SPE 166097

High Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of GoM Oil Mixed with Nitrogen Odd Steve Hustad, Statoil ASA / NTNU, Na Jenna Jia, Schlumberger DBR Technology Center, Karen Schou Pedersen, Calsep A/S, Afzal Memon, Schlumberger DBR Technology Center, Sukit Leekumjorn, Calsep Inc

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September2 October 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Pet roleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract This paper presents high pressure PVT measurements and equation-of-state (EoS) modeling results for a GoM oil and for the oil mixed with nitrogen in various concentrations. The data includes:

1. Upper and lower asphaltene onset pressures and bubble point pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94C (201.2F) asphaltene precipitation is seen after addition of 27 mole % of nitrogen.

2. Viscosity data for the swelled fluids showing that addition of nitrogen significantly reduces the oil viscosity. 3. Slim tube runs indicating that the minimum miscibility pressure of the oil with nitrogen is significantly higher than estimated

from published correlations. The data has been modeled using the volume corrected Soave-Redlich-Kwong (SRK) and the Perturbed-Chain Statistical Association Fluid Theory (PC-SAFT) EoS. While both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid phase compressibility of the reservoir fluid swelled with nitrogen.

Nitrogen gas flooding is expected to have a positive impact on oil recovery due to its favorable oil viscosity reduction and phase behavior effects. Introduction Oil exploration is going into regions of more extreme conditions and large oil deposits (0.3 to 4 billion BOE) are discovered in deepwater (~2,000 m / 6,500 ft) Gulf of Mexico (GoM). Many of these deepwater reservoirs were formed during the Paleogene geological period (lower Tertiary) and are posing a significant challenge to exploit. These reservoirs are found at approximately 8,000 m (26,000 ft) true vertical depth (TVD) and consists of Turbidite deposits under-laying thick salt deposits. The salt deposits pose significant challenges for seismic interpretation. The oils are highly undersaturated with low bubble point pressure (~17 MPa / ~2,500 psia) and fairly reasonable temperatures (~100C / 212F). Undersaturated oils have little expansion energy. Characteristic for these reservoirs are also their low permeability (1 30 mD). The high initial pressures (125 to 175 MPa / 18,000 to 25,000 psia) in these reservoirs make it necessary with a primary production by pressure depletion. However, producing these reserves by pressure depletion will only result in recovery factors in the range of 6 to 12%. These low recoveries with large in-place oil volumes give incentives to investigate alternative drainage strategies to obtain an Increased Oil Recovery (IOR). Water or gas injection processes are traditional IOR processes. However, making these processes profitable presents some challenges. High cost wells (> 350 million USD per well) limits the number of wells that can be drilled for

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a particular reservoir. Injectivity in low permeable formations may hinder getting injection fluids into the reservoir. This is more severe for water than for gas, especially when the displacement distances are taken into consideration. For these highly undersaturated reservoirs gas injection may lead to asphaltene precipitation in the reservoir. Understanding these phenomena and enabling appropriate forecasts of the impact of the gas injection is highly challenging. The extreme conditions present other technical challenges, which need to be overcome.1 The well technologies and reservoir technologies all have their specific technical challenges. The DeepStar technology development project, managed by Chevron and supported by several operators, is a forum for advancing deepwater technologies.2 It is highly desirable to have the capability to perform high pressure measurements and it is important that results from such measurements are made available to the oil community. Gas injection is a proven IOR process that can be economical and increase oil recovery. Gas injection will make the reservoir fluid swell and will therefore help maintain the reservoir pressure and prolong the production rates. Gas injection may however cause asphaltene precipitation and its impact to reservoir dynamics needs to be better understood. Asphaltene precipitation phenomena have been studied by many authors.3-9 Presented below are results from a phase behavior study on GoM oil at high pressure. The oil has been mixed with varying amounts of nitrogen and its properties measured. Fluid compositions, asphaltene onset and disappearance pressures are presented along with constant mass expansion (CME) results, oil viscosities and slim tube measurements. The results show that two liquid phases are formed prior to asphaltene precipitation and the emergence of a gas phase at 94 MPa. The oil viscosity is reduced by a factor two during the swelling process. The minimum miscibility pressure is significantly higher than results obtained from correlations in the literature.10-13 Phase equilibrium modeling of the measured data is presented using the Soave-Redlich-Kwong14 (SRK) EoS and the PC-SAFT15 EoS. The established EoS models were able to reproduce the measured data. The PC-SAFT EoS is slightly superior to the SRK EoS. Phase Behavior Measurements In depth studies are required to understand the possible outcome of gas injection into low permeable Turbidite formations in high pressure GoM reservoirs. The first step in this study is to map the phase behavior properties of the selected oil when mixed with nitrogen gas and to validate the measurements by modeling the data. In this study nitrogen (N2) is used as injection gas. The phase behavior studies are at high pressures (94 MPa) for varying concentrations of N2. A similar study has been conducted by Gonzalez et al.3 where variations in pressure and temperature were the main focus. A TBP distillation was performed on the Stock Tank Oil (STO) sample to obtain data for the molar concentration, molecular weight and density of the heavy components of the oil. The results are listed in Table 1. The STO was recombined with a synthetic gas to obtain single phase reservoir oil, the compositions and properties of which are shown in Table 2. Titration at 94 MPa and 94C was conducted with N2 to obtain the Asphaltene Onset Concentration (AOC). During the N2 titration test an unknown second liquid phase appeared at 24 26 mol% nitrogen added. The second liquid phase seemed to have similar density as the first liquid phase. Asphaltene precipitation was observed at 26 to 28 mol% nitrogen added. Figure 1 shows pictures taken from a High Pressure Microscope (HPM) at two conditions with 26 and 28 mol% added nitrogen. A Solid Detection System (SDS) analysis was also performed to confirm the visual results. Table 3 presents the phase volumes from the swelling of the oil with nitrogen. The oil volume is increased by 12% prior to asphaltene precipitation (~28 mol% N2 added) at 94 MPa and 94C. Four additional fluid mixtures were created with varying amounts of nitrogen. The original recombined oil (labeled M0) had a nitrogen concentration of 0.121 mol%. The first three of the additional samples contained respectively 8.853 (M1), 17.244 (M2), and 25.925 (M3) overall mol% of N2. The last M4 mixture, with 67 mol% overall N2 concentration, split into two phases at 94 MPa and 94C where the vapor and liquid nitrogen mol% were 79.937 and 38.231 respectively.

