382 Reservoir Formation Damage Characteristics of Asphaltenic Oils As indicated by Figure 14-1 by Philp et al. (1995), the boiling and melting points of hydrocarbons increase by the carbon number. Heavy crude oils contain large quantities of higher boiling components, which create problems during oil production (Speight, 1996). Speight and Long (1996) point out that chemical and physical alteration of oils may affect the dispersibility and compatibility of their higher molecular weight fractions and create various problems, such as phase separation, pre- cipitation and sludge formation during the various phases of petroleum production, transportation, and processing. Speight (1996) classified the constituents of the crude oil into four hydrocarbon groups: (1) volatile saturates (paraffins) and aromatics, (2) nonvolatile saturates (waxes) and aromatics, (3) resins, and (4) asphaltenes. Speight (1996) explains that the nomenclature of the petroleum fractions, such as given in Figure 14-2, is based on the techniques of separation of the crude oil into its fractions. Figure 14-3 by Leontaritis (1997) describes the various steps and techniques involved 600 Q. I 500- 400- 300- 200- 100- 0- -100- .200 o Boiling Point • Melting Point 10 20 30 40 50 Carbon Number 60 70 Figure 14-1. Effect of n-alkane carbon number on boiling and melting point temperatures (after Philp, R. P., Bishop, A. N., Del Rio, J C., and Allen, J., Cubitt, J. M., and England, W. A. (eds.), Geological Society Special Publica- tion No. 86, pp. 71-85, ©1995; reprinted by permission of R. P. Philp and the Geological Society Publishing House). Formation Damage by Organic Deposition 383 Feedstock n-Heptane Insolubles 1 g Insolubles | Carbon Olsulflde or Pyrldine * 1 Carboids | (Insolubles) < ! Deasphaltened Oil Benzene or Toluene I Asphaltenes Carbenes S (Solubles) ; | i 3. Benzene- Methanol r i Resins (Polars) \ I Silica or Alumina 2. Benzene or 1. Heptar Toluene Aromatics Saturates | Figure 14-2. Classification of petroleum constituents based on laboratory fractionation (reprinted from Journal of Petroleum Science and Engineering, Vol. 22, Speight, J. G., "The Chemical and Physical Structure of Petroleum: Effects on Recovery Operations," pp. 3-15, ©1999, with permission from Elsevier Science). in the analysis of the crude oil, including cryoscopic distillation (CD), solvent extraction (SE), gas chromatography (GC), high performance liquid chromatography (HPLC), and gel permeation chromatography (GPC). Table 14-1 by Srivastava and Huang (1997) presents data on the chemical and physical properties of typical oil samples taken from Weyburn wells. Leontaritis (1996, p. 14)* described the heavy fractions of petroleum as following: Asphaltenes: Highly condensed polyaromatic structures or molecules, containing heteroatoms (i.e., S, O, N) and metals (e.g., Va, Ni), that exist in petroleum in an aggregated state in the form of suspension and are surrounded and stabilized by resins (i.e., peptizing agents). They are known to carry an electrical charge, and thought to be polydisperse. Asphaltenes are a solubility class, hence, they are not pure, identical molecules. Pentane and Heptane are the two most frequently used solvents for separating asphaltenes from crude oil. The prefix n-Pentane or n-Heptane asphaltenes refers to the solvent used for * Reprinted from Leontaritis ©1996, p. 14, by courtesy of Marcel Dekker, Inc. 384 Reservoir Formation Damage Live Sample Insoluble Fraction nC 6 Asphaltenes Cg_ Fraction Tffl Heterocyclics THI Aromatics Pseudo-components Paraffins-Wax Pure Components Figure 14-3. Steps of oil analysis and characterization for paraffin, aromatic, resin, and asphaltene (after Leontaritis, ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers). Formation Damage by Organic Deposition 385 Table 14-1 Chemical and Physical Properties of Weyburn Dead Oils* Temperature °C 15 20 59 61 63 Pressure MPa 0.1 3.54 6.99 10.44 17.33 Oil W1' Density kg/m 3 878.9 875.9 846.1 Density @59°C d 846.1 849.2 852.4 858.0 860.9 BS&W, vol % Molecular Weight, g/g-mol Component Saturates Aromatics Resins Asphaltenes Viscosity mPa»s . 