Lowering the Viscosity of DobaChad Heavy Crude Oil for Pipeline

1156

Energy & Fuels 2004, 18, 1156-1168

Lowering the Viscosity of Doba-Chad Heavy Crude Oil for Pipeline TransportationsThe Hydrovisbreaking Approach Soumaı¨ne Dehkissia, Faı¨c¸ al Larachi,* Denis Rodrigue, and Esteban Chornet† Department of Chemical Engineering, Laval University, Que´ bec, Canada G1K 7P4 Received February 19, 2004. Revised Manuscript Received April 16, 2004

This study was instigated in view of the recent commercial exploitation of the Doba oil field in landlocked Chad, which is a region from which crude oil is extracted and expected to be routed to the Atlantic shore through pipeline transportation. Thus, nonisothermal kinetic hydrovisbreaking tests of Doba crude oil were conducted in a mechanically stirred baffled autoclave reactor under various conditions to alter the rheological properties of the treated crude. The crude hydrovisbreaking kinetics was modeled based on the four-parameter reaction severity concept (ω, γ, E, βo), as a function of the conversion in polyaromatics and polar maltenic subfractions. The hydrovisbreaking of Doba crude was observed to be a pseudo-first-order reaction (i.e., in excess of H2), with respect to the polyaromatics and polar maltenic conversion. The following assortment of kinetic parameters was identified under noncatalytic hydrovisbreaking conditions: heterogeneity coefficient, γ ) 1; characteristic temperature, ω ) 29.95 K; and activation energy, E ) 140.9 kJ/mol. Four viscosity mitigation scenarios involving catalytic (FeS, MoS2) and noncatalytic hydrovisbreaking of Doba heavy crude oil were investigated. It was found that the minor proportions of the fractions that distilled before 250 °C and the small asphaltene yields marginally affected the crude viscosity. It was therefore determined that it is possible to meet the viscosity specification for pipeline transportation via (noncatalytic) hydrovisbreaking, which requires neither predistillation (topping) nor post-deasphalting units. The treated crudes and the syncrudes (mixtures of untreated and treated crudes) were observed to exhibit nonelastic viscous Newtonian behavior over the temperature range typical of crude transportation via pipeline. Treated crudes at 440 °C for 25 min and syncrudes that were the result of mixing 50 wt % of untreated crudes with crudes treated at 460 °C for 15 min yielded kinematic viscosities within the pumping specifications (i.e., e 25cSt @ 50 °C). The use of catalysts led to even lessviscous maltenes subfractions; however, post-deasphalting was required, because the catalystcoke mixture, as well as asphaltenes, inflated the viscosity above the norm. An iron sulfide catalyst outperformed a molybdenum sulfide catalyst, in terms of the deasphalted crude viscosity. Aging tests over two-month periods indicated that the higher the treatment severity, the more stable the viscosity of the Doba treated crudes, which is potentially compatible with the residence times of syncrudes within the 1050-km-long transportation pipeline between Chad and Cameroon.

1. Introduction Regardless of the many energy scenarios being advocated by industry analysts, there is a consensus that world primary energy demand will roughly double from the current 9 Gtoe to 18 Gtoe by the year 2020. (Gtoe ≡ gigatonne oil equivalent.) Projections forecast that both conventional and nonconventional oil reserves are to contribute 40% of all energy consumed over the next two decades. The gradual reserve depletion of so-called conventional oil and the increasing needs for petroleum light products are forcing the oil sector to unveil and exploit nonconventional hydrocarbon deposits, such as heavy crude oils, bitumen, and residues,1-5 by opening new areas to international investment.6 * Author to whom correspondence should be addressed. Telephone: 418-656-3566. Fax: 418-656-5993. E-mail: [email protected]. † Currently at the Chemical Engineering Department, University of Sherbrooke, Sherbrooke, Canada J1K 2R1. (1) Speight, J. G. The Chemistry and Technology of Petroleum, 3rd ed.; Marcel Dekker: New York, 1999; 909 pp.

Often, the remoteness of oil fields from markets or refineries makes crude oil transportation a key component of the economic scheme. Large-scale transportation of crude oil is usually accomplished using pipelines and tankers.1 Recently in Chad, an important heavy oil reserve that has been estimated at one billion barrels and should be capable of producing 225 mbpd (thousand barrels per day) at peak operation is being exploited by a consortium of three international petroleum companies (Exxon-Mobil, ChevronTexaco, and Petronas). Economic returns from this project, which are expected (2) Speight, J. G. Handbook of Petroleum Analysis; Wiley: New York, 2001; 477 pp. (3) Scott, D. S.; Radlein, D.; Piskorz, J.; Majerski, P.; Debruijn, T. J. W. Fuel 2001, 80, 1087-1099. (4) Wauquier, J.-P. Pe´ trole Brut, Produits Pe´ troliers, Sche´ mas de Fabrication; E Ä ditions Technip: Paris, 1994; 478 pp. (5) Ovalles, C.; Filgueriras, E.; Morales, A.; Scott, C. E.; GonzalezGimenez, F.; Embaid, B. P. Fuel 2003, 82, 887-892. (6) Bauquis, P. R. A Reappraisal of Energy Supply and Demand in 2050; The Institute of Energy Economics: Japan, July 2002 (available via the Internet at http://eneken.ieej.or.jp/en/outlook/).

10.1021/ef0499527 CCC: $27.50 © 2004 American Chemical Society Published on Web 06/05/2004

Lowering the Viscosity of Doda-Chad Heavy Crude Oil

Energy & Fuels, Vol. 18, No. 4, 2004 1157

but it is also meant to mitigate the crude viscosity through breakup and hydrogenation of its constituent bulky hydrocarbons. To implement and optimize a costeffective solution for the purpose of reducing crude viscosity (to meet pipeline specifications), kinetic studies, fractionation, and rheological characterizations of the raw and upgraded feedstocks are required prior to syncrude transportation via pipeline. Hence, the objectives of this work were 2-fold. The first was to examine the appropriateness of some upgrading schemes7 to meet viscosity specifications for pipeline transportation of Doba heavy oil through a combination of (i) thermal hydrovisbreaking with and without catalysts, (ii) upstream distillation, and (iii) post-deasphalting. A second objective was to perform an in-depth characterization and separation study of the treated crude into its gas, coke, asphaltene, and maltene fractions, followed by deeper fractionation of the two latter fractions into four subfractions each, to monitor crude conversion during treatment as well as viscosity evolution, as a function of the severity factor.