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The asphaltene onset pressure (AOP), saturation pressure and asphaltene disappearance pressure (ADP) were measured for these fluid systems and are summarized in Figure 2 and Table 4. The AOP increases approximately linearly with increasing nitrogen concentration. The ADP is low as compared to the saturation point and first decreases and then increases as the overall nitrogen content increases. Once the gas concentration in the oil gets below a limiting value at ADP, due to pressure reduction, the asphaltene will redissolve. Redissolution of asphaltene generally takes some time. In the experiments with precipitated asphaltene (Mixtures M1, M2 and M3), enough time was probably not taken for complete equilibrium to be reached. Thus, a probable explanation for the observed decrease in ADP may be kinetic effects.

Fig. 1 - HPM pictures of a) second liquid phase with 26 mol% added N2 and b) asphaltene precipitation with 28 mol%

added N2

Fig. 2 - p-x phase envelope for reservoir fluid swelled with nitrogen at 94C Constant Mass Expansion (CME) experiments were performed for four of the five mixtures. The results are illustrated in Figure 3. The following was observed:

a. The relative volume curves become less abrupt at the saturation pressure as the concentration of nitrogen increases. This is due to the oil becoming more volatile.

b. Above the saturation pressure the oil density increases almost linearly with pressure and the linear trend becomes more pronounced as the concentration of nitrogen increases.

c. The slope of the Y-factor is similar for the M0, M1 and M2 mixtures, but is different for M3, which is a mixture close to the AOC at 94 MPa. More asphaltene is precipitated for this mixture affecting the measured volumes below the saturation pressure.

d. The compressibility pattern for the recombined reservoir fluid deviates from that seen for the fluids with added nitrogen (M1, M2 and M3). The slopes of the compressibilities for the latter three mixtures are fairly similar.

The oil viscosity was measured with an electromagnetic viscometer (EMV), model SPL440. As can be seen from Table 5 and Figure 4 the oil viscosity as a result of the N2 swelling dropped to half its original value. Once an equilibrium vapor phase was formed, the equilibrium oil viscosity increased to a value slightly above its original value. This is explained by lighter and intermediate components from the oil phase entering into the nitrogen rich equilibrium vapor phase. At 94 MPa the oil viscosity changes linearly with nitrogen concentration during the swelling process.

0

20

40

60

80

100

120

140

0 10 20 30 40 50 60 70

Pre

ssur

e (M

Pa)

N2 Concentration (mol%)

Bubble Point PressureAOP (SDS+HPM)ADP (PVT+SDS+HPM)AOP (PVT+SDS+HPM)Trendline (Psat)Trendline (ADP)Trendline (AOP)

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The various mixtures of oil were flashed to standard conditions and the STOs Refractive Indices (RI) were measured. The results are listed in Tables 6 and 7. This data can possibly be applied with the ASIST method for asphaltene analysis.4 An attempt was made to experimentally determine the minimum miscibility pressure (MMP). The MMP was not reached at the maximum operation pressure of 69 MPa. The runs at 94 C were conducted at 45, 55 and 68.4 MPa with oil recoveries of 70%, 75.5% and 83.2% respectively as can be seen from Table 8. Figure 5 illustrates the slim tube results and an extrapolation line is added to the data indicating that the MMP is significantly higher. The indications are that the MMP value may be above 94 MPa. This value is almost twice the value that may be obtained from correlations in the literature.10-13

Fig. 3 - CME result at 94C for reservoir fluid with varying nitrogen concentrations

Fig. 4 Oil viscosity at 94C for reservoir fluid with varying nitrogen concentrations