12.8 4.2 - - Viscosity @59°C d 4.2 . - - - 0.1 230 wt.% 48.5 33.5 13.2 4.8 OilW2" Density kg/m 3 854.9 842.4 - 813.1 - Density @61°C d 813.1 816.4 819.6 822.9 829.3 Viscosity mPa*s . 4.60 - 2.35 - Viscosity @61°C d 2.35 2.49 2.62 2.76 3.04 0.2 203 wt.% 55.3 31.1 9.6 4.0 Oil W3 C Density kg/m 3 869.2 864.4 - - 839.4 Density @63°C d 839.4 842.4 845.2 848.4 854.7 Viscosity mPa«s 11.76 9.40 - - 3.15 Viscosity @63°C d 3.15 3.26 3.37 3.49 3.71 0.5% 215 wt.% 48.4 33.5 13.2 4.9 'Collected from Weyburn well 14-17-6-13 W2M " Collected from Weybum well 3-11-7-13 W2M 0 Collected from Weybum well Hz 1 2-1 8-6-13 W2M d Reservoir temperature for the oil samples * Srivastava and Huang, ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers. their separation. The composition of n-Pentane asphaltenes is differ- ent from that of n-Heptane asphaltenes. Resins: Aromatic and polar molecules, also often containing heteroatoms and metals, that surround the asphaltene structures and are dissolved in the oil and help keep the asphaltenes in suspension. They are surface active and, at some thermodynamic states, form their own reversible micelles. They are polydisperse and have a range of polarity and aromaticity. Resins are considered to be pre-cursors to asphaltenes. 386 Reservoir Formation Damage Paraffin Waxes: Primarily aliphatic hydrocarbons (both straight and branched chain) that change state from liquid to solid during conventional oil produc- tion and processing operations. In addition to aliphatics, field deposits usually contain aromatic, naphthenic, resin, and asphaltenic molecules as well. The combined mass is called wax. Paraffin waxes usually melt at about 110°-160°F. Field waxes contain molecules that can have melting points in excess of 200°F. Asphalt: The residual (non-distillable) fraction of crude oil that contains suspended asphaltenes, resins, and the heaviest aromatic and para- ffinic components of oils. Propane has been traditionally a very efficient and convenient solvent for separating asphalt from petroleum. Although, the latest commercial processes use other more efficient solvents for asphalt separation. Leontaritis (1997) describes that: "Since waxes, asphaltenes and most resins are solid in their pure form and the other oil molecules are in liquid form, the overall crude oil mixture is a liquid solution of waxes, asphaltenes, and resins in the remaining liquid oil. In general, the waxes and resins are dissolved in the overall crude oil. Whereas the asphaltenes are mostly undissolved in colloidal state." Anderson et al. (1997) state: "Petroleum asphaltenes are defined as the solids precipitating from a crude oil upon addition of an excess of a light hydrocarbon solvent, in general n-heptane or n-pentane." Therefore, for practical purposes, the crude oil is considered in two parts. The first part consists of the high boiling-point and polar asphaltic components. This fraction of the crude oil creates various deposition problems during the exploitation of petroleum reservoirs. The second part is the rest of the crude oil, referred to as the deasphatened oil or the maltenes. This fraction of the crude oil acts as a solvent and maintains a suspension of the asphaltenes in oil as illustrated in Figure 14-4 by Leontaritis (1996). However, ordinarily, the asphaltenes do not actually disperse in the maltene unless some resins are also present in the crude oil. The resins help asphaltenes to disperse in oil as a suspension by means of the hydrogen-bonding process and the irreversible acid-base reactions of the asphaltene and resin molecules (Speight, 1996; Speight and Long, 1996; Chang and Fogler, 1994, 1996). Therefore, Leontaritis et al. (1992) point out that: "An oil that contains asphaltenes will not necessarily cause asphaltene problems during recovery and processing." Leontaritis et al. (1992) draw attention to the fact that the Boscan crude of Venezuela has not created any asphaltene problems, although it has a large fraction (over Formation Damage by Organic Deposition r ,* 387 ASPHALTENE PHAS Figure 14-4. A proposed model for asphaltenic oils (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.). 