SPE-169123-MS. Hydrocarbon and Non-hydrocarbon Gas Miscibility with Light Oil in Shale. Reservoirs. Tadesse Weldu Teklu, Najeeb Alharthy, Hossein ...
SPE-169123-MS Hydrocarbon and Non-hydrocarbon Gas Miscibility with Light Oil in Shale Reservoirs Tadesse Weldu Teklu, Najeeb Alharthy, Hossein Kazemi, Xiaolong Yin, Ramona M. Graves, Colorado School of Mines
Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 12–16 April 2014. 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 Petroleum 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 Miscible and immiscible hydrocarbon and non-hydrocarbon gas injection have been effective in enhancing oil recovery in conventional reservoirs. In unconventional shale reservoirs, gas injection could potentially improve oil recovery based on experimental observations of Hawthorne et al. (2013) for CO2. A theoretical study by Teklu et al. (2014) indicated that minimum miscibility pressure (MMP) of CO2 and NGL with unconventional reservoir oil could be several hundred psia lower than in conventional reservoirs because of the pore size difference. The reduction in MMP is attributed to a favorable shift in critical temperature and pressure of molecules. While miscibility is not critical in improved oil recovery in conventional reservoirs, it is critical in unconventional reservoirs. For instance, methane and nitrogen have been used in conventional reservoirs below MMP for gravity drainage IOR operations where miscibility is not required. If miscibility is required, methane and nitrogen MMP is too large for economic viability in most conventional reservoirs. On the other hand, methane and nitrogen injection could become viable injectants in unconventional reservoirs because of the lower MMP in confined space of unconventional reservoirs. Furthermore, CO2 MMP is much lower with light oils in very small nanopores, and CO2 swells oil; thus a great incentive to choose CO2 as the injection gas of choice. In this paper we review the current theory of the phase behavior for lowering MMP in nanopores and the relevance of low MMP to enhanced oil recovery in unconventional reservoirs. Critical pressure and critical temperature suppression effect are mathematically calculated and utilized in an MMP calculation algorithm. Our numerical simulation results show that lower MMP of carbon dioxide, and the fact that it swells oil, renders it a beneficial solvent for fracture cleanup and counter-current improved oil recovery in unconventional reservoirs. It is also true for the LPG. 1. Gas Injection in Shale Reservoirs The maximum oil recovery of shale oil reservoirs, such as the Bakken, is projected to be near ten percent despite the use of long horizontal wells and reservoir stimulation by multi-stage hydraulic fracturing. This is because of the ultra-low matrix permeability that significantly hinders fluid flow from the matrix into the smaller fractures and ultimately into the wellbore. Immiscible displacement of water or gas in such tight formations is not practical because the injected fluid can flow only through the interconnected fractures and will have a difficult time entering the tight matrix to displace oil. Miscible gas injection, on the other hand, can mobilize oil from ultra-low permeability shale matrix by solvent extraction, which is different from oil displacement by solvent in high-permeability conventional reservoirs. Hawthorne et al. (2013) perceive that oil can be mobilized in shale formations by miscible CO2 in the following manner: CO2 flows into fractures first, and then CO2 enters into the exposed matrix to swell and mobilize oil by viscosity reduction and diffusion mass transfer. Hawthorne et al. concept stems from observations on CO2 soaking experiments using millimeter size Bakken chips and centimeter diameter core plugs. The experiments were conducted at 5,000 psi and 230 oF. The exposer time was up to 96 hours for the Middle Bakken chips, which resulted in near-complete hydrocarbon recovery. They also reported similar recoveries for the Upper and Lower Bakken matrix fragments, but with higher exposer time and smaller chip sizes to increase the specific surface area of exposure. In field practice, solvent extraction is very slow and modest because the specific surface area of reservoir matrix blocks is very small compared to the laboratory samples used by Hawthorne et al. Nevertheless, experimental results provide the impetus to pursue EOR in unconventional reservoirs, and numerical modeling becomes the tool to scale laboratory results to field.