to trickle into the Chadian government, in terms of direct and indirect benefits, are estimated to be $8.5 billion (U.S. dollars) over ca. 30 years of production. Despite this important heavy oil reserve, major obstacles to developing this resource have been the remote and landlocked geography of Chad. A proposed pipeline that measures 1050 km in length and 76 cm in diameter has been constructed and has recently begun operation for transporting the oil from the Doba oil field in Chad to the Kribi 1 Floating Storage Offloading facility in Cameroon, before being dispatched from a marine export terminal onto tankers for transport to international markets. One perennial concern in pumping heavy oils over large distances is the higher pipeline drag, which translates to higher energy requirements to run pumps and convey payload. This may be highly incompatible with remote/enclaved locations such as Chad, where energy is rare. Establishing methods to allow lowering of the pressure drops without sacrificing capacity are thus key to a cost-effective pipeline infrastructure extending from the oil field to the Cameroon Atlantic shores. It is important to recall that, for pipeline transportation of crude oils, the viscosity specification recommended in Europe and North America is 25 cSt at 50 °C.7 The crude oil from the Doba oil field has a specific gravity of 0.94, corresponding to 18.8° API and a kinematic viscosity of 184 cSt at 50 °C.8 Based on the taxonomy of Lepage et al.,7 Doba crude is almost entirely heavy oil and, therefore, cannot be pipelined right away without treatment. Methods for mitigating the heavy oil viscosity are numerous, although all advocate some form of treatment near the reservoir before transport via pipeline.1 The most common method among them is the process of heating, blending with some light crudes/solvents, the addition of pipeline boosters, and catalytic upgrading. Heating the pipeline is not practical; however, the availability of diluent fluids onsite is crucial, although they affect some of the feedstock properties, to some extent. For instance, in Canada, before heavy oil recovered from the Cold Lake region can be transported via pipeline, its viscosity must be reduced, at significant cost, by the addition of up to 30 wt % naphtha diluent.9 Considering the landlocked character of Chad and without sources of diluent, blending with a diluent is very costly and likely alters the product properties. The use of pipeline boosters (i.e., high-molecular-weight polymeric drag-reducing agents to help reduce pipeline frictional losses) may also carry an economic burden. Catalytic upgrading, and, more specifically, hydrovisbreaking, in conjunction with distillation and deasphalting7 to treat heavy crude oils at the oilfield is regarded as an acceptable compromise among all these options. Hence, when heavy oils contain significant amounts of asphaltenes, polar and polyaromatic maltenic compounds, and sulfur-, nitrogen- and metalbearing organocompounds, not only does hydrovisbreaking help to remove the objectionable heteroatoms

The crude oil investigated in this work came from the Doba oil field, which is located in southeastern Chad. A detailed characterization of the crude has been presented elsewhere.8 The experimental work includes the following: kinetics and rheological investigations on the hydrogen-free thermal cracking; catalytic and noncatalytic hydrovisbreaking of crude oil; separation via solubility of treated crude oil into coke, asphaltenes, and maltenes; fractionation of the asphaltenes and maltenes into four subfractions; and Fourier transform infrared (FT-IR) and gas-phase chromatographic analyses. 2.1. Experimental Methodology. The hydrovisbreaking tests were conducted in a four-baffle stainless-steel 300-mL autoclave reactor (Parr Instrument Company) that was agitated with a magnetically driven six-bladed pitched turbine impeller. Gaseous hydrogen was delivered from 6000-psi gas cylinders, and the H2 pressure in the reactor headspace was permanently maintained at 13.8 MPa (or 2000 psi) by means of a pressure regulator (model CGA-703). Hydrogen was sparged into the autoclave reactor in semibatch mode (open flow, with respect to gas, and batch, with respect to the crude). Hydrogen was metered at a mass-flow-controlled specific flow rate per unit mass of crude that was equal to 0.2 LSTP g-1 min-1. This specific flow rate was chosen on the basis of the optimized operating conditions set in a previous study for the hydrovisbreaking tests of Athabasca bitumen vacuum bottoms.10,11 In all tests, crude oil samples of 140.5 g each were used and the vessel load was thoroughly stirred at a speed of 500 rpm by a magnetic drive agitator (Parr model A1120HC). The reactor was heated by means of a band heater with an insulating jacket that was connected to a Parr model 4843 temperature controller. A Parr model NCCA818HC head assembly for a vessel capacity of 300 mL was installed to accommodate the high temperature and high pressure in use during the hydrovisbreaking tests (up to 2000 psi and 470 °C). This assembly was equipped with a gas/liquid sampling valve, a dip tube, a gas release valve, a 3000-psi safety rupture disk, a type-J thermocouple (for measuring the reaction medium temperature), and a port for a magnetic drive (model A1120HC). The head assembly of the vessel system was also equipped with

(7) Lepage, J. F.; Chatila, S. G.; Davidson, M. Raffinage et Conversion des Produits Lourds du Petrole; E Ä ditions Technip: Paris, 1990; 190 pp. (8) Dehkissia, S.; Larachi, F.; Rodrigue, D.; Chornet, E. Revision submitted to Fuel, 2004. (9) Lai, W.-C.; Smith, K. J. Fuel 2001, 80, 1121-1130.

(10) Dehkissia, S.; Larachi, F.; Chornet, E. Fuel 2004, 83, 13231331. (11) Nbigui, T. Approche Cine´ tique non Homoge` ne aux Syste` mes Complexes: Application a` l’Hydrocraquage des Huiles Lourdes Re´ siduaires; Ph.D. Thesis, Universite´ de Sherbrooke, Sherbrooke, U.K., 1996, 227 pp.

2. Experimental Section

1158 Energy & Fuels, Vol. 18, No. 4, 2004

Dehkissia et al.

Table 1. Reaction Conditions and Operation Strategy run

plateau reaction temperature, T (°C)

heating time, tHa (min)

plateau reaction time, tP (min)

cooling time, tCb (min)

log Ro

440

12.5

(1)

9

5.3

30 25 25 15 15

7 8 9 11 12

6.0 6.2 6.3 6.4 6.6

R016 R07 R06 R02 R04 R05

410 430 440 460 470

Without Catalyst 10.3 11 12.2 14 15.5 With Catalyst

nonsolubilized MoS2 catalyst R08 R09 R10 solubilized MoS2 catalyst R11 nonsolubilized FeS catalyst R12 R13 R14 solubilized FeS catalyst R15 a

430 410 440

11 10.3 12.2

25 30 25

8 7 9

6.2 6.0 6.3

430

11

25

8

6.2

410 430 440

10.3 11 12.2

30 25 25

7 8 9

6.0 6.2 6.3

430

11

25

8

6.2

b

From 250 °C to temperature T. From temperature T to 300 °C.

a model NCCA2013HC reflux/takeoff condenser for light component reflux. The condenser volume, relative to the reactor volume, was sufficient to ensure the proper cooling of light and condensable gases that were escaping the reactor. Cold water (temperature of 30 mL/g, as suggested by Andersen and Speight.12 The n-pentane insolubles (i.e., asphaltenes) were isolated after filtration on a medium (10-15 µm)-fritted glass filter (Fisher Scientific Company, Catalog No. 10-358-22L), whereas the n-pentane solubles (i.e., maltenes) were obtained after solvent evaporation. 2.3. Fractionation of Maltenes and Asphaltenes. The maltenes and asphaltenes were fractionated into four subfractions and analyzed via infrared spectroscopy. The FT-IR spectra were recorded in the absorbance mode on an FT-IR spectrometer (model IR-200, Thermo Nicolet, Mattson) over the spectral range of 4000-400 cm-1. A liquid sample holder was used to analyze the (liquid) maltenes subfractions, whereas a solid sample holder was used for the (solid) asphaltenes subfractions. The maltenes were fractionated on a 3.4-cm-ID (inner diameter) column packed with silica (100 g)/alumina (50 g) powder layers, using sequentially three solvents, or mixtures thereof, with increasing polarity. A first subfraction (MF1), which was composed of saturates, was eluted with n-pentane, whereas a second fraction (MF2), which also was eluted with n-pentane, yielded monoaromatics and diaromatics. Subfraction MF3, which was eluted with n-pentane/CH2Cl2 mixtures, restored the polyaromatics. Finally, subfraction MF4, which was eluted with a mixture of CH2Cl2 and methanol (MeOH), yielded the polars that contribute to the maltenes. (12) Andersen, S. I.; Speight, J. G. Petrol. Sci. Technol. 2001, 19, 1-34.

