Formation Damage by Organic Deposition 407 O BEREA SANDSTONE O100 MESH) A DICKITE (WISCONSIN) D DOLOMITE (DOLOCRON) OTTAWA SAND (SUPER X. >325 MESH) O CALCtTE (DOVER CHALK) • KAOLIN MINERAL • (LUTE (BEAVER'S BEND) O ALUMINA 1000 2000 EQUILIBRIUM ASPHALTENE CONCENTRATION, ppm —•> Figure 14-33. Adsorption isotherms for asphaltenes on clay and mineral surfaces from toluene (Dubey and Waxman, ©1991 SPE; reprinted by per- mission of the Society of Petroleum Engineers). Then, assuming that all oil is in contact with the porous media, the surface excess of species i can be expressed as: nf = n f (xl — ;c ( .) : i = asphaltene or oil (14-8) They assume that the theory is applicable for both mono- and multi-layer adsorption. A balance of the oil and asphaltene adsorbed over the pore surface yields: 1 n m. (14-9) 408 Reservoir Formation Damage 0 500 1000 1500 2000 2500 A8PHALT6NE EQUILIBRIUM CONCENTRATION, ppm —*• Figure 14-34. Hysteresis of adsorption/desorption isotherms for asphaltenes on kaolin from toluene (Dubey and Waxman, ©1991 SPE; reprinted by permission of the Society of Petroleum Engineers). 300 600 900 1200 Equilibrium concentration of asphaltenes (mg/1) 3000 Figure 14-35. Adsorption isotherm for Cerro Negro asphaltenes on inorganic material surface from toluene at 26°C (reprinted from Journal of Fuel, Vol. 74, Acevedo, S., Ranaudo, M. A., Escobar, G., Gutierrez, L, & Ortega, P., "Adsorption of Asphaltenes and Resins on Organic and Inorganic Substrates and Their Correlation with Precipitation Problems in Production Well Tubing," pp. 595-598, ©1995, with permission from Elsevier Science). Formation Damage by Organic Deposition 409 400 600 800 1000 1200 MOO 1600 1800 2000 2200 2400 2600 Equilibrium concentration of uphaitenes (mg/L) Figure 14-36. Adsorption isotherm for Ceuta asphaltenes on inorganic material surface from toluene at 26°C (reprinted from Journal of Fuel, Vol. 74, Acevedo, S., Ranaudo, M. A., Escobar, G., Gutierrez, L, & Ortega, P., "Adsorption of Asphaltenes and Resins on Organic and Inorganic Substrates and Their Correlation with Precipitation Problems in Production Well Tubing," pp. 595-598, ©1995, with permission from Elsevier Science). In Eq. 14-9, m l and ra 2 denote the monolayer coverage of asphaltene and carrier oil, respectively, expressed as mass of species adsorbed per unit mass of porous solid. Then, a selectivity parameter, as defined below, is introduced: (14-10) Therefore, from Eqs. 14-9 and 10, they obtained the following expression for the amount of asphaltene adsorbed: nf = n'x( = Sx (14-11) Using Eqs. 14-8 and 10, they derived the following expression for the surface excess amount of the asphaltene: m {Xl x 2 (S-l) ji — - - C _i_ f / i kJ Al T" I f/li / ftl''2 ) ^ (14-12) 410 Reservoir Formation Damage As a result, the rates of adsorption or desorption are expressed accord- ing to: dt - n : j ' = adsorption , desorption (14-13) where n\ and n{ a denote the amount of species 1 (asphaltene) adsorbed/ desorbed and the actual surface excess of species 1 per unit mass of porous formation. The initial condition is given as: n ea _ ea t — f\ n, — n\o,i — u (14-14) Empirical Algebraic Model for Formation Damage by Asphaltene Precipitation in Single Phase Minssieux (1997) has demonstrated that the predominant mechanisms of the asphaltene deposition can be identified by means of the Wojtanowicz et al. (1987, 1988) analytic models. He also observed that the asphaltene precipitates existing in the injected oil can pass into porous media without forming an external filtercake. The characteristics of the oils used are given in Tables 14-2 and 14-3, and the conditions and results of the coreflood experiments are given in Tables 14-4 and 14-5 by Minssieux (1997). The analyses of typical data according to Wojtanowicz et al. (1987, 1988) formulae are given in Figures 14-37 and 14-38 by Minssieux (1997). Figure 14-37 Table 14-2 Characteristics of Stock Tank Oils* Field Weyburn Lagrave Hassi-Messaoud Boscan (Reference) Reservoir temperature «a 50 80 119 81 S Sat 40.1 65.7 70.5 15 ARA/ AT 46.1 22.8 25.5 37 kNALYSIJ Resins 8.5 7.5 3.3 34 5 Asph. 5.3 4 0.15 14 Res/Asph ratio 1.6 1.9 22 2.4 Viscosity (cP 20°) 13 7.7 1.5 (80°) "API 29 43 43 10 * Minssieux, ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers. Formation Damage by Organic Deposition 411 Table 14-3 Characteristics of Crude and Asphaltenes* Crude origin ("API) Weybum 29 Lagrave 43 H. Messaoud 45 Boscan (10°) "as a reference" % Asphaltene (weight) 5.3 4 0.15 10.7 Average MW (vpo/toluene) 6000 "7000 a 8700" 1120 "well scales" 8000 As H/C 1.00 1.00 0.88 1.14 phaltenes anal) O/C 0.025 0.010 0.034 0.039 sis %S 3.80 0.80 6.70 Tmax (°C) pyrolysis 416 416 420 406 * Minssieux, ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers. Table 14-4 Conditions of Core Floods* Test ref. GF 1 GF2 GF3 GF 12 GVM5 GVM 10 GVM 13 GVR8 GVR 11 GP9 GP 14 HMD 11 HMD 26 Type of rock Fontainebleau sandstone id. id. id. Vosges sandstone id. id. id. id. Palatinat sandstone id Res. rock from HMD id. T(°C) 50 id. id. 80 50 50 80 50 80 80 id. id. id. Crude used Weyburn id. id. H. Messaoud Weyburn Weyburn Lagrave Weyburn Lagrave H. Messaoud id. id. id. Petrophy 0% 13.1 13.6 13.7 8 24.7 24.3 26 22.6 22.6 23 7.1 sical data K H (mD) 107 87 77.4 6 29 12.2 73 15.2 1.1 2 0.67 Injection rate (cm 3 /hour) 50 80 10 10 20 50 80 10 10 10 5 10 10 10 5 5 8 * Minssieux, ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers. 412 Reservoir Formation Damage Table 14-5 Conditions of Core Flood Tests* Test ref. GF1 GF2 GF3 GF 12 GVM 5 GVM 10 GVM 13 GVR8 GVR 11 GP9 GP 14 HMD 11 HMD 26 Crude used Weyburn W. W. H.MD W. W. Lagrave W. Lagrave H.MD H.MD H.MD H.MD Average amount of deposits (mg/fl rock) 0.30 0.21 0.34 1.0 0.48 - 0.11 <0.10 0.33 No plugging 0.58 ("Resins") 0.41 ("Resins") Deposition profile inlet -» outlet Uniform Uniform Decreasing Decreasing Decreasing - Decreasing Near core inlet accumulation Decreasing Uniform Uniform K reduction (%) after 50 PV 20 42.5 58.5 0 47 after 150 PV 88 89 <10 87 60 - 6 (50 after 700 PV) Observations Model type of porous medium (pure silica) Vosges clayey sandstone (illite) additive in flowing crude (750 ppm) Vosges sandstone II Final KH difficult to measure Palatinat sandstone (Kaolinite) crude injected with additive Reservoir-rock core samples from H.MD field * Minssieux, ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers. shows the results of the analysis of the GF3 test data considering the possibility of the gradual surface deposition, single pore plugging, and in-situ cake formation by pore filling mechanisms in formation damage. As can be seen, only the ^K/K 0 vs. PV (pore volume) data yields a straight line plot, indicating that the damage mechanism is the gradual surface deposition. In the case of the GV5 data, Figure 14-38 indicates that the damage mechanism is the in-situ cake formation by pore filling, because KQ/K vs. PV data yields a straight line plot for this case (see Table 10-1). Formation Damage by Organic Deposition 413 RUNGF3 40 50 CRUDE PV INJECTED Figure 14-37. Correlation of the experimental permeability reduction data reveals a uniform surface deposition mechanism (Minssieux, ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers). 30 40 CRUDE PV INJECTED Figure 14-38. Correlation of the experimental permeability reduction data reveals a pore blocking deposition mechanism (Minssieux, ©1997 SPE; reprinted by permission of the Society of Petroleum Engineers). 414 Reservoir Formation Damage Simplified Analytic Model for Asphaltene-Induced Formation Damage in Single-Phase Leontaritis (1998) developed a simplified model for prediction of formation damage and productivity decline by asphaltene deposition in under-saturated (above bubble-point pressure) asphaltenic oil reservoirs. This model consists of a set of algebraic equations. In this section, the Leontaritis model is presented with some modifications for consistency with the rest of the presentation of this chapter. As schematically shown in Figure 14-39, for analysis, Leontaritis (1998) considers the portion of the reservoir defined by the radius of drainage of a production well. In this region, the flow is assumed radial. Figure 14-40 schematically depicts the variation of the flowing bottom hole pressure during constant rate production, while the external reservoir pressure and the onset of the asphaltene flocculation pressure remain constant. The calculational steps of this model are described briefly in the following. Step 1. The initiation time for asphaltene precipitation is referred to as zero (i.e., ? = 0). Given the well productivity index, PI, the flowing bottom hole pressure, p w [=Q , prior to asphaltene damage is calculated from the definition of the productivity index: PI= (14-15) Then, the steady-state radial pressure profile prior to damage is calcu- lated by: (14-16) The asphaltene deposition is assumed to occur within the near wellbore region, r w <r<r AF , where the pressure is below the asphaltene floccula- tion pressure, p AF . The radius of this region, r AF , is determined by Eq. 14-16 for p = p AF , according to Figure 14-41. Leontaritis (1998) assumes that the pressure beyond this region (i.e., r AF <r<r e } is not influenced by asphaltene deposition in the near wellbore region. The region r w < r < r AF is divided into a number of sections of finite width Ar. Steps 2 and 3 calculations are carried out over each Ar segment for a time increment by A?, consecutively, as described in the following. Formation Damage by Organic Deposition 415 Asphaltene deposition region Figure 14-39. Producing reservoir drainage area (modified after Leontaritis, 1998). Q_ P CD i p. CO CD AF w 0 Constant external reservoir pressure Onset of asphaltene flocculation pressure Flowing bottonr hole pressure 0 Time, t Figure 14-40. Variation of the flowing bottom hole pressure during constant rate production (modified after Leontaritis, 1998). 416 Reservoir Formation Damage Well Reservoir radial drainage area •w Enlarged section of a hydraulic tube r AF •* Asphaltene region No deposition region Figure 14-41. Asphaltene deposition induced formation damage in the near- wellbore region (modified after Leontaritis, 1998). Step 2. Similar to Wojtanowicz et al. (1987, 1988), Leontaritis considers the porous media as a bundle of tortuous flow tubes. Thus, the mean hydraulic diameter is estimated by the ratio of the total pore volume to the total pore surface area of the flow channels according to: ALcj) 2 AL(l-j>)A g /V g (14-17) [...]... 11.3 20 0 0.5,1 ,2, 3 0.35 29 .29 2. 71 136 0.5 1 2 3 0.1 15 100 0.05 /10 20 0.0 08 6.3 0.00 085 through 0.01 0.0 32 0 .2 10 10 0. 82 10 11.3 10 * After Ali and Islam, ©19 98 SPE; reprinted by permission of the Society of Petroleum Engineers  4 28 Reservoir Formation Damage •5 1 .20 0.00 5.00 10.00 15.00 Time, hr Figure 14- 48 Permeability reduction for injection at 0.5 mL/min rate (after Ali and Islam, ©19 98 SPE;... the plugging paths is given by: (14- 42) (text continued on page 424 ) 422 Reservoir Formation Damage 120 00 Reservoir Ten perature, 25 0.0 'Bubble Point 'Lower Onset Upper Onset Figure 14-43 Asphaltene deposition envelope for an AsphWax Oil Company reservoir oil (after Leontaritis, ©19 98 SPE; reprinted by permission of the Society of Petroleum Engineers) 9000 88 00 70 40 2. 5 4.5 Radial Distance, feet Figure... estimated by: (14 -24 ) where y = 6p/oc is a combined constant Hence, the area open to flow during damage is given by: = A0-At (14 -25 ) where the area open to flow is determined by: A = 2nrh§ (14 -26 ) and the initial area of flow is given by: A0=2nrh0 (14 -27 ) Based on Eqs 14 -25 through 27 , the instantaneous porosity is given by: 4> = 4> 0 (1-A,/A 0 ) (14 - 28 ) According to Wojtanowicz et al (1 987 , 1 988 ), the area... and the moles of reservoir fluid, mRF, at the prevailing pressure and temperature conditions within the near wellbore region are determined according to Leontaritis (1997) Figure 14- 42 shows a typical asphaltene particle size distribution 0 .25 0.00 0 0 0 0 1 1 1 1 1 2 4 6 8 2 4 6 8 Asphaltene Particle Diameter, micron 80 79.5 psia -7345 psia • 587 6 psia •4407 psia Figure 14- 42 Asphaltene particle size... the asphaltene particles retained in porous media, estimated as: _4n(DA /2) 2 _ 6 a = **(°L 3 I 2 (14 -23 ) Formation Damage by Organic Deposition 419 where DA is the mean diameter of the asphaltene particles retained, p is an empirical factor accounting for the plugging by asphaltene particles Therefore, combining Eqs 14 -20 through 23 over a number of N consecutive, discrete time steps, Af, the cumulative... asphaltene-damaged region (after Leontaritis, ©19 98 SPE; reprinted by permission of the Society of Petroleum Engineers) Formation Damage by Organic Deposition + at 0.0 Hrs — . (Reference) Reservoir temperature «a 50 80 119 81 S Sat 40.1 65.7 70.5 15 ARA/ AT 46.1 22 .8 25 .5 37 kNALYSIJ Resins 8. 5 7.5 3.3 34 5 Asph. 5.3 4 0.15 14 Res/Asph ratio 1.6 1.9 22 2. 4 Viscosity (cP 20 °) 13 7.7 1.5 . HMD id. T(°C) 50 id. id. 80 50 50 80 50 80 80 id. id. id. Crude used Weyburn id. id. H. Messaoud Weyburn Weyburn Lagrave Weyburn Lagrave H. Messaoud id. id. id. Petrophy 0% 13.1 13.6 13.7 8 24 .7 24 .3 26 22 .6 22 .6 23 7.1 sical . Tubing," pp. 595-5 98, ©1995, with permission from Elsevier Science). Formation Damage by Organic Deposition 409 400 600 80 0 1000 120 0 MOO 1600 180 0 20 00 22 00 24 00 26 00 Equilibrium