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Asphaltene deposit in production tubing, creating flow assurance issues.
Heat exchanger fouling due to asphaltenes.

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Asphaltenes are a solubility class of the crude oil defined as soluble in aromatic solvents and insoluble in n-alkanes [1][2]. It can appear in a gas condensate system if the reservoir has an oil rim[3]. The ASTM D-3279-90 (IP143/90) test defines asphaltenes as solids that precipitate when an excess of n-heptane or pentane is added to a crude oil. The choice of light alkane will affect the quantity of asphaltenes precipitation and can mislead any asphaltene content comparison between two oils if the solvent choice is not clear.

Asphaltene molecules have complex structures and are typically polar with relatively high molecular weights (~700 to 1,000)[4] and a density of about 1.2g/cc [5]. Asphaltenes may precipitate from crude oil during production and deposit on the internal surface of the production system or accumulate in equipments with high resident time or dead legs[6], creating flow assurance and processing issues (emulsion, heat exchanger fouling, etc.).


Asphaltene deposition problems

Asphaltenes precipitated under different conditions have different morphology.

In the oil industry, asphaltenes are only a problem when they are precipitated. Asphaltenes deposits can occur throughout the production system, from near wellbore reservoir to production tubing, flowlines, and processing facilities, e.g separators. They cause production rate decline and various other operational problems, such as higher viscosity and water oil emulsion, etc. It is a key risk to handle in flow assurance and production chemistry.

  • Near wellbore reservoir[7]: asphaltene deposition in the reservoir has been reported causing permeability reductions or changes to wettability, resulting in lower recoveries.
  • Production tubing[8]: Tubing deposits can cause decreased production rate and severe problems to wireline operations.
  • Flowline: flowline deposits also cause decreased production and can cause pigs to get stuck during pigging operations.
  • Processing facilities[9]: asphaltene deposits have also been seen in production equipment, such as separators, where asphaltenes have collected after having been precipitated further upstream. Asphaltenes also cause oil/water separation problems by stabilizing emulsions.

Asphaltene deposits can appear hard and coal-like, or more sticky and tar-like. The more resins are precipitated with the asphaltenes, then the more oil-like the deposit may appear. The nature of the deposits is determined by the crude oil and the conditions under which precipitation occurred.

Understand more about asphaltenes

Hypothetic asphaltene structures.

Geological origin

Asphaltenes are today widely recognised as soluble, chemically altered fragments of kerogen which migrated out of the source rock for the oil, during oil catagenesis. The nickel to vanadium contents of asphaltenes reflect the pH and Eh conditions of the paleo-depositional environment of the source rock for oil (Lewan, 1980;1984) and this ratio is therefore in use in the petroleum industry for oil-oil correlation and for identification of potential source rocks for oil (oil exploration)

Heavy oils, tar sands and biodegraded oils (as bacteria can not assimilate asphalten[e]s, but readily consume saturated hydrocarbons and certain aromatic hydrocarbon isomers - enzymatically controlled) contain much higher proportions of asphaltenes than do medium-API oils or light oils. Condensates are virtually devoid of asphaltenes.


Asphaltenes consist primarily of carbon, hydrogen, nitrogen, oxygen, and sulfur, as well as trace amounts of vanadium and nickel. The C:H ratio is approximately 1:1.2, depending on the asphaltene source. Asphaltenes are defined operationally as the n-heptane (C7H16)-insoluble, toluene (C6H5CH3)-soluble component of a carbonaceous material such as crude oil, bitumen or coal. Analysis of n-pentane precipitated asphaltenes might typically show 80-85% by weight carbon of which 50-60% is aromatic, 7-10% hydrogen, and up to 10% sulphur, 3% nitrogen and 5% oxygen, plus traces of heavy metals such as vanadium and nickel. The resultant molecular weight of the precipitated material therefore can vary enormously from thousands to millions, depending upon the solvent.