Lowering the Viscosity of Doda-Chad Heavy Crude Oil Similarly, the asphaltenes underwent fractionation on a 3.4cm-ID column that was loaded with 120 g of silica powder, using sequentially four solvents, or mixtures thereof, with increasing polarity: toluene, CHCl3, a mixture of CHCl3 and ethyl alcohol (EtOH), and a CHCl3/MeOH mixture (the four asphaltene subfractions obtained using these solvents will be hereafter referenced as AF1, AF2, AF3, and AF4, respectively). The adsorbents used here have the following characteristics: alumina (Fischer Scientific Company, Catalog No. A540-3), 80-200 mesh, dried at 350 °C for 24 h; and grade-62 silica gel (Fischer Scientific Compan, Catalog No. S704-10), 60-200 mesh, dried at 135 °C for 24 h. In this fractionation procedure, the adsorbent/sample ratios for maltenes and asphaltenes fractions were 50:1 and 100:1 w/w, respectively. 2.4. Gas Analysis. The GC analyses were conducted on a Hewlett-Packard model 5890 unit that was equipped with a thermal conductivity detector, and two 3.2-mm-OD (outer diameter) stainless-steel columns in series. The first column (1.8 m long) was packed with a molecular sieve 13X, to analyze H2, N2, argon, methane (CH4), and carbon monoxide (CO) at room temperature. The second column (2.3 m long and packed with Porapak Q) was used to separate and quantify CO2, C2C5, and H2S at programmed temperatures from 40 °C to 200 °C and at a heating rate of 10 °C/min. The temperature was first held at 40 °C for 4 min, then ramped from 40 °C to 80 °C, where it was maintained for 7 min, and then raised to 200 °C. The carrier gas helium was flowing at a flow rate of 30 mL/ min.

3. Theory: Hydrovisbreaking Kinetics The hydrovisbreaking kinetics of Doba crude oil was expressed based on the reaction severity concept pioneered by Chornet and co-workers.13-16 This approach revolves around the notion of a severity parameter17 that is used as a kinetic descriptor of the reacting system and can be related to well-trodden kinetics parameters such as the activation energy and the preexponential factor. In essence, the severity approach belongs to the realm of lumped kinetics and may prove particularly powerful for describing the fate of species in complex reacting systems characterized by time- and conversion-dependent rate constants. The main premise behind the severity approach is that complexity arises not because of molecularity discrepancies of the reaction events but rather is an outcome of a group of very similar species reacting in parallel, each one undergoing a first-order reaction.13,14 Thus, for reasons of simplicity, the reaction order of the global reaction is to be assumed also to be first-order. The kinetics evolution of crude oil transformation and viscosity alteration during treatment was thus monitored on the basis of the severity factor log Ro.13,14 For a given catalyst with constant concentration, or without catalyst, log Ro incorporates both time and temperature into one single factor:

[∫ (

ln Ro ) ln

)

T - Tref γ-1 exp t dt 0 ω t

]

(1)

T - Tref + γ ln t - ln γ ω

temperature chosen arbitrarily to be 373 K where the reaction rate is effectively zero,14 ω a characteristic temperature representing the scaled temperature span (δT/(ln 2)) required for doubling the reaction rate, and γ (0 < γ e 1) a heavy-oil specific heterogeneity coefficient that defines the shape and sharpness of the activation energy distribution used to model the reactions and species quasi-continuum involved in the conversion of the complex heavy-oil mixture.13,14 The closer it is to unity, the sharper the activation energy distribution, meaning that conversion implies reacting species that have comparable activation energies. Ultimately, for γ ) 1, the system becomes homogeneous with a Dirac activation energy distribution and the severity factor simplifies to

[∫ (

ln Ro ) ln

t

exp 0

) ]

T - Tref dt ω

(3a)

or

ln Ro )

T - Tref + ln t ω

(3b)

for the isothermal case. As will be discussed later, analysis of the yields of the coke, gas, asphaltenes, and maltenes of the Doba crude oil indicated that the mass fractions of the asphaltenes, gas, and coke increased during treatment at the expense of a decrease in the maltenes mass fraction. Finer analysis of the yields of the maltenic subfractions revealed that the polyaromatics (MF3) and polars (MF4) mass fractions decreased, whereas the saturates (MF1) and monoaromatics/diaromatics (MF2) mass fractions increased with treatment. The betweenfractions interconversion process is thus dictated by the consumption of MF3 and MF4 during hydrovisbreaking. Thus, it seems natural to monitor the fractional mass conversion (f) of the heavy oil, in terms of depletion of these two subfractions:

f)

[xMF3 + xMF4]o - [xMF3 + xMF4]t,T [xMF3 + xMF4]o

(4)

where x denotes mass fraction, the subscript o stands for the MF3 + MF4 composition in crude oil before treatment, and the subscript t,T stands for the residual composition at reaction time t and temperature T. Assuming that an overall first-order irreversible kinetics is occurring at T, the reaction rate that expresses the conversion of subfractions MF3 and MF4 can be formulated as

df ) β(T)tγ-1(1 - f) dt

(5)

where β(T) is the Plonka14 rate constant originally

For isothermal conditions, the severity factor simplifies to

ln Ro )


(2)

where t is the reaction time (given in minutes), T the reaction temperature (given in Kelvin), Tref a reference

(13) Montane´, D.; Overend, R. P.; Chornet, E. Can. J. Chem. Eng. 1998, 76, 58-68. (14) Montane´, D.; Overend, R. P.; Chornet, E. Can. J. Phys. 1990, 68, 1105-1111. (15) Abatzoglou, N.; Chornet, E.; Belkacemi, K.; Overend, R. P. Chem. Eng. Sci. 1992, 47, 1109-1122. (16) Belkacemi, K.; Abatzoglou, N.; Overend, R. P.; Chornet, E. Ind. Eng. Chem. Res. 1991, 30, 2416-2425. (17) Geniesse, J. C.; Reuter, R. Ind. Eng. Chem. 1930, 22, 12741279.


Dehkissia et al.

validated for the decay reactions of radiation-generated radicals within polymeric media, and later extended and generalized by Chornet and co-workers13,14 to any nonhomogeneous complex system exhibiting time-dependent rate constants. This parameter is modeled according to an Arrhenius dependence:15

(

β(T) ) βo exp -

E RT

)

(6)

On integrating eq 5 from the limits f ) 0 at t ) 0 to f at t under isothermal conditions, one finds

- ln(1 - f) )

( )

β(T) γ t γ

(7)

or equivalently,

x

t)γ

γ 1 ln 1-f β(T)

(

)

(8)

Injecting eqs 8 and 6 into eq 3 provides an alternate expression for the severity factor, which, after rearrangement, becomes

( )

ln ln

1 ) γ ln Ro + ln βo 1-f E γ ln γ + (T - Tref) (9) + RT ω(T)

[

]