17% by weight) of asphaltenes (Lichaa, 1977). Whereas, the Hassi- Messaoud oil has created severe asphaltene problems, although it has only a small fraction (0.1% by weight) of asphaltenes (Haskett and Tartera, 1965). In fact, de Boer et al. (1995) have concluded that light to medium crudes containing small amounts of asphaltenes may create more asphaltene precipitation problems during primary production. Nghiem and Coombe (1997) explain: "Heavier crudes that contain a larger amount of asphaltene have very little asphaltene precipitation problems as they can dissolve more asphaltene." Leontaritis et al. (1992) state that: "Asphaltene floccula- tion can be prevented by addition of resins and aromatics." The investi- gations of Chang and Fogler (1994, 1997) using model chemicals for resins have verified this statement. 388 Reservoir Formation Damage Leontaritis (1996, p. 13) describes that ". . . asphaltene particles or micelles aggregate or flocculate into larger aggregates or floes. . . . Asphaltene flocculation can be both reversible and irreversible. . . . Paraf- fin waxes, on the other the hand, . . . exhibit the phenomenon of crystal- lization. . . . Wax crystallization is generally a reversible process. However, paraffin waxes more than often precipitate together with resins and asphaltenes (which are said to be responsible for the observed irrevers- ible thermodynamic phenomena). Hence, some wax precipitation is occasionally reported as irreversible." Leontaritis (1996) points out that temperature and composition have a large affect and pressure has a small affect on the solubility of wax in oil. Leontaritis (1996) explains that the behavior of wax in oils can be determined by means of the cloud and pour points. Ring et al. (1994) defined the cloud point as "the equilibrium tempera- ture and pressure at which solid paraffin crystals begin to form in the liquid phase." Leontaritis (1996) states: The "pour point is defined as the lowest temperature at which the fuel will pour and is a function of the composition of the fuel." Mechanisms of the Heavy Organic Deposition In this section, the mechanisms of the heavy organic deposition accord- ing to Mansoori (1997) are described. Mansoori (1997) states that organic deposition during petroleum production and transportation may occur by one or several of the following four mechanisms: 1. Polydispersivity effect. As depicted in Figure 14-5 by Mansoori (1997), a stable state of a polydispersed oil mixture can be attained for a certain proper ratio of the polar to nonpolar and the light to heavy constituents in the crude oil at given temperature and pressure conditions. Thus, when the composition, temperature, or pressure are varied, the system may become unstable and undergo several processes. Figure 14-6 by Mansoori (1997) depicts the formation of micelle-type aggregates of asphaltene when polar miscible com- pounds are added into the system. Figure 14-7 by Mansoori (1997) describes the separation of the asphaltenes as a solid aggregate phase when more paraffinic hydrocarbons are added into the system. 2. Steric colloidal effects. At high concentrations, asphaltenes tend to associate in the form of large particles, as depicted in Figure 14-8 by Mansoori (1997). In the presence of some peptizing agents, such as resins, these particles can adsorb the peptizing agents and become suspended in the oil. Formation Damage by Organic Deposition 389 Figure 14-5. Heavy organics in petroleum crude (straight/curved line = paraffin molecules, solid ellipse = aromatic molecules, open ellipse = resin molecules, and solid blocky forms = asphaltene molecules) (reprinted from Journal of Petroleum Science and Engineering, Vol. 17, Mansoori, G. A., "Modeling of Asphaltene and Other Heavy Organic Depositions, pp. 101- 111, ©1997, with permission from Elsevier Science; after Mansoori ©1994 SPE; reprinted by permission of the Society of Petroleum Engineers). Figure 