Carbonated Water Injection (CWI) Studies - h. W · Carbonated Water Injection (CWI) Studies ... oil were tested to investigate the impact of oil type on the performance ... migration

29th Annual Workshop & Symposium IEA Collaborative Project on Enhanced Oil Recovery

1

Carbonated Water Injection (CWI) Studies

Mehran Sohrabi, Masoud Riazi, Mahmoud Jamiolahmady, Shaun Ireland and

Christopher Brown

[email protected], [email protected], [email protected]

[email protected], [email protected]

Institute of Petroleum Engineering, Heriot-Watt University,

Riccarton, Edinburgh, UK

Abstract

CO2 injection is a well-established method for increasing recovery from oil reservoirs.

However, poor sweep efficiency has been reported in many CO2 injection projects.

Various injection strategies including gravity stable, WAG and SWAG have been

suggested and, to some extent, applied in the field to alleviate this problem. An alternative

injection strategy could be carbonated water injection (CWI).

This paper describes an investigation of the process of CWI by performing high-pressure

flow experiments. The experiments reveal the underlying physics and the pore-scale

mechanisms of fluid-fluid and fluid-solid interactions during CWI. The results show that

CWI, compared to unadulterated water injection, improves oil recovery as both secondary

(before water flooding) and tertiary (after water flooding) recovery methods. The

improvement is, however, higher when carbonated water is injected in secondary recovery

mode. The main mechanisms of oil recovery by CWI are improved sweep efficiency due to

a favourable increased in water viscosity and decrease in oil viscosity and also swelling

and coalescence of the isolated oil ganglia and the resultant fluid redistribution. A larger

part of the porous medium is contacted by carbonated water compared to direct CO2

injection.

1 Introduction

Many of the existing giant oil fields discovered to date are approaching the end of their

water flooding lives and are in tail end production. EOR (enhanced oil recovery) processes

are therefore needed to maximise oil recovery from these reservoirs to meet the rising

global energy demand. CO2 injection is increasingly considered as having potential


2

applications as a possible EOR process for these reservoirs. The pore space available in

these reservoirs can also store significant quantities of CO2 as part of a CCS (carbon

capture and storage) programme for a long period of time.

CO2 injection for EOR is a well-established technology. CO2 increases oil recovery by

primarily altering the physical properties of the oil phase i.e. swelling of the oil, reduction

of oil viscosity and possible vaporization and extraction of intermediate components. It has

been reported that poor sweep efficiency (due to a high CO2 mobility) has been a problem

in CO2-floods of many oil reservoirs1. Therefore, direct injection of CO2 (both continuous

flooding and WAG) might not result in economically significant amount of additional oil

recovery. In terms of CO2 storage potential, poor sweep efficiency also implies lower

storage capacity. An alternative injection strategy could be carbonated water

(CO2-enriched water) injection.

Carbonated water has advantages over direct CO2 injection as it has a better sweep

efficiency. In water flooded reservoirs, CWI can alleviate the adverse effect of high water

saturation and the water shielding effects as a result of mixing with the resident water. This

in turn facilitates CO2 dissolution and the subsequent oil swelling. In direct CO2 injection, it

has been shown that, due to low sweep efficiency and gravity segregation, the time scale for

CO2 diffusion in oil can be several years2. In terms of CO2 storage, since in CWI CO2 is

dissolved in water (and later oil) rather than as a free phase, CWI would provide a safe

method of storage.

In this study, to investigate the process of carbonated water injection and to identify the

dominant mechanisms in this process, a series of fluid flow experiments were performed

using high-pressure transparent porous media (micromodel). Carbonated water injection as

both secondary and tertiary oil recovery methods was investigated. Both light and viscous

oil were tested to investigate the impact of oil type on the performance of CWI.

2. Experimental Work

2.1 Experimental Facilities

A high-pressure micromodel rig is being used for performing carbonated water injection

tests. The rig can operate at pressures as high as 6000 Psia and at a temperature of 100 °F.