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Fig. 5 Slim tube oil recoveries with N2 injection at 94C Data Evaluation The compositions from the TBP distillation and gas chromatography (GC) were compared. Figure 6 demonstrates that the GC data differs from the TBP distillation data. The C30+ weight % found in two TBP tests agrees well with each other. However, C30+ weight % from GC analysis is 35.61 while the average C30+ weight % from TBP analyses is 40.42. The GC and TBP distillation are two different processes for compositional analyses and both methods have some limitations. The TBP analysis result is influenced by the carry-over of components from one carbon-number range to another range, temperature control and losses (especially light ends). The GC analysis results are influenced by the sample preparation issues, GC procedure and possible loss of heavy ends in the GC column. Moreover, the mol% results are found from the weight % composition using published default molecular weights.16 Application of correct molecular weights for individual fractions in the characterization of models is essential when establishing the fluids molar composition. Weight % results are actual raw data from TBP and GC analyses and they should be used as such in tandem with correct molecular weights for the fluid that is being studied. For modeling purpose in this work, reliance was given to the TBP data. The C36+ molecular weight from TBP was 833.7. Figure 7 shows two extrapolated molecular weight curves representing C36+ molecular weights of 833.7 and 725. The later of these values seem to coincide better with the C7-C35 trend. A C36+ molecular weight of 808 was used in establishing the models based on adjustment for a gas/oil ratio of 102.2 Scm3/Scm3 and a STO density of 0.88 g/cm3. The reservoir fluid composition when recombining GC analysis and TBP analysis is shown in Table 9.

Fig. 6 Boiling point data for stabilized oil

Fig. 7 Extrapolated C36+ molar distribution assuming

C36+ molecular weights of 833.7 and 725 Phase Behavior Modeling One of the objectives of the experimental program was to establish EoS models describing the experimental data. This would be a requirement to perform compositional reservoir simulation studies of the impact of gas injection. Three EoS models have been established based on the measured data:

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22 component PC-SAFT Model15 22 component SRK-Peneloux EoS Model14,17 Nine component SRK-Peneloux EoS Model

The PC-SAFT EoS model parameters were found using the characterization procedure presented by Pedersen et al.18 The characterization procedure of Pedersen et al.19 was used to find the SRK model parameters and the associated volume corrections. The model parameters are listed in Tables 10, 11 and 12. The last component in each of these models represents the asphaltene components, which are assumed to be in the C50+ aromatic fraction.20 Figure 8 illustrates how well the EoS models reproduce the p-x phase envelope data. As may be seen the saturation pressure and AOP are represented fairly well. However, the simulated ADPs are higher than the measured values. The ADP is primarily determined by the gas concentration in the liquid phase. Asphaltenes will redissolve when the gas concentration is below a limiting value, which is almost constant with pressure. The data suggests that the gas concentration in the liquid phase at the ADP should be lower when more N2 was added to the total mixture. The reason is rather that there is more asphaltene to redissolve when higher N2 amounts were added, i.e. the low ADPs seen when more N2 is added may be due to kinetic effects and simply show that the asphaltene may require longer time to redissolve in the oil than the two hours allocated in the experimental procedure.

(a) 22 Comp PC-SAFT EoS (b) 22 Comp SRK-P EoS (c) 9 Comp SRK-P EoS Fig. 8 Experimental and simulated phase envelopes for reservoir fluid swelled with N2 at 94C Figure 9 shows experimental and simulated CME density data for the fluid mixtures M0, M1, M2 and M3 using the 22 component PC-SAFT and SRK-Peneloux models. The oil density of the reservoir fluid is matched very well while the simulated densities are up to 1.5% higher than the experimental values for the mixtures with nitrogen. Figure 10 shows experimental and simulated oil compressibilities. Figure 10a is for the reservoir fluid, for which the SRK equation provides a better match at the higher pressures while the PC-SAFT performs better at the lower pressures. As the nitrogen content is increased the PC-SAFT model becomes superior to SRK at all pressures. The compressibilities may play an important role when evaluating gas injection. A more compressible fluid will keep the pressure higher when the field is produced than a less compressible fluid. Since three phases are present between the saturation pressure and the ADP, the CME simulations were carried out using a multiflash algorithm21,22 and the simulated oil densities and compressibilities are weighted averages between the oil and the asphaltene phases. Figure 11 shows experimental and simulated Y-factors. The Y-factor is defined as

1

1

sat

tot

sat

sat

sattot

sat

VV

pp

VVV

ppp

factorY (1)

and experimentally determined from the absolute measured volumes. Near the saturation point the measured volumes of the disappearing phase are small and this may partly explain the deviations seen between the simulated and experimental Y-factors.

