Laboratory Investigations of CO2

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SPE 129710

Laboratory Investigations of CO2 Near-miscible Appl ication in ArbuckleReservoirL. H. Bui, J. S. Tsau, and G. P. Willhite, SPE, University of Kansas

Copyright 2010, Society of Petroleum Engineers

This paper was prepared for presentation at the 2010 SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 24–28 April 2010.

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 beenreviewed 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, itsofficers, 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 toreproduce 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.

Abst ract

Carbon dioxide (CO2) is a proven enhanced oil recovery technology. However, many reservoirs are located at shallow depths

or geologic conditions such that CO2 can not be injected at pressures above the MMP. CO2 injection is usually not

considered as an enhanced oil recovery process in these reservoirs. When CO2 is injected below the MMP, displacementefficiency decreases as a result of the loss of miscibility. Near miscible displacement has sometimes been referred to as the

process occurring between immiscible and miscible pressures, but has never been clearly defined. This paper describes

laboratory study of CO2 near miscible displacement in an Arbuckle reservoir in Kansas.

Phase behavior studies between CO2 and Arbuckle crude oil were carried out to define near miscible conditions at

reservoir conditions. Swelling/extraction tests combined with slim-tube experiments were interpreted to identify the mass

transfer mechanisms at near miscible condition. A phase behavior model was developed to match PVT data and MMP in theslim-tube experiment. Good agreement was obtained between simulated and observed data from slim-tube experiments.

Core flooding tests were conducted to evaluate oil recovery at near miscible condition at which pressure varies from 1350 psi

(MMP) to 1150 psi. Recovery of over 50% of the waterflood residual oil saturation was observed when CO2 was used todisplace Arbuckle oil from Berea, Baker dolomite and Arbuckle dolomite cores.

At near miscible conditions, extraction appears to be the primary mechanism for mass transfer between hydrocarbon

components and CO2. However, the reduction of oil viscosity by a factor of five occurred when CO2 dissolved in the oil.

This suggests that some of the additional oil recovery may be attributed to reduction of the mobility ratio between CO2 andresident oil.

Introduction

Arbuckle reservoirs are a significant resource in Kansas for improved oil recovery. These reservoirs have produced an

estimated 2.2 billion barrels of oil representing 35% of the 6.1 billion barrels of oil of total Kansas oil production (Franseen

et al., 2004). Most Arbuckle reservoirs have active water drives which have maintained reservoir pressure at 1000-1100 psig

for nearly 50 years eventhough millions of barrels of fluid have been produced. Initial studies of CO2 miscible floodingindicated that miscibility is not achievable at the reservoir operating pressure in most Arbuckle reservoirs. For example, theArbuckle reservoir oil in the Bemis-Shutts field has a MMP of 1400 psi while the current operating pressure is 1100 psi in a

large portion of the field. The possibility of operating at pressures below the MMP means that many of these fields in central

Kansas, which might be otherwise abandoned with substantial remaining oil left in place could be considered for CO 2 injection.

Carbon dioxide (CO2) injection is normally operated at pressures above minimum miscibility pressure (MMP),which is determined by crude oil composition and reservoir conditions. When carbon dioxide is injected at pressures slightly

below MMP, the process is commonly referred as a near miscible displacement. The effectiveness of near miscible

displacement within a certain range of pressure also depends on the oil composition and reservoir condition. Within this

pressure range, significant oil recovery efficiency has been observed in slim-tube experiments and to a lesser extent in core

tests. Although recovery efficiency is less than that from miscible displacement, the recovery efficiency is still much greater



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than for waterflood recovery. This effect of pressure on the oil recovery has been investigated with different conclusions.

Shyeh-Yung (1991) suggests that recovery of residual oil by injection of CO2 at pressure below MMP benefits from a

possible improvement of mobility ratio between CO2 and oil thereby increasing oil recovery. Grigg et al. (1987) report that

oil recovery below the MMP in the near miscible region is not effective due to an inefficient extraction process.

This paper summarizes a study of the injection of CO2 at near miscible condition to improve oil recovery in an

Arbuckle reservoir where the current operating pressure is approximately 1150 psig. Phase behavior studies and core flood

tests were carried out to improve understanding of the mechanisms affecting the process of near-miscible CO 2 flooding andevaluate the feasibility of near miscible carbon dioxide injection in Arbuckle reservoirs. All experiments were performed

with centrifuged and filtered Ogallah stock tank oil obtained from Ogallah Unit, Trego Country, Kansas. The location of theunit is shown in Figure 1.