High-pressure micromodel rigs have been extensively used in our research group and the

details of the rig have been reported in our previous publications3, 4, 5 and 6

.

2.2 Test Fluids

The fluid system used in the experiments consisted of distilled water, carbon dioxide and

n-Decane or a viscous mineral oil. The viscosity of the mineral oil at atmospheric pressure

and the temperature of the experiments (38 ºC) is 16.5 mPa.s (cP) whereas the viscosity of

n-Decane is 0.83 mPa.s7 (cP) at 2000 psia and 38°C. Carbonated water was prepared by


3

mixing blue degassed distilled water with pure CO2 in a rocking cell at 38 °C and 2000

psia.

To distinguish between oil and the aqueous phase, the colour of the water was changed to

blue using a water-soluble dye. The dyed fluids were filtered using fine filter papers to

remove any un-dissolved dye particles.

3. Results and Discussion

In all the tests reported here, the micromodel orientation was horizontal to minimise the

gravity effect. Figure 1 shows the whole micromodel saturated with 100% blue water.

Figure 2 shows a part of the micromodel in higher magnification. The tests began by

saturating the micromodel with water. Then, to simulate primary drainage of water, initial

migration of oil into the water bearing porous media, the oil phase was injected from one

end of the horizontal micromodel.

Figure 1: The whole micromodel including two triangle sections fully saturated with

degassed blue dyed water.

Figure 2: A magnified section of micromodel fully saturated with degassed blue dyed water.


4

Figure 3, shows a smaller section of micromodel than Figure 2 at the end of the oil

injection period in which the initial oil and connate water saturation has been established.

This image shows the relative position of the wetting phase, blue water, and non-wetting

phase, oil, in the micromodel. The shape of the water-oil interfaces and the fact that some

of the smaller and dead-end pores are filled with water are good indications of the

water-wet conditions of the micromodel.

Figure 3: Initial oil saturation (n-Decane) in just a selected frame in higher magnification.

After this initial oil injection stage (establishment of ‘irreducible’ water), two experiments

with n-Decane were carried out to study carbonated water injection process as both

secondary and tertiary oil recovery mechanisms.

3.1 Secondary Recovery

In this test, CW (carbonated water), was injected as a secondary (pre waterflood) recovery

method, at a low rate of 0.01 cm3 h

-1 into the micromodel saturated with oil at Swi. Figure

4 shows the fluid distribution in a section of the micromodel after the breakthrough (BT) of

CW. As this image demonstrates, the oil phase has become discontinuous after CWI and

the remaining oil is in the form of isolated and fragmented oil pieces. The mechanisms

observed for oil recovery and displacement during CWI were both film flow and piston

type displacements. Figure 4 shows snapped and bypassed oil ganglia as a result of these

two different flow mechanisms.

Water

Grain, glass

Oil

Direction of CW

and W injection


5

Figure 4: Oil production by snapping off and bypassing mechanisms in the early time of

CWI, after 0.68 hrs, in the same selected frame shown in the Figure 3

Figure 5 shows fluid distribution within the selected section of the micromodel (as Figure

4) after 19 hrs of CWI. Comparison of this image with Figure 4 reveals that both swelling

and reconnection of some of the isolated oil ganglia happened due to the partitioning of

CO2 from the injected CW and its dissolution in the oil. This swelling and reconnection

improves sweep efficiency. In Figure 5, the red rectangle and circle demonstrate an

example of oil swelling and the reconnection of the oil due to swelling. Figure 6 shows the

same section of the micromodel during CWI after 79 hours. Comparison of Figure 6 and

Figure 5 shows that some of the oil has been recovered during this CWI stage.

During CWI, significant quantities of CO2 dissolve in the oil and water. An additional oil

recovery process could be the in situ release of CO2 subsequent to carbonated water

injection by pressure blow-down of the reservoir. If the pressure of the reservoir is allowed

to drop below the saturation pressure of CO2 in the oil and water a free gas (CO2) phase is

expected to form in the reservoir. This blow-down phase following carbonated water

injection can cause additional oil recovery as well as a significant redistribution of the

fluids within the reservoir. A subsequent waterflooding might also further reduce the

amount of residual oil. After the CWI period, the micromodel went through a

depressurising period in which the pressure was reduced slowly.

