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EnhancedOilRecoveryandCO2StoragebyCarbonatedWaterInjection

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DOI:10.2523/14070-ABSTRACT

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1

CARBONATED WATER INJECTION FOR OIL

RECOVERY AND CO2 STORAGE

M. Sohrabi, M. Riazi, M. Jamiolahmady, S. Ireland and C. Brown

Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, Scotland

Abstract

CO2 injection is increasingly considered as having potential applications as a possible

enhanced oil recovery (EOR) process for oil reservoirs. Storage potential of these

reservoirs to store CO2 for a long period of time also provides an opportunity to

develop sustainable solutions in response to the challenge of continued use of fossil

fuels, climate-change and compliance with national and international commitments to

reduce CO2 emissions. Poor sweep efficiency has been a problem in CO2-floods of

many oil reservoirs and hence, injection strategies like WAG (water-alternating-gas)

injection have been proposed and applied as a way to mitigate the problem. An

alternative injection strategy is carbonated water injection (CWI).

This paper describes some of the results of an ongoing research project to investigate

both experimentally and theoretically the process of CWI. The results of our flow

visualization experiments using high-pressure transparent micromodels, reveal the

underlying physical processes 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 the secondary recovery mode. The main

mechanisms of oil recovery by CWI are swelling and coalescence of the isolated oil

ganglia and the resultant fluid redistribution as a result of CO2 diffusion. A

favourable increase in water viscosity and decrease in oil viscosity also contribute to

this promising enhanced oil recovery method.

A one-dimensional mathematical model is also presented which honours the

experimental observations and simulates the dynamic process of oil swelling due to

CO2 dissolution with and without water layers separating the oil from the source of

CO2.

2

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 and to

meet the rising global energy demand. CO2 injection is increasingly considered as

having potential applications as a possible EOR process for these reservoirs. The pore

space available in these reservoirs can also store a significant amount of CO2 as part

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

Storage of CO2 in geological reservoirs is likely to provide the first large-scale

opportunity for concentrated storage of CO2. The method involves injecting carbon

dioxide directly into underground geological formations. Declining oil fields, saline

aquifers, and unminable coal seams are being considered as possible storage sites.

Based on international energy agency’s report (December 2006), global geological

storage potential equals at least equivalent of some 80 years current level of CO2

emissions (2000 GtCO2); Saline formations 400-10 000 Gt; depleted oil/gas fields

900 Gt; unmineable coal seams 30 Gt. Although hydrocarbon reservoirs might have

lower capacity than aquifers for geological CO2 storage, they are most likely to be

implemented first because of a number of reasons including additional economic

benefit through EOR, existence of abundant characterisation data and utilising at least

part of the existing infrastructure.

Studies show at depths below about 800–1000 m, CO2 has a liquid-like density that

provides the potential for underground storage in the pore spaces of sedimentary

rocks. CO2 can be trapped underground by various storage mechanisms, such as

(Semere Solomon 2007):

1. Trapping below an impermeable, confining layer or caprock (Structural and

stratigraphic trapping or physical trapping)

2. The CO2 is retained or adhered on the surfaces of the pore spaces of the

storage formation so that it becomes contained as immobile phase (Residual

CO2 trapping)

3

3. Dissolved in the fluids contained in the pore spaces of the formation

(Solubility or dissolution trapping), and

4. Additionally, it may be trapped by reacting with the minerals in the storage

formation and caprock to produce carbonate minerals (Mineral trapping).

CO2 becomes less mobile over time as a result of multiple trapping mechanisms,

further lowering the prospect of leakage, which builds the confidence in geological

security of carbon dioxide storage.

CO2 has been injected into oil fields for the purpose of EOR (enhanced oil recovery)

for more than 30 years, to increase oil recovery. CO2 injection for EOR and storage is

attractive because the additional oil recovery can offset at least part of the CO2

storage costs. Further benefits might include:

• Low-cost exploration, because the geology is already well known

• Proof that the reservoirs have been capable of retaining liquid and gases over a

very long period of time.

• Production and often injection equipment already installed on site, which

could be used to transfer and inject CO2.

• Regulations already in existence.