14-6. Colloidal phenomenon activated by addition of a polar miscible solvent (solid ellipse = an aromatic hydrocarbon) (reprinted from Journal of Petroleum Science and Engineering, Vol. 17, Mansoori, G. A., "Modeling of Asphaltene and Other Heavy Organic Depositions, pp. 101-111, ©1997, with permission from Elsevier Science). Aggregation effect. When the concentration of the peptizing agent is low and its adsorbed quantity is not sufficient to occupy the particle surface completely, several particles can combine to form bigger particles as depicted in Figure 14-9 by Mansoori (1997). This phenomenon is called flocculation. When the particles become 390 Reservoir Formation Damage Figure 14-7. Flocculation and precipitation of heavy components by addition of a non-polar miscible solvent (dashed line = a paraffin hydrocarbon) (reprinted from Journal of Petroleum Science and Engineering, Vol. 17, Mansoori, G. A., "Modeling of Asphaltene and Other Heavy Organic Deposi- tions, pp. 101-111, ©1997, with permission from Elsevier Science; after Mansouri ©1994 SPE; reprinted by permission of the Society of Petroleum Engineers). Figure 14-8. Steric colloidal phenomenon activated by addition of paraffin hydrocarbons (reprinted from Journal of Petroleum Science and Engineer- ing, Vol. 17, Mansoori, G. A., "Modeling of Asphaltene and Other Heavy Organic Depositions, pp. 101-111, ©1997, with permission from Elsevier Science; after Mansouri ©1994 SPE; reprinted by permission of the Society of Petroleum Engineers). sufficiently large and heavy, they tend to deposit out of the solution as depicted in Figure 14-10 by Mansoori (1997). 4. Electrokinetic effect. As explained by Mansoori (1997), during the flow of oil through porous media and pipes, a "streaming current" and a potential difference are generated because of the migration Formation Damage by Organic Deposition 391 Figure 14-9. Migration of peptizing molecules (solid arrows) by change of chemical potential balance (reprinted from Journal of Petroleum Science and Engineering, Vol. 17, Mansoori, G. A., "Modeling of Asphaltene and Other Heavy Organic Depositions, pp. 101-111, ©1997, with permission from Elsevier Science; after Mansouri ©1994 SPE; reprinted by permission of the Society of Petroleum Engineers). Figure 14-10. Flocculation and deposition (big arrow) of large heavy organic particles (reprinted from Journal of Petroleum Science and Engineering, Vol. 17, Mansoori, G. A., "Modeling of Asphaltene and Other Heavy Organic Depositions, pp. 101-111, ©1997, with permission from Elsevier Science; after Mansouri ©1994 SPE; reprinted by permission of the Society of Petroleum Engineers). of the charged particles of the asphaltene colloids. The asphaltene particles are positively charged but the oil phase is negatively charged, as depicted in Figure 14-11 by Mansoori (1997). Therefore, the negative upstream and positive downstream potentials are gen- erated along the pipe to resist the flow of the colloidal particles, as [...]... Dekker, Inc.) Formation Damage by Organic Deposition 401 0.080 2 b 0.060 Reservoir Pressure, 28 0.0 atm Reservoir Temperature, 338.0 *K o.ooo 27 0 Temperature, °K 29 0 Figure 14 -25 Wax weight fraction vs temperature for an Asph Wax Oil Company live oil at 20 0 atm pressure (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.) 0.16 •• 0. 12 0.09 • Reservoir Pressure, 28 0.0 atm Reservoir Temperature... Temperature 338.0 *K —i— 28 0 29 0 300 310 Temperature, °K 340 Figure 14 -26 Wax weight fraction vs temperature for an Asph Wax Oil Company live oil at 50 atm pressure (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.) 4 02 Reservoir Formation Damage 0.3 T Reservoir Pressure 28 0.0 aon Reservoir Temperature, 338.0 *K 25 0 29 0 300 310 320 330 Temperature, °K Figure 14 - 27 Wax weight fraction... 0 .20 0 T Reservoir Pressure 28 0.0 atm Reservoir Temperature 338.0 *K 100 ISO 25 0 Pressure, atm Figure 14 -28 Wax weight fraction vs pressure for an Asph Wax Oil Company live oil at 28 0°K temperature (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.) Formation Damage by Organic Deposition 403 3500 I 300 025 0 020 00- 15001000500- 0 10 20 30 40 50 60 70 80 90 100 CO2 Mole% Figure 14 -29 ... for three different reservoir oils (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.) 