Linear regression of the left-hand side (LHS) of eq 9, as a function of log Ro, enables the heterogeneity factor γ to be estimated from the straight-line slope. Similarly, the increment temperature parameter ω is inferred from the y-intercept, according to an iterative procedure whose results are detailed in the Appendix. Because ω and β both are dependent on temperature,13,14 the y-intercept weakly drifts with temperature and both effects must be taken into account during the parameter identification. Because the severity factor, for a given reaction, combines time and temperature into one single dimensionless number, it has the advantage of requiring fewer experiments without sacrificing information on the impact of operating conditions on the product yields15,16 and also on the viscosity change of the synthetic crudes to be formulated, as will be detailed later. The analysis of thermal cracking, catalytic, and noncatalytic hydrovisbreaking results, as well as the viscosity evolution of the crude, the treated crude, and the synthetic crude (syncrude), was based on the severity factor. 4. Results and Discussion 4.1. Heavy Crude Oil Fractionation Results. To assess the extent of thermal hydrovisbreaking conversion of the Doba crude oil, the reaction products (including gases, coke, maltenes and subfractions thereof, and asphaltenes and subfractions thereof, were analyzed, and their yields were expressed per 100 g of crude petroleum. The raw untreated oil displayed the following mean yield distribution (given in weight percentage of untreated crude), in terms of maltenes subfractions:8 45.0%, 11.0%, 26.8%, and 12.8%, respectively, for saturates (MF1), monoaromatics and diaromatics (MF2), polyaromatics (MF3), and polars (MF4). Similarly, the

asphaltenes isolated from the untreated crude were fractionated according to their solubility in toluene (AF1, 0.3%), chloroform (AF2, 0.7%), chloroform/3%EtOH (AF3, 0.2%) and chloroform/20%MeOH (AF4, 0.6%), on a weight basis of untreated crude. The averaged yields were 97.4% maltenes (n-pentane solubles), 1.8% asphaltenes (n-pentane insolubles), and 0.1% coke (tolueneinsoluble). 4.2. Screening Hydrovisbreaking Strategies. The high values of the kinematic viscosities of crude oil (184.4 cSt at 50 °C) and of deasphalted crude oil (152.4 cSt at 50 °C)8 suggested that partial upgrading would be necessary to comply with the viscosity specifications recommended for crude transportation by pipeline. As detailed in Figure 1, four hydrovisbreaking scenarios for crude oil transformation were explored for syncrude viscosity reduction. The screening treatments were undertaken at a severity factor of log Ro ) 6.3 (440 °C, 25 min) and a H2 pressure of 13.8 MPa, and the viscosity comparisons were performed at a specification temperature of 50 °C. In scenario I, the initial crude oil (CO) was split in two equal mass fractions. One fraction remained unaltered, whereas the other experienced the following chain of transformations: atmospheric distillation (A), hydrovisbreaking (B), deasphalting (D). The resulting deasphalted oil (DAO) was mixed with the primary untreated fraction (CO) and the light fraction (L) coming out of the atmospheric distillation to yield a syncrude (SCO) with a viscosity of 60 cSt at 50 °C. Scenario II was similar to scenario I, with the exception of elimination of the deasphalting step. The initial crude oil (CO) was split in two equal mass fractions and the treated crude oil (TCO) issued from the hydrovisbreaking was mixed with the light fraction (L) of the atmospheric distillation and the untreated fraction (CO), yielding a syncrude with 71.4 cSt at 50 °C. Considering the marginal recovery in light cut distilling in the temperature range from the initial boiling point to 250 °C (IBP-250 °C) at atmospheric pressure (ca. 10 vol%; see Table 2), the atmospheric distillation step was discarded in scenario III. The deasphalted oil, following the hydrovisbreaking step, was readily mixed with the primary untreated crude fraction. The viscosity of the resulting syncrude was 57.1 cSt at 50 °C. The treatment strategy in scenario IV included only hydrovisbreakin; the distillation and deasphalting steps were skipped. The treated crude oil (TCO) was mixed with the primary untreated crude fraction (CO) to yield a syncrude (SCO) with a viscosity of 65.7 cSt. In view of the marginal difference between the viscosities from the deasphalted oil (20 cSt at 50 °C, scenario III) and the nondeasphalted treated crude oil (23 cSt at 50 °C, scenario IV), the treatment strategy of scenario IV was judged the less costly route for viscosity reduction and was therefore retained for further experiments. The buildup of asphaltenes during treatment yielded larger amounts (scenario I: 3.7/0.5/0.9-2.9 ) 5.2 wt %, scenario III: 4.3/0.5-2.4 ) 6.2 wt %; see Table 3b), in comparison to that of the crude-oil-borne asphaltenes (1.8 wt %). Interestingly, the syncrude viscosity without deasphalting seemed to be barely affected by the presence of asphaltenes (see scenarios II and IV in Figure



Figure 1. Hydrovisbreaking treatment scenarios explored for Doba crude transformation (log Ro ) 6.3, for a H2 pressure of 13.8 MPa and flow rate of 0.2 LSTP g-1 min-1). Table 2. Percentage of Recovered Light Oil (from Initial Boiling Point (IBP) to 250 °C) from Atmospheric Distillation

runa

distilled volume (mL)

initial boiling point, IBP (°C)

1 2 3 4 5 6 7

100 100 100 565 450 407 580

85.2 86.0 85.0 85.6 85.0 85.0 85.6

a

Light Oil Recovered volume percentage (mL) (% v/v) 10.0 10.4 10.2 57.0 45.0 40.4 58.4

10 10 10 10 10 10 10

Water content is 0.9% (solvents were xylene and toluene).

1). One reason could be that the molecular weight of the newly formed asphaltenes is likely smaller than that for those native asphaltenes in the untreated oil. Another reason could be ascribed to the lack of colloidal structuring in freshly treated loads, because aging has been identified as a factor that has a key role in determining the colloidal structure and stability of asphaltenes, as determined in petroleum heavy ends and bitumen.18,19 It is likely that the atmospheric distillation residue (with a boiling point of >250 °C) is more concentrated and thus more viscous (scenarios I, II) than the nondistilled crude (scenarios I, II). A posteriori addition of distillate (IBP-250 °C) to treated residue (DAO or TCO from scenarios I and II) or abortion of the distillation step (DAO and TCO from scenarios III and IV) yielded correspondingly comparable viscosities: 21 cSt (scenario I) vs 20 cSt (scenario III), and 25 cSt (scenario II) vs 23 cSt (scenario IV). The slight positive viscosity bias (18) Mastrofini, D.; Scarsella, M. Fuel 2000, 79, 1005-1015. (19) Scarsella, M.; Mastrofini, D.; Barre, L.; Espinat, D.; Fenistein, D. Energy Fuels 1999, 13, 739-747.

observed in the case of treated concentrated residues can be ascribed to inevitable losses of tiny amounts of noncondensable light hydrocarbons during the atmospheric distillation step. TCO atmospheric distillation right after hydrovisbreaking of the topped crude oil (scenarios I and II) led to an IBP of 120 °C and a 17% (v/v) yield in light hydrocarbons (see Table 3a). Similarly, the IBP and light hydrocarbons yield of TCO from scenario IV were 90 °C and 23% (v/v), respectively (see Table 3a). The slight shift of IBP from 85 °C (untreated crude oil) to 90 °C is indicative of the chemical conversion of some original more-volatile hydrocarbons into less-volatile ones, without excluding that some light fractions could have escaped within the hydrogen flow. On the other hand, TCO from hydrogenless thermal cracking exhibited, as expected, a lower IBP value, because of the formation of more volatiles and zero loss (reactor completely batchwise) (see Table 3a). The role of hydrogen in limiting asphaltenes and coke buildup5,7 during treatment is illustrated in Table 3b for the three treated crude oils. 4.3. Heating and Cooling Transients. For short reaction times, as addressed in this study, the hydrovisbreaking data exhibit poor isothermal character and require that the severity factor be precisely integrated along the entire t-T path that depicts the history of reaction. Hence, the impact of heating and cooling time intervals vis-a`-vis reaction conversion, and thus viscosity reduction, was taken into account and examined. For a reaction to be conducted at sufficiently high temperatures, for example, 410-470 °C, heating and cooling durations cannot be neglected in computing the severity factor (see Table 1). Hence, heating the crude to 440 °C for 12.5 min, where it was held briefly (for 1 min), and cooling to 300 °C for 9 min (see Table 1) contributed to


Dehkissia et al.

