Characterization, PVT properties and phase behavior of a condensate

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Process Engineering

Characterization, PVT properties and phase behavior of a condensate gas and crude oil Fedra A. V. Ferreira, Thales Cainã dos Santos Barbalho, Izabella Regina Souza Araújo, Humberto Neves Maia de Oliveira, and Osvaldo Chiavone Filho Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00469 • Publication Date (Web): 27 Mar 2018 Downloaded from http://pubs.acs.org on March 28, 2018

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Characterization, PVT properties and phase behavior of a condensate gas and crude oil F. A. V. Ferreira*,a, T. C. S. Barbalhob, I. R. S. Araújoa, H. N. M. Oliveiraa, O. Chiavone-Filhoa aUFRN,

Department of Chemical Engineering, Natal, Brazil (*[email protected]) b UFRJ, COPPE, Rio de Janeiro, Brazil

1. ABSTRACT The oil reservoirs are underground and have the oil and gas contained in the porous rock at high temperatures and pressures. Only 5 to 20% of the oil is withdrawn in primary production. Further recovery can be achieved by injecting carbon dioxide (CO2) that displaces and dissolves part of the remaining oil, this process is called enhanced oil recovery. Although the characterization and fractionation of petroleum are well known and studied, each oil sample represents a unique multicomponent system, so an individual study of the sample is required. Real samples of condensate gas (CG) and light crude oil (LCO) were collected and analysed for density, viscosity, atmospheric distillation and fractionation, aiming characterization. Synthetic visual and non-visual methods for high pressure were successfully applied for bubble point measurements of the systems composed of supercritical CO2 and CG or LCO. Phase envelope calculations were developed based on pseudo-components obtained by atmospheric distillation and density values using Adachi-Lu-Sugie equation of state with van der Waals mixing rule with one interaction parameter (kij) from the literature. PVT (pressure-volume-temperature) measurements are reported for the systems CG + CO2 and LCO + CO2 as function of temperature and pressure, and in a wide range of CO2 composition. Crude oil characterization using atmospheric distillation and density measurements demonstrated to be feasible with accuracy, since the boiling points and specific mass obtained, allowed us the proposal of a series of pseudo-components to represent the sample phase behavior, studied experimentally. Thus results suggest that the characterization and fractioning of the samples were effective. Thermodynamic modelling and experimental data presented average deviation of 3.1% to CG + CO2 and 2.5% to LCO + CO2 systems, indicating reasonable accuracy for petroleum samples.

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2. INTRODUCTION Enhanced oil recovery (EOR) is a generic term for tertiary crude recovery techniques that increase the amount of oil that can be extracted. EOR techniques increase the recovery of crude through the use of heat, chemicals, or solvents and are utilized after primary and secondary techniques have already been deployed. One of the solvents studied in EOR technique is the carbon dioxide (CO2). That technique consists in the injection of CO2 into the well to improve the recoverability of crude oil by reducing viscosity, swelling crude oil, and lowering interfacial tension1,2. CO2 has many advantages that make it a good choice for the injection into the pore spaces of a rock, to help the crude oil movement, such as, its miscibility with crude oil, the low cost of CO2 in comparison with other similarly miscible fluids, and its ability to reduce crude oil viscosity3. When CO2 is injected into an oil reservoir, it becomes soluble with the residual crude oil and with the light hydrocarbons. At high pressures, the CO2 density is higher and its solubility increases. When the oil contains a higher content of light hydrocarbons the dissolution is even better. As long as temperature decreases, the density of the CO2 is higher, and the crude oil is no longer miscible in CO22. Phase equilibrium at high pressures is very important in the study of reservoir oil PVT behavior simulation. Dohrn4,5 and his contributors made an extensive review through the years gathering the works that have been reported in the area of phase equilibrium at high pressures, contemplating various methods, equipment types and experimental data. Production of petroleum and its refining require equipment such as phase separators, distillation and absorption columns, heat exchangers, reactors, pipelines, storage tanks, pumps and mixers. Optimum design and operation, of the necessary equipment for oil refining units, require accurate values of thermodynamic and physical properties which include density, vapor pressure, viscosity, thermal conductivity, diffusivity, surface tension and fugacity6. For the thermophysical properties, thermodynamic relations such as equations of state or generalized correlations are widely used. Riazi and Aladwani6 present a study with some guidelines for choosing a characterization method for petroleum fractions in process simulators. Such correlations require input properties which include critical temperature (Tc), critical pressure (Pc), critical volume (Vc), acentric factor (ω) and molecular mass (MM) to convert a molar property into weight, or mass, based property. The critical constants of petroleum mixtures needed for these correlations are pseudocritical properties which cannot be measured. Characterization of 2 ACS Paragon Plus Environment