All techniques are now roughly in accord, including many different mass spectral methods (ESI FT-ICR MS, APPI, APCI FIMS, LDI) and many different diffusion techniques (time-resolved fluorescence depolarization (TRFD), fluorescence correlation spectroscopy (FCS), Taylor dispersion)[10]. This result deviates substantially from previous conventional wisdom, the old and incorrect view is promulgated on many popular web sites putatively illustrating asphaltene molecular structures. Asphaltene molecular weight is ~750 Da with 500 - 1000 FWHM. Aggregation of asphaltenes at very low concentrations (in toluene) led to aggregate weights being misinterpreted as molecular weights with techniques such as VPO or GPC. The chemical structure is difficult to ascertain, due to the complex nature of the asphaltenes, but has been studied by all available techniques including X-ray, elemental, and pyrolysis GC-FID-GC-MS. However, it is undisputed that the asphaltenes are composed mainly of polyaromatic carbon i.e. polycondensed aromatic benzene units with oxygen, nitrogen, and sulfur, (NSO-compounds) combined with minor amounts of a series of heavy metals, particularly vanadium and nickel which occur in porphyrin structures.

Asphaltene molecular architecture has also been controversial. The TRFD rotation diffusion measurements have indicated there is predominantly one PAH per asphaltene molecule. Asphaltene rotational diffusion measurements show that small PAH chromophores (blue fluorescing) are in small asphaltene molecules while big PAH chromophores (red fluorescing) are in big molecules. This implies that there is only one fused polycyclic aromatic hydrocarbon (PAH) ring system per molecule. Very recent fragmentation studies by FT ICR-MS and by L2MS (two-color laser mass spectroscopy) strongly support this 'island' molecular architecture as shown by TRFD and refuting the 'archipelago' molecular architecture.

Nanocolloidal structure: it has been shown that asphaltenes have two distinct nanocolloidal structures. The island molecule architecture, with attractive forces in the molecule interior (PAH)and steric repulsion from alkane peripheral groups gives rise to nanocolloids with aggregation numbers less than 10. Methods to show these structures in clude SANS, SAXS, high-Q ultrasonics, NMR, AC-conductivity, DC-conductivity, centrifugation. These structures are also observed in oil reservoirs with extensive vertical offset (where gravitational effects are evident). In addition to these 'primary' nanoaggrgeates, CLUSTERS of nanoaggregates can also form as seen by a variety of techniques.

What can cause asphaltenes to precipitate?

Asphaltene precipitation envelope
Comparision of asphaltene stabilities by live oil solubility parameters. Pb is bubble point pressure.

Asphaltenes are typically stable under virgin reservoir condition, which are believed to be held in solution by resins (similar structure and chemistry, but smaller). During production, asphaltenes can be destabilized and precipitate due to changes in temperature (to a lesser extent), pressure and the chemical composition of the crude. Asphaltene deposition risk is dependent on both precipitation and flow shearing, which will be explained further in the risk assessment section.

Effect of Temperature

The effect of temperature is critical in the mechanism for paraffin wax precipitation, but its impact on asphaltenes precipitation is less pronounced. As shown in the asphaltene phase envelope, asphaltene stability tends to increase at higher temperatures.

Effect of Pressure

Pressure has a large effect on the flocculation of asphaltenes. Studies of asphaltene deposition in production well tubing have found that deposition occurs below the depth at which the bubble point for the crude occurs[11], which means asphaltenes can precipitate at pressures above the bubble point. As the fluid rises in the tubing, the pressure gradually drops and the oil expands. Different species in the oil expand at different rates depending upon their compressibilities. The lighter ends such as methane expand to a greater degree than the heavier components. This has the effect of increasing the molar volume of the lighter ends in the crude, increasing their influence on the stabilising resins, and hence increasing the likelihood of asphaltene precipitation.

The greatest risk of precipitation however, occurs at a depth just below where the fluids are at their bubble point because gas starts to breakout at the bubble point, where lighter gases such as methane, ethane and propane are lost from the oil. This marks the turning point for asphaltene solubility, from which point on asphaltenes become more and more stable in solution as pressure decreases and more gas leaves the oil phase.

Effect of Gas Lift

Lift gas usually consists mainly of light alkanes which are able to strip away the stabilizing resins. In wells where gas lift has been installed, there can therefore be an increased risk of asphaltene precipitation. The magnitude of the risk depends upon how close to flocculation the oil was before mixing with lift gas and the lift gas volumes compared to the amount of oil. On the other hand, adding gas increases the overall fluid velocity and therefore makes asphaltenes harder to deposit.

