measurement on a methane + decane + multi-paraffins system. Fluid Phase Equilib. 117 (1–2): 241-248.
  5. 5.0 5.1 Pan, H., Firoozabadi, A., and Fotland, P. 1997. Pressure and Composition Effect on Wax Precipitation: Experimental Data and Model Results. SPE Prod & Oper 12 (4): 250-258. SPE-36740-PA.
  6. Daridon, J.-L., Pauly, J., Coutinho, J.A.P. et al. 2001. Solid−Liquid−Vapor Phase Boundary of a North Sea Waxy Crude:  Measurement and Modeling. Energy Fuels 15 (3): 730-735.
  7. Meray, V.R., Volle, J.-L., Schranz, C.J.P. et al. 1993. Influence of Light Ends on the Onset Crystallization Temperature of Waxy Crudes Within the Frame of Multiphase Transport. Presented at the SPE Annual Technical Conference and Exhibition, Houston, 3-6 October. SPE-26549-MS.
  8. Lira-Galeana, C. and Hammami, A. 2000. Wax Precipitation from Petroleum Fluids: A Review. In Asphaltenes and Asphalts, ed. T.F. Yen and G.V. Chilingarian, Vol. 2, No. 40B, Chap. 21, 557–608. Amsterdam, The Netherlands: Developments in Petroleum Science, Elsevier Science B.V.
  9. Pedersen, W.B., Hansen, A.B., Larsen, E. et al. 1991. Wax precipitation from North Sea crude oils. 2. Solid-phase content as function of temperature determined by pulsed NMR. Energy Fuels 5 (6): 908-913.

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See also

Asphaltenes and waxes

Thermodynamic models for wax precipitation

Formation damage from paraffins and asphaltenes

Wax problems in production

Models for wax deposition in pipelines

Remediating wax deposition