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petroleum fractions involve methods that use measurable properties such as boiling point (Tb) and specific gravity (SG) to estimate critical properties and molecular weight needed in the thermodynamic correlations7. Lee–Kesler8 correlations requires Tb and SG, as input variables, and are based on critical properties of pure hydrocarbons (up to C18), and they allow estimation of critical constants from vapor-pressure data for heavier hydrocarbons up to boiling point of 550 ºC. Correlations have been developed empirically and contain 14 numerical coefficients explicit in terms of Tc and Pc. Acentric factor (ω) is used as a third parameter beside Tc and Pc in generalized corresponding states correlations or cubic equations of state for calculation of thermodynamic properties. Accurate calculation of  requires accurate values of Tc, Pc and vapor pressure at T=0.7 Tc. Edmister9 correlation is the simplest relation, to calculate acentric factor, that is based on the Clausius– Clapeyron equation10. Riazi and Daubert11 developed a simple and generalized correlation based on cubic equations of state constants which has three numerical coefficients. The equation has unique form for calculation of Tc, Pc, Vc, MM and density (ρ). These equations are based on properties of pure hydrocarbons (from C5 to C20) and should be applied to petroleum fractions with boiling point from 30 – 350 ºC. Reiter et al.12 claim that there are other approach for oil characterization such us the generation of substitute mixtures containing real chemical components. The comparison between the two methods of oil characterization shown similar results. Cubic equations of state (EoS) are naturally chosen as the thermodynamic basis for the model to be developed, since cubic EoS's are simple and fast models and easy to implement in a reservoir simulation program13. Orr and Jensen14 and Petersen and Stenby15 found the Adachi-Lu-Sugie16 (ALS) equation of state to be the most accurate for prediction of the phase behavior of well-defined hydrocarbon mixtures with and without a considerable content of CO2. The interaction parameters (kij) are assumed to be zero between all hydrocarbons and non-zero between hydrocarbons and non-hydrocarbons. There are several works made on this area, contemplating the CO2 and crude oil, and CO2 with condensate gas, with different purposes. Petersen and Stenby15 studied the prediction of thermodynamic properties of oil and condensate gas mixtures using ALS EoS. Sun et al.17 and Shariati et al.18 used a synthetic visual method to determine PVT data for condensate gas at high pressures. It is noteworthy that Shariati et al.18 used also a synthetic mixture of hydrocarbons to represent the condensate gas sample. Lucas et al.19 studied phase behavior of crude oil in CO2. Jaubert et al20 made an extensive research and created 3 ACS Paragon Plus Environment

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a crude oil data bank. Cao and Gu21 studied the temperature effects on phase behavior light crude oil with CO2. Varzandeh et al.22 made a research based on a large PVT data bank and have applied a general approach to characterizing reservoir fluids for EoS models. Su et al.23 made an experimental and modelling study of CO2 aiming the optimization of the recovery in condensate gas reservoir. Satyro and Yarraton24 used experimental distillation data to characterize crude oil by simulation. The contributions of this work are the characterization procedure and new phase equilibrium experimental data at high pressures for light crude oil (LCO) with CO2 and condensate gas (CG) with CO2. A Brazilian sample of condensate gas and light crude oil were fractionated by atmospheric distillation and described via density and viscosity. Phase behavior data of the LCO + CO2 and CG + CO2 mixtures were experimentally determined. Critical properties of the pseudo-components were estimated and modelled with ALS equation of state with a quadratic mixing rule (vdw1) using predetermined interaction parameters (kij) for CO2. Therefore, it is demonstrated a characterization approach for real oil samples based on physical and phase equilibrium properties. It is noteworthy that there are no researches using PVT experiments with the system CO2 + CG in the open literature. For this reason, the PVT data obtained for CO2 + CG is a contribution for the industry and academic field. 3. EXPERIMENTAL SECTION For the execution of this work a methodology was developed in order to achieve the expected results. Therefore, computational simulation, literature known correlations and experimental work were used simultaneously and a good agreement between them can be observed in the results. First of all, atmospheric distillation, as well as measurements of density and viscosity were made and the samples of condensate gas and light crude oil were fractionated. With those experimental data, literature correlations were used in order to obtain the pseudo-components parameters, such as, Tci, Pci, ωi, MMi and kij (j = CO2). The parameters were inserted in a simulation program (SPECS v.5.63 – Separation and Phase Equilibrium Calculations – Center of Energy Resources Engineering, Technical University of Denmark, 2010) and phase envelopes were obtained. This important step is necessary for the initial input of temperature and pressure in the equilibrium cell. PVT data were obtained using a synthetic visual and non-visual methods, for a wide range of CO2 composition, temperature and pressure for both CG and LCO samples. The