Effect of Acid Stimulations

Production wells subjected to acid stimulation can result in asphaltene deposits although asphaltenes are stable during normal production. Acid stimulation treatments have been shown to adversely affect the asphaltene stability of certain crudes causing sludging and rigid film emulsions[12]. There are examples in the literature of methods to limit these effects[13]. Asphaltene sludges and emulsions stabilised by asphaltenes have been observed. The polar nature and consequent surface activity of asphaltenes attracts them to oil/water interfaces and is enhanced during acid treatments.

During initial well-unload, the produced hydrocarbon is flowed back together with some low pH completion/stimulation fluids, which is also a scenario subjected to higher than normal asphaltene deposition risk.

Effect of Miscible Gas

In some CO2 or N2 miscible flood programs, formation damage can occurred, which subsequently was considered to be due to asphaltene deposits plugging the formation. Little is reported on the nature of the deposits but it appears that CO2 can destabilise asphaltene micelles by two mechanisms. Firstly, dissolution of CO2 into the crude depeptises the resins in much the same manner as light hydrocarbons. Secondly, CO2 tends to strip out the lighter hydrocarbons, further increasing the risk of asphaltene precipitation.

Effect of Oxidation

Exposure to air can cause resins to oxidise. Where this has occurred, the resultant measured asphaltene content has been shown to rise. This effect would not normally be considered important during normal operations.

Effect of Electric Fields

The polar nature of asphaltenes can cause an attraction to positive or negative electrodes, and electrodeposition has been reported in some heavy crudes[14]. This could occur, for instance, in electrostatic separators. However, the effect is likely to be small, and any crude which is susceptible to asphaltene precipitation is likely to have lost asphaltenes before this point in the production system.

Effect of Mixing Different Streams

Each hydrocarbon has a given asphaltene content and a particular solvency for its asphaltenes. In a major export line, there may be several streams from different reservoirs all using the same line. Mixing different crude streams can have a significant impact on the risk of asphaltene precipitation. For instance, a light condensate with little asphaltenes can destabilise a crude with a high asphaltene content which on its own has good asphaltene solvency.

Asphaltene Risk Assessment

Establish the risk of asphaltene precipitation during oilfield operations, the crude oil must be characterised for its asphaltene content and the solvency it has for its asphaltenes, and then the effect of the external conditions determined. It is important to keep in mind that asphaltene content is NOT directly correlated with asphaltene risk. High asphaltene content may be stable asphaltenes while low asphaltene content may be unstable asphaltenes.


Studies have shown that asphaltene precipitation can be essentially irreversible. Once the intermolecular force which stabilises the asphaltene resin micelle is broken, the precipitated asphaltene cannot be easily resolubilised. To obtain a representative sample from which to determine the risk of asphaltenes the oil must not have lost any of its asphaltenes. To achieve this, samples must be taken at pressures above the bubble point and maintained single phase. When the fluids are below their bubble point in the reservoir, this is clearly impossible. Even when the bubble point falls in the production tubing between the perforations and the wellhead it is not easy. Frequently, only wellhead samples are available. Wellhead samples may have lost some asphaltenes, however, providing the well has been flowing for some time, the amounts lost are likely to be only a fraction of the total asphaltene content. Once sampled, further asphaltene deposition should be avoided. This could be achieved by sampling into a high pressure vessel, and pressurising the sample to above its bubble point.

SARA Analysis

Asphaltene stabilizability assessment using SARA analysis.

SARA refers to the saturate, aromatic, resin, and asphaltene (SARA) fractions of a crude oil. The saturate fraction consists of nonpolar material including linear,branched, and cyclic saturate hydrocarbons. They typically decrease asphaltene solubility. Aromatics, which contain one or more aromatic rings, are more polarizable and increase asphaltene solubility. The asphaltene content of an oil can be determined by the IP laboratory test method IP 143. This method extracts asphaltenes and the waxy fractions from a crude oil using n-heptane. Asphaltenes are then extracted into toluene, which is finally evaporated off leaving the solid weight of asphaltenes. The asphaltene content of a crude oil is insufficient alone to predict the likelihood of asphaltene precipitation, and as such is of limited value without further information.