Phase Behavior Studies

Phase behavior studies consisted of slim-tube experiments to determine the minimum miscibility pressure (MMP) of the

Ogallah oil, swelling/extraction tests to determine the effect of pressure on the solubility of CO2 in oil and measurement of

the viscosity and density of Ogallah crude oil saturated with CO 2 at various pressures. A phase behavior model was

constructed by tuning Peng-Robinson Equation of State (PREOS) with experimental data. The composition of Ogallah oil

was determined by gas chromatography analysis and shown in Figure 2. Physical properties of the oil and the lumped heavycomponent are presented in Table 1. Commercial CO2 of 99.99 % purity was used.

Slim-Tube Experiments. The slim-tube setup is shown in Figure 3. The slim-tube consists of a coiled 40 ft-long stainlesssteel tube with an ID of 0.24 in. packed with glass beads. The slim tube has a pore volume (PV) of 128 cm 3 and a

permeability of 4900 md. The pressure of the system was maintained by the back-pressure regulator at the outlet. CO2 was

injected at a constant rate of 0.1cc/min to displace the oil. Density of the effluent was measured continuously using an inline

densitometer. The effluent was continuously flashed to atmospheric conditions. The separator gas was connected to a flow

meter for measurement of the gas flow. The amount of fluid produced was collected in a graduate cylinder and determined byweight. The composition of the produced fluid was not determined.

An oil recovery factor of at least 90% at 1.2 HCPV of CO 2 injected was used to define MMP in the slim-tubeexperiments for this oil. Experiments were done at two temperatures (110 F̊ and 125 F̊) representing the range of

temperatures obtained from field data. Oil recovery at 1.2 HCPV CO2 injected was plotted in Figure 4 against average

pressure. The MMP was estimated to be 1350 psig at 110 oF and 1650 psig at 125 oF. The measurement of MMP indicatesthat miscibility would not be reached during carbon dioxide injection at the current reservoir pressure of 1150 psig.

However, the recovery efficiency from the slim-tube experiments was about 80% at the current reservoir pressure. Thesedata indicate that substantial amounts of hydrocarbon constituents were extracted by the CO2 as it was displaced through the

slim-tube.

Figure 5 shows the density profile of the effluent at pressures below MMP. Prior to the breakthrough of CO2 the

effluent density was equal to the oil phase density (0.834 g/cc) at reservoir temperature and slim-tube average pressure. The

abrupt change in density of the effluent corresponds to the breakthrough of CO2. Significant reduction of effluent densityoccurred at pressures below MMP following CO2 breakthrough. After breakthrough of CO2, average densities of the effluent

were 0.434, 0.535 g/cc at average pressures of 1100, 1200 psig. At the same pressure and temperature, the densities of pure

CO2 are 0.221 g/cc and 0.275 g/cc. The increase of density in the effluent profile is evidence that light hydrocarbon

components from the oil continued to be vaporized or extracted by CO2 contributing to relatively high recovery efficienciesfor near miscible CO2 displacement.

Swelling/Extraction Tests. Swelling/extraction experiments were conducted in a visual PVT cell with a total volume of 26cc. Details of the experimental setup are described in a companion paper (Tsau et al., 2010). Typically, a pre-determined

volume of crude oil is injected into the view cell. The cell pressure is increased in discrete steps by CO2 injection from thetop of the view cell until a desired pressure is achieved. A stir bar inside the view cell is used to accelerate the mass transfer

between oil and CO2. When the equilibrium is achieved, the volume of CO2-saturated oil is measured with a cathetometer.

Solubility of CO2 in oil, relative volume change of oil and density of CO2-saturated oil are determined as a function of pressure.

Figure 6 shows the swelling/extraction curve for oil/CO2 system at 110 ºF with 3 cc of sample (12 % volume of cellvolume). CO2 solubility is also plotted in the same figure as a function of pressure. The swelling factor (SF) of oil is the ratio

of volume at reservoir conditions to volume at stock tank conditions. This value was determined by measuring the change of

interface level as a result of CO2 dissolution in the oil. CO2 solubility was calculated based on the assumption that negligible

hydrocarbon component in the vapor phase. Maximum swelling occurred at 1150 psig, when its volume was 1.21 of its



SPE 129710 3

original volume with 0.728 mole fraction of CO2 dissolves in the liquid phase. Extraction appears to have started at

approximately the same pressure. As the pressure increased, the oil volume continued to shrink and CO2 extracted more

hydrocarbon components from liquid phase. The rate of oil volume shrinking by extraction was faster than the rate of

swelling by continued dissolution of CO2. At 2035 psig, the oil volume shrank as much as 39.2 % of its original volume.