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SPE-169123-MS
Miscible gas injection in shale reservoirs, specifically CO2, NGL and LPG, can be beneficial in several ways: (a) clean fracture surfaces from residue to improve matrix-fracture mass transfer, (b) soak into the matrix to mobilize oil by oilswelling and viscosity reduction, and (c) re-stimulate the reservoir small fractures. In the latter, successful field application of LPG-based fracturing fluids (Le Blanc, et al., 2011 and Tudor, et al., 2009) is great evidence in support of re-stimulation of reservoir fractures by miscible gas injection. 2. Fluid Property and MMP in Nanopores Several studies indicate that the phase behavior in nanopores deviate from the bulk (PVT cell) properties (Morishige et al., 1997, Zarragoicoechea and Kuz 2003, Singh et al., 2009, Travallonia et al., 2010, Sapmanee, 2011, Devegowda et al., 2012, Nojabaei et al., 2013, Alharthy et al., 2013, Teklu et al., 2013). Similarly, bubble-point and dew-point pressure, interfacial tension (IFT) and minimum miscibility pressure (MMP) between the injection and reservoir fluid change in nanopores because of the small pore confinement effect (Teklu et al., 2014). These authors calculated MMP in confined pores by including capillary pressure and critical property shifts. For this study, we use the critical property shift, given by Eq 1 and Eq 2 (Morishige et al., 1997, Zarragoicoechea and Kuz, 2004), where the collision diameter, σ LJ , can be calculated from the bulk critical properties using Eq 3 (Bird et al., 2007); and MMP calculation using the multiple mixing cell (MMC) algorithm of Ahmadi and Johns (2011). Capillary pressure effect was not included. ΔT = * c
Δ pc* =
Tcb − Tcp Tcb Pcb − Pcp Pcb
σ LJ = 0.244
3
= 0.9409 = 0.9409
σ LJ rp
σ LJ rp
⎛σ − 0.2415 ⎜ LJ ⎜ rp ⎝
⎞ ⎟⎟ ⎠
⎛σ − 0.2415 ⎜ LJ ⎜ rp ⎝
⎞ ⎟⎟ ⎠
2
..........................(1)
2
..........................(2)
Tcb p cb
Where, r p pore throat radius [nm]
........................(3)
σ LJ Lennard-Jones size parameter (collision diameter) [ nm ]
Δ T relative critical temperature shift [-] * c
Tcb bulk critical temperature [ K ] Tcp pore critical temperature [K ]
Δ p relative critical pressure shift [-] * c
pcb bulk critical pressure [atm] pcp pore critical pressure [atm]
3. Injection Gases For this study, injection gases considered are carbon dioxide, nitrogen, carbon monoxide, hydrogen sulfide, methane, ethane, propane, gas mixtures, liquefied petroleum gas (LPG), and natural gas liquid (NGL). The NGL composition used in the study is: C2 – 0.61, C3 – 0.22, C4 – 0.095, C5 – 0.065, C6 – 0.01. Figure 1 shows density and viscosity versus pressure of the injection gases at reservoir temperature of 189 oF. Figure 2 through Figure 5 presents the MMP for several gas components with shale reservoirs.
SPE-169123-MS
3
Figure 1: Density and viscosity of hydrocarbon and non-hydrocarbon gases at 189 oF. At lower pressure, all components are in vapor phase whereas at higher pressure they are in supercritical phase except propane and hydrogen sulfide which are in liquid phase. Transition from vapor to supercritical or liquid phase is shown. In addition, nitrogen and carbon monoxide are on top of each other with minor difference.