400 Reservoir Formation Damage 3000 T 25 00 - 60 70 Temperature, °F 80 Figure 14 -23 Wax deposition envelope for a North American recombined reservoir oil (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.) 27 0 28 0 29 0 300 310 Temperature, °K Figure 14 -24 Wax deposition envelope... Inc.) Formation Damage by Organic Deposition 3 97 Reservoir Pressure, 3SO.O aim Reservoir Temperature 344 . 27 *K 1.5 2 Asphaltene Phase Volume, cc Figure 14-18 Asphaltene phase volume vs temperature for an Asph Wax Oil Company live oil at 20 0 atm pressure (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.) Bubble Point Pressure, 27 9.16 atm at 340 *K Reservoir Pressure, 350.0 atm Reservoir. .. Figures 14 -20 and 14 -21 by Leontaritis (1996) depict the affect of the light-ends and the pressure-temperature relationship on the onset of wax crystallization (cloud point) of oils The affect of the pressure on the onset of wax crystallization is demonstrated for (text continued on page 399) 396 Reservoir Formation Damage 70 00 Upper ADE Boundary 6000- -S* a, sooo H 4000 3000 20 00 140 22 0 180 26 0 300... Reservoir Temperature 344 . 27 *K 3 4 5 Asphaltene Phase Volume, cc Figure 14-19 Asphaltene phase volume vs pressure for Asph Wax Oil Company live oil at 340°K temperature (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.) 398 Reservoir Formation Damage 130V 120 - 110- 80O) 8 O 70 - 60 20 00 1000 3000 4000 5000 Bubble point pressure, psig (at 195 °F) Figure 14 -20 Onset of wax crystallization... courtesy of Marcel Dekker, Inc.) 6000 20 00 74 76 78 Onset Temperature, °F Figure 14 -21 Pressure-temperature effects on onset of wax crystallization in a synthetic mixture of kerosene and candle wax (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.) Formation Damage by Organic Deposition 399 (text continued from page 395) three live-oils in Figure 14 -22 by Leontaritis (1996) The typical... Temperature, °F * Mis of asphaltene phase per mole of reservoir fluid Figure 14-16 Asphaltene deposition envelope (ADE) for a South American reservoir oil (after Leontaritis, ©1996; reprinted by courtesy of Marcel Dekker, Inc.) No Solids No Solids 28 0 320 340 360 Temperature, °K Reservoir Pressure, 3SOOttm RwervoirTaiipentwe 344 . 27 *K 420 Figure 14- 17 Asphaltene deposition envelope (ADE) for Asph Wax... Figure 14 -29 , mixed with the same miscible injectant (Ml) at 120 °F (reprinted from Journal of Petroleum Science and Engineering, Vol 17, Mansoori, G A., "Modeling of Asphaltene and Other Heavy Organic Depositions, pp 101111, ©19 97, with permission from Elsevier Science, after Mansoori ©1994 SPE, reprinted by permission of the Society of Petroleum Engineers) 404 Reservoir Formation Damage T-1MF 3000 20 00 . g/g-mol Component Saturates Aromatics Resins Asphaltenes Viscosity mPa»s . 12. 8 4 .2 - - Viscosity @59°C d 4 .2 . - - - 0.1 23 0 wt.% 48.5 33.5 13 .2 4.8 OilW2" Density kg/m 3 854.9 8 42. 4 - 813.1 - Density @61°C d 813.1 816.4 819.6 822 .9 829 .3 Viscosity mPa*s . 4.60 - 2. 35 - Viscosity @61°C d 2. 35 2. 49 2. 62 2 .76 3.04 0 .2 203 wt.% 55.3 31.1 9.6 4.0 Oil W3 C Density kg/m 3 869 .2 864.4 - - 839.4 Density @63°C d 839.4 8 42. 4 845 .2 848.4 854 .7 Viscosity mPa«s 11 .76 9.40 - - 3.15 Viscosity @63°C d 3.15 3 .26 3. 37 3.49 3 .71 0.5% 21 5 wt.% 48.4 33.5 13 .2 4.9 'Collected . g/g-mol Component Saturates Aromatics Resins Asphaltenes Viscosity mPa»s . 12. 8 4 .2 - - Viscosity @59°C d 4 .2 . - - - 0.1 23 0 wt.% 48.5 33.5 13 .2 4.8 OilW2" Density kg/m 3 854.9 8 42. 4 - 813.1 - Density @61°C d 813.1 816.4 819.6 822 .9 829 .3 Viscosity mPa*s . 4.60 - 2. 35 - Viscosity @61°C d 2. 35 2. 49 2. 62 2 .76 3.04 0 .2 203 wt.% 55.3 31.1 9.6 4.0 Oil . Dekker, Inc.). Formation Damage by Organic Deposition 401 0.080 2 0.060 b o.ooo Reservoir Pressure, 28 0.0 atm Reservoir Temperature, 338.0 *K 27 0 Temperature, °K 29 0 Figure 14 -25 . Wax