• All oil fields have a geological barrier preventing upward migration of oil. It is

supposed that these geological barriers will also be sufficient as long-term

barrier to contain the injected CO2

Many of the reservoirs today are produced efficiently with water injection and have

been for some time. However, after water flooding, quite a large volume of oil is still

left in the reservoir. There is thus a good scope for CO2 storage due to high CO2

solubility in the oil phase.

CO2 injection to enhance oil recovery is well documented. CO2 injection into an oil

reservoir increases oil recovery by primarily altering the physical properties of the oil

phase i.e. swelling of the oil, reduction of oil viscosity, reduction of interfacial tension

to water 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

4

problem in CO2-floods of many oil reservoirs (Patel, P.D. 1987). 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 might have advantages over direct CO2 injection in terms of 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 might in turn improve increase the rate of CO2 diffusion and the

subsequent oil swelling. It has been shown that in direct CO2 injection, due to low

sweep efficiency and gravity segregation, the time scale of diffusion can be several

years (Semere Solomon 2007). In terms of CO2 storage, as 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 understand the dominant mechanisms in carbonated water injection

(CWI) a series of two phase fluid flow experiments were performed using high-

pressure two dimensional glass micromodel. CWI as both secondary and tertiary oil

recovery processes was studied. The recorded video clips of these tests give

quantitative and qualitative information which are being used in our modeling work.

A mathematical model has been developed to simulate the CWI process at the pore

level. The dynamic process of swelling of an oil droplet separated from a CO2 source

(carbonated water) by a water layers as well as when it is in direct contact with CO2

source was studied.

One of the advantages of this model could be the estimation of the effective diffusion

coefficient in porous media, which can be considered as a matching parameter

between the results of the model and the experiments under the same prevailing

conditions. Partition coefficient is another important pertinent parameter that can be

determined in similar manner.

5

EXPERIMENTAL WORK

Experimental Facilities

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

water injection tests. The rig can operate at pressures as high as 5000 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

publications (Sohrabi et al, 2000, Sohrabi et al, 2007, Sohrabi et al, 2008). The

micromodel rig is shown schematically in Figure 1. The rig consists of the following

major components.

Fluid Storage Oven

A temperature-controlled air oven is used to store the injection fluids, lines and

connections at constant temperature. In this part of the rig there are six storage cells,

five of which are for injection of CO2 in temperature equilibrium with water (gas),

carbonated water, plain water, oil and overburden fluid (glycerol) and one is used to

retract the fluids from bypass and micromodel outlet.

Micromodel Oven

Another temperature-controlled air oven is used to maintain the overburden chamber,

which houses the micromodel and maintains it at constant temperature. This chamber

can be turned to allow performing flow tests at any desired degree of orientation,

including vertical and horizontal. This is particularly important for inclusion or

exclusion of the gravity effects.

Low Rate Pumps

To inject fluid into the system (micromodel and overburden chamber) two low-rate

pumps are being used. A third pump is used to pull back the fluids and collect them

into the retract cell. The pumps are capable of working at pressures up to 5000 psia

with a flow rate in the range 0.0001 to 14 cm3/hr.

Optical System

A camera mount and positioning system is used which allows a camera and its

magnifying lens to be positioned at any part of the micromodel. It is also used to scan

6

the micromodel for video and still image recording. Figure 2 shows the optical system

of the rig.

Glass Micromodels

A two-dimensional pore structure is etched onto the surface of a glass plate, which is

otherwise completely flat. A second glass plate is then placed over the first, covering

the etched pattern and thus creating an enclosed pore space. This second plate, the

cover plate, has an inlet hole and an outlet hole drilled at either end, allowing fluids to

be displaced through the network of pores (Figure 3). Because the structure is only

one pore deep, and the containing solid walls are all glass, it is possible to observe the

fluids as they flow along the pore channels and interact with each other. It is also

possible to observe how the geometry of the pore network affects the patterns of flow

and trapping.

At this stage of the project a water-wet micromodel with a geometric pore pattern has

been used. The micromodel dimensional characteristics are shown in Table 1.