4. Reservoirs We studied fluids from four liquid-rich reservoirs -- Bakken, Monterey, Eagle Ford, and Niobrara. Table 1 shows reservoir temperature and oil composition of the four reservoirs. Bakken Petroleum System: Bakken is a highly productive tight oil play in the Williston basin, North America. According to the 2013 USGS resource assessment, the Bakken formation contains 3.65 billion barrels of technically recoverable oil (Gaswirth et al., 2013). The Devonia-Missisippian age Bakken formation is divided into the Upper, Middle and Lower Bakken members. The Upper and Lower members are organic rich and are the primary source rock for the Middle Bakken. Bakken is present in parts of Montana, North Dakota and Canadian provinces of Saskatchewan and Manitoba. The average thickness of the Middle Bakken Formation is 85 ft and the lithology includes sandstone, siltstone, dolomite and mudstone. The porosity of the Middle Bakken is approximately 6%, and the reservoir permeability is in the range of 30 to 100 nd (Nojabaei et al., 2013; Kurtoglu et al., 2013). Monterey Petroleum System: Monterey formation is Miocene age siliceous, calcareous and carbonaceous, extremely tight biogenic shale (Behl, 2012) with total organic content (TOC) of 6.5%. It is California’s primary petroleum source rock for many conventional reservoirs such as the Kern River and Elk Hills fields. According to 2011 US Energy Information Administration report (EIA, 2011), The Monterey formation could yield about 15.4 billion barrels oil. The Monterey shale is up to 2,000 feet thickness, spans from 6,000 feet to 15,000 feet of depth and encompasses 1,750 square miles, which extends from northern California down to the Los Angeles area. An example of oil composition of Monterey shale can be found in Vega et al., 2010. Eagle Ford Petroleum System: Eagle Ford shale is located in the Western Gulf Basin in the southwest where it dips to the Gulf of Mexico. The EFS is Cretaceous sediment that was traditionally known as a source rock in South and East Texas. The formation is the source rock for the Austin Chalk oil and gas formation. In south Texas, where it has hydrocarbon potential within the fairway, the Eagle Ford formation is found 5000 ft and 16,000 ft under the surface. Through the area that the EFS spans the thickness is typically between 125 ft and 300 ft. Reservoir properties vary across the area, for example, the effective porosity ranges between 3% to 10% with a mean of 6% and permeability ranges between 3 nd to 405 nd, with an average value of 180 nd. In the liquid rich part of Eagle Ford, the hydrocarbons present are wet gas, gas condensate, and oil. Analysis of outcrops and samples from this liquid rich portion of identified kerogen types II, and II/III deposited in a marine environment under anoxic conditions (Liro et al., 1994; Gong et al., 2013). Niobrara Petroleum System: Niobrara is a low permeability, hydrocarbon liquid rich, Cretaceous formation in the Denver-Julesburg (DJ) Basin of Colorado and Wyoming. Niobrara formation consists of three benches of naturally fractured limestone, marls and calcareous
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SPE-169123-MS
shales. Niobrara porosity is in the range of 10% - 14% and permeability less than 0.1 md. Thermal maturity varies across the DJ basin, causing a variety of reservoir fluids -- dry gas, wet gas, condensate, and oil (Savimaki and Seidle, 2013). In the liquid rich part, the oil is light and there is large variation in GOR. For example, Niobrara has a GOR greater than seven Mscf/bbl in the southwest of the Wattenberg field. Table 1: Bakken, Monterey, Eagle Ford, and Niobrara live oil samples used in this study
Bakken Oil o
Tres = 241 F Composition, % CO2 0.00
Monterey Oil o
Tres = 210 F Composition, % CO2 0.36
Eagle Ford Oil o
Tres = 189 F Composition, % CO2 0.81
Niobrara Oil o
Tres = 230 F Composition, % CO2 1.34
N2
0.00
N2
0.00
N2
0.07
N2
0.32
C1
36.74
C1
15.65
C1
65.54
C1
42.26
C2
14.89
C2-3
8.15
C2
12.97
C2
10.86
C3
9.33
C4-6
10.02
C3
6.17
C3
7.08
C4
5.75
C7-15
44.94
i-C4
1.50
i-C4
1.24
C5-6
6.41
C16-34
15.76
n-C4
2.42
n-C4
3.71
C7-12
15.85
C35+
5.12
i-C5
1.08
i-C5
1.37
C13-21
7.33
n-C5
1.02
n-C5
2.18
3.70 C22-80 Molecular Weight 78.30 C5-6 120.56 C7-12 220.72 C13-21 C22-80 443.52
Molecular Weight C2-3 36.99 C4-6 70.14 C7-15 135.20 C16-34 305.01 C35+ 644.85
C6 1.38 C7+ 7.04 Molecular Weight C7+ 177.11
C6 2.67 C7+ 26.97 Molecular Weight C7+ 180.60
5. Results and Discussion Figure 2 through Figure 5 and Appendix 1 indicate that the MMPs of the light oils form four U.S. shale reservoirs, with several common gases, is lower than MMP of the same oils if there were present in a conventional high permeability reservoir. This MMP reduction is because of the greater pore confinement in shale reservoirs than in conventional reservoirs. Miscibility of CO2 and ethane with oil, in ultra-low permeability shale reservoirs, occurs at somewhat lower MMPs compared to conventional reservoirs if the pore throat radius is less than 10 nm. However, miscibility of methane, nitrogen, and carbon monoxide is much lower in the same shale environment. For example, the MMP of nitrogen with Bakken oil is 3,235 psia in pores less than 10 nm pore radius (Figure 2 and Appendix 1) compared with 3800 psia in conventional reservoirs. Nonetheless, in general the MMP is lower in unconventional reservoirs because of the confined pore space of these reservoirs.