Viscosity Measurement. The viscosity of CO2-saturated oil was measured using a Cambridge Applied Systems high

pressure viscometer (ViscoPro 2000 System 4-SPL-440 with Viscolab software). The schematic drawing of this setup is

shown in Figure 7. Detail of the experimental setup is described elsewhere by Ahosseini, et al. (2008). Figure 8 shows theeffect of solubility of CO2 on viscosity of CO2-saturated oil at 110 oF. Dissolution of CO2 into crude oil reduces the viscosity

of crude oil to as much as a factor of five. The reduction of oil viscosity observed in the near miscible pressure range reducesthe mobility ratio between CO2 and oil in the displacement process and consequently viscous fingering.

Phase Behavior Model. A phase behavior model was constructed using the PREOS. Parameters of the EOS were adjusted

to match the laboratory-determined PVT data. The fluid system consists of CO2 and hydrocarbon with four pseudo-

components. Molecular weight of the plus fraction was adjusted to match the oil density. Coefficients of Pedersen viscositycorrelation were adjusted to match the oil viscosity. Binary interaction coefficients between CO2 and hydrocarbon

components as well as CO2 volume shift factor were adjusted to match saturation pressure and swelling data. Figure 9

presents the match of density and viscosity of oil. Figure 10 shows the match of swelling factor and saturation pressure while

Figure 11 shows the match of crude oil saturated with CO2 as a function of saturation pressure.

Core Flow Tests

Cores from Arbuckle reservoirs are limited. Core tests were made using Berea sandstone, Baker dolomite and Arbuckle

dolomite. Berea sandstone and Baker dolomite were quarried rock samples whereas Arbuckle dolomite was cored sample

from Hadley well, Bemis-Shutts Field at Ellis County, Kansas. Cores were epoxy encased and cast inside an aluminum

cylinder with high strength epoxy. The core properties are tabulated in Table 2. The pore volumes of the cores were

determined by measuring the volume of brine imbibed by the evacuated core and confirmed by tracer test with 1 wt%MgNO3 as the tracer. The cores were cleaned and reused after completion of each CO2 flood. During core cleaning, the core

was flushed with 10 PV of methylene chloride followed by 10 PV of methanol. The sequence was repeated at least three

times and finally the core was flushed with 10 PV of brine prior to be used for the flow test. All flow tests were conductedwith 1wt% total dissolved solids (TDS) brine consisting of 0.5 wt% MgCl2 and 0.5 wt% CaCl2 in deionized water. Density

and viscosity of brine measured at 110 ºF and atmospheric condition were 0.9959 g/cc, 0.7250 cp, respectively.

A schematic diagram of the core displacement apparatus is shown in Figure 12. The core displacement apparatus

consists of a core holder, injection system, a production system and a data acquisition system. The injection system consistsof three pumps (for fluid transfer and injection at a desired rate) and a transfer cylinder (for crude oil storage). The production

system utilizes a back pressure regulator to control the core outlet pressure at a set level. During the experiment, the core

effluent was flashed to atmospheric conditions. The separator gas was connected to a flow meter for flow rate measurement.

The separator fluid was collected in glassware designed for a specific flooding. The amount of fluids produced wasdetermined gravimetrically and/or volumetrically.

Secondary and tertiary CO2 flooding experiments were conducted to evaluate the recovery efficiency at operating

pressure in the near miscible condition. Injection of CO2 was controlled at 0.1 cc/min at operating pressure. The amount of

fluid recovered by CO2 displacement was compared at 6 PV of injection.

Secondary CO2 Flooding. Berea sandstone was used in this series of experiments with the core saturated with oil prior to

injection of CO2. The recovery efficiency was determined by the amount of oil recovered at 6 PV of CO 2 injections. The

recovery efficiency is presented in Figure 13 where the recovery efficiency from slim-tube experiment is also plotted forcomparison. The recovery efficiency in a short core was much less than that from slim-tube displacements. The lower

recovery at pressure above MMP is probably due to lack of development of multiple-contact miscibility in a short core. At pressure below MMP, the extraction was also less effective as the dispersion is dominated for flow in the core plug as

compared to that in a slim-tube. Nevertheless, the density profiles of core flooding effluents showed similarity in density

profiles of slim tube effluents at pressure below MMP. Density of effluent during the displacement was higher than density of pure CO2 at near miscible pressure. The density behavior of the effluent suggested that the vaporization process took place

during core flooding process despite the length of core is short.