Test fluids

The fluid system used in the experiments consisted of distilled water, n-Decane and

carbon dioxide. Carbonated water was prepared by mixing degassed distilled water

with CO2 in a rocking cell at 38 °C and 2000 psia. The content of the rocking cell was

mixed for a long period of time while its pressure was monitored. Obtaining constant

pressure during mixing is a good indication that the fluids inside the cell are at

equilibrium and the pressure can be considered the equilibrium pressure. Finally, the

equilibrium phases were transferred into their storage vessels and maintained at the

test pressure and temperature.

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

changed to blue using a water-soluble dye. In two of the preliminary tests, the colour

of oil (n-Decane) was changed to red using an oil soluble red dye but some evidence

of wettability alteration, away from strongly water-wet, was observed so it was

decided to eliminate the red dye in the oil phase. The dyed fluids were filtered using

fine filter papers to remove any un-dissolved dye particles.

7

Test procedure

In the tests reported here, the micromodel orientation was horizontally to minimise

the gravity effect. After cleaning and pressurising the system, the (water-wet)

micromodel was fully saturated with clear distilled water and subsequently displaced

with blue dyed water, Figure 4. Figure 5 shows a part of micromodel 100% saturated

with degassed blue dyed water. Similar images, taken from the middle of micromodel

and in higher magnification, were prepared to show the details of changes of fluid

distribution during the tests. The whole micromodel is made up ten of these frames. It

should be noted that the entire micromodel was used to estimate the swelling, oil

saturation and amount of oil production during the experiments. 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.

The oil injection was carried out at a rate of 2 cm3

h-1

. Figure 6 reveals the irreducible

(connate) water saturation (Swi), established after oil injection for the same section of

micromodel shown in Figure 5. 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 interface and the fact that some of the smaller and dead-end pores are filled

with water phase are good indications of water-wet conditions.

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

experiments were carried out to study carbonated water injection process as both

secondary and tertiary oil recovery mechanisms. In the first test, CW (carbonated

water), as a secondary recovery method, was injected at a low rate of 0.01 cm3

h-1

into

the micromodel saturated with oil at Swi.

Figure 7 shows the fluid distribution (in the same section of the micromodel shown in

Figure 5) after breakthrough (BT) of CW (injected as a secondary recovery

mechanism). As this image demonstrates, the oil phase has been disconnected 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 displacement.

8

Figure 8 shows fluid distribution within the selected section of the micromodel after

79 hrs of CWI. Comparison of this image with Figure 7 shows both swelling and

reconnection of some oil ganglia due to this swelling as well as oil displacement in

this frame of the micromodel. In Figure 8, the red rectangle demonstrates an example

of oil reconnection due to swelling during CWI.

Figure 9 shows some magnified images that were taken from another section of the

micromodel in this experiment. These images show fluid distribution during different

stages of CWI (as a secondary oil recovery method). Figure 9A shows the initial oil

saturation (oil is shown in bright colour) after the irreducible (connate) water

saturation (Swi) (blue) was established. Figure 9B shows the fluid distribution after the

breakthrough (BT) of CWI. The main production of oil happened at this stage and the

un-recovered oil remained trapped. Figure 9C illustrates oil swelling after about 19

hrs of CWI and the resultant coalescence of some of the oil blobs enriched with CO2.

CW has been displaced by the swollen oil in several locations (highlighted by red

rectangles in Figure 9B and 9C). Figure 9D shows a second oil displacement and

reduction of Sor, i.e., oil production, (highlighted by pink rectangles in the frames C

and D) due to the coalescence of the trapped oil blobs and the resultant change in the

fluid distribution. In the second test, CWI as a tertiary recovery method, after the

breakthrough of the injected water, no more oil production and changes in fluid

distribution took place. This confirms that the change in fluid distribution, after BT of

CWI, as mentioned above, is due to the diffusion of CO2 from CW into the oil phase.

The oil saturation of the porous section of the micromodel was estimated using the,

Adobe Photoshop CS image analysis software. In this method we estimated fluid

saturation based on the number of pixels representing each phase. The depth of the

pores in the micromodel was assumed equal.

Figure 10 and Table 2 show oil saturation in the micromodel versus time during CWI.