Table 3. Comparison between Initial Boiling Points (IBPs) of TCO from the Different Scenarios (log Ro ) 6.3), and Role of Hydrogen on the Fractional Distribution within TCO for Different Treatments R01_440 °C/25 min scenario IBP (°C) volume recovered (mL) percentage recovered (% v/v) scenario gas (including loss) (wt %) coke (wt %) asphaltenes (wt %) maltenes (wt %)

R02_440 °C/25 min

R03_440 °C/25 min

(a) Comparison between Initial Boiling Points (IBPs) of TCO II: 100 mL topped crude IV: 100 mL crude treated with H2 treated with H2 120 90 22.0 23.0 17 23

other case: 100 mL crude treated without H2 80 22.0 22

(b) Role of Hydrogen on Fractional Distribution within TCO I: topped crude treated III: crude treated with H2 with H2 13.6 13.9 2.9 2.4 5.2 6.2 78.9 77.4

other case: crude treated without H2 13.0 4.0 7.9 75.2

Figure 2. Impact of heating and cooling on viscosity reduction.

Figure 3. Typical nonisothermal temperature-time path during the catalytic and noncatalytic hydrovisbreaking treatments that account for the heating and cooling transients.

a tremendous decrease in viscosity, compared to that of untreated crude oil (Figure 2): the lower the measured temperature, the higher the viscosity discrepancy. Increasing the severity factor (log Ro) from 5.3 (R016) to 6.3 (R02) through a longer plateau (i.e., 25 min instead of 1 min) at 440 °C resulted in further TCO viscosity reduction, albeit modest, under hydrovisbreaking conditions (see Figure 2). At log Ro ) 5.3, TCO has already underwent 73% of the 94% viscosity decrease at 30 °C, and 65% of the 88% reduction in viscosity when the treated crude viscosity was measured at 50 °C. Such results indicate that, at relatively high temperatures (g450 °C), the hydrovisbreaking reaction time does not need to be too long. As a matter of fact, Lepage et al.7 suggested reaction times of ∼1 min.

Figure 4. (a) Evolution of Doba MF3 + MF4 conversion with the (temperature-corrected) treatment severity (noncatalytic hydrovisbreaking). (b) Arrhenius plot of the Plonka rate constant for estimating activation energy (E) and preexponential factor (βo) in eq 9.

4.4. Identification of the Doba Crude Hydrovisbreaking Kinetic Constants ω, γ, and E. One of the advantages of the severity approach is that kinetics tests do not need to be run under entirely isothermal conditions, as long as the temperature-time locus is known. Under those circumstances, eq 3 is integrated along the t-T path, as shown in Figure 3 for run R02 (Table 1). Note that the heating/cooling rates, R and δ, respectively (i.e., slopes), are determined via calibration for each run summarized in Table 1. Figures 4a and b respectively show the linear and Arrhenius plots of eqs 9 and 3. The kinetic parameters were obtained after iterative determination of ω, as


Energy & Fuels, Vol. 18, No. 4, 2004 1163 Table 4. Fractional Composition Analysis of Gas Formed during Hydrovisbreaking of Doba Crude at a Severity Factor of 6.3 identified gas CO2 H2S C2H4 C2H6 C3H6 C3H8 C4H8 C4H10 C5H10 C5H12 C6 C7 total

Figure 5. (a) Fractional distribution of Doba crude products and (b) corresponding maltenic subfractions, as a function of the severity treatment (noncatalytic hydrovisbreaking).

detailed in Table A1 of the Appendix. The optimal ω value was obtained according to the procedure detailed in ref 14 by correcting the severity factor values, with respect to a floor temperature, and maximizing the correlation coefficient R2 between the measured and predicted conversions from eq 9. The best data fit for the noncatalytic hydrovisbreaking tests for the heavy oil pseudo-component MF3 + MF4 yielded a correlation coefficient R2 ) 0.977 (see Table A1) for ω ) 29.95 K. Correspondingly, the slope (or the heterogeneity factor γ) was 1.01 (see Figure 4a), which suggests that the Doba crude petroleum is very homogeneous and far more regular than Athabasca heavy oil for which the heterogeneity coefficient was γ ) 0.95.11 Figure 4b shows that the fitted activation energy was 140.9 kJ/ mol and was compatible with literature findings on hydrovisbreaking where E values in the range of 230 and 90 kJ/mol are typical.7,14 4.5. Analysis and Characterization of Hydrovisbreaking Products. The evolution of product yields, as a function of the severity factor, is illustrated in Figures 5a and b. Coherent with literature findings regarding the promoting effect of severity on dealkylation,11 the yield in gaseous products steadily increased with severity (see Figure 5a). Chromatographic analysis of gaseous products obtained at log Ro ) 6.3 revealed the presence of C2-C6 hydrocarbons, whereas H2S went undetected below apparatus detection limits (Table 4). This confirms that Doba crude petroleum is a low-sulfur crude.20 The dominance of paraffins versus olefins in the gas is an indication of the role that hydrogen has (20) http://www.exxon.com/essochad/project/stations.html.

yield (% wt/wt) 7.6 0.0 7.8 1.9 43.7 5.1 9.2 7.8 9.4 7.6 100.0

in interfering, during hydrovisbreaking, with the undesirable coke-precursor condensation reactions. The maltenes yield steadily decreased as the severity increased from 97.4% (untreated crude) to 73.1% when the substrate was treated at the highest severity, i.e., log Ro ) 6.6 (see Figure 5a). As will be discussed later, such a reduction in maltenes was ascribed to the conversion of the maltenic heavy subfractions (MF3 and MF4). Contrary to Athabasca bitumen vacuum bottoms hydrocracking,10 Doba crude hydrovisbreaking leads to an increase in asphaltenes yield as the severity factor increases, peaking at log Ro ) 6.4 before undergoing a decline. At log Ro ) 6.3, the asphaltenes yield was 6.3%, as opposed to 1.8% in the untreated Doba crude. Correspondingly, the four asphaltenic subfraction yields were 1.7% (AF1), 2.1% (AF2), 0.6% (AF3), and 1.9% (AF4), versus 0.3% (AF1), 0.7% (AF2), 0.2% (AF3), and 0.6% (AF4) in the untreated crude oil. The peak yield of 6.5% was attained at log Ro ) 6.4, before decreasing to 4.6% at log Ro ) 6.6. A breakdown of the evolution of MF1 through MF4 subfraction yields with severity is illustrated in Figure 5b. The maltenic polyaromatics (the MF3 subfraction) underwent a monotonic decrease with increasingly severity. A sharper decrease in the polars (the MF4 subfraction) occurred, with yields varying from 12.8% in the untreated crude to 4.7% for the treated crude at log Ro ) 6.4. At further higher severity values, a buildup in polar components occurred. A plausible explanation could be that interconversion between the asphaltenes being formed and the polars is happening, thus enriching the MF4 subfraction, as suggested for the asphaltenes conversion during Athabasca bitumen vacuum bottoms hydrocracking.10 On the other hand, the declining yields in polar subfraction (MF4) in the low-tomoderate severity range (6.0-6.4) was due to MF4 conversion to saturates (MF1), monoaromatics and diaromatics (MF2), coke, etc. However, the irreversible decrease observed in the case of polyaromatics (MF3) mainly inflated the saturates, the monoaromatics and diaromatics subfractions, and, to a much lesser extent, the coke fraction. Hence, without excluding the MF3 ≈ MF4 interconversion, each of the two maltenic heavy subfractions generated all products, including gaseous products.10 As expected, the MF1 yield increased as the severity increased in the log Ro ) 6.0-6.2 range, from 45.0% (untreated crude) to 40.9%, and to 53.4%, respectively (see Figure 5b). Above log Ro ) 6.2, although the MF1 yield slightly declined, it still remained above that


Dehkissia et al.