SPE-169123-MS
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Figure 2: MMP of Bakken oil with different gases at various pore confinements.
Figure 3: MMP of Monterey oil with different gases at various pore confinements.
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Figure 4: MMP of Eagle Ford oil with different gases at various pore confinements.
Figure 5: MMP of Niobrara oil with different gases at various pore confinements.
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7
6. Conclusions The following are the conclusions of this study: • Miscibility of CO2 and ethane with oil, in ultra-low permeability shale reservoirs, occurs at somewhat lower MMPs compared to conventional reservoirs, if the pore throat radius is less than 10 nm. However, miscibility of methane, nitrogen, and carbon monoxide is much lower in the same shale environment. Nonetheless, in general the MMP is lower in unconventional reservoirs because of the confined pore space of these reservoirs. • In unconventional reservoirs, CO2, NGL and LPG can potentially mobilize matrix oil by solvent extraction mechanism instead of oil displacement; thus, CO2, NGL and LPG can become the EOR gas of choice. • We also believe that CO2, NGL and LPG are beneficial solvents for fracture cleanup and counter-current improved oil recovery in unconventional reservoirs. • Mathane, nitrogen, and carbon monoxide injection can be viable in unconventional reservoirs because of their lower MMP with light oil in confined space. Nomenclature p pressure [psi] Δpc* relative critical pressure shift [-] pcb bulk critical pressure [psi] pcp pore critical pressure [psi] pc
critcal pressure [psi]
rp
pore throat radius [nm]
ΔT relative critical temperature shift [-] * c
Tcb bulk critical temperature [o F] Tcp pore critical temperature [o F] Tc
critical temperature [o F]
Tres reservoir temperature [o F]
σ LJ Lennard-Jones size parameters [ nm ] Acknowledgment The authors would like to thank Abu Dhabi National Oil Company (ADNOC), The Petroleum Institute (PI) Abu Dhabi, and Marathon Center of Excellence for Reservoir Studies (MCERS), Unconventional Natural Gas and Oil Institute (UNGI), and Center for Earth Materials, Mechanics, and Characterization (CEMMC) at Colorado School of Mines for support of this project. References Ahmadi, K. and Johns, R.T., 2011. Multiple-Mixing-Cell Method for MMP Calculations. SPE-116823, SPE Jour 16 (4): 733-742. Alharthy N., Nguyen T. N., Teklu T. W., Kazemi H., and Graves R. M., 2013. Multiphase Compositional Modeling in SmallScale Pores of Unconventional Shale Reservoirs. SPE 166306, Annual Technical Conference and Exhibition, New Orleans, Louisiana, 30 Sep – 2 Oct. Behl R. J., 2012. The Monterey Formation of California: New Research Directions. AAPG Annual Convention and Exhibition, Long Beach, California, April 22-25, 2012. Bird, R. B., Stewart, W. E., & Lightfoot, E. N., 2007. Transport phenomena. Revised 2nd Edition, John Wiley & Sons. Brusilovsky, A. I. 1992. Mathematical simulation of phase behavior of natural multicomponent systems at high pressures with an equation of state. SPE Reservoir Engineering, 7(1): 117-122. Devegowda, D., Sapmanee, K., Civan, F., Sigal, R., 2012. Phase Behavior of Gas Condensates in Shales Due to Pore Proximity Effects: Implications for Transport, Reserves and Well Productivity. SPE 160099, Technical Conference and Exhibition held in San Antonnio, Texas, 8-10 October 2012. Firincioglu T., Ozkan E., and Ozgen C., 2012. Thermodynamics of Multiphase Flow in Unconventional Liquids-Rich Reservoirs. SPE 159867, presented at SPE Annual Technical Conference and Exhibition, San Antonio, Texas, Oct 8-10.