Resins provide a protective shield around the asphaltenes to prevent them from aggregating and precipitating. When this resin encapsulation shield is removed by addition of n-alkanes, asphaltene precipitation takes place. It is important to establish the balance of the asphaltene and resin fractions of the crude since this information is essential to identifying the instability of a stock tank crude sample.

The resin content of a crude can be measured by an HPLC technique. Resins are isolated on an amino propyl normal phase HPLC column. A known amount of the oil from which the asphaltene has been removed is separated. Using isocratic elution with the same solvent, saturates and aromatics are eluted from the column for a specific time period. Resins are then eluted by backflushing the column with chloroform/methanol. The resins are recovered by evaporation, determined by weight and reported as a percentage of the original oil.

Colloidal stability index (C.S.I.) can be calculated from SARA analysis and be used to estimate asphaltene stability.

\(C.S.I.= \frac{Saturates + Asphaltenes}{Aromatics + Resins}\)

De Boer Plot

De Boer plot with field data

The best known, most widely used screening method for evaluating the risk of asphaltene precipitation during depressurization is that proposed by de Boer et al. [15]. It is a simple evaluation based on (1) the difference between reservoir and bubble-point pressure, (2) density of the reservoir fluid, and (3) asphaltene saturation at reservoir conditions, as summarized in what is often referred to as a "de Boer plot". The unstable and stable regions are based on calculations of asphaltene supersaturation using the Hirschberg model [16]. An intermediate area, labeled "Possible problems" lies between the extremes and is bounded by calculated supersaturation values of 1 and2 (assuming the solubility parameter of asphaltene is 20 MPa1/2.)

Although the de Boer plot clearly distinguishes very stable oils from very unstable ones, experience over the past decade has shown that predictions tend to be somewhat pessimistic, indicating asphaltene precipitation in cases where no problems develop in the field, i.e., "false positive".


Use of ASIST to predict onset for oil at reservoir condition[17]

The ASIST method was developed by Wang and Buckley[18] and is often used by Chevron[19] for asphaltene risk assessment. The ASIST refers to Asphaltene Instability Trend, a linear relationship between the solubility parameter at the onset of asphaltene precipitation and the square root of the molar volume of precipitating agents for a series of liquid n-paraffins. This trend could be used to predict asphaltene onset pressures during oil production from stock-tank oil (STO) titration experiments with liquid n-paraffins at near ambient conditions and solubility parameter estimates based on refractive index (RI) measurements.

The information required consists of standard PVT an compositional data for the reservoir fluid. The only additional information is the oil-specific ASIST data for STO samples, which can be obtained from as few as two or three onset titrations with different n-paraffins at each of two different temperatures. The ASIST data can be extrapolated to predict the onset solubility conditions for addition of the oil's light ends (C1 - C6) as well as for addition of injection or lift gas. Comparisons of these onset solubility conditions to the in-situ solubility parameter of live oil or live oil plus injection/lift gas, which can be estimated from the PVT and compositional data, will tell under what circumstances the reservoir oil should experience asphaltene instability.

Lab Measurement of Asphaltene Flocculation

Asphaltene onset characterization by High Pressure Microscope.

The asphaltene and resin contents do not define whether asphaltenes will be precipitated from any given crude under operational conditions. Companies have used two methods to establish how close to asphaltene instability a crude will be.

  • High Pressure Microscope - This apparatus allows a crude oil to be pumped through a windowed cell at pressures and temperatures similar to those experienced under field conditions. A narrow path length and a powerful light source are used to examine the transmittance through the oil as the pressure and/or temperature are altered. On reduction of pressure, the solvency of a crude for its asphaltenes is reduced, and asphaltene flocculation can take place. This can be observed by the formation of flocculated black deposits which adhere to the window. The pressure required for this to commence is then noted.
  • Asphaltene Flocculometer - The solvency of a crude oil for its asphaltenes can be determined quantitatively by titrating the crude with an n-alkane flocculant and measuring the volume of alkane required before sufficient resins are removed to allow asphaltenes to precipitate. Light scattering is used to detect the onset of asphaltene flocculation, whilst an oil sample is titrated at the required temperature and pressure. To measure the onset of flocculation, a known volume of the test oil sample is transferred to the pressure vessel. Once at temperature, the oil sample is titrated with the flocculant. The volume of flocculant added is recorded against the voltage signal from the photo diode. As the flocculant is added, the crude becomes lighter and there is an increase in the returned signal. When sufficient flocculant is added, the oil reaches the threshold of flocculation, and there is a marked decrease in the returned signal, as asphaltene particles scatter the reflected light.

