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Wax problems in production

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Many crudes contain dissolved waxes that can precipitate and deposit under the appropriate environmental conditions. These can build up in production equipment and pipelines, potentially restricting flow (reducing volume produced) and creating other problems. This page discusses how to anticipate, prevent, and remediate wax problems in production.

Waxes in crude oil

Paraffin wax produced from crude oil consists primarily of long chain, saturated hydrocarbons (linear alkanes/ n-paraffins) with carbon chain lengths of C18 to C75+, having individual melting points from 40 to 70°C. This wax material is referred to as “macrocrystalline wax.” Naphthenic hydrocarbons (C18 to C36) also deposit wax, which is referred to as “microcrystalline wax.” Macrocrystalline waxes lead to paraffin problems in production and transport operations; microcrystalline waxes contribute the most to tank-bottom sludges.[1] Fig. 1 shows the generic molecular structures of n-paraffins, iso-paraffins, and naphthenes. The n-heptane structure is an example of a “normal” paraffin; 2-methyloctane is an “iso” paraffin and n-butylcyclopentane is a naphthene. These specific n-paraffins and naphthenes are too small to crystallize as wax deposits (i.e., outside the carbon-number range specified above). The drawings illustrate the type of structures involved.

Waxes isolated from crudes can contain various amounts of all classes: n-paraffins, naphthenes, and iso-paraffins. For example, waxes derived from several Venezuelan crudes[1] showed n -paraffin/(cyclo + iso paraffin) ratios ranging from 1.28 to 0.23. The iso-paraffins of the 2-methyloctane type (Fig. 1) are more likely to be included in a wax deposit than the more highly branched alkanes.

A “clean waxy crude” is defined as a crude oil that consists of only hydrocarbons and wax as the heavy organic constituents. “Regular waxy crudes” contain other heavy organics in addition to the waxes (e.g., asphaltenes and resins). These heavy organics have interactions with the crude, which can either prevent wax-crystal formation or enhance it.

More information on the characteristics of waxes in crude oil can be found in Asphaltenes and waxes.

Phenomenology

As the temperature of the crude drops below a critical level and/or as the low-molecular-weight hydrocarbons vaporize, the dissolved waxes begin to form insoluble crystals. The deposition process involves two distinct stages: nucleation and growth. Nucleation is the forming of paraffin clusters of a critical size (“nuclei”) that are stable in the hydrocarbon fluid. This insoluble wax itself tends to disperse in the crude.

Wax deposition onto the production system (“growth”) generally requires a “nucleating agent,” such as asphaltenes and inorganic solids. The wax deposits vary in consistency from a soft mush to a hard, brittle material. Paraffin deposits will be harder, if longer-chain n-paraffins are present. Paraffin deposits can also contain:[2]

  • Asphaltenes
  • Resins
  • Gums
  • Fine sand
  • Silt
  • Clays
  • Salt
  • Water

High-molecular-weight waxes tend to deposit in the higher-temperature sections of a well, while lower-molecular-weight fractions tend to deposit in lower-temperature regions. Prior to solidification, the solid wax crystals in the liquid oil change the flow properties from a Newtonian low viscosity fluid to a very-complex-flow behavior gel with a yield stress.

Coping with waxes

The primary chemical parameter to establish is the critical temperature at which these wax nuclei form—the wax appearance temperature (WAT). The WAT (or “cloud point”) is highly specific to each crude. The WAT value is a function of:[3]

  • Oil composition
  • Cooling rate during measurement
  • Pressure
  • Paraffin concentration
  • Molecular mass of paraffin molecules
  • Occurrence of nucleating materials such as asphaltenes, formation fines, and corrosion products
  • Water/oil ratio
  • Shear environment

See Wax precipitation for additional information.

A variety of experimental methods have been used to obtain this number. Among these are:

  • Differential scanning calorimetry (DSC) - measures the heat released by wax crystallization
  • Cross polarization microscopy (CPM) - exploits the fact that insoluble wax crystals rotate polarized light, but liquid hydrocarbons do not
  • Filter plugging (FP) - measures the increase in differential pressure across a filter, which can be attributed to wax-crystal formation
  • Fourier transform infrared energy scattering (FTIR) - detects the cloud point by measuring the increase in energy scattering associated with wax solidification

Each of these techniques has its advantages and disadvantages. A comparison/review of these methods is found in Monger-McClure, et al.[4] In testing, cloud points, measured by each of the four methods, agreed with the average value of all methods within 3 to 5°F.