Snapped Oil ganglion

Bypassed oil droplet


6

Figure 5: More oil swelling and subsequent coalescence of oil droplets after 19 hrs of CWI

in the same selected frame shown in the Figure 4.

Figure 6: second displacement and more oil production for the late time period, 79 hrs, in

the same frame shown in Figure 5.


7

This depressurisation period was carried out to both identify the dead-oil volume of the

remaining oil and also to observe the potential of a depressurising process subsequent to

CWI. The distribution of the fluids after this slow depressurisation period is shown in

Figure 7. Comparison of the remaining oil volume in Figure 7 with the oil volume at the

beginning of CWI period (Figure 5) shows that significant amount of oil was recovered

during CWI period. The yellow colour in Figure 7 shows the free gas phase that has

formed during the pressure blow down period, in this figure gas has been digitally coloured

in yellow. Comparison of Figures 6 and 7 shows a significant fluid redistribution has taken

place. Some additional oil recovery was achieved and significant amount of CO2 gas was

recovered as well.

Figure 7: Fluid distribution after blow down mode, depressurization period, when pressure

reached to 180 psia.

Figure 8 show oil saturation in the whole micromodel (at the test pressure) versus time

during CWI. The data plotted in this Figure can be divided into three parts: 1) main oil

displacement up to the BT of CWI, 2) oil swelling after trapping of the oil phase during the

main displacement, 3) coalescence of the isolated oil ganglia as a result of swelling and the

resultant more oil production. It should be noted that the micromodel is a two dimensional

(2D) porous medium and one would expect more oil connectivity and more oil

displacement in a more realistic 3-D realistic porous medium.


8

48

50

52

54

56

58

60

62

64

66

68

0 20 40 60 80

Time (h)

So

(%

)

Figure 8: Oil saturation in the micromodel versus time during CWI as a secondary

recovery method.

3.2 Tertiary Recovery

This test was carried out at the same condition of pressure and temperature as the previous

test with the purpose of investigating the performance of carbonated water injection (CWI)

as a tertiary (post waterflood) oil recovery method and comparing with the performance of

CWI as secondary recovery method.

In this test, after establishing the initial oil saturation, water was injected (at the same

injection rate of 0.01 cm3h

-1 as the previous test) into the micromodel. Water injection

continued until no further oil production and change in fluid distribution was observed.

Unlike the CWI test reported earlier, no more oil movement took place after the water

breakthrough (BT). After establishing residual oil saturation by water flooding, CWI was

performed with the same rate as the preceding water flooding (0.01 cm3h

-1). CWI was

continued until no further change was noticed. Finally a second water injection period was

commenced to determine dead-oil saturation and to compare it with the residual oil

saturation after first water injection.

Figure 9 shows a sequence of magnified images of the micromodel during various stages

of this test. Figure 9A and 9B show initial and trapped oil saturation after WI (plain water

injection), respectively. Although in this image there is some indication of film flow but

the main fluid displacement was piston-wise displacement as was the case for CWI in the

previous test. Figures 9C and 9D show fluid distribution after 23 and 100 hours of CWI,

Main Swelling Second displacement

1st displacement


9

respectively. Swelling and re-connection of isolated oil droplets in Figure 9C and

subsequent oil displacement can be seen in Figure 9D. Although Figure 9D, compare to

Figure 9C reveals oil displacement and production but to make a more accurate

comparison we conduct a second water injection to strip the dissolved CO2 out of the oil

and to obtain the dead oil saturation. Figure 9E, which shows the same selected frame of

the micromodel after the second WI, shows that oil shrank due to the stripping of the oil

from its dissolved CO2. Comparison of fluid saturation after first WI (Figure 9B) and

second WI (Figure 9E) confirms the additional oil recovery during CWI after WI.