Deposition Modelling

Precipitated asphaltenes do not necessarily deposit and become a flow assurance risk because their deposition behavior is heavily impacted by the fluid flow. If the wall shear stress is high enough, some asphaltene deposits can actually be sheared off by the flow. A few field cases have been reported that the production tubing has no asphaltene deposition although asphaltene is unstable in the tubing. Modeling asphaltene deposition is not a easy task, but progress has been made in the past few years[20] [21].

Asphaltene Mitigation

Asphaltene Inhibitors

Asphaltene inhibitors are long chain molecules that mimic the stabilising effect of a resin layer to preventing flocculation. However, some current asphaltene inhibitors are actually dispensents, that it, they don't prevent asphaltene flocculation, but instead disperse the precipitated asphaltenes to prevent deposition or agglomeration. Asphaltene inhibitors have to injected upstream of the asphaltene flocculation location for optimal performance. In general, their effectiveness has been questionable as reported by several operators[22]. Their efficiency could be around 50-70% if it works. Additionally, current lab asphaltene inhibitor screening methods have questionable correlation with field performance[23].

Asphaltene inhibitor squeeze has been proposed to mitigate near wellbore asphaltene problem, but with limited success case studies[24].


Epoxy resin coatings have been applied to tubulars (12) in an attempt to stop asphaltenes from sticking and building up into a deposit.

Reservoir pressure maintenance

One of greatest risk of asphaltene deposition is in the near wellbore region because it can quickly curtail production and choice of mitigation or remediation is very limited. Water flood is often used to maintain reservoir pressure and improve ultimate recovery. The target reservoir pressure maintenance is usually set right above the asphaltene onset pressure to prevent asphaltene from dropping out in the reservoir.

Asphaltene Remediation

Since none of the asphaltene mitigation methods is 100% effective, remediation typically becomes unavoidable if asphaltene deposition is a risk. Depending on the location of the deposit, conventional remediation methods include chemical (e.g. dispersants, solvent, etc.), mechanical (e.g. coil tubing jetting, wireline cutting, pigging, shoveling, etc), or combination of the two[25].


Many operators rely upon periodic solvent washes to remove asphaltenes that have formed. Typically hot aromatic solvents such as xylene prove effective, although production wells must be shut in for several hours for such a treatment. There is an additional risk if the solvent reaches the formation, since changes to wettability can alter the relative permeability to oil, and cause a dramatic reduction in oil production rates. Also, asphaltene deposits may be dislodged and get pushed into the formation during bullheading. Further, aromatic solvents can pose environmental hazard and tend to dissolve elastomer seals. The rule of thumb is 100 gallon of solvent per foot of tubing with deposit. More environmentally terpene based solvents are available, but at a much higher cost.

Long chain carboxylic acids have been identified as effective for deasphalting, probably by reacting with precipitated asphaltenes via hydrogen bonding. Long chain anionic surfactant have also been reported as effective although this chemical type would not be suitable in production systems since they would encourage formation of emulsions.


Dual completions have been used to allow the injection of Xylene directly into the production stream. Details are limited of how effective this method was and the high cost of such completions probably eliminates this as a solution in many cases.

Coiled tubing has also been used to inject asphaltene solvents/inhibitors, although in this reported case results were disappointing, possibly as a result of the relatively poor performance of the chemicals used.

Wireline cutting is an effective means of asphaltene removal if the wellbore is readily accessible.

Mechanical scraping devices can been used to remove blockages in production tubing. In one field a downhole hydraulic motor has been used, lowered and powered from coiled tubing. It was found to be the most economical method of controlling asphaltenes for this development.

Pigging can be used to remove asphaltene deposits in flowlines. However, effective removal requires the appropriate types of pigs to be used and the pigging should be performed on a regular basis. Spherical or foam pigs are not suitable for asphaltene removal.

A recent report has indicated ultrasonic treatments can clean up asphaltenes deposited in near wellbore regions[26], although at the time of writing, no commercial equipment is available.