SPE 166097 7

(a) Recombined oil (M0) (b) Fluid mixture M1

(c) Fluid mixture M2 (d) Fluid mixture M3 Fig. 9 Experimental and simulated CME oil densities at 94C with 22 component PC-SAFT and SRK EoS

(a) Recombined oil (M0) (b) Fluid mixture M1

(c) Fluid mixture M2 (d) Fluid mixture M3 Fig. 10 Experimental and simulated CME oil compressibilities at 94C with 22 component PC-SAFT and SRK EoS

8 SPE 166097

(a) Recombined oil (M0) (b) Fluid mixture M1

(c) Fluid mixture M2 (d) Fluid mixture M3 Fig. 11 Experimental and simulated CME oil Y-factors at 94C with 22 component PC-SAFT and SRK EoS The principle of corresponding states (CSP)20 resulted in good match of the oil viscosities as shown in Table 5. No tuning of the model parameters to the experimental data was conducted. Conclusions Compositional data and PVT data are presented for a GoM reservoir fluid. A TBP analysis was performed to ensure a good compositional description of the heavy end components. The PVT data includes measured upper and lower asphaltene onset pressures for the reservoir fluid swelled with nitrogen and CME data for the swelled fluids. The results indicate:

1. The asphaltene upper envelope increases almost linearly with increasing nitrogen concentration. 2. The asphaltene lower envelope is lower than what is modeled and does not behave as expected with increase in nitrogen

concentration, which may be due to kinetic effects. 3. During the oil titration with nitrogen a second liquid phase appeared between the M2 and M3 mixture compositions and

prior to asphaltene precipitation at 94 MPa and 94C. 4. The oil viscosity was reduced to half its original value before reaching the asphaltene nitrogen onset concentration at 94

MPa and 94C. The PC-SAFT and SRK EoS performed well in representing the p-x phase envelope and the asphaltene upper onset pressure. The lower asphaltene envelope may have some kinetic issues influencing the results. The PC-SAFT EoS was superior to the SRK EoS in representing the oil compressibility with high concentrations of nitrogen.

Nomenclature

SPE 166097 9

Symbols p Pressure psat Saturation Pressure T Temperature

Vsat Volume at saturation pressure Vtot Total Volume zi Overall mole % of component i

Acronyms AOC Asphaltene Onset Concentration ADP Asphaltene Disappearance Pressure AOP Asphaltene Onset Pressure API American Petroleum Institute BOE Barrel of Oil Equivalent CME Constant Mass Expansion CSP Corresponding States Principle EMV Electromagnetic Viscometer EoS Equation of State GC Gas Chromatography GoM Gulf of Mexico GOR Gas/Oil Ratio (scf/STB or Scm3/Scm3) HPM High Pressure Microscope

IOR Increased Oil Recovery MW Molecular Weight PVI Pore Volume Injected PVT Pressure-Volume-Temperature RF Recombined Reservoir Fluid RI Refractive Index scf Standard cubic feet (ft3) SDS Solid Detection System STO Stock Tank Oil STB Stock Tank Barrels STP Standard Temperature and Pressure (T= 15.6

C or 60 F; p= 1.013 bar or 14.696 psia)

Acknowledgement Statoil is acknowledged for the permission to publish these results and for the financial support. Saybolt/CoreLab, The Netherlands, and CanMet, Edmonton Canada, are acknowledged for conducting the TBP distillation analysis. Acknowledgement is given to Donavon Robinson and Michael Rudneski for performing a majority of the PVT, asphaltene and slim tube measurements. References 1. Mazerov, K. 2012. HPHT Research Heats Up. Drilling Contractor (July/August). 2. Grecco, M. 2007. DeepStar: 15 Years of Collaboration between Contractors, Academia, and the Oil Companies on

Technology for Deep Water. Paper presented at the 2007 Offshore Technology Conference, Houston, 30 April 3 May. Doi: 10.4043/11511-MS.

3. Gonzalez, D. L., Mahmoodaghdam, E., Lim, F., Joshi, N. 2012. Effects of Gas Additions to Deepwater Gulf of Mexico Reservoir Oil: Experimental Investigation of Asphaltene Precipitation and Deposition. Paper SPE 159098 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, 8-10 Oct.

4. Buckley, J. S., Wang, J. and Creek, J. L. 2007. Solubility of the Least-Soluble Asphaltenes. Asphaltenes, Heavy Oil, and Petroleomics. O.C. Mullins, E.Y. Sheu, A. Hammami and A.G. Marshall Editors, Springer, New York.

5. Srivastava, R. K., Huang, S. S. and Dong, M. 1999. Asphaltene Deposition during CO2 Flooding. SPE Production & Facilities 14 (4): 235-245. SPE-59092-PA. Doi: 10.2118/59092-PA.

6. Jamaluddin, A. K. M. et al. 2002. Laboratory Techniques to Measure Thermodynamic Asphaltene Instability. Journal of Canadian Petroleum Technology 41 (7): 44-52. Doi: 10.2118/01-07-04.

7. Jamaluddin, A. K. M., Joshi, N., Iwere, F. and Gurpinar, O. 2002. An Investigation of Asphaltene Instability under Nitrogen Injection. Paper SPE 74393 presented at the SPE International Petroleum Conference and Exhibition in Mexico, Villahermosa, 10-12 February. Doi: 10.2118/74393-MS.

