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Asphaltene problems in production
Certain crude oils deposit solid asphaltenes during production. These deposits may plug the wellbore tubing and valves, as well as coat surface safety and process control equipment. Asphaltenes can also accumulate in separators and in pipelines.
Definition of asphaltenes
Asphaltenes are a compound class, not a single compound, concentrated in the high-temperature distillation residue of petroleum (> 530°C). Other components are:
- Heavy oils
- High-molecular-weight waxes
The asphaltene class is defined in accord with the solubility sequence illustrated in Fig. 1.
See Asphaltenes and waxes for a more detailed characterization of asphaltenes.
Anticipating asphaltene deposition
The tendencies of crudes to deposit asphaltenes do not correlate with the quantity of dissolved asphaltenes present in the reservoir fluid. Some oils with 1% asphaltene or less will form deposits in tubulars, while others with 10% or more asphaltenes will form no deposits. Asphaltenes chemistry varies with field. Asphaltenes contained in oil from a well in the North Sea are chemically different from asphaltenes found in the Venezuela fields, or another North Sea well. The chemistry controlling these depositions is not well defined. Nevertheless, some generalities are possible, which can aid in the design of prevention and remediation technology for a given well.
Asphaltene precipitation as changing pressure and temperature is illustrated in Figs. 2 and 3. The first figure is a plot of weight percent asphaltene precipitated as a function of pressure at reservoir temperature. A plot of saturation level, rather than percent asphaltene, gives the same form (data obtained from Burke, et al. The observed general scenario is as follows. There is no asphaltene precipitation on pressure reduction until a critical “onset pressure” is reached—here, nominally 4,500 psi; for the well described in Fig. 2, the reservoir pressure is in excess of 5,000 psi. The total amount deposited increases with decreasing pressure, reaching a maximum at nominally the saturation pressure. Asphaltene deposits can then redissolve as pressure falls, at least partially, possibly reaching zero deposition at low pressure (“dissolution pressure”). Not all crudes will show a dissolution pressure at accessible temperatures.
Fig. 2—Pressure dependence of asphaltene precipitation (cumulative) at constant temperature, 100oC (data from Ref. 2) .
Fig. 3—A pressure/temperature phase diagram for the stability of asphaltenes in a crude oil.
Fig. 3 shows an asphaltene deposition envelope (ADE), a plot of such onset pressures (upper boundary) and dissolution pressures (lower boundary) as a function of temperature, overlaid with a saturation pressure/temperature (PT) curve. The sense of the ADE region is that asphaltenes precipitate for PT values between the boundaries. The precipitation problem will be greater the closer the PT values are to the saturation line (as indicated in Fig. 2). A possible PT route to avoid asphaltene deposition during production is also shown in the figure.
Pressure and temperature changes are not the only drivers for asphaltene deposition. Combining certain crudes can deposit asphaltenes at the point of mixing (e.g., in the wellbore, flowlines, headers, pipelines, and oil treatment facilities.) Gas lift would favor deposition of asphaltenes from the heavy oil. ADE diagrams can be drawn for such compositional variations as well. Shear effects and electrokinetic effects during flow have been claimed as additional mechanisms for asphaltene precipitation. [It is claimed that asphaltenes are electrically charged and the electrical potential generated by flow of these ions through small orifices (similar chemistry to electro-osmosis) can overcome charge stabilization, causing flocculation.]
Increases in asphaltene problems with water-production onset are generally observed, as is the decrease in problems with larger water cuts; the definition of “large” varies with field. The presence of other solids with water in the produced fluid can exacerbate the consequences of asphaltene precipitation, generating a greater mass of solids and/or stable emulsions. A rationale for this exacerbation is shown schematically in Fig. 4. The surface-active resin/asphaltene aggregates adsorb with wax and other solids onto water droplets, stabilizing an emulsion that can be sufficiently strong to plug production.
Fig. 4—A visualization of the stabilizing effect of asphaltene and other solids on water droplets.
The quantity, and possibly chemistry, of the asphaltene mixture depends on, at least, the final solvent used after the initial separation (e.g., n-pentane vs. n-heptane). (Data are from Mitchell and Speight.) An asphaltene mixture using n-C5 as a precipitant will contain more material than an asphaltene mixture using n-C7. Asphaltenes precipitated from a cyclopentane addition would be very small in quantity, compared with those precipitated by n-pentane.