Table 5. Product Fractions Breakdown from Hydrovisbreaking with and without Catalyst, and Comparison of the Fractional Yields of Catalytic Hydrovisbreaking Obtained Using “with Dilution” and “without Dilution” Procedures (a) Product Fractions Breakdown from Hydrovisbreaking Maltenes log Ro

no catalyst

6.0 6.2 6.3

90.6 86.8 81.1

With Catalyst MoS2 FeS 90.8 83.7 81.7

Cokea

Asphaltenes

89.2 85.6 82.9

no catalyst 3.8 3.9 6.5

With Catalyst MoS2 FeS 4.1 5.5 6.2

4.8 5.7 5.3

Gas

With Catalyst MoS2 FeS


2.0 2.4 2.6

0.9 1.1 2.9

With Catalyst MoS2 FeS


3.1 8.3 9.4

5.1 7.6 9.9

(b) Comparison of Fractional Yields of Catalytic Hydrovisbreaking Maltenes

Cokea

Asphaltenes

Gas

No Dilution

With Dilution

No Dilution

With Dilution

No Dilution

With Dilution

No Dilution

With Dilution

log Ro

MoS2

FeS

MoS2

FeS

MoS2

FeS

MoS2

FeS

MoS2

FeS

MoS2

FeS

MoS2

FeS

MoS2

FeS

6.2

83.7

85.6

81.5

82.1

5.5

5.7

5.1

5.4

2.4

1.1

2.2

1.4

8.3

7.6

11.2

11.1

a

In the treatment with catalyst, the coke fraction may interfere with catalyst content.

of the untreated substrate. MF1 consumption was likely to be ascribed to its partial transformation into gaseous and volatile products. Monoaromatics and diaromatics (MF2) yield increased as the severity increased, from 11.0% (untreated crude) to 12.4%, 13.2%, 13.2%, 11.8%, and 11.5% at log Ro ) 6.0, 6.2, 6.3, 6.4, and 6.6, respectively. The MF2 contributing species are believed to be the intermediates in the conversion of polars and polyaromatics to the saturated hydrocarbons (MF1).10 Besides the noncatalytic hydrovisbreaking tests, several runs were also performed where powdered catalytic materials of transition-metal sulfides were also injected in the autoclave reactor (see Table 1). Hence, the catalytic activity of FeS (CAS 1317-37-9; density at 20 °C ) 4.74 g/cm3, melting point ) 1195 °C; 99% purity, from Alfa-Aesar Company) and MoS2 (CAS 1317-33-5; density at 20 °C ) 4.80 g/cm3, melting point ) 1185 °C; 99% purity, from Alfa-Aesar Company) was assessed. Two catalyst introduction procedures were evaluated. In the first procedure (which is referred to as “no dilution”), 2 wt % of the powdered catalyst was mixed and agitated without special precaution in the feedstock before vessel filling. Comparative analysis of the separation results indicated, in this case, an almost passive contribution of the catalysts, quantitatively speaking (Table 5a). The slight increase in coke and, to a lesser extent, in asphaltenes, compared to that observed for treatments without catalyst, at log Ro ) 6.0 and 6.2 was attributed to the interference of catalyst with isolated coke and/or asphaltenes during the separation process. In the second procedure (which is referred to as “with dilution”), the powdered catalyst, which was poured in a certain amount of heavy crude oil, was dissolved in CH2Cl2 (1/30, v/v). The thus-obtained suspension was sonicated for mixing for 90 min. The mixture was then allowed to settle for 12 h and the catalyst-crude oil system was transferred to the autoclave after complete evaporation of the CH2Cl2 solvent. Such a procedure was thought to be efficient at deepening the interpenetration between the catalyst and the heavy oil hydrocarbon mixture to enhance catalytic activity.10 As shown in Table 5b, at constant severity, the gaseous yields increased from 8.3% to 11.2% for MoS2 and from 7.6% to 11.1% for FeS. Although the “with dilution” procedure resulted in slightly lower maltenic yields than the “no dilution” procedure, the viscosity data (to be discussed in Section 4.6, in Figures 11 and 12) showed that the

Figure 6. Fourier transform infrared (FT-IR) spectra of MF1-MF4 maltenes subfractions for untreated and treated Doba crude (noncatalytic hydrovisbreaking) at log Ro ) 6.3.

former procedure was very beneficial to viscosity mitigation than the latter, presumably because more light hydrocarbons were formed in the catalyst-mediated hydrovisbreaking reactions. The crude oil aromatic character was qualitatively confirmed by the fractionation results (maltenes + asphaltenes + coke - MF1 ) 55%) and also by the FTIR spectra of the MF1 to MF4 maltenic subfractions isolated from the untreated and treated crude oil at log Ro ) 6.3 for run R02 (Figure 6). The FT-IR spectra for the other severities were qualitatively similar to those shown in Figure 6. The spectrum of the MF1 subfraction exhibits absorbance bands reminiscent of C-H vibrations in saturated aliphatic hydrocarbons in the 29502850 cm-1 and 1480-1370 cm-1 region that are ascribed to the stretching and bending modes, whereas the 720725 cm-1 peak ascribed to alkyl chains that have four or more methylene groups is prominent in the nonsaturated subfractions MF2 to MF4. Note that, for all eight examined subfractions, the alkyl region 29502850 cm-1 is mainly dominated by the methylene groups. MF1 seems to contain saturated hydrocarbons, as especially suggested by the relatively high content in methyl groups appearing in the left-side shoulder of the 2950-2850 cm-1 wavenumber region. It must be emphasized that the signal contributed by the methyl groups evolves in a decreasing manner, with respect to


Energy & Fuels, Vol. 18, No. 4, 2004 1165 Table 6. Fractional Distributions Isolated from Treated and Untreated Doba Crude Petroleum during Noncatalytic Hydrovisbreaking, and Viscosity of Untreated Crudes, Treated Crudes, and Syncrudea (a) Fractional Distributions Isolated from Treated and Untreated Doba Crude Petroleum Products Isolated from Treated and Untreated Crude Petroleum (wt %) severity, asphaltmaltlog Ro enes gas coke enes MF1 MF2 MF3 MF4 f (%)b