Comparison of other parts of micromodel indicates fluid re-distribution as a result of cyclic

injection of water and carbonated water flooding. It seems that fluid re-distribution during

cyclic injection of water and carbonated water injection has potential to increased oil

recovery. Further investigation of this issue is currently under study.

Comparison of this test (tertiary) with the previous test (secondary) reveals that although

CWI recovered additional oil after BT both in the secondary and tertiary recovery tests, the

additional oil was recovered faster (40 hrs of CWI) and in larger quantity in the secondary

rather than tertiary (100 hrs of CWI) injection mode. CWI was continued in both these

tests till no further notable fluid distribution change was observed in the micromodel. The

main mechanisms of oil recovery by CWI, base on the results of these tests, are improved

sweep efficiency due to swelling and coalescence of the isolated oil ganglia and the

resultant fluid redistribution. It is also expected that a favourable increase in water

viscosity and decrease in oil viscosity would improve the CWI performance.

A


10

Figure 9: Fluid distribution in a selected frame of the micromodel showing oil recovery

process during CWI as a tertiary recovery method: A) initial oil saturation condition B)

Residual oil saturation after first WI, C and D) fluid distribution after 23 and 100 hrs of

CWI, respectively E) Dead oil saturation condition after second WI.

3.3 Diffusion Rate and Swelling Factor

The swelling of the oil during CWI was estimated by monitoring the size of oil ganglia

within the micromodel in the course of CWI. Figure 10 shows an isolated trapped in lower

part of the micromodel. Several highly magnified images of this oil were taken during

CWI (as tertiary recovery method). Figure 10 shows this oil drop at two different time

steps, t=1.72 and 8.35 hrs, respectively. Comparison of these images demonstrates swelling

of the oil during CWI. The numbers of pixels contained in the area covered by this oil

versus time is plotted in Figure 11. Assuming that the depth of this section of the

B C

D E


11

micromode is uniform, the amount of swelling based on these data was estimated to be

around 22.4%.

Figure 11 shows that the initial swelling rate is high but latter it slows down. The trend of

the curve demonstrates that the diffusion driving force reduces by time as it approaches

equilibrium.

A B

Figure 10: Swelling of an oil ganglion due to diffusion of CO2 from CW into oil phase

(n-Decane). A), and B) after 1.72 and 8.35 hrs respectively.

Oil Swelling

10000

10500

11000

11500

12000

12500

13000

13500

0 20 40 60 80 100

Time (h)

Pix

el N

o. o

f o

il p

ha

se

Figure 11: A typical curve of the swelling of the oil phase versus time in the micromodel.

22.4 % Swelling


12

3.4 Light Oil Versus Viscous Oil

Two main mechanisms of oil recovery during carbonated water injection are; the swelling

and subsequent coalescence of trapped oil ganglia and the reduction of oil viscosity as a

result of partitioning of CO2 from carbonated water and its dissolution into oil. The former

is a dominant mechanism in light oil due to higher CO2 solubility in this type of oil and the

latter is more relevant to more viscous oil due to significant reduction in viscosity of these

oils as a result of CO2 dissolution. To investigate the performance of CWI in viscous oil

and to compare the result with CWI into light oil (n-decane), a CWI test was carried out in

a viscous oil with an initial viscosity of 16.5 cP at the conditions of the experiments.

To allow a direct comparison, first, plain water was injected at the same slow rate of 0.01

cm3 h

-1 into the micromodel fully saturated with decane (representing conventional light

oils). The micromodel was full saturated with oil (no connate water) to facilitate the

comparison. Figure 12A shows a selected frame of the micromodel saturated with 100%

decane. Figure 12B shows fluid distribution after 1.25 hrs of WI (plain water injection). In

this test, due to the absence of Swi the displacement was piston wise. Based on image

analysis, after this water injection the residual oil saturation (Sor) in the whole micromodel,

was estimated at 42.6 %.

A B

Figure 12: A) 100% initial oil saturation B) Residual oil (decane) saturation after WI.