Of more importance, is how well laboratory-measured cloud points anticipate WATs found in the field. Measured cloud-point data should only match field results for wells producing at low shear (high shear rates tend to delay the deposition of waxes). Another inherent problem is that the cloud-point measurement sees the precipitation of the most insoluble paraffin, not the mass of lower-molecular-weight paraffins that might contribute the major amount of wax deposit. Nevertheless, CPM measurements have been found to correlate well with the temperature at field deposition, more so than optical techniques that required a greater mass of wax to register a signal.[3] A major problem in correlating these measurements and simulations with field experience is the acquisition of good field data.[4] Illustrative of the state of the art in interpreting these measurements is that closer agreement is found between stock-tank oil measurements and field experience, even though it is live oil that is being produced.

An alternative to the measurement of cloud point is its prediction from compositional data by thermodynamic models. These models can predict cloud point as the temperature at which the first infinitesimal amount of wax appears, as well as predicting that mass of wax precipitating out of solution that, from experience, corresponds to field deposition.[5] Models that use detailed n-paraffin composition input data, as obtained from high-pressure gas chromatography, generally outperform models based on less specific information like compositions to C7+ [the numbers are more generally available in the routine pressure/volume/temperature (PVT) reports].

Paraffin deposition models

Given the cloud point, what is the propensity for wax precipitation during the production and, in particular, the pipelining and processing of the crude? This is the regime of “paraffin deposition models.” These are engineering simulators used to predict wax buildup in flowing systems,[6] taking into account such parameters as:

  • Heat transfer
  • Phase behavior of the crude
  • Flow regime
  • Wax deposition kinetics
  • Shear rate
  • Diffusivity
  • Wall conditions (roughness, coatings, scale)
  • Produced-water/oil ratio

See also Models for wax deposition in pipelines.

Prevention/inhibition

As with other solids-depositing problems, prevention can be more cost effective than removal. One key to wax-deposition prevention is heat. Electric heaters can be employed to raise the crude oil temperature as it enters the wellbore. The limitations are the maintenance costs of the heating system and the availability of electrical power. As with hydrates, maintaining a sufficiently high production level may also keep the upper-wellbore temperature above the WAT. In addition, high flow rates tend to minimize wax adherence to metal surfaces because of the shearing action of the flowing fluid. Insulated pipelines are also an alternative to minimize, if not eliminate, the problem, but the cost can be prohibitive for long pipelines.

Wax deposition can be prevented, delayed, or minimized by the use of dispersants or crystal modifiers. As with asphaltenes, paraffin-wax characteristics vary from well to well. Chemicals that are effective in one system are not always successful in others, even for wells within the same reservoir. “For this reason it is of fundamental importance to establish a good correlation between oil composition and paraffin inhibitors efficiency, leading to an adequate product selection for each particular case, avoiding extremely expensive and inefficient ‘trial-and-error’ procedures.”[1]

Crystal modifiers

Paraffin-crystal modifiers are chemicals that interact with the growing crude-oil waxes by cocrystallizing with the native paraffin waxes in the crude oil that is being treated. These interactions result in the deformation of the crystal morphology of the crude-oil wax. Once deformed, these crystals cannot undergo the normal series of aggregation steps. Types of paraffin-crystal modifiers include:

  • Maleic acid esters
  • Polymeric acrylate and methacrylate esters
  • Ethylene vinyl acetate polymers and copolymers

Dispersants

Dispersants act to keep the wax nuclei from agglomerating. Dispersants are generally surfactants and may also keep the pipe surface water wet, minimizing the tendency of the wax to adhere. Some water production is required, of course. High levels of water alone may maintain the system in a water-wet state. As with scale prevention, a smooth surface tends to decrease wax adherence. However, the operational problem is to maintain such a surface for an extended period of time. Various forms of erosion are highly detrimental.

Obviously, these inhibitors must be delivered into the crude oil at temperatures above the WAT. This need not cause a problem for surface equipment, but it could cause a problem for wellbore treatment, if the bottomhole temperatures are low.

Removal of deposits

Removal of wax deposits within a wellbore is accomplished by:

  • Cutting
  • Drilling
  • Chemical dissolution
  • Melting—the use of hot oil, hot water, or steam

Of these, the use of hot oil has been the most popular, normally pumped down the casing and up the tubular. It is intended that the high temperature of the liquid phase heat and melt the wax, which then dissolves in the oil phase. Using the bottom-up delivery approach, hot oil first reaches those waxes most difficult to melt. The higher in the tubular the hot oil proceeds, the lower its temperature becomes, thereby reducing its wax-carrying capacity. Hot oiling can cause permeability damage, if the fluid containing the melted wax enters the formation.[2]

Hot water, hot-water/surfactant combinations, and steam are alternatives to hot oiling. Plain hot-water treatments do not provide the solvency required to remove the wax, hence the use of surfactants to disperse the wax. The advantage of water is its greater heat capacity.

Chemical generation of heat has also been proposed as a method of melting wax deposits. One field-tested scheme uses the thermochemical process of reacting two specific nitrogen salt solutions, acidic ammonium chloride and sodium nitrite;[7] an orgainc solvent is included to keep the wax in solution after the system has cooled.