6.0 6.2 6.3 6.4 6.6

1.8

0.0

3.8 3.9 6.5 6.5 4.6

5.4 8.4 9.9 15.3 16.7

Untreated Crudec 0.1 97.4 45.0 11.0 26.8 12.8 Treated Crude 0.2 90.6 48.9 0.9 86.8 53.4 2.5 81.1 50.0 4.6 73.6 47.0 5.6 73.1 46.0

12.4 13.2 13.2 11.8 11.5

22.7 15.0 13.0 10.1 9.3

6.6 5.2 4.9 4.7 6.4

0.0 26.0 49.0 54.8 62.6 60.4

(b) Viscosity of Untreated Crude, Treated Crudes, and Syncrude Viscosity (mPa‚s) severity, log Ro

6.0 6.2 6.3 6.4 6.6

Figure 7. Effect of shear rate on viscosity and its (a) temperature dependence of Doba crude treated at log Ro ) 6.0 and (b) dependence on the treatment severity and viscosity measurement at 50 °C (noncatalytic hydrovisbreaking).

the methylene group response, suggesting an impoverishment in saturated structures from MF1 to MF4, for both untreated and treated crudes. The MF2 subfraction spectrum has absorbance peaks similar to those found for MF1, in addition to a feature in the region of 16001450 cm-1 that is assigned to the stretching of aromatic CdC groups, and another feature that emerges in the region of 700-900 cm-1, which is typically ascribed to the out-of-plane bending of aromatic C-H groups or to toluene and benzene vibrational frequencies. That supposes that the MF2 subfraction contains aromatic hydrocarbons that have one or two rings. MF3 and MF4 spectra are similar to the MF2 spectrum but with a pronounced increase in intensity of aromatics signals, and the appearance of some signals, from MF2 to MF4, possibly assigned to the carbonyl stretch in the region of 1800-900 cm-1 and particularly to amide carbonyls in the region of 1700-1650 cm-1.11,14 These observations suggest that polyaromatics are major constituents in the MF3 and MF4 subfractions. As a matter of fact, the MF4 subfraction has a contribution from polar polyaromatics close to asphaltenes. The MF3 and MF4 subfractions in the treated crude oil display a noticeable increase in the aromatic absorbance bands, with respect to the respective subfractions in the untreated crude. It is suggested that MF3 and MF4 become more aromatic after treatment, because of dealkylation or condensation of some unstable entities. Dealkylation, on the other hand, produces light products that contribute to the MF1 and gas fractions. In the asphaltenes spectra, the

30 °C

50 °C

60 °C

Untreated Crude 563.7 280.3

169.4

103.4

Treated Crude 134.0 85.3 75.1 43.9 35.6 26.0 8.8 8.5 16.3 12.6

54.9 30.8 20.5 6.9 10.2

38.4 22.1 16.6 7.5 8.9

Syncrude 135.4 104.5 92.3 30.4 54.4

87.9 65.8 62.2 23.7 37.5

57.8 44.3 43.5 19.3 27.4

245.4 211.3 155.4 42.7 93.7

40 °C

a Syncrude is synthetic crude; it is composed of treated crude mixed with 50 wt % untreated crude. b From eq 4. c Losses of 0.7% and 1.8% were observed during untreated crude separation and maltenes fractionation, respectively.

aromatic CdC bands are more prominent than in the maltenic subfractions. Similar assignments and interpretations were formulated for both untreated and treated crude asphaltene subfractions, so the results will not be shown here. The work of Dehkissia et al.8 can be consulted for the FT-IR spectra of the asphaltenic subfractions of the untreated Doba crude oil. Note that these FT-IR spectra are very similar to those discussed in the case of Athabasca bitumen vacuum bottoms,11 pitches from Avgamasya asphaltite and Raman-Dinc¸ er heavy crude,21 and asphaltenes from Mexican crudes.12 4.6. Rheological Behavior. The viscosity (η) versus shear rate (γ′) profiles for temperatures typical of pipeline transport (30-60 °C) revealed that the treated Doba crude oil exhibits a Newtonian viscous behavior. The η-γ′-T plots for a treatment severity at log Ro ) 6.0 are illustrated in Figure 7a. This behavior compares well with that already observed for the untreated Doba crude8 (see Figure 2). Similarly, the η-γ′-log Ro plots of Figure 7b illustrate the incidence of the severity factor on the treated oil viscosity measured at 50 °C. Coherent with the trends in Figure 2 above and as shown in Figure 7b, increasing the severity factor reduced the viscosity of the treated crude. However, beyond log Ro (21) Akrami, H. A.; Yardin, M. F.; Akar, A.; Ekinci, E. Fuel 1997, 76, 1390-1394.


Dehkissia et al.

Figure 8. Arrhenius plots of dynamic viscosity of untreated and treated Doba crude at different severity factors. Table 7. Parameters of the Newtonian Viscosity Correlation η ) A exp(B/T) for the Treated and Untreated Crudesa sample

A

B

R2

untreated crude crude treated @ 6.0 crude treated @ 6.2 crude treated @ 6.3 crude treated @ 6.4 crude treated @ 6.6

4.43 × 10-9 1.22 × 10-7 1.13 × 10-7 7.74 × 10-6 4.66 × 10-4 1.81 × 10-5

5629 4210 4046 2548 898 2053

0.993 0.998 0.987 0.992 0.960 0.983

a For temperature T given in Kelvin. The correlation coefficient R2 also is given for each sample.

) 6.4, the trend reversed and the viscosity of the treated crude began to increase, despite the decrease in the asphaltenes yield, which was sharper than that of the maltenes yield (see Figure 5a). It was speculated that this viscosity increase was ascribed to reconversion of asphaltenes produced during reaction to viscous polar species (the MF4 subfraction), whose yield indeed increased as discussed previously in this subsection and shown also in Table 6a. Similarly, the frequency and temperature dependence of the viscous moduli (G′′) and elastic moduli (G′) of the treated crudes indicates that G′′ is at least an order of magnitude higher than G′ within the 30-60 °C temperature range, regardless of the chosen severity for treatment. Because the treated crudes do not exhibit any elastic character in the studied ranges, they can also be viewed as purely viscous, as for the untreated crude.8 Hence, besides the treatment history (which is embedded in the severity factor), temperature seems to be the only important factor that affects the viscosity of the treated crude oil. The dynamic viscosities obeyed an Arrhenius-type of dependence: η ) A exp(B/T) (Figure 8), with parameters A and B summarized in Table 7 for each severity factor. A fortiori, the rheology of the syncrudes resulting from mixing Newtonian untreated and Newtonian treated crudes, according to scenario IV, would yield Newtonian systems, as confirmed in Figures 9a and 9b. Figure 9a confirms the independence of the syncrude viscosity (treated + 50% untreated) from the shear rate over the 30-60 °C temperature range when the treated crude underwent hydrovisbreaking at log Ro ) 6.4. Figure 9b confirms the neglect of the elastic modulus G′, with respect to the viscous modulus G′′, for syncrudes obtained by mixing treated crudes at different severities.

Figure 9. Effect of (a) shear rate on syncrude oil viscosity at different temperatures, and (b) frequency on the syncrude viscous modulus (G′′) and elastic (G′) modulus at 50 °C and different severities. Syncrude is composed of 50 wt % untreated Doba crude + 50 wt % treated crude (noncatalytic hydrovisbreaking).

Figure 10. Evolution of treated crude viscosity and maltenic subfraction conversion versus treatment severity.