Tertiary CO2 Flooding. Core plugs of Arbuckle dolomite, Baker dolomite and Berea sandstone, were used in this series of

experiments. Each core sample was saturated with brine at the test pressure and permeability was measured. The core was

then flooded with oil to connate water saturation at flow rate of 0.1cc/min. After connate water saturation was established,

the core was water flooded at same rate to residual oil saturation. At least 10 PV of brine and crude oil were used in each



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sequence of displacement to establish a steady state residual fluid saturation. Carbon dioxide was finally injected to displace

the remaining oil in the core. The amount of oil recovered by CO2 flooding was determined volumetrically. A typical result

of CO2 flooding is presented in Figure 14 where the recovery history of fluid is plotted. Most of recovery occurred before 4

PV of CO2 injection. No significant fluid recovery was observed after 6 PV of CO2 were injected.

Figure 15 gives a comparison of recovery efficiency between secondary and tertiary CO2 flooding with Berea

sandstone. Higher recovery efficiency of remaining oil in place (ROIP) in tertiary CO2 flooding indicates the existence of

water phase is not necessarily detrimental to CO2 displacement efficiency due to its blocking effect. Instead, the relative permeability of CO2 at presence of water might be reduced. Coupled with the reduction of the oil viscosity, the mobility ratio

between the oil and CO2 is reduced and therefore the recovery efficiency is improved.

The results of tertiary CO2 flood in different cores are summarized in Table 3 to 5. Relatively high values of SorCO2,

0.21 to 0.29 were found in Berea sandstone as it had an unusual high Sorw, 0.48 to 0.50 prior to CO2 injections. On the other

hand, the Sorw of the dolomite core was found to vary from 0.32 to 0.41 with the SorCO2 from 0.07 to 0.17 at the near miscible

condition. Figure 16 presents the comparison of recovery efficiency among the cores tested. The recovery efficiency ofROIP varied from 60% to 80% for dolomite cores while it varied from 35% to 58 % for sandstone core as pressure increased

from 900 psig to 1400 psig. Although the recovery efficiency differed among the rock types, substantial recovery was

observed for Arbuckle rock at current reservoir operating pressure of 1150 psig.

The recovery efficiency was similar between two dolomite cores and was substantially higher than that in Berea

core. Wylie and Mohanty (1998) in their study of effect of wettability on oil recovery by gas injection concluded that the

mass transfer from the bypassed region to the flowing gas inside a core is enhanced under oil-wet conditions over water-wet

conditions. Although the wettability of core was not determined in this study, it is generally believed that Berea sandstone isstrongly water wet whereas the dolomite is less water wet. After CO2 breakthrough from the core, the extraction or the mass

transfer between the bypassed region and flowing CO2 becomes more important to extract the remaining oil inside the core.

The findings from Wylie’s study may explain why the recovery efficiency is higher in dolomite than that in sandstone tested

in this study.

Simulation o f Slim-Tube Experiments

Slim-tube displacements were simulated using a 1D compositional simulator (GEM, CMG) with the tuned EOS. A series of

simulations were run over a range of pressures. Figure 17 compares the recovery efficiencies from simulation and experiment

at 1.2 HCPV of injection. Figure 18 compares the density of the effluent after CO2 breakthrough calculated from the modelwith measured effluent densities at 1100 psig. The calculated density is consistent with two phase flow with liquid dispersed

in vapor phase as observed from the experiment. This supports that extraction/vaporization is a primary mechanism at nearmiscible condition to result in a relatively high recovery efficiency of this particular oil. The phase behavior model predicts

the MMP and the oil recovery reasonably well and will be used in future work to simulate oil recovery from CO2 injection in

an Arbuckle reservoir.