Asphaltene phase separation and deposition in the field generally involve only a portion of the asphaltene fraction generated from the crude oil in the laboratory by n-C5 fractionation (nominally 30 to 50% of the asphaltenes present are precipitated). An example is shown in Fig. 5 — a plot of the quantity of asphaltene dissolved (as per n-C5 precipitation) vs. pressure at constant temperature.
The asphaltene mixtures precipitated by either the n-C5 or n-C7 addition are dark brown to black, amorphous solids. The resins tend to be lighter in color and less viscous. Resins have H/C ratios ranging from 1.3 to 1.6; asphaltenes range from 1.0 to 1.3. An asphaltene molecule consists of clusters of condensed aromatic and naphthenic rings. Each cluster contains not more than 5 to 6 rings, connected by paraffin linkages, which may also contain oxygen and sulfur atoms (as sulfides and disulfides). The resins and asphaltenes contain about half the total nitrogen and sulfur in the crude oil. Nitrogen atoms are present predominantly as primary amines and pyridines (bases). It is these nitrogen atoms that can react with stimulation acid, potentially forming sludges. Oxygen is present predominantly in the form of acidic functional groups (carboxylic acids and phenols). These oxygen atoms can form chelants (salts) with iron, potentially forming sludges. Additional compositional details are given in Calemma. An example of an asphaltene molecule is given in Fig. 6.
Asphaltene molecules form aggregates with themselves, nominally 35 to 40Å in size, while remaining dissolved in oil. The specific nature of the chemical bonding between the monomer asphaltene molecules within the aggregates has not been well defined, which complicates anticipation (computer simulation) of their deposition tendencies. Various polar interactions are possible in principle, as well as acid-based interactions between the basic nitrogen and acidic carboxyl functions.
The asphaltene molecules and aggregates in a given crude cover a range of molecular weights; the smaller-molecular-weight asphaltenes are the most polar. The difficulties in quantifying asphaltene molecular weight result from the aggregation problem. For example, molecular weight ranges of 935 to 16,840 were found for one crude, depending on the instrumental techniques used; others have reported ranges of 1,000 to 2,000,000.
There is ample evidence that resin molecules play a major role in solvating the asphaltenes in oil. Petroleum resins are nominally C30 compounds and are different from nonpetroleum resins, which tend to be a 3- to 5-membered condensed aliphatic ring structure. Fig. 7 is a depiction of the structure of two resins derived from a crude oil:
- The aliphatic side chains are the nonpolar groups
- The condensed aromatic rings are the polar groups
“Common wisdom” is that resins attach themselves to the asphaltene aggregates by polar-group interactions. The nonpolar “tails” of the resin molecules provide compatibility (solvation) with the nonpolar components in crude oil. The concept that resins are the sole solvating oil constituents for the asphaltenes is an oversimplification. Naphthenes precipitate less asphaltenes9 than the low-carbon-number paraffins (solvate asphaltenes better than paraffins); xylene is used as a solvent for asphaltene removal, which is discussed later. Both classes of compounds (naphthenes and aromatics) are present in oil. The amounts vary depending on the source of the crude.
When this bonding chemistry between asphaltene aggregates and the solvating entities in the crude oil is disrupted, the aggregates come out of solution and flocculate to form larger particles. These flocs are the source of the operational problems. Only after flocculation occurs does deposition occur. The sequence of forms for the asphaltene during oil production is soluble → colloidal particles → flocculated → deposit.
Modeling asphaltene deposition
Preventing and/or mitigating asphaltene deposition is facilitated by the availability of the ADE for the particular well. The direct measurement of this stability envelope is difficult, tedious, expensive, and not always possible, particularly with crudes from old exploratory wells. Computer simulations of asphaltene precipitation tendencies are an option, whereby the computer takes key information about oil composition and asphaltene properties in order to generate the stability diagram. A problem in establishing a workable model is defining the relevant key information in terms of readily measurable oil and asphaltene parameters. The model is to specify:
- Operating envelope of pressure
- Temperature under which asphaltenes will and will not deposit
- How much asphaltene will deposit
- How these parameters vary with liquid composition, particularly in the context of mixing oils from different reservoirs and/or using gas lift to assist production
- How to best remove the asphaltene deposit (e.g., which solvents will be most effective for a particular asphaltene deposit)
Not all models available specify all of these items.