8. Lim, F. et al. 2008. Design and Initial Results of EOR and Flow Assurance Laboratory Fluid Testing for K2 Field Development in the Deepwater Gulf of Mexico. Paper OTC 19624 presented at the 2008 Offshore Technology Conference, Houston, 5-8 May.

9. Memon, A. et al. 2012. Miscible Gas Injection and Asphaltene Flow Assurance Fluid Characterization: A Laboratory Case Study for Black Oil Reservoir. Paper presented at the SPE EOR Conference of Oil and Gas West Asia, Muscat, Oman, 16-18 April. Doi: 10.2118/150938-MS.

10. Glas, . 1990. Miscible Displacement: Recovery Test with Nitrogen. SPE Reservoir Engineering 5 (1): 61-68. Doi: 10.2118/17378-PA.

11. Hudgins, D. A., Llave, F. M. and Chung, F. T. H. 1990. Nitrogen Miscible Displacement of Light Crude Oil: A Laboratory Study. SPE Reservoir Engineering 5 (1): 100-106. Doi: 10.2118/17372-PA.

10 SPE 166097

12. Hanssen, J. E. 1988. Nitrogen as a Low-Cost Replacement for Natural Gas Reinjection Offshore. Paper SPE 17709 presented at the SPE Gas Technology Symposium, Dallas, 13-15 June.

13. Sebastian, H. M. and Lawrence, D. D., 1992. Nitrogen Minimum Miscibility Pressure. Paper SPE/DOE 24134 presented at the SPE/DOE Eighth Symposium on Enhanced Oil Recovery, Tulsa, 22-24 April.

14. Soave, G. 1972. Equilibrium Constants from a Modified Redlich-Kwong Equation of State. Chem. Eng. Sci., Vol. 27, 1198-1203.

15. Gross, J. and Sadowski, G. 2001. Perturbed-Chain SAFT: An Equation of State Based on a Perturbation Theory for Chain Molecules. Ind. Eng. Chem. Res. 40 (4): 1244-1260. Doi: 10.1021/ie0003887.

16. Katz, D. L. and Firoozabadi, A. 1978. Predicting Phase Behavior of Condensate/Crude-Oil Systems Using Methane Interaction Coefficients. JPT 30 (11): 1649-1655. Doi: 10.2118/6721-PA.

17. Peneloux, A., Rauzy, E. and Frze, R. 1982. A Consistent Correction for Redlich-Kwong-Soave Volumes. Fluid Phase Equilibria 8 (7).

18. Pedersen, K. S., Leekumjorn, S., Krejbjerg, K. and Azeem, J. 2012. Modeling of EOR PVT Data using PC-SAFT equation. Paper presented at the Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, UAE, 11-14 November. Doi: 10.2118/162346-PP

19. Pedersen, K. S., Blilie, A. L. and Meisingset, K. K. 1992. PVT-Calculations on Petroleum Reservoir Fluids Using Measured and Estimated Compositional Data for the Plus-Fraction. Ind. Eng. Chem. Res. 31, 1378.

20. Pedersen, K. S., and Christensen, P. L. 2007. Phase Behavior of Petroleum Reservoir Fluids. CRC Press, Taylor & Francis Group, Boca Raton FL 33487-2742. ISBN 0-8247-0694-3.

21. Michelsen, M. L. 1981. The Isothermal Flash Problem. Part I. Stability. Fluid Phase Equilibria 9 (1). 22. Michelsen, M. L. 1981. The Isothermal Flash Problem. Part II. Phase Split Calculations. Fluid Phase Equilibria 9 (21).

Table 1. Distillation Data on Stock Tank Oil

TBP Cut (C)

Density at 15 C

(g/cm3)

Weight (%)

Cumulative Weight %

Volume (%)

Cumulative % Volume

Loss 0.22 0.22

C4 Minus 0.5527 0.38 0.60 0.61 0.83

C5-36.6 0.6225 0.88 1.48 1.24 2.07

36.6-69.3 0.6677 1.62 3.10 2.14 4.21

69.3-98.9 0.7170 3.07 6.17 3.77 7.98

98.9-126.2 0.7408 3.73 9.90 4.44 12.42

126.2-151.3 0.7617 3.59 13.49 4.16 16.58

151.3-196.4 0.7852 6.78 20.27 7.61 24.19

196.4-254.0 0.8154 8.55 28.82 9.25 33.44

254.0-302.8 0.8461 8.74 37.56 9.11 42.55

302.8-344.4 0.8645 6.94 44.50 7.08 49.63

344.4+ 0.9692 55.50 100.00 50.49 100.12

344.4-402.2 0.8884 7.99 52.49 7.93 57.56

402.2-450.0 0.9035 5.32 57.81 5.19 62.75

450.0-490.6 0.9240 6.87 64.67 6.55 69.30

490.6+ 1.0093 35.33 100.00 30.86 100.16

STO (ASTM D 1298)

0.8817 - - - -

STO API Gravity 28.89 - - - -

Table 2a. Composition Analysis of Recombined Reservoir Fluid Component

MW (g/mol)