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Gaswirth, S.B., Marra, K.R., Cook, T.A., Charpentier, R.R., Gautier, D.L., Higley, D.K., Klett, T.R., Lewan, M.D., Lillis, P.G., Schenk, C.J., Tennyson, M.E., and Whidden, K.J., 2013. Assessment of undiscovered oil resources in the Bakken and Three Forks Formations, Williston Basin Province, Montana, North Dakota, and South Dakota. US Geological Survey Fact Sheet, 2013-3013. Gong, X., McVay, D. A., Ayers, W. B., Tian, Y., & Lee, J., 2013. Assessment of Eagle Ford Shale Oil and Gas Resources. SPE 167241, SPE Unconventional Resources Conference Canada, 5-7 November, Calgary, Alberta, Canada. Hawthorne, S. B., Gorecki, C. D., Sorensen, J. A., Steadman, E. N., Harju, J. A., Melzer, S., 2013. Hydrocarbon Mobilization Mechanisms from Upper, Middle, and Lower Bakken Reservoir Rocks Exposed to CO2. SPE 167200, SPE Unconventional Resources Conference Canada, 5-7 November, Calgary, Alberta, Canada. Kurtoglu, B., Sorensen, J., Braunberger, J., Smith, S., and Kazemi, H., 2013. Geologic Characterization of a Bakken Reservoir for Potential CO2 EOR, Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013: pp. 1834-1844. LeBlanc, D., Mrtel, T., Graves, D., Tudor, E. H. and Lestz, R., 2011. Application of Propane Based Hydraulic Fracturing in McCully Gas Field, New Brunswicj, Canada. SPE 144093, presented at the North American Unconventional Gas Conference and Exhibition, 14-16 June, The Woodlands, Texas, USA Liro, L.M., Dawson, W.C., Katz, B.J., and Robinson, V.D., 1994. Sequence Stratigraphic Elements and Geochemical Variability within a “Condensed Section”: Eagle Ford Group, East-Central Texas. Gulf Coast Association of Geological Societies Transactions. 44. 393-402. Morishige, K., Fujii, H., Uga, M., and Kinukawa, D., 1997. Capillary critical point of argon, nitrogen, oxygen, ethylene, and carbon dioxide in MCM-41. Langmuir 13(13): 3494-3498. Nojabaei, B., Johns, R.T., and Chu, L. 2013. Effect of Capillary Pressure on Phase Behavior in Tight Rocks and Shales. SPE Res Eval & Eng 16 (3): 281-289, SPE-159258-PA. Sapmanee, K., 2011. Effects of pore proximity on Behavior and Production Prediction of Gas/Condensate. Master Thesis, Mewbourne School of Petroleum and Geological Engineering, University of Oklahoma. Savimaki, D., and Seidle, J., 2013. An Assessment of Selected Rate-Decline Models for Horizontal Oil Wells in the Niobrara Formation. SPE 167011 presented at SPE Unconventional Resources Conference and Exhibition-Asia Pacific, 11-13 November, Brisbane, Australia. Singh, S.K., Sinha, A., Deo, G. and Singh, J.K., 2009. Vapor-Liquid Phase Coexistence, Critical Properties, and Surface Tension of Confined Alkanes, J. Phys. Chem 113 (17): 7170–7180. Teklu, T., Ghedan, S. G., Graves, R. M., Yin X., 2012. Minimum Miscibility Pressure Determination: Modified Multiple Mixing Cell Method. SPE 155454, presented at SPE EOR Conference Oil and Gas West Asia, Muscat, Oman, April 16-18. Teklu, T., Alharthy, N., Kazemi, H., Yin, X., Graves, R., and AlSumaiti, A. 2013. Minimum Miscibility Pressure in Conventional and Unconventional Reservoirs. URTeC 1589572 / SPE 168865, presented at Unconventional Resources Technology Conference, Denver, Colorado, August 12-14. Teklu, T., Alharthy, N., Kazemi, H., Yin, X., Graves, R., and AlSumaiti, A. 2014. Pahse Behavior and Minimum Miscibility Pressure in Nanopores. SPE Res Eval & Eng, approved for publication. Travallonia, L., Castierb, M., Tavaresa, F. W., and Sandler, S. I., 2010. Critical behavior of pure confined fluids from an extension of the van der Waals equation of state, Journal of Supercritical Fluids 55 (2): 455-461. Tudor, E. H., Nevison, G. W., Allen, S., & Pike, B., 2009. 100% Gelled LPG Fracturing Process: An Alternative to Conventional Water-Based Fracturing Techniques. SPE 124495-MS, presented at the SPE Eastern Regional Meeting, 2325 September, Charleston, West Virginia, USA US Energy Information administration, Review of emerging resources US shale gas and shale oil plays, July 2011. Vega, B., O’Brien, W. J., & Kovscek, A. R., 2010. Experimental Investigation of Oil Recovery from Siliceous Shale by Miscible CO2 Injection. SPE 135627, SPE Annual Technical Conference and Exhibition, 19-22 September, Florence, Italy. Zarragoicoechea,G. J., Kuz, V. A., 2004. Critical shift of a confined fluid in a nanopore. Fluid Phase Equilibria 220 (2004): 7-9.