Reversibility and Irreversibility of Asphaltene Deposition

This subject has been addressed by many authors and remains the most controversial part in studying the behavior of asphaltenes. Depending on the method used to detect asphaltene, some investigators reported that asphaltene deposition is irreversible or less likely to be reversible process[27][28], others have reported that the process is reversible[29][30]. Thou[31] argued that asphaltene deposit is more reversible if the flocculation occurred at higher temperatures (>30C).

External links


  1. Mullins, OC et al. Editors, Asphaltenes, Heavy Oils and Petroleomics, Springer, New York (2007) 700 pages, 23 Chapters, 46 contributing scientists.
  2. Asphaltene
  3. Thou, S. and Ruthammer, G. "Detection of asphaltene flocculation onset in a gas condensate system", SPE 78321, 2002
  4. Groenzin and Mullins, "Asphaltene molcular size and structure", J. Phys. Chem, A 103 (1999), 1013-1020
  5. Yarranton and Masliyah, "Molar mass distributlion and solubility modeling of asphaltenes", AIChE J 42.12 (1996), 3533-3543
  6. J. Creek, "Freedom of action in the state of asphaltenes: escape from conventional wisdom", Energy&Fuels, 19.4 (2005), 1212-1224
  7. Newberry M.E. and Barker K.M. 1985 "Formation Damage Prevention through the Control of Paraffin and Asphaltene Deposition." SPE Paper 13796, Oklahoma City, March 10-12, 1985
  8. Adailas, S. 1982 Investigation of Physical and Chemical Criteria as Related to the Prevention of Asphaltene Deposition in Oil Well Tubings. MSc Thesis.
  9. Thaver R. Nicoll and Dick G. 1988 Asphaltene deposition in Production Facilities. SPE Paper 18473.
  10. Institute of Petroleum, London Standard Methods for Analysis & Testing of Petroleum and Related Products IP143/84
  11. Adalialis S. "Investigation of Physical and Chemical Criteria as Related to the Prevention of Asphalt Deposition in Oil Well Tubings". MSc thesis, Petroleum Engineering Department, Imperial College University of London, 1982.
  12. Tuttle R.N., High‑Pour‑Point and Asphaltic Crude Oils and Condensates. J. Petroleum Tech. 35. Jan‑June 1983
  13. Newberry M.E. and Barker K.M. "Formation Damage Prevention through the Control of Paraffin and Asphaltene Deposition." SPE Paper 13796, Oklahoma City, March 10-12, 1985
  14. Lichaa P.M. and Herra L. Electrical and Other Effects Related to the formation and prevention of Asphaltenes Deposition. SPE Paper 5308 Oilfield & Geothermal Chemistry Symposium, Dallas, Jan, 16 17.
  15. de Boer, R.B., Leerlooyer, K., Eigner, M.R.P., and van Bergen, A.R.D.: "Screening of crude oils for asphalt precipitation: theory, practice, and the selection of inhibitors", SPE PF (Feb. 1995) 10, 55-61.
  16. Hirschberg, A., DeJong, L.N.J., Schipper, B.A., and Meijer, J.G.: "Influence of temperature and pressure on asphaltene flocculation," SPEJ (June 1984) 24, 283-293
  17. J.X.Wang, J.L. Creek, "Screening of potential asphalene problems" SPE 103137, 2006.
  18. Wang, J.X. and Buckley, J.S.: "An experimental approach to prediction of asphaltene flocculation", SPE 64994 presented at 2001 OCS, Houston, 13-16 Feb.
  19. Montesi et al. "Asphaltene management in GOM DW subsea development", OTC 21587, 2011
  20. S. Takhar*, P. D. Ravenscroft*, D. C. A. Nicoll 1996 Prediction of Asphaltene Deposition During Production - Model description and Experimental Details. SPE 30108.
  21. D.Eskin, J.Ratulowski, K. Akbarzadeh, S. Andersen, "Modeling of asphaltene deposition in a production tubing", AIChE Journal, 2011
  22. Montesi et al. "Asphaltene management in GOM DW subsea development", OTC 21587, 2011