Flashed Gas Flashed Oil Monophasic Fluid (Wt%) (Mole %) (Wt%) (Mole %) (Wt%) (Mole %)

CO2 44.01 0.205 0.121 0.000 0.000 0.023 0.065

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H2S 34.08 0.000 0.000 0.000 0.000 0.000 0.000

N2 28.01 0.243 0.225 0.000 0.000 0.027 0.121

C1 16.04 42.661 68.963 0.000 0.000 4.818 37.091

C2 30.07 11.507 9.924 0.000 0.000 1.300 5.338

C3 44.1 16.609 9.769 0.178 0.959 2.034 5.697

i-C4 58.12 2.972 1.326 0.072 0.293 0.399 0.849

n-C4 58.12 10.461 4.668 0.414 1.687 1.548 3.290

i-C5 72.15 3.700 1.330 0.396 1.300 0.769 1.316

n-C5 72.15 4.436 1.595 0.667 2.191 1.093 1.870

C6 84 3.488 1.077 1.633 4.608 1.842 2.709

Mcyclo-C5 84.16 0.505 0.156 0.369 1.041 0.385 0.565

Benzene 78.11 0.060 0.020 0.052 0.157 0.053 0.083

Cyclo-C6 84.16 0.400 0.123 0.330 0.929 0.338 0.496

C7 96 1.350 0.365 2.248 5.550 2.146 2.761

Mcyclo-C6 98.19 0.412 0.109 0.825 1.992 0.778 0.979

Toluene 92.14 0.094 0.026 0.237 0.610 0.221 0.296

C8 107 0.479 0.116 2.963 6.564 2.682 3.096

C2-Benzene 106.17 0.027 0.007 0.187 0.417 0.169 0.196

m&p-Xylene 106.17 0.018 0.004 0.392 0.876 0.350 0.407

o-Xylene 106.17 0.012 0.003 0.177 0.395 0.158 0.184

C9 121 0.248 0.053 2.860 5.604 2.565 2.618

C10 134 0.091 0.018 3.814 6.748 3.394 3.128

C11 147 0.017 0.003 3.355 5.410 2.978 2.502

C12 161 0.004 0.001 3.109 4.577 2.758 2.116

C13 175 0.001 0.000 3.335 4.517 2.958 2.088

C14 190 0.001 0.000 3.074 3.835 2.727 1.773

C15 206 0.000 0.000 3.234 3.721 2.868 1.720

C16 222 0.000 0.000 2.814 3.005 2.496 1.389

C17 237 0.000 0.000 2.764 2.764 2.451 1.278

C18 251 0.000 0.000 2.743 2.591 2.434 1.198

C19 263 0.000 0.000 2.641 2.380 2.342 1.100

C20 275 0.000 0.000 2.336 2.014 2.072 0.931

C21 291 0.000 0.000 2.245 1.829 1.991 0.845

C22 305 0.000 0.000 2.122 1.649 1.882 0.762

C23 318 0.000 0.000 2.015 1.502 1.788 0.694

C24 331 0.000 0.000 1.921 1.376 1.704 0.636

C25 345 0.000 0.000 1.823 1.253 1.617 0.579

C26 359 0.000 0.000 1.790 1.182 1.588 0.546

C27 374 0.000 0.000 1.758 1.115 1.560 0.515

C28 388 0.000 0.000 1.743 1.065 1.546 0.492

C29 402 0.000 0.000 1.758 1.037 1.560 0.479

C30+ 750 0.000 0.000 35.610 11.256 31.588 5.202

Calculated MW (g/mol)

25.9 237.1 123.5

Mole Percent 53.78 46.22 Table 2b. Property of Recombined Reservoir Fluid STO Properties at Standard Condition

Measured Calculated C30+

Properties MW 237 750

Density (g/cc) 0.880 0.880 1.034

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Single Stage Flash Data GOR (Scm3/Scm3) 102.3

STO Density (g/cm3) 0.880

STO API Gravity 29.1

Mass Balance Error (wt%) 0.56

Properties Flashed Gas Flashed Oil Monophasic Mole %

C 7+ 0.70 86.84 40.51

C10+ 0.02 64.83 29.97

C12+ 0.00 52.67 24.34

C20+ 0.00 25.28 11.68

C30+ 0.00 11.26 5.20

Weight %

C 7+ 2.75 95.89 85.37

C10+ 0.11 86.00 76.30

C12+ 0.01 78.83 69.93

C20+ 0.00 55.12 48.90

C30+ 0.00 35.61 31.59

Molar Mass

C 7+ 101.34 261.79 260.29

C10+ 137.05 314.51 314.44

C12+ 167.42 354.84 354.83

C20+ 516.97 516.97

C30+ 750.00 750.00

Density (g/cc)

C 7+ 0.745 0.893 0.893

C10+ 0.781 0.912 0.912

C12+ 0.805 0.926 0.926

C20+ 0.974 0.974

C30+ 1.034 1.034

Fluid Density at STP Condition (g/cm3)

0.880

Gas Gravity (Air=1) 0.896

Dry Gross Heating Content (Btu/scf)

1538

Wet Gross Heating Content (Btu/scf)

1512

SPE 166097 13

Table 3. Volume vs. N2 Injection Concentration at 94 MPa and 94C Step No.