Field Applications

Results of this study indicate that CO2 injection at current reservoir pressure in an Arbuckle reservoir could mobilize more

than 50% of the waterflood residual oil eventhough the reservoir pressure is substantially less than the MMP. Principal oil

recovery mechanism in near miscible flooding appears to be extraction/evaporation of light hydrocarbon constituents into the

carbon dioxide rich vapor phase coupled with enhanced mobility control due to the reduction of oil viscosity due todissolution of CO2. This suggests that application of carbon dioxide in the field would require injection of and recycling of

large volumes of carbon dioxide. Further study is needed to determine if such a process is economically feasible. However,

the potential of recovering up to 1 billion barrels of oil from Arbuckle reservoirs offers significant economic potential

Conclusions

1. Properties of Ogallah unit oil produced from an Arbuckle reservoir in Kansas were determined at reservoir temperature

from a series of phase behavior and slim tube experiments where CO2 was dissolved in or used to displace the oil. TheMMP at 110 ºF was 1350 psig. The MMP increased to 1650 psig when the temperature increased to 125 ºF.

2. At near miscible conditions (p>1100 psig), the oil viscosity was reduced by a factor of five due to the dissolution of

carbon dioxide.

3. Phase behavior data were used to develop an equation of state that correlated properties of carbon dioxide saturated crudeoil as a function of pressure at reservoir temperature.

4. Recovery of more than 50% of the waterflood residual oil from Berea, Baker dolomite and Arbuckle reservoir rock was

obtained when CO2 was injected at the current average reservoir pressure of 1150 psig, substantially less than the



SPE 129710 5

MMP(1350 psig).

5. Good agreement was observed between simulated and measured oil recovery from slim-tube tests for CO 2 injection over

pressures ranging from 1000 psig to 1500 psig.

6. Simulated effluent densities from the slim-tube experiments were in good agreement with measured effluent densities.7. At near miscible conditions, relatively high recovery efficiency in the slim-tube experiment supports

extraction/vaporization as a principle displacement mechanism.

NOMENCLATURES

S wr Oil flood residual water saturationS wf CO2 flood residual water saturation

S orw Waterflood residual oil saturation

S orco2 CO2 flood residual oil saturation

ACKNOWLEDGEMENTS

The authors wish to acknowledge the funding support by Research Partnership to Secure Energy for America (RPSEA) small

producer program, RPSEA Contract DE-AC26-07NT42677/Subcontract 07123-03, Scott Ramskill of TORP for help in

laboratory work, and Computer Modeling Group Inc. for the software package used in the simulation.

RERERENCES

Ahosseini, A. and Scurto, A.: “Viscosity of Imidazolium-Based Ionic Liquids at Elevated Pressures: Cation and Anion Effects,”

International Journal of Thermophysics, 2008. 29 (4), 1222-1243. Franseen, E. K., Byrnes, A. P. Cansler, J. R. Steinhauff, D. M. and Carr, T. R.: “The Geology of Kansas ARBUCKLE GROUP,” Current

Research in Earth Sciences, Bulletin 250, part 2, 2004.Grigg, R.B. and Gregory, M.D., and Purkaple, J.D.: “The Effect of Pressure on Improved Oil flood Recovery from Tertiary Gas Injection,”

SPERE, August 1997, 179-187.Shyeh-Yung, J-G, J: “Mechanisms of Miscible Oil Recovery: Effects of Pressure on Miscible and Near-Miscible Displacements of Oil byCarbon Dioxide,” paper SPE 22651 presented at 1991 Annual Technical Conference at Dallas, Texas, October 6-9.Tsau, J. S., Bui, L. H., and Willhite, G. P.: “Swelling/Extraction Test of a Small Sample Size for Phase Behavior Study,” paper SPE129728 to be presented at the Improved Oil Recovery Symposium, Tulsa, OK. April 24-28, 2010.

Wylie, P. and Mohanty, K. K.: “Effect of Wettability on Oil Recovery by Near-miscible Gas Injection,” paper SPE 39620 presented at theImproved Oil Recovery Symposium, Tulsa, OK. April 19-22, 1998.