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modelling was developed using ALS EoS with van der Waals (vdw1) mixing rule for the interaction parameter. 3.1. Samples fractionation and characterization A sample of Brazilian condensate gas (CG), with a density of 0.7212 g.cm-3 at 20 ºC, and a sample of Brazilian light crude oil (LCO), with a density of 0.8413 g.cm-3 at 20 ºC and a ºAPI of 35.89, were fractionated through an atmospheric distillation process. In the distillation process, a sample equivalent in mass to a volume of 100 mL was weighed using an analytical balance (Shimadzu AUW220D; ± 0.1 mg), and thus the values were provided in a gravimetric basis. The samples of condensate gas and light crude oil were fractionated into six fractions named F1 to F6, from the lighter to the heavier fraction, respectively. Density values were measured in triplicate in a digital densimeter (Anton Paar, DMA4500 M), with a resolution of 10−5 g.cm−3. The viscosity of condensate gas sample was measured at five temperatures (293.15, 303.15, 313.15, 323.15 and 333.15 K) in an Anton Paar VM 3000 Stabinger viscosimeter. For the measurements of light oil viscosity was used a Saybolt Furol viscosimeter. 3.2. Prediction of critical properties, acentric factor and interaction parameter Based on the properties measured for the fractions F1 to F6 for both CG and LCO, it was performed a pseudo-component characterization using Riazi-Daubert11 correlation for the calculation of molecular mass (MM), Lee-Kesler8 correlation for critical temperature (Tc) and critical pressure (Pc) and Edmister9 correlation for acentric factor (ω). The interaction parameter, kij, between each pseudo-component and supercritical CO2 were obtained with Stryjek correlation25,26. 3.3. Phase equilibrium apparatus and procedure The synthetic static method was used to obtain the phase equilibria of the studied systems. Synthetic visual and non-visual procedures were applied, for exactly the same conditions of temperature, pressure and molar composition, in order to compare both methods. Phase equilibrium experiments were carried out in a high-pressure variable-volume view cell. The liquid mixtures were prepared into the cell gravimetrically using an analytical balance (± 0.1 mg). For CO2 addition the syringe pump was used (± 0.008 g). Considering also losses from the operational processes of transfer and mixture, the uncertainty on the 5 ACS Paragon Plus Environment

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composition was estimated to be 0.005 in mole fraction. Details on the description and experimental procedure for this apparatus are available in previous reports27,28.

4. RESULTS AND DISCUSSION 4.1.

Condensate Gas and Light Crude Oil fractionation and characterization

In Table 1 experimental data is presented, such as the boiling temperature, color, molar fraction and density at 293.15 K, of each fraction for both samples, i.e., condensate gas and light crude oil. Specific gravity and molar mass are calculated parameters, based on experimental data. Table 1. Mole fraction, boiling temperature, specific gravity, molar mass, density and color of the fractions for condensate gas and light crude oil samples. Sample

CG

LCO

0.69877

MM g.mol-1 90.34

ρ (293.15 K) kg.m-³ 698.77

Colorless

0.71416 0.72465

96.19 100.64

714.16 724.65

Colorless Colorless

381.15 391.15 402.65

0.73069 0.73608 0.74324

105.24 110.53 116.79

730.69 736.08 743.24

Light yellow Dark yellow Dark

386.15 418.15 450.15 481.15

0.70682 0.75011 0.77593 0.7976

108.04 125.65 144.75 164.98

706.82 750.11 775.93 797.60

Colorless Colorless Light yellow Light yellow

Fraction

Mole fraction

Tb /K

SG

F1

0.3215

351.15

F2 F3

0.2050 0.2377

363.15 372.15

F4 F5 F6

0.1345 0.0735 0.0278

F1 F2 F3 F4

0.3744 0.1636 0.1267 0.1308

Color

F5 0.0884 513.15 0.81263 188.47 812.63 Dark yellow F6 0.1161 543.15 0.88638 202.30 886.38 Dark Tb – bubble temperature; SG – specific gravity; MM – molecular mass; ρ – density.