  23. Montesi et al. "Asphaltene management in GOM DW subsea development", OTC 21587, 2011
  24. Alberto G. Di Lullo, Thomas P. Lockhart, EniTecnologie SpA; Carlo Carniani, Mauro Tambini, Eni - Agip, "A Techno-Economic Feasibility Study of Asphaltene Inhibition Squeeze Treatments", European Petroleum Conference, 20-22 October 1998, The Hague, Netherlands
  25. UNDERSTANDING PARAFFIN AND ASPHALTENE PROBLEMS IN OIL AND GAS WELLS, Petroleum Technology Transfer Council, South Midcontinent Region, July 16, 2003 Workshop in Smackover, Arkansas at the Arkansas Natural Resources Museum[1]
  26. Gollapudi U k, Bang S S, and Islam M R. 1994 "Ultrasonic Treatmentfor Removal of Asphaltene Deposits During Petreoleum Production." SPE 27377 Louisiana , February 7-10. 1994
  27. Fotland, P. "Precipitation of asphaltenes at high pressures: Experimental techniques and results" Fuel Sci & Tech. Int., 14 (1&2), p313-325, 1996
  28. Wang, et. al, "Advances in observation of asphaltene destabilization" SPE 50745, SPE International Symposium on Oilfield Chemistry, Houston, Texas, 16-19 Feb 1999
  29. Hammami, et al. "Asphaltene precipitation from live oil: an experimental investigation of the onset conditions and reversibility" DBR research Ltd., Edmonton, Alberta, Canada
  30. Hirschberg, et al. "Influence of temperature and pressure on asphaltene flocculation", JPT, P283-293, June 1984
  31. Thou, S. and Ruthammer, G. "Detection of asphaltene flocculation onset in a gas condensate system", SPE 78321, 2002
  • Institute of Petroleum, London Standard Methods for Analysis & Testing of Petroleum and Related Products IP143/84
  • Leontatritis K.J. and Mansoori G.A. 1987 Asphaltene Flocculation Duriong Oil Production and Processing: A Thermodynamic Colloidal Model. SPE Paper 16258. Symposium on Oilfield Chemistry, San Antonio, Texas, Feb 4 6
  • Lichaa P.M. and Herra L. Electrical and Other Effects Related to the formation and prevention of Asphaltenes Deposition. SPE Paper 5308 Oilfield & Geothermal Chemistry Symposium, Dallas, Jan, 16 17.
  • Haskett C.E. and Tantera M. 1965 A Solution to the Problem of Asphaltene Deposits Hassi Mesoud Field, Algeria. J. Pet. Tech. (April 1965), 387 391.
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  • Thaver R. Nicoll and Dick G. 1988 Asphaltene deposition in Production Facilities. SPE Paper 18473.
  • Kawanaka S. Park and S.J. & Mansoori G.A. The Role of Asphaltene Deposition in EOR Gas Flooding: A Predictive Technique. SPE/DOE Paper 17376
  • Tuttle R.N. 1983 High Pour Point and Asphaltic Crude Oils and Condensates. J. Petroleum Tech. 35. Jan June 1983
  • Newberry M.E. and Barker K.M. 1985 "Formation Damage Prevention through the Control of Paraffin and Asphaltene Deposition." SPE Paper 13796, Oklahoma City, March 10-12, 1985
  • Gollapudi U k, Bang S S, and Islam M R. 1994 "Ultrasonic Treatmentfor Removal of Asphaltene Deposits During Petreoleum Production." SPE 27377 Louisiana , February 7-10. 1994
  • Reichert C, Fuhr B J, and Klein LL 1986 "Measurement of Asphaltene Flocculation in Bitumen solutions." JCPT Montreal, Sept-Oct 1986
  • Akbar S.H. and Saleh A.A. 1989 A Comprehensive Approach to Solve Asphaltene Deposition Problems in Some Deep Wells. SPE Paper 17965. Middle East Oil Technical Conference and Exhibition, Manama, Bahrain, 11 14 March.
  • Adailas, S. 1982 Investigation of Physical and Chemical Criteria as Related to the Prevention of Asphaltene Deposition in Oil Well Tubings. MSc Thesis.
  • S. Takhar*, P. D. Ravenscroft*, D. C. A. Nicoll 1996 Prediction of Asphaltene Deposition During Production - Model description and Experimental Details. SPE 30108.