The data of this Figure can be divided into three parts: 1) main oil displacement after

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

9

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

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

In the second test, CWI as a tertiary oil recovery method, water was first injected at

the same injection rate of 0.01 cm3h

-1 into the oil saturated micromodel at Swi till no

further oil production and change in fluid distribution observed. Then CWI was

performed with the same rate as the preceding water flood.

Figure 11 shows oil saturation in the micromodel versus time for this test. Table 3

gives the same data in Tabular form. The green line in Figure 11 shows WI stage. The

main oil recovery took place as a result of WI and in a relatively short period of time

compared to the rest of this experiment. The blue line indicates the second stage of

this test that corresponds to the main swelling as a result of CWI. At the end of this

stage some oil (estimated around 2.3 %) was produced, which is shown as a drop in

oil saturation at the end of the curve of Figure 11.

A comparison of these two tests revealed that although CWI recovered extra oil after

BT both as secondary and tertiary recovery methods, the extra oil was recovered

faster and in larger quantity in the secondary rather than tertiary 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 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.

It is not possible to show the swelling curve of the whole micromodel as oil

displacement and production continues when swelling is in progress. Hence, we

focused on an oil drop trapped in lowest part of the micromodel. CW trapped this oil

after entering the porous section of the micromodel. Several highly magnified images

were taken during CWI. Figure 12 shows this oil drop at three different time steps,

t=0, 5.43 and 93.17 hrs, respectively. The approximate dimensions of this oil drop are

477 mµ * 135 mµ as shown in Figure 12. Comparison of these images indicates some

swelling during CWI. It was assumed that the depth of this section of the micromode

10

is uniform. The numbers of areal oil phase pixels are given in Table 4 and plotted in

Figure 13. The amount of swelling based on these data was estimated to be around

22.4%.

Based on equilibrium condition of these two tests the stored CO2 in the residual oil

saturation is about 18 Vol% (23% of dead oil volume) and in water phase around 7

Vol%, Table 5 compares the percentage of CO2 in the micromodel after CWI in both

tests. This data reveals that although the oil recovery in the second test is less, the

amount of CO2 storage (13.37%) is higher than the corresponding value in the first

test (12.94%) mainly due to higher CO2 solubility in oil compare to water.

This amount of storage in real scale is huge and considerable: Based on the recent

UK production Data Release (1 April 2008) the total injected water in all the oil fields

in the UK, offshore and land oil fields, in the last year, 2007, was about 7.1E+7 tons.

A rough estimate shows that if carbonated water had been used instead of water,

assuming the same level of CO2 solubility observed in our experiments, we would

have had about 4.05E+6 tones of CO2 storage.

MATHEMATICAL MODELING

One of the most important mechanisms that could lead to increased oil recovery in

CWI process is swelling, coalescence and remobilisation of the isolated oil ganglia as

a result of the diffusion of CO2 from CW into the oil. The impact of CO2 diffusion in

direct CO2 injection, as a tertiary oil recovery mechanism, has been investigated by

several researchers (Grogan, et al. 1987, 1988- Campell, et al. 1985- Do 1993-

Bijeljic, et al. 2002). In all these studies the presence of a water layer separating the

oil and CO2 phases has been shown to have a significant negative impact on the CO2

diffusion process. However, the impact of pertinent parameters on CWI process is yet

unknown.

Figures 14.A and 14.B show a schematic diagram of an isolated oil droplet in a dead

end pore for two different scenarios. In the first scenario, oil is surrounded by flowing

CW (CO2 source). In the second case water (from previous water flood) is separating

oil from injected CO2 source (CW).

11

Figures 15.A and 15.B are 1-D demonstrations of CO2 concentration in water, oil and

CW for the above mentioned two scenarios, respectively. We have assumed that CO2

concentration in the flowing CW is constant. The CO2 concentration in the oil phase

at the interface is more than that in the water (or carbonated water) phase due to its

increased solubility. This value can be estimated assuming CO2 concentrations in the

two phases are at equilibrium at the interface using partition coefficient as follows:

WCOowCOOCO CKC −−− = 2/22, (1)

where KCO2-w/o is the water/oil-CO2 partition coefficient, which is defined as the ratio

of the equilibrium concentrations of a solute (CCO2 in this case) in two largely

immiscible solvents.