Density and viscosity of condensate gas and light crude oil samples Figure 1 presents the density data for the condensate gas and light crude oil fractions at 293.15 K depending on boiling point temperature of each fraction. It can be observed that with increase of the boiling point of the fraction, the density increases as well. This result is expected because a higher boiling temperature indicates a heavier fraction and consequently, a higher density of that fraction. It is noteworthy that the experiments were accurate for the characterization purpose. The comparison of the density between the two samples is also possible, and it can be seen that the condensate gas presented densities of fractions much lower than those presented by the light crude oil fractions. The range of boiling temperatures presented by fractionation of the condensate gas sample were 6 ACS Paragon Plus Environment

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significantly lower relative to light crude oil, which indicates the presence of linear chain hydrocarbons with sequential carbon numbers. F6

875 845 F5

815

ρ/kg.m-3

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F4

785 F3

755 F3

725

F4

F5 F6

F2

CG LCO

F2 F1

F1

695

330

380

430

480

530

Tb/K Figure 1. Density of condensate gas and light crude oil fractions at 293.15 K vs bubble point temperature of the fractions coming from atmospheric distillation.

Table 2 presents density and cinematic viscosity for the raw samples of condensate gas and light crude oil. It can be observed that the increase of the temperature leads to the reduction of the sample density. It is important to note that for the oil sample the viscosity tended to stabilize after 323.15 K. Table 2. Density and cinematic viscosity of condensate gas and light crude oil samples at different temperatures.

T/K 288.15 293.15 298.15

ρ/kg.m-3

ʋ/mm2.s-1

ρ/ kg.m-3

CG 724.8 721.6 716.4

ʋ/mm2.s-1

LCO 0.6351 -

845.4 841.3 838.1

-

303.15 713.1 0.5696 48.68 313.15 704.5 0.5095 35.21 317.65 21.88 323.15 695.8 0.4518 18.15 333.15 686.9 0.3693 17.07 342.15 16.59 T – Temperature; ρ – density; ʋ - cinematic viscosity.


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Application of correlations to obtain de parameters: Tc, Pc, LMV, ω and kij Table 3 presents pseudo-component parameters for the fractions of condensate gas and light crude oil. Fraction 1 is the lighter and fraction 6 is the heavier one. Those parameters were calculated with literature correlations (Tc, Pc, ω, kij), as mentioned. The parameters presented at the rows CG and LCO are weighted average of the fractions, according to the corresponding mole fractions. (Table 1). Table 3. Pseudo-components parameters for the fractions of condensate gas (CG) and light crude oil (LCO) Sample

Fraction

Tb/K

F1

351.15

LMV/ m³.mol-1 0.129

F2

363.15

0.135

537.83

F3

372.15

0.139

F4

381.15

F5 F6

Condensate Gas

Light Crude Oil

Pc/ MPa 523.17 3.11 Tc/K

ω

ln Pc

Tr

kij

1.13

0.6712

0.2959 0.10697

3.05

1.12

0.6752

0.3127 0.10692

548.58

3.00

1.10

0.6784

0.3254 0.10689

0.144

558.28

2.91

1.07

0.6827

0.3399 0.10686

391.15

0.150

568.64

2.80

1.03

0.6879

0.3569 0.10683

402.65

0.157

580.65

2.70

0.99

0.6934

0.3763 0.10679

CG

367.00

0.137

541.88

3.01

1.10

0.6771

0.3190 0.10691

F1

386.15

0.153

557.23

2.61

0.96

0.6930

0.3591

0.1068

F2

418.15

0.167

595.92

2.54

0.93

0.7017

0.4045

0.1067

F3

450.15

0.186

629.93

2.34

0.85

0.7146

0.4572

0.1067

F4

481.15

0.207

661.49

2.15

0.76

0.7273

0.5107

0.1066

F5

513.15

0.232

691.33

1.93

0.66

0.7422

0.5727

0.1066

F6

543.15

0.228

738.45

2.14

0.76

0.7355

0.5729

0.1065

LCO 441.37 0.180 619.30 2.39 0.86 0.7109 0.4425 0.1067 Tb – bubble temperature; LMV – liquid molar volume; Tc – critical temperature; Pc – critical pressure; Tr – reduced temperature; ω – acentric factor; kij – interaction parameter.

4.2. High-pressure phase equilibrium for the system CO2 + condensate gas Phase equilibrium data obtained for the binary CO2 + condensate gas using visual and non-visual synthetic methods in the range of 0.3997 mole fraction of CO2 up to 0.7998 and the range of temperature of 313.49 up to 393.60 K are listed in Table 4. Table 4. Experimental results for the CO2 (1) + Condensate Gas (2) system using the syntheticvisual (SynVis) method and synthetic non-visual (SynNon) method x1 (mole fraction)

T/K

0.3997 0.3997

363.45 373.18

P/MPa x1 SynVis SynNon (mole fraction) 6.52 6.97

6.53 6.97

0.7001 0.7001

P/MPa T/K 323.01 333.31

SynVis SynNon 6.93 8.10

7.03 8.10


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P/MPa

0.3997 0.3997

P/MPa x1 T/K SynVis SynNon (mole fraction) 382.18 7.36 7.35 0.7001 343.35 393.60 7.90 7.89 0.7001 353.19