N2 Overall Conc. (mol%)

Total Volume (cm3)

Liquid Volume (cm3)

Vapor Volume (cm3)

1 0 40.357 40.357 -

2 10 41.515 41.515 -

3 20 43.084 43.084 -

4 30 45.715 45.715 -

5 35 47.125 47.125 -

6 40 49.067 45.417 3.650

7 45 50.993 44.098 6.895 Table 4. AOP, Saturation Pressure and ADP at 94C Fluid Mixture

Added N2 (mol%)a

Psat (MPa)b

AOP (MPa)c

ADP (MPa)d

M0 0 17.59 - -

M1 9 29.99 41.37 13.79

M2 18 46.20 75.77 6.89

M3 27 68.02 94.00 4.14

M4 67 - - 13.79 a Added mol% per (100% - added mol% N2) reservoir fluid b Measured by PVT cell cAOP measured by SDS and HPM systems dAOP/ADP measured by PVT c ell equipped w ith SDS and HPM systems

Table 5. Experimental and Simulated Viscosity Measurement (cP) at 94C Fluid Mixture

Experimental Pressure (MPa) SRK-P (CSP Model) Pressure (MPa) PC-SAFT (CSP Model) Pressure (MPa) 103.4 94 84 103.4 94 84 103.4 94 84

M0 2.026 1.865 1.706 2.179 2.053 1.916 2.031 1.912 1.912

M1 1.712 1.573 1.451 1.844 1.734 1.614 1.652 1.548 1.436

M2 1.407 1.295 1.194 1.461 1.369 1.270 1.242 1.171 1.096

M3 1.101 1.025 0.960 1.130 1.069 1.004 1.016 0.939 0.855

Fluid Mixture Pressure (MPa)

103.4 96.5 94 Eq. oil of M4 at 94 MPa

2.075 1.952 1.908

Table 6. Refractive Index of STO at 40C Solvent M0 M1 M2 M3 M4 No solvent

1.4795 1.4798 1.4800 1.4799 1.4796

C7 1.4383 1.4367 1.4361 1.4472 1.4405

C11 1.4523 1.4480 1.4484 1.4553 1.4499

C15 1.4625 1.4571 1.4539 1.4618 1.4571

Table 7. Asphaltene Onset Concentration (Oil Vol% / Solvent

14 SPE 166097

Vol%) of Stock Tank Oils for Different Solvents at 40C Solvent M0 M1 M2 M3 M4 C7 69 / 31 69 / 31 69 / 31 69 / 31 59 /41

C11 68 / 32 69 / 31 68 / 32 70 / 30 62 / 38

C15 79 / 21 78 / 22 79 / 21 72 / 28 65 / 35 Table 8. Oil Recovery (%) from Slim Tube Displacements at

Displacement Pressure and 94C Pressure (MPa)

1.0 PVI 1.2 PVI Material Balancea

Gas Breakthrough (PVI)

68.43 82.9 83.2 84.9 0.845

55 75.1 75.1 77.4 0.799

45 70.1 70.1 71.1 0.729 a Toulene rinsed ROS in slim tube with back calculation Table 9. Reservoir fluid composition generated by recombining GC

analysis flashed gas composition with TBP analysis in Table 1.

Component

Weight % Mole % Molecular Weight

Density (g/cm3)

N2 0.027 0.123

CO2 0.023 0.066

C1 4.823 37.769

C2 1.301 5.435

C3 2.064 5.88

iC4 0.336 0.726

nC4 1.520 3.285

iC5 0.418 0.728

nC5 1.282 2.232

C6 1.831 2.669

C7 2.985 4.025 92.9 0.7188

C8 3.420 4.029 106.6 0.7416

C9 3.219 3.355 120.5 0.7619

C10-C11 6.026 5.438 139.2 0.7852

C12-C14 7.584 5.444 175.0 0.8154

C15-C17 7.752 4.589 212.2 0.8461

C18-C20 6.155 3.038 254.5 0.8645

C21-C25 7.087 2.838 313.7 0.8884

C26-C30 4.718 1.694 350.0 0.9035

C31-C35 6.093 1.763 434.2 0.9240

C36+ 31.335 4.872 808 1.0093 Table 10. PC-SAFT EoS Parameters

Component zi (mol%) m (ngstrm) (K)