There are two broad classes of models for asphaltene dissolution and flocculation, variously labeled as the molecular-thermodynamic approach and thermodynamic-colloidal approach. The scope, limitations, and details of the concepts underlying these model classes are reviewed in Leontaritis and Cimmino. See Thermodynamic models for asphaltene precipitation for more information.
Given the uncertainties in asphaltene precipitation chemistry discussed, these computer models should be validated by the operator with comparisons of predicted onset pressures with experimental values for the fields of interest. These models are then best applied to new wells within the field by applying this correlation.
Coping with asphaltene deposition
The most effective procedure is configuring the production conditions to stay out of the precipitation envelope established for the well. This involves minimizing pressure drops within the production system—possibly fracturing the formation to minimize drawdown. The use of pressure maintenance by water injection might be appropriate if the field is of sufficient size. If prevention cannot be achieved, it may be possible to move the deposition to a location more easily treated (e.g., at the choke rather than at the perforations).
Chemical inhibitors can be used to prevent asphaltene precipitation. The inhibitors must be placed in the oil before asphaltene precipitation has taken place. In completion systems where capillary (“macaroni”) tubing already exists, a continuous injection of an inhibitor can be used. Continuous injection of an inhibitor into pipelined crude is straightforward, as well as the injection of inhibitors immediately before the mixing of asphaltene in incompatible oils. Asphaltene inhibitors can be squeezed into the formation, similar to inorganic-scale inhibitors. However, these inhibitors are necessarily oil soluble, resulting in a short functional lifetime for the inhibitor.
Asphaltene inhibitors are, generally, resinous organic polymers. Their functional groups interact with the asphaltenes in much the same way natural resins keep the asphaltenes dissolved. It is claimed that the strength of the interaction is stronger than with natural resins, keeping the asphaltene dissolved over a broader range of pressure and temperature. Given the variability in the asphaltene structure, it is important that the polymer inhibitor be evaluated on the specific crude in which it will be placed. In principle, it is possible that these polymers could also cause formation damage by altering the wetting properties of the rock. It is obviously prudent to evaluate this possibility on core samples before treatment.
Removal of deposits
Asphaltene deposits are generally removed manually, if present in readily accessible equipment, such as separators and other surface equipment. For tubular and flowline deposits, removal techniques involve chemical methods such as solvent soaks with or without dispersants. Combining solvents and heating may also be effective (see the section-REWORD on wax removal). Physical methods can be used depending on the hardness of the deposit (e.g., pigging, hydroblasting, and drilling). Pigging (cutting) is appropriate for removing pipeline deposits—often, mixtures of waxes and asphaltenes.
The traditional solvent of choice has been xylene. Cimino, et al.12 and Del Bianco, et al. describe the use of certain refinery cuts as solvents for asphaltene deposits—mixtures cheaper and more effective than xylene. It is to be expected, given the variability of asphaltene chemistry described, that the refinery-solvent mixture will have to be tailored to the specific well—one mixture will not necessarily cure all. A logic for deriving such mixtures is discussed in Minssieux.
Terpenes (more-expensive natural products) have been used effectively as solvents, replacing xylene because of health, safety, and environment (HSE) considerations. Certain alkylbenzene compounds will stabilize (dissolve or disperse) asphaltenes in simple aliphatic solvents (e.g., heptane). Also, the highly polar and readily available p - ( n -dodecyl) benzenesulfonic acid is a highly effective compound.
The prevention-by-well-design scenario, albeit initially potentially expensive, may be more cost effective throughout the life of the well vs. cleaning/dissolving. As with the removal of inorganic scale, the costs of the treatments involve not only the chemical itself but the deferred and/or lost oil production attendant to the well’s downtime for the treatment. A methodology for asphaltene control in the field, including all aspects previously described, is illustrated in Alf, et al.
- Hunt, J. 1996. Petroleum Geochemistry and Geology. New York: W. Freeman and Co.