The evolution of crude petroleum viscosity and conversion versus treatment severity (log Ro) is presented in Figure 10 and Table 6a. It can be seen that the decrease in crude oil viscosity correlated well with the increase in the conversion of the maltenic subfractions MF3 and MF4. Recall that MF3 and MF4 were the only subfractions whose yields decreased during treatment and not asphaltenes (see Figure 5b); thus, both subfractions are believed to be the controlling parameters of the heavy oil viscosity. Furthermore, according to the viscosity specification (25 cSt @ 50 °C) for pipeline



Figure 12. Comparison between “with dilution” and “no dilution” procedures for viscosity mitigation of post-deasphalted treated crude.

Figure 11. Evolution of treated crude and syncrude mixture viscosities, as a function of weight composition and severity treatment (catalytic and noncatalytic hydrovisbreaking).

transport, if the entire crude were to be treated, this specification is reached at a severity of 6.3 (440 °C, 25 min): η ) 20.5 mPa s (or 23 cSt). Obviously, for economic reasons, this option is unfeasible. Instead, scenario IV (Figure 1) is preferred, because it requires only 50 wt % of the crude oil to be treated prior to mixing with 50% of untreated crude oil to generate a syncrude at lesser cost (see Table 6b). Under such circumstances, the syncrude viscosity at a severity of log Ro ) 6.4 (460 °C, 15 min) is 23.7 mPa s at 50 °C (or ca. 26.5 cSt), which practically meets the specification. For log Ro > 6.4, the viscosity increase in the 30-60 °C range is probably due to reconversion of the asphaltenes produced during the reaction into polar components (MF4). The viscosity of the treated crude oil was affected by the presence of 2 wt % of catalyst. To substantiate the impact of the activity of the tested catalysts, nondeasphalted and post-deasphalted crude (for coke and catalyst recovery) were evaluated, in terms of viscosity reduction. Figure 11 shows plots of the kinematic viscosity at 50 °C versus log Ro for the treated crude oil (noncatalytic hydrovisbreaking) and two syncrude oils obtained from mixing the treated crude oil with 25% and 50% of the untreated crude oil. As expected, the kinematic viscosity decreased as either the severity or treated crude mass fraction in the syncrude increased. Also, the catalytically treated (nondeasphalted) heavy oils are slightly more viscous than their post-deasphalted counterparts, because of the presence of the spent catalyst. The latter could eventually be removed during coke and asphaltenes isolation. Even without deasphalting, there is an advantage of using an FeS catalyst, because the resulting treated crude oil has a lower viscosity (26.7 cSt) than the noncatalytically treated crude (34.1 cSt) at log Ro ) 6.2. Mixing with 50% untreated crude oil, according to scenario IV, yielded syncrudes with viscosities of ∼55 and 57 cSt at log Ro ) 6.2 for FeS and MoS2 catalysts,

Figure 13. Effect of aging and severity on stability of the viscosity of treated crude.

respectively. This viscosity is less than the viscosity of syncrude (72.3 cSt) when no catalyst was used (see Figure 11). Achievement of syncrude viscosities of 25 cSt at 50 °C without post-deasphalting may still be possible by locking the severity at log Ro ≈ 6.35 (see Figure 11). Otherwise, post-deasphalting would be required for lower severity, thus overshadowing the catalytic route, because the entailed extra cost must be taken into account in the process economics. Nonetheless, the processing extra cost eventually can be reduced via the availability and recovery of the deasphalting solvent. Furthermore, better interpenetration between the catalyst and the hydrocarbon matrix, according to the “with dilution” procedure, is believed to yield lessviscous treated crudes. The “no dilution” procedure yielded indistinguishable viscosities of the (postdeasphalted) oil treated at 50 °C and log Ro ) 6.2, regardless of whether the crude oil was catalytically mediated (with either FeS or MoS2) or not (Figure 12). With the ultrasonic mixing, the viscosity decrease, with respect to the noncatalytic hydrovisbreaking route, is remarkable, with a slight advantage of FeS over MoS2. The generation of more light products10 by means of both catalysts explains the further reduction in viscosity in the “with dilution” procedure, despite the slightly smaller yields of total maltenes fraction (see Table 5).


Dehkissia et al.

Table A1. Estimation of the Characteristic Temperature (ω) at the Floor Temperature and after Temperature Correction For Estimation of ω at the Floor Temperature ω) 12.5

ω) 17.5

log Ro

12.3 12.9 13.2 13.7

9.2 9.6 9.9 10.2

R2 slope, γ intercepta

0.899 0.35 -5.14

0.912 0.53 -5.71

ω) 22.5

ω) 26.3

ω) 26.9

ω) 27.5

ω) 28.5

ω) 29.95

ω) 30.5

ω) 35.5

ω) 44.5

log[-log(1 - f)]

7.5 7.8 8.0 8.2

6.6 6.9 7.0 7.2

6.5 6.7 6.9 7.1

6.4 6.6 6.8 6.9

6.2 6.5 6.6 6.7

6.0 6.2 6.4 6.5

5.9 6.1 6.3 6.4

5.3 5.5 5.6 5.6

4.5 4.7 4.8 4.8

-0.88 -0.53 -0.43 -0.37

0.924 0.74 -6.35

0.932 0.92 -6.89

0.933 0.94 -6.97

0.934 0.98 -7.07

0.936 1.03 -7.22

0.939 1.10 -7.45

0.940 1.13 -7.54

0.946 1.42 -8.39

0.944 2.0 -10.09

For Estimation of ω after Temperature Correction ω) 12.5

ω) 17.5

log Ro

12.1 12.9 13.2 13.6

9.1 9.6 9.9 10.1

R2 slope, γ intercepta

0.948 0.33 -4.88

0.959 0.50 -5.38

a

ω) 22.5

ω) 26.32

7.4 7.8 8.0 8.1

6.5 6.9 7.0 7.1

0.968 0.69 -5.92

0.973 0.85 -6.37

ω) 26.85

ω) 27.5

ω) 28.5

ω) 29.95

ω) 30.5

ω) 35.5

ω) 44.5

log[-log(1 - f)]

6.4 6.7 6.9 7.0

6.3 6.6 6.8 6.9

6.1 6.4 6.6 6.7

5.9 6.2 6.4 6.4

5.8 6.1 6.3 6.3

5.2 5.5 5.6 5.6

4.5 4.6 4.8 4.7

-0.88 -0.53 -0.43 -0.37

0.974 0.90 -6.51

0.975 0.92 -6.51

0.977 1.01 -6.81

0.974 1.07 -7.09

0.971 1.25 -7.39

0.965 1.80 -8.84

0.9736 0.87 -6.43

ln βo - {ln γ + [E/(RT)] + (γ/ω(T))(T - Tref)} in eq 9.

The typically long residence times of crudes in pipelines in actual storage and under transportation conditions suggest that crude aging may be an important factor to be investigated.22 Our findings, which are presented in Figure 13, seem to suggest that there is an important increase of viscosity with increasing storage time, as illustrated in the case of a crude treated at log Ro < 6.4. For crude oils treated at severities of log Ro g 6.4 (460 °C, 15 min), the viscosity remains virtually unaffected by time over storage periods up to two months. This time period corresponds typically to the residence time of the Doba crude oil in the 1050km-long pipeline. These results align with previous results on Athabasca topped heavy oil (ATHO),8 which demonstrated that the viscosity of high-temperature products (>480 °C) was stable over two-week periods, whereas that of low-temperature products (

Lowering the Viscosity of DobaChad Heavy Crude Oil for Pipeline

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