Following the above test, a similar test was carried out with the only difference being that

the viscous oil was used instead of decane. Figures 13A and 12B compare fluid

distribution after water injection in these two tests. As it can be seen, the recovery of

decane due to plain water injection (Figure 12.B) is more than viscous oil (Figure 13.A).

This is due to the fact that the mobility ratio of water-decane is more favourable than

water-viscous oil.

The test with the viscous oil was repeated and this time CWI was carried out instead of WI.

The test was then followed with WI to remove the dissolved CO2 from the oil in order to

obtain dead oil volume and compare the results with the previous tests. Figure 13B shows


13

the same section of the micromodel after CWI and WI. A comparison of Figure 13A and

13B shows that more oil has been recovered by CWI. The results show that CWI can be an

attractive oil recovery mechanism for viscous oils in which water flood efficiency is

generally poor.

A B

Figure 13: A). Residual viscous oil saturation after WI B) Residual dead viscous oil

saturation after CWI.

4. Conclusions

Based on the experimental work and results presented, the following conclusion can be

drawn:

1. CW increases oil recovery both as a secondary and tertiary recovery method.

However this increase is higher and takes place faster in the secondary flood

scenario.

2. Although more swelling was seen in decane than in heavier oil but CWI was more

effective in production of viscous oil. This was due to a significant reduction in

viscosity as a result of diffusion of CO2 into viscous oil.

3. The main mechanisms of oil recovery by CWI are improved sweep efficiency due

to swelling and coalescence of the isolated oil ganglia and the resultant fluid

redistribution. A favourable increase in water viscosity and decrease in oil viscosity

should also favour higher oil recovery.

4. The amount of oil swelling for decane as a result of diffusion of CO2 from CW at

2000 psia and 38 °C was estimated around 23%. The swelling rate is initially high

but later diminishes as it approaches the equilibrium conditions.


14

5. Blow down of the micromodel subsequent to a period of carbonated water injection

showed that residual oil saturation can be further reduced and more oil can be

recovered during this process.

5. Acknowledgements

The Carbonated Water Injection (CWI) project in the Institute of Petroleum Engineering at

Heriot-Watt University is supported equally by: the UK BERR (former DTI), Total

Exploration and Production UK, StatoilHydro, Dong Energy and Petrobras which is

gratefully acknowledged.

References

[1] Patel, P.D., Christman, R.G., and Gardner, J. W.: “An Investigation of Unexpectedly

Low Field-Observed Fluid Mobilities during Some CO2 Tertiary Floods”, SPERE

(November 1987) 507.

[2] Semere Solomon: ’’The Bellona Foundation- Fact sheet: CO2 Storage’’ Bellona

Report may 2007. http://www.bellona.org/factsheets/1191921304.33

[3] Sohrabi, M., Henderson, G.D., Tehrani, D.H. and Danesh, A.: ’’ Visualisation of Oil

Recovery by Water Alternating Gas (WAG) Injection Using High Pressure Micromodels -

Water-Wet System’’ SPE Annual Technical Conference and Exhibition held in Dallas,

Texas, 1–4 October 2000, SPE paper 63000.

[4] Sohrabi, M, Danesh, A., Tehrani, D. H and Jamiolahmady, M.’’ Microscopic

Mechanisms of Oil Recovery By Near-Miscible Gas Injection’’ Transp Porous Med. 2007.

[5] Sohrabi M., Danesh A., and Jamiolahmady M.,” Visualisation of Residual Oil

Recovery by Near-Miscible Gas and SWAG Injection Using High-Pressure Micromodels”,

Transport in Porous Media, January 2008.

[6] Sohrabi M., Riazi M., Jamiolahmady M., Ireland S. and Brown C.,’’Carbonated Water

Injection for Oil Recovery and CO2 Storage’’, Sustainable Energy UK: Meeting the

science and engineering challenge conference, 13-14 May 2008, Oxford

[7] National Institute of Standard and Technology Website. ’’http://www.nist.gov/srd/’’

Documents

Carbonated Water Injection (CWI) Studies - h. W · Carbonated Water Injection (CWI) Studies ... oil were tested to investigate the impact of oil type on the performance ... migration