Appendix 1: MMP of different injection gas with some of the major shale oils of the USA M M P with Ba kken o il, psia Gas injectio n co mpo sitio n
M M P with M o nterey o il, psia
Confined
Unconfined
Confined
Unconfined
rp ≥ 1000 nm
rp = 10nm
rp = 3nm
M M P with E agle Fo rd o il, psia Confined
Unconfined
M M P with N io brara o il, psia Confined
Unconfined
rp ≥ 1000 nm
rp = 10nm
rp = 3nm
rp ≥ 1000 nm
rp = 10nm
rp = 3nm
rp ≥ 1000 nm
rp = 10nm
rp = 3nm
CO 2 / N 2 / CO / N GL / C1 / C2 / C3 / H 2 S 100 % CO2
2350
2300
2045
2960
2605
1565
2290
2375
1890
2680
2520
1730
100% N 2 or 100% CO
3825
3235
2260
12325
8675
3000
4375
3695
2340
4475
3840
2115
100% NGL
1005
1110
1125
710
745
740
780
845
920
965
1050
975
100 % C1
3785
3370
2260
5685
4520
2190
4375
3700
2350
4150
3835
2120
100 % C2
1430
1520
1375
1510
1475
1065
1285
1360
1210
1445
1475
1180
100 % C3
695
775
850
600
617
635
400
540
700
616
730
765
100 % H2 S
1365
1430
1260
1130
1235
985
915
1125
1175
1285
1350
1155
90 % [N 2 or CO] and 10% CO2
3830
3185
2260
12415
8865
3000
4375
3695
2345
4475
3835
2115
80 % [N 2 or CO] and 20% CO2
3830
3300
2260
12600
8720
3000
4375
3695
2345
4014
3835
2115
50 % [N 2 or CO] and 50% CO2
3880
3390
2255
8290
5795
2525
4360
3700
2340
4260
3825
2120
90 % [N 2 or CO] and 10% NGL
3825
3290
2255
12560
8685
3005
4375
3695
2345
4285
3835
2115
80 % [N 2 or CO] and 20% NGL
3825
3275
2250
10325
7890
3000
4375
3695
2345
4015
3835
2115
50 % [N 2 or CO] and 50% NGL
3830
3465
2255
3025
3115
1755
3760
3310
2340
4330
3645
1920
90 % CO2 and 10% NGL
2660
2275
2035
2710
2345
1495
2270
2280
1830
2700
2200
1685
80 % CO2 and 20% NGL
2350
2282
1940
2295
2080
1410
2160
2175
1740
2470
2360
1630
50 % CO2 and 50% NGL
1875
2050
1655
1435
1450
1140
1585
1620
1405
1865
1820
1385
M ixture o f [N 2 o r CO] and CO 2
M ixture o f [N 2 o r CO] and N GL
M ixture o f CO 2 and N GL
N OTE :
(1 ) The MMP of N 2 and CO are very close, hence reported together. (2 ) Generally, the MMP decreases with confinement except for NGL, H2 S, C2 and C3 cases;
N GL co m po sitio n C2
0.61
This is due to the fact that with critical property shift, ethane and propane somehow behave as methane at confined pores.
C3
0.22
Hence the MMP increases slightly at confined pores
C4
0.095
C5
0.065
C6
0.01
(3 ) The MMP of given oil with propane is the smallest; and with nitrogen or carbon monoxide is the largest MMP.