0.5003 0.5003

353.38 362.95

7.30 7.90

7.30 7.89

0.7001 0.7001

362.81 373.15

11.17 12.02

11.20 12.02

0.5003 0.5003 0.5003 0.6008 0.6008 0.6008 0.6008 0.6008

373.67 383.49 393.21 324.10 333.80 343.30 353.30 363.15

8.58 9.33 9.87 6.40 7.10 7.95 8.74 9.58

8.58 9.32 9.87 6.41 7.09 7.95 8.74 9.58

0.7001 0.7001 0.7998 0.7998 0.7998 0.7998 0.7998 0.7998

383.19 393.19 313.31 323.09 333.03 343.15 353.35 363.37

12.77 13.37 6.84 7.90 9.08 10.30 11.53 12.45

12.76 13.37 6.84 7.89 9.09 11.52 12.43

0.6008 0.6008

373.13 383.45

10.35 10.83

10.35 10.83

0.7998 0.7998

373.33 383.11

13.20 13.78

13.19 13.78

x1 (mole fraction)

T/K

SynVis SynNon 9.16 9.15 10.19 10.21

0.6008 392.89 10.94 11.04 0.7998 393.15 14.38 0.7001 313.49 6.28 6.27 a u(x1) = 0.005 mole fraction; bu(T) = 0.3 K; cu(P) = 0.02 MPa (combined uncertainties, considering operational and systematic errors)

In Figure 2 the experimental results in the form of a P-x-y diagram for the system CO2 + condensate gas at 353.15, 363.15, 373.15, 383.15 and 393.15 K are presented, using the synthetic-visual method. The vapor-liquid equilibrium data were correlated with the Adachi-Lu-Sugie16 equation of state, with acentric factor for the alpha function and vdw1 mixing rule with interaction parameter (kij) prefixed from the literature25. Agreement between our measurements with thermodynamic model used was observed within experimental uncertainties. Absolute Average Deviation (AAD) in pressure (Equation 1) was 3.1% that is quite satisfactory for real mixtures. Similar representation of the measurements was also described by the Soave-Redlich-Kwong (7.2%) and PengRobinson (4.8%) EoS´s. 𝑁

|𝑃𝑒𝑥𝑝,𝑖 − 𝑃𝑐𝑎𝑙𝑐,𝑖 | 100 ∑ 𝐴𝐴𝐷 = 𝑁 𝑃𝑒𝑥𝑝,𝑖

(1)

𝑖=1


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14

12

10

P/MPa

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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8

6

4

2

0 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

x1, y1 Figure 2. P-x-y diagram for the binary system CO2 + condensate gas at five different temperatures:

353.15 K;

363.15 K;

373.15 K;

383.15 K;

EoS with kij = 0.10691 from Stryjek

393.15 K;

ALS

25,26

.

The synthetic-nonvisual (SynNon) method was also used in this work for the same conditions of temperature, pressure and mole fraction of the mixture. Measurements are available in Table 4. The bubble pressure of each point was determined by the intersection of the two curves, i.e., the first one describes the equilibrium points of the homogeneous liquid region and the second one of the heterogeneous phase region (liquid and vapor). The results are illustrated in Figure 3 for one mixture at constant composition and four temperatures. It is worth to note that the volume presented in the graphic (Figure 3) is not the system volume, but the volume indicated by the syringe pump in order to obtain the depressurization curve of the phase behavior. It was also observed a thermal effect in the phase transition, i.e., it was detected a depletion in the temperature of the system in the formation of the bubble, in the order of the decimal places for all measurements. That is a second evidence applicable for the bubble point determination of the non-visual method. The quantitative agreement between visual and non-visual methods indicates the feasibility of the technique for the non-translucent samples. Thus, for quantitative data we have considered both visual and non-visual values.


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180

170

160

V/cm3

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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150

140

130

120 6

7

8

P/MPa

9

10

11

Figure 3. Depressurization behavior for the system CO2 + CG with mole fraction of CO2 of 0.7001 at four different temperatures:

322.95 K;

333.25 K;

343.25 K;

353.35 K.

4.3.High-pressure phase equilibrium for the system CO2 + light crude oil Phase equilibrium data obtained for the binary CO2 + light crude oil using visual and nonvisual synthetic methods in the range of 0.3993 mole fraction of CO2 up to 0.8004 and the range of temperature of 303.51 up to 393.65 K are listed in Table 5. It should be observed that the light crude oil is actually a mixture of the first five fractions of the distillation. This was due to the fact that the sixth, or last fraction, was a dark residue, being considered negligible and not feasible to be introduced in the equilibrium cell. Table 5. Experimental results for the CO2 (1) + light crude oil (2) system using the synthetic-visual (SynVis) method and synthetic non-visual (SynNon) method P/MPa x1 SynVis SynNon (mole fraction)