- Burke, N.E., Hobbs, R.E., and Kashou, S.F. 1990. Measurement and Modeling of Asphaltene Precipitation. J. Pet Tech 42 (11): 1440–1446; Trans., AIME, 289. SPE-18273-PA. http://dx.doi.org/10.2118/18273-PA.
- Leontaritis, K.J., Amaefule, J.O., and Charles, R.E. 1994. A Systematic Approach for the Prevention and Treatment of Formation Damage Caused by Asphaltene Deposition. SPE Prod & Oper 9 (3): 157–164. SPE-23810-PA. http://dx.doi.org/10.2118/23810-PA.
- Nghiem, L.X., Coombe, D.A., and Farouq Ali, S.M. 1998. Compositional Simulation of Asphaltene Deposition and Plugging. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 27–30 September. SPE-48996-MS. http://dx.doi.org/10.2118/48996-MS.
- Limanowka, W.A. and Voytechek, M.J. 1999. Asphaltene Deposition Problems in Oil Industry with Focus on Electric Submersible Pump Applications. Presented at the SPE Annual Technical Conference and Exhibition, Houston, 3–6 October. SPE-56662-MS. http://dx.doi.org/10.2118/56662-MS.
- Leontaritis, K.J. 1989. Asphaltene Deposition: A Comprehensive Description of Problem Manifestations and Modeling Approaches. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 13–14 March. SPE-18892-MS. http://dx.doi.org/10.2118/18892-MS.
- Sarbar, M.A. and Wingrove, M.D. 1997. Physical and Chemical Characterization of Saudi Arabian Crude Oil Emulsions. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 5–8 October. SPE-38817-MS. http://dx.doi.org/10.2118/38817-MS.
- Mitchell, D. and Speight, J. 1973. The Solubility of Asphaltenes in Hydrocarbon Solvents. Fuel 52 (4): 149.
- Colmenares, R. and Smith, R.W. 1997. Short and Long term Management of El Furrial Field, Venezuela. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 5–8 October. SPE-38781-MS. http://dx.doi.org/10.2118/38781-MS.
- Edmonds, B. 1999. Technical Update—Asphaltene Deposition. London: Infochem Computer Services Ltd.
- Cimimo, R., Correra, S., Del Bianco, A. et al. 1995. Solubility and phase behavior of asphaltenes in hydrocarbon media. In Asphaltenes: Fundamentals and Applications, 3, 97–130. New York: Plenum Press. Cite error: Invalid
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- Calemma, V. et al. 1995. Structural Characterization of Asphaltenes of Different Origins. Energy Fuels 9 (2): 225. Cite error: Invalid
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- Kawanka, S. et al. 1989. Thermodynamic and Colloidal Models of Asphaltene Flocculation. In Oil Field Chemistry, 24. Toronto: Symposium 390, ACS.
- Suzuki, T. et al. 1982. Chemical Structure of Tar-Sand Bitumens by 13-C and 1-H NMR Spectroscopy Method. Fuel 61 (1): 40.
- Ali, J., Betancourt, J., and Avila, C. 1999. A Methodology for Asphaltene Control in Production Facilities in North of Monagas, Venezuela. Presented at the SPE Annual Technical Conference and Exhibition, Houston, 3–6 October. SPE-56572-MS. http://dx.doi.org/10.2118/56572-MS.
- Allenson, S. and Walsh, M. 1997. New Chemicals and Treatment Methods that Prevent Asphaltene Deposition Problems Found in Oil Production. Proc., IBC U.K. Conference, Aberdeen.
- Del Bianco, A., Stroppa, F., and Bertero, L.: "Tailoring Hydrocarbon Streams for Asphaltene Removal," paper SPE 28992 presented at the 1995 International Symposium on Oilfield Chemistry, San Antonio, Texas, 14–17 February.
- Minssieux, L.: "Removal of Asphalt Deposits by Covalent Squeezes: Mechanisms and Screening," paper SPE 39447 presented at the 1998 SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, 18–19 February.
- Chang, C. and Folger, S.H. 1994. Stabilization of Asphaltenes in Aliphatic Solvents Using Alkylbenzene Derived Amphiphiles. Langmuir 10 (1): 749.
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