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Table 1 Physical properties of Ogallah stock tank oil

Molecular Weigh, g/mol 228.71

API 33.34

Density @ 14.7 psi & 60oF, g/cc 0.8584

Viscosity @ 14.7 psi & 60oF, cp 13.4

C36+ molecular weight, g/cc 873.24C36+ density @ 14.7 psi & 60

oF, g/cc 0.9978

Table 2 Core properties

Type Berea sandstone Arbuckle dolomite Baker dolomite

Length (cm) 5.861 5.967 8.068

Cross section 2.53 2.46 2.34

Area (cm ) 5.007 4.750 4.301

Pore volume (cc) 5.796 6.046 7.195

Porosity 19.7 % 21.3% 20.7%

Permeability (mD) 238.50 2.5 89.7

Table 3 Tertiary CO2 flood results of Berea sandstone

Pressure Swr Sorw Sorco2 Swf Recovery1-(Sorco2/Sorw)

(psig)

905 0.318 0.483 0.311 0.370 35.71

1104 0.318 0.500 0.293 0.388 41.38

1198 0.318 0.483 0.259 0.405 46.43

1317 0.318 0.500 0.207 0.336 58.62

1413 0.318 0.483 0.207 0.336 57.14

Table 4 Tertiary CO2 flood results of Arbuckle dolomite


(psig)

901 0.380 0.414 0.165 0.512 60.00

1100 0.380 0.414 0.165 0.553 60.00

1200 0.446 0.331 0.083 0.636 75.00

1305 0.446 0.331 0.066 0.636 80.00

1407 0.380 0.380 0.099 0.529 73.91

Table 5 Tertiary CO2 flood results of Baker dolomite


(psig)

905 0.284 0.389 0.153 0.437 60.711109 0.312 0.375 0.125 0.409 66.67

1201 0.340 0.347 0.097 0.451 72.00

1303 0.368 0.347 0.069 0.534 80.00

1402 0.368 0.320 0.069 0.465 78.26



SPE 129710 7

Figure 1 Ogallah unit, Trego County, Kansas Figure 4 Minimum miscibility pressure (MMP)

Figure 5 Densities of slim-tube effluents during CO2

injection at pressures below MMP and a reservoir

temperature of 110 °F

Figure 2 Carbon number distributions of Ogallah

crude oil

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

0 500 1000 1500 2000 2500

Pressure, psi

S w e l l i

n g F a c t o r

0.0

0.2

0.4

0.6

0.8

1.0

C O

2

s o l u b i l i t y

Swelling Factor

CO2 solubility

CO2

Gas

Oil

Electronic BalanceISCO Pump ISCO Pump

PTDPT

Densitometer Test Oil

BPR

CO2

Gas

Oil


PTDPT


BPR

Gas

Oil

Gas

Oil


PTDPT


BPR

Figure 6 Swelling/extraction curve of Ogallah crude

oil with carbon dioxide at 110 °FFigure 3 Slim-tube experimental setup



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Liquid Inlet

High Pressure Generator

Circulation Pump

RD

PT

RTD

CO2 Inlet

Liquid Outlet

Liquid Outlet

High pressure sensor

Oven

Liquid Inlet

High Pressure Generator

Circulation Pump

RD

PT

RTD

CO2 Inlet

Liquid Outlet

Liquid Outlet


Oven

Circulation Pump

RD

PT

RTD

Circulation Pump

RD

PT

Circulation Pump

RD

PT

Circulation Pump

RD

PT

RTDRTD

CO2 Inlet

Liquid Outlet

Liquid Outlet


Oven

Figure 7: Experimental setup for high pressure

viscosity measurement

Figure 10 Match of saturation pressure and swelling

factor at 110 °F

0.0

1.0

2.0

3.0

4.0

5.0

0 500 1000 1500 2000Pressure (psi)

V i s c o s i t y ( c p )

Run 1

Run 2

Run 3

Figure 8 Viscosity of crude oil saturated with carbon

dioxide at 110 °F

Figure 9 Match of density and viscosity of oil at 110 °F

Figure 11 Match of viscosity of oil saturated with

carbon dioxide at 110 °F

Gas

Oil/Brine

ISCO Pump

ISCO Pump

Quizix Pump

BPR

DPT

Test Oil

CO2

Brine

Gas

Oil/Brine

ISCO Pump

ISCO Pump

Quizix Pump

BPR

DPT

Test Oil

CO2

Brine

Figure 12 Coreflood experimental setup



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Figure 13 Comparison of recovery efficiency between

slim-tube and coreflood experiment at 110 °F

Figure 14 Effluent profile of production fluid during

CO2 flooding at 1317 psig and 110 °F

Figure 15 Effect of water saturation on recovery

efficiency at 110 °F

Figure 16 Effect of rock type on recovery efficiency at

110 °F

Figure 17 Match of oil recovery efficiency and MMP

in slim-tube test at 110 °F

Figure 18: Comparision of simulated and measured

effluent density for slim-tube experiment at 1100 psig

Laboratory Investigations of CO2

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