P/MPa

x1 (mole fraction)

T/K

0.3993 0.3993 0.3993 0.3993 0.3993 0.4995

353.30 363.40 373.20 383.10 393.15 333.01

6.50 7.10 7.65 8.20 8.68 6.89

6.49 7.09 7.66 8.20 8.68 6.90

0.6992 0.6992 0.6992 0.6992 0.6992 0.6992

313.53 323.52 333.03 343.31 353.01 363.31

6.88 8.07 9.46 10.85 12.16 13.48

6.88 8.06 9.45 10.87 12.16 13.48

0.4995 0.4995

343.08 353.35

7.56 8.34

7.56 8.35

0.6992 0.6992

373.35 383.49

14.63 15.68

14.63 15.68

T/K

SynVis SynNon


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0.4995 0.4995

P/MPa x1 T/K SynVis SynNon (mole fraction) 363.19 9.07 9.06 0.6992 393.65 373.33 9.67 9.66 0.8004 303.51

0.4995 0.4995

383.19 393.15

x1 (mole fraction)

T/K

10.31 10.93

10.31 10.92

0.8004 0.8004

313.13 323.07

P/MPa SynVis SynNon 16.61 16.62 6.20 6.17 7.27 8.63

7.28 8.64

0.6002 313.03 6.33 6.32 0.8004 333.31 10.22 10.23 0.6002 323.30 7.25 7.25 0.8004 343.17 11.76 11.76 0.6002 333.25 8.23 8.22 0.8004 353.27 13.33 13.35 0.6002 343.39 9.20 9.19 0.8004 363.37 14.76 14.78 0.6002 353.31 10.13 10.12 0.8004 373.11 16.05 16.07 0.6002 363.35 11.06 11.05 0.8004 383.29 17.13 17.14 0.6002 373.29 11.94 11.93 0.8004 393.03 17.98 18.00 0.6002 383.37 12.78 12.76 a u(x1) = 0.005 mole fraction; bu(T) = 0.3 K; cu(P) = 0.02 MPa (combined uncertainties, considering operational and systematic errors)

In Figure 4 the experimental results in the form of a P-T diagram for the system CO2 + LCO are presented, using the synthetic-visual and non-visual methods. The vapor-liquid equilibrium data were described with Adachi-Lu-Sugie16 equation of state, with acentric factor for the alpha function and vdw1 mixing rule with one interaction parameter (kij). Quantitative agreement between our measured with thermodynamic model was achieved. Absolute Average Deviation in Pressure (AAD_P) was 2.5%. Similar representation of the measurements was also described by the Soave-Redlich-Kwong (7.5%) and PengRobinson (4.6%) EoS´s.


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P/MPa

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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7 5 3 1 230

280

330

380

430

480

530

580

T/K Figure 4. P−T diagram for system CO2 + LCO at five different compositions in mole fraction: x1 = 0.3992;

x1 = 0.4995;

x1 = 0.6002;

x1 = 0.6992;

= 0.10669 from Stryjek

x1 = 0.8004;

ALS EoS with kij

25,26

.

5. Conclusions The apparatus is capable of operating at temperatures up to 393 K and at pressures up to 30 MPa, in the whole concentration range. The performance of the cell and accuracy of the procedure were tested in the previous work27 for synthetic mixtures. Now, they are demonstrated for real mixtures from the petroleum industry with CO2. A series of new data was measured, at several temperatures, pressures and compositions, for the systems CO2 + condensate gas and CO2 + light crude oil. The agreement between visual and nonvisual synthetic methods was observed in average to be within 1.3 %. Further, non-visual method presents less operational uncertainty. Vapor-liquid equilibrium data were properly described using the Adachi-Lu-Sugie EoS with acentric factor for the alpha function and the classical van der Waals mixing rule (vdw1) with interaction parameter retrieved from the literature. It is demonstrated that measurements of density and atmospheric distillation curve of the samples (CG and LCO), and further proposed pseudo-components parameters with literature correlations can provide quantitative agreement of the phase envelope data when compared to the PVT measurements of the same real mixtures. The fractioning and characterization of the 13 ACS Paragon Plus Environment

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Page 14 of 22

samples were also important as a previous knowledge of the phase behavior to support the PVT experiments and accuracy. This is especially helpful for not translucent systems that is the case of petroleum samples. It can be verified that through accessible and inexpensive analyzes it is possible to characterize real oil samples aiming the description of PVT properties under the reservoir conditions. There are several works with a similar approach for crude oils in the literature, but, since they are real samples, the comparison of experimental data is difficult. By the other hand, it was not found phase equilibrium data for real samples of condensate gas with CO2 in the open literature, and thereby this work has provided a contribution in the field.