Various aromatic solvents can be used to dissolve the wax. These are generally not heated, relying solely on the solvency properties of the fluid. As with asphaltene dissolution, o-xylene has been one of the more effective solvents for waxes. Kerosene and diesel tend to be poor solvents. However, as with asphaltenes dissolution, one solvent does not necessarily work equally well on all wax deposits; an example of solvent screening procedures is given in Ferworn, et al.[8]

Pigging is the primary mechanical method of removing wax buildup from the internal walls of pipelines. The pig cuts the wax from the pipe walls; a bypass can be set with a variable-flow pass, allowing the pig to prevent wax buildup in front. Pig sizing can vary, and multiple pig runs with pigs of increasing size can be used. For subsea pigging, a looped flowline is required or a subsea pig launcher for a single flowline. The major uncertainty in this operation is the wax hardness as it is formed in the pipeline.

Coiled tubing with the appropriate cutters at the end also can be used for wax removal—the drawback for pipeline cleaning being the limited reach of the coiled tubing. For wellbore cleaning this is obviously less of a problem.

References

  1. 1.0 1.1 1.2 Garcia, M.C., Carbognani, L., Urbina, A. et al. 1998. Correlation Between Oil Composition and Paraffin Inhibitors Activity. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 27–30 September. SPE-49200-MS. http://dx.doi.org/10.2118/49200-MS.
  2. 2.0 2.1 Allen, T. and Roberts, A. 1982. Paraffins and Asphaltenes. In Production Operations, 2. Tulsa, Oklahoma: Oil and Gas Consultants Intl. Inc.
  3. 3.0 3.1 Hammami, A. and Raines, M.A. 1997. Paraffin Deposition From Crude Oils: Comparison of Laboratory Results to Field Data. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 5–8 October. SPE-38776-MS. http://dx.doi.org/10.2118/38776-MS.
  4. 4.0 4.1 Monger-McClure, T.G., Tackett, J.E., and Merrill, L.S. 1997. DeepStar Comparisons of Cloud Point Measurement & Paraffin Prediction Methods. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 5–8 October. SPE-38774-MS. http://dx.doi.org/10.2118/38774-MS.
  5. Calange, S., Ruffier-Meray, V., and Behar, E. 1997. Onset Crystallization Temperature and Deposit Amount for Waxy Crudes: Experimental Determination and Thermodynamic Modelling. Presented at the International Symposium on Oilfield Chemistry, Houston, 18–21 February. SPE-37239-MS. http://dx.doi.org/10.2118/37239-MS.
  6. Brill, J. 1997. Experimental Investigation of Paraffin Deposition Prediction in Single-Phase and Multiphase Flowlines and Wellbores. Proc., IBC UK Conference, Aberdeen.
  7. Khalil, C.N., Rocha, N.O., and Silva, E.B. 1997. Detection of Formation Damage Associated to Paraffin in Reservoirs of the Recôncavo Baiano. Presented at the International Symposium on Oilfield Chemistry, Houston, 18–21 February. SPE-37238-MS. http://dx.doi.org/10.2118/37238-MS.
  8. Ferworn, K., Hammami, A., and Ellis, H.: "Control of Wax Deposition: An Experimental Investigation of Crystal Morphology and an Evaluation of Various Chemical Solvents," paper SPE 37240 presented at the 1997 International Symposium on Oilfield Chemistry, Houston, 18–21 February.

Noteworthy papers in OnePetro

Kang, P.-S., Lee, D.-G., & Lim, J.-S. (2014, August 7). Status of Wax Mitigation Technologies in Offshore Oil Production. International Society of Offshore and Polar Engineers. OnePetro

Oseghale, C. I., & Akpabio, E. J. (2012, January 1). Managing Paraffin Wax Deposition in Oil Wells - Related Problems in Nigerian Oil Fields. Society of Petroleum Engineers. http://www.doi.org/doi:10.2118/163037-MS

Reistle, C. E. (1935, January 1). Paraffin Production Problems. American Petroleum Institute. OnePetro

Venkatesan, R., & Creek, J. L. (2010, January 1). Wax deposition and rheology: progress and problems from an operator. Offshore Technology Conference. http://www.doi.org/doi:10.4043/20668-MS

Online multimedia

Jamaluddin, Abul. 2013. Flow Assurance – Managing Flow Dynamics and Production Chemistry. https://webevents.spe.org/products/flow-assurance-managing-flow-dynamics-and-production-chemistry-2

External links

Tukenov, Dauren. 2014. Nanochemistry Drives New Method for Removal and Control of Wax. Journal of Petroleum Technology. http://www.spe.org/jpt/article/7788-technology-update-1-7/

See also

Asphaltenes and waxes

Wax precipitation

Thermodynamic models for wax precipitation

Remediating wax deposition

Models for wax deposition in pipelines

PEH:Well_Production_Problems

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