SPE 166097 15

N2 0.12 1.205 3.313 90.960

CO2 0.07 2.073 2.785 169.210

C1 37.77 1.000 3.704 150.030

C2 5.44 1.607 3.521 191.420

C3 5.88 2.002 3.618 208.110

iC4 0.73 2.262 3.757 216.530

nC4 3.28 2.332 3.709 222.880

iC5 0.73 2.562 3.830 230.750

nC5 2.23 2.690 3.773 231.200

C6 2.67 3.058 3.798 236.770

C7 4.02 3.114 3.790 249.483

C8 4.03 3.516 3.786 251.013

C9 3.36 3.929 3.783 252.492

C10-C11 5.44 4.480 3.778 254.375

C12-C14 5.44 5.544 3.772 256.256

C15-C17 4.59 6.593 3.769 260.434

C18-C20 3.04 7.821 3.768 262.374

C21-C25 2.84 9.484 3.770 266.129

C26-C30 1.69 10.457 3.771 269.291

C31-C49 3.31 14.767 3.775 275.595

C50-C80 2.56 28.648 3.597 247.386

C50-C80-A 0.76 11.000 4.530 500.000

Non-zero Binary Interaction Coefficients kij N2 CO2 C1- C9 CO2 -0.0315 C1 0.0278 0.12 C2 0.0407 0.12 C3 0.0763 0.12 iC4 0.0944 0.12 nC4 0.07 0.12 iC5 0.0867 0.12 nC5 0.0878 0.12 C6 0.08 0.12 C7 0.13 0.1 C8 0.13 0.1 C9 0.13 0.1 C10-C11 0.13 0.1 C12-C14 0.13 0.1 C15-C17 0.13 0.1 C18-C20 0.13 0.1 C21-C25 0.13 0.1 C26-C30 0.13 0.1 C31-C49 0.13 0.1 C50-C80 0.13 0.1 C50-C80-A 0.17 0.1 0.017

Table 11. 22 Component SRK-Peneloux EoS Parameters

Component zi

(mol%) Tc

(C) Pc

(MPa) Acentric Factor

Volume Correction

16 SPE 166097

(cm3/mol)

N2 0.12 146.950 3.394 0.0400 0.92

CO2 0.07 31.050 7.376 0.2250 3.03

C1 37.77 -82.550 4.600 0.0080 0.63

C2 5.44 32.250 4.884 0.0980 2.63

C3 5.88 96.650 4.246 0.1520 5.06

iC4 0.73 134.950 3.648 0.1760 7.29

nC4 3.28 152.050 3.800 0.1930 7.86

iC5 0.73 187.250 3.384 0.2270 10.93

nC5 2.23 196.450 3.374 0.2510 12.18

C6 2.67 234.250 2.969 0.2960 17.98

C7 4.02 254.641 3.168 0.4595 10.05

C8 4.03 278.352 2.819 0.4986 17.62

C9 3.36 300.277 2.555 0.5384 24.58

C10-C11 5.44 326.702 2.300 0.5908 32.17

C12-C14 5.44 369.652 1.969 0.6877 42.61

C15-C17 4.59 409.299 1.799 0.7834 43.96

C18-C20 3.04 447.802 1.644 0.8851 42.59

C21-C25 2.84 496.827 1.527 1.0142 29.98

C26-C30 1.69 525.114 1.492 1.0850 16.98

C31-C49 3.31 640.904 1.383 1.2935 -47.31

C50-C80 2.56 815.372 1.416 1.0274 -289.03

C50-C80-A 0.76 1069.410 1.435 1.2740 -289.03 Non-Zero Binary Interaction Coefficients kij N2 CO2 C1 - C9 CO2 -0.0315 C1 0.0278 0.12 C2 0.0407 0.12 C3 0.0763 0.12 iC4 0.0944 0.12 nC4 0.07 0.12 iC5 0.0867 0.12 nC5 0.0878 0.12 C6 0.08 0.12 C7 0.13 0.1 C8 0.13 0.1 C9 0.13 0.1 C10-C11 0.13 0.1 C12-C14 0.13 0.1 C15-C17 0.13 0.1 C18-C20 0.13 0.1 C21-C25 0.13 0.1 C26-C30 0.13 0.1 C31-C49 0.13 0.1 C50-C80 0.13 0.1 C50-C80-A 0.17 0.1 0.017

Table 12. Nine Component SRK-Peneloux EoS Parameters

SPE 166097 17

Component zi (mol%) Tc

(C) Pc

(MPa) Acentric Factor

Volume Correction (cm3/mol)

N2 0.123 -146.950 3.394 0.0400 0.92 C1 37.769 -82.550 4.600 0.0080 0.63 CO2+C2+C3 11.382 71.473 4.512 0.1318 3.89 C4-C6 9.641 192.223 3.374 0.2434 11.85 C7-C11 16.847 296.957 2.631 0.5348 22.63 C12-C20 13.071 406.335 1.814 0.7788 45.34 C21-C49 7.843 578.658 1.444 1.1758 3.27 C50-C80 2.558 815.372 1.410 1.0274 -289.03 C50-C80-A 0.765 1069.410 1.470 1.2740 -289.03 Non-Zero Binary Interaction Coefficients kij N2 C1 CO2+C2+C3 C1 0.0278 CO2+C2+C3 0.0587 0.0007 C4-C6 0.0800 0.0007 C7-C11 0.1300 0.0006 C12-C20 0.1300 0.0006 C21-C49 0.1300 0.0006 C50-C80 0.1300 0.0006 C50-C80-A 0.1700 0.0170 0.0006

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