Acknowledgments Financial support provided by ANP (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis), CNPq (Conselho Nacional de Desenvolvimento Científico e Tecnológico), CAPES (Coordenação de Aperfeiçoamento de Pessoal de Nível Superior), and Petrobras is gratefully acknowledged. References (1)

Cooney, G.; Littlefield, J.; Marriott, J.; Skone, T. J. Evaluating the Climate Benefits of CO2 -Enhanced Oil Recovery Using Life Cycle Analysis. Environ. Sci. Technol. 2015, 49 (12), 7491-7500.

(2)

Asghari, K.; Al-Dliwe, A.; Mahinpey, N. Effect of Operational Parameters on Carbon Dioxide Storage Capacity in a Heterogeneous Oil Reservoir: A Case Study. Ind. Eng. Chem. Res. 2006, 45 (8), 2452-2456.

(3)

Gabrienko, A. A.; Martyanov, O. N.; Kazarian, S. G. Behavior of Asphaltenes in Crude Oil at High-Pressure CO2 Conditions: In Situ Attenuated Total Reflection−Fourier Transform Infrared Spectroscopic Imaging Study. Energy & Fuels 2016, 30, 4750-4757.

(4)

Fonseca, J. M. S.; Dohrn, R.; Peper, S.; Fonseca, J. M. S. High-Pressure FluidPhase Equilibria: Experimental Methods and Systems Investigated (2005-2008). Fluid Phase Equilib. 2011, 300, 1-69. 14 ACS Paragon Plus Environment

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(5)

Christov, M.; Dohrn, R. High-Pressure Fluid Phase Equilibria: Experimental Methods and Systems Investigated (1994-1999). Fluid Phase Equilib. 2002, 202 (1), 153-218.

(6)

Aladwani, H. A.; Riazi, M. R. Some Guidelines for Choosing a Characterization Method for Petroleum Fractions in Process Simulators. Chem. Eng. Res. Des. 2005, 83 (2), 160-166.

(7)

Pedersen, K. S..; Christensen, P. L. Phase Behavior of Petroleum Reservoir Fluids; CRC/Taylor & Francis, 2007.

(8)

Lee, B. I.; Kesler, M. G. A Generalized Thermodynamic Correlation Based on Three-Parameter Corresponding States. AIChE J. 1975, 21 (3), 510-527.

(9)

Edmister, W. C. Applied Hydrocarbon Thermodynamics, Part 4: Compressibility Factors and Equations of State. Pet. Refin. 1958, 37, 173-179.

(10) Riazi, M. R. Petroleum Fractions Characterization and Properties of, 1st ed.; Baltimore, 2005. (11) Riazi, M. R.; Daubert, T. E. Prediction of the Composition of Petroleum Fractions. Ind. Eng. Chem. Process Des. Dev. 1980, 19 (2), 289-294. (12) Reiter, A. M.; Wallek, T.; Mair-Zelenka, P.; Us Siebenhofer, M.; Reinberger, P. Characterization of Crude Oil by Real Component Surrogates. Energy & Fuels 2014, 28, 5565-5571. (13) Ahmed, T. Equations of State and PVT Analysis: Applications for Improved Reservoir Modeling, 1st ed.; Gulf Publishing Company, 2007. (14) Orr, F. M.; Jensen, C. M. Interpretation of Pressure-Composition Phase Diagrams for CO2/Crude-Oil Systems. Soc. Pet. Eng. J. 1984, 24 (5), 485-497. (15) Aasberg-Petersen, K.; Stenby, E. Prediction of Thermodynamic Properties of Oil and Gas Condensate Mixtures. Ind. Eng. Chem. Res. 1991, 30 (1), 248-254. (16) Adachi, Y.; Lu, B. C. Y.; Sugie, H. Three-Parameter Equations of State. Fluid Phase Equilibr. 1983, 13, 133-142. (17) Sun, C.-Y.; Liu, H.; Yan, K.-L.; Ma, Q.-L.; Liu, B.; Chen, G.-J.; Xiao, X.-J.; Wang, H.-Y.; Zheng, X.-T.; Li, S. Experiments and Modeling of Volumetric Properties 15 ACS Paragon Plus Environment

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and Phase Behavior for Condensate Gas under Ultra-High-Pressure Conditions. Ind. Eng. Chem. Res. 2012, 51 (19), 6916-6925. (18) Shariati, A.; Straver, E. J. M.; Florusse, L. J.; Peters, C. J. Experimental Phase Behavior Study of a Five-Component Model Gas Condensate. Fluid Phase Equilib. 2014, 362 (0), 147-150. (19) Lucas, M. A.; Borges, G. R.; da Rocha, I. C. C.; Santos, A. F.; Franceschi, E.; Dariva, C. Use of Real Crude Oil Fractions to Describe the High Pressure Phase Behavior of Crude Oil in Carbon Dioxide. J. Supercrit. Fluids 2016, 118, 140-147. (20) Jaubert, J.-N.; Avaullee, L.; Souvay, J.-F. A Crude Oil Data Bank Containing More than 5000 PVT and Gas Injection Data. J. Pet. Sci. Eng. 2002, 34 (1), 65-107. (21) Cao, M.; Gu, Y. Temperature Effects on the Phase Behaviour, Mutual Interactions and Oil Recovery of a Light Crude oil–CO2 System. Fluid Phase Equilib. 2013, 356, 78-89. (22) Varzandeh, F.; Stenby, E. H.; Yan, W. General Approach to Characterizing Reservoir Fluids for EoS Models Using a Large PVT Database. Fluid Phase Equilib. 2017, 433, 97-111. (23) Su, Z.; Tang, Y.; Ruan, H.; Wang, Y.; Wei, X. Experimental and Modeling Study of CO2 - Improved Gas Recovery in Gas Condensate Reservoir. Petroleum 2017, 3 (1), 87-95. (24) Satyro, M. A.; Yarranton, H. Oil Characterization from Simulation of Experimental Distillation Data. Energy & Fuels 2009, 23 (8), 3960-3970. (25)

Stryjek, R.; Vera, J. H. PRSV. An Improved Peng - Robinson Equation of State for Pure Compounds and Mixtures. Can. J. Chem. Eng. 1986, 64, 323-333.

(26) Proust, P.; Vera, J. H. PRSV: The Stryjek-Vera Modification of the Peng-Robinson Equation of State. Parameters for Other Pure Compounds of Industrial Interest. 1989; 67, 170-173. (27) Ferreira, F. A. V.; Barbalho, T. C. S.; Oliveira, H. N. M.; Chiavone-Filho, O. Vapor–Liquid Equilibrium Measurements for Carbon Dioxide + Cyclohexene + Squalane at High Pressures Using a Synthetic Method. J. Chem. Eng. Data 2017, 62 (4), 1456-1463. 16 ACS Paragon Plus Environment

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(28) Guerra-Neto, D. B.; Ferreira-Pinto, L.; Giufrida, W. M.; Zabaloy, M. S.; CardozoFilho, L.; Chiavone-Filho, O. Bubble Point Determination for CO2 + Ethanol + Alkanolamines (Monoethanolamine, Diethanolamine, or Triethanolamine) at High Pressures. J. Chem. Eng. Data 2014, 59 (11), 3319-3323.


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Graphics for manuscript

F6

875 845 F5

815

ρ/kg.m-3

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F4

785 F3

755 F3

725

F4

F5

F6

F2

CG LCO

F2 F1

F1

695 330

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Figure 1. Density of condensate gas and light crude oil fractions at 293.15 K vs bubble point temperature of the fractions coming from atmospheric distillation.

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0 0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

x1, y1

Figure 2. P-x-y diagram for the binary system CO2 + condensate gas at five different temperatures:

353.15 K;

363.15 K;

373.15 K;

383.15 K;

ALS EoS with kij = 0.10691 from Stryjek24,25.


393.15 K;

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170

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V/cm3

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150

140

130

120 6

7

8

P/MPa

9

10

11

Figure 3. Depressurization behavior for the system CO2 + CG with mole fraction of CO2 of 0.7001 at four different temperatures:

322.95 K;

333.25 K;

K.


343.25 K;

353.35

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P/MPa

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Figure 4. P−T diagram for system CO2 + Oil fractions at five different compositions in mole fraction:

x1 = 0.3992;

0.8004;

x1 = 0.4995;

x1 = 0.6002;

x1 = 0.6992;

ALS EoS with kij = 0.10669 from Stryjek24,25.


x1 =

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Abstract graphic 15.0

x1=0.3997 x1=0.5003

13.0

x1=0.6008

x1=0.7998

11.0

ALS EoS

P/MPa

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9.0

7.0

5.0

3.0

1.0 230

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Abstract Graphic - P−T diagram for system CO2 + Condensate Gas at four different compositions in mole fraction.


Characterization, PVT properties and phase behavior of a condensate

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