CCO2-O is the CO2 concentration in the oil phase,

CCO2-W is the CO2 concentration in the water phase.

The following further assumptions were made:

1. The effect of capillary force on the interface is neglected, i.e., the interface is

flat.

2. CO2 diffusion coefficients in oil and water are constant during the diffusion

process.

3. The fluid system is an ideal mixture, that is, the total volume is the summation

of volumes of oil and CO2.

4. The partial density of CO2 is known and constant.

5. The change in the volume of water barrier due to CO2 diffusion has been

neglected, in the second scenario.

6. Oil, water and CW are at equilibrium conditions at the CW/water interface and

the water/oil interface.

7. In the model (Figure 15), oil/water boundary in the second scenario and

oil/CW boundary in the first scenario moves to the right due to the swelling of oil

only. The resultant displaced water will be flowing with no additional resistance with

the main flow stream.

12

Governing Equations

Second Fick’s law states that CO2 concentration in oil and water is a function of time

(t) and position (x, y and z). Equation 2 expresses this relationship in our 1D (one

dimensional) system:

2

2

2

22 ),(),(

x

xtCD

t

xtC COCOCO

∂

∂=

∂

∂ (2)

The oil volume increases because of increased CO2 concentration due to CO2

diffusion. A combination of mass balance and the assumption of an ideal mixture,

gives Equation 3, which determines the speed of interface movement:

)](1[

])(

)([)(

2

2

2

2

2

2

tCMw

t

tCtx

Mw

dt

tdx

CO

CO

CO

CO

CO

CO

ρ

ρ

−

∂

∂

= , (3)

where )(2 tCCO and t

tCCO

∂

∂ )(2 are the volumetric average of CO2 concentration and its

gradient with respect to time, at any time, and are calculated using Equations 4 and 5,

respectively.

)(

),(

)(

)(

0

2

2tx

dxxtC

tC

tx

CO

CO

∫= , (4)

)(

),(

)(

)(

0

2

2

tx

dxt

xtC

t

tC

tx

CO

CO

∫ ∂

∂

=∂

∂. (5)

Initial and Boundary Conditions

Equations 2 to 5 describe the dynamics of the process. In the case of first scenario,

direct contact of oil and carbonated water, two initial conditions and two boundary

conditions are required, to solve equations 2 to 5, as follows:

Initial CO2 concentration in oil is zero, 0)0(,2 ==tC OCO ,

13

The initial position of interface (xi) is known.

At oil/water interface, right hand side boundary of oil domain (Figure 15.A),

concentration of CO2 in the water phase is known and that of the oil phase is

calculated using Equation 1.

There is no diffusion at the left hand side boundary.

To solve this set of equations, for the second scenario, three initial conditions and four

boundary conditions, two for each (oil & water) sub-domain, are required. The initial

conditions are:

Initial CO2 concentration in oil is zero, 0)0(,2 ==tC OCO ,

Initial CO2 concentration in water is zero, 0)0(,2 ==tC wCO ,

The initial position of interface (xi) is known.

At oil/water interface, the right hand side boundary of the oil domain (Figure 15B),

CO2 diffuses from a high CO2 concentration calculated using Equation 1. The CO2

concentration on the left hand side of water domain at this interface is updated from

the solution of Equation 2. The left hand side boundary of oil domain is a no flow

boundary without any diffusion.

At the water/CW interface, right hand side of water domain (Figure 15.B), CO2

diffuses from a high CO2 concentration, which is equal to the CO2 concentration in

CW.

Solution Technique

The partial (Equation 2 for both oil and water) and ordinary (Equation 3) differential

equations together with two auxiliary equations (Equations 4 and 5) and the

associated boundary and initial conditions described above were solved using Comsol

multi-physics, which is based on the finite element method.

In this study, we initially verified the integrity of the model by simulating the

experiment conducted by Campbell, et al. (1985). In Campbell’s experiment

Soltrol130, which is a mineral oil, was used as the oil phase, so the result of this

section of study is based on Soltrol 130 for which all the required data are available

from the literature (Campbell, et al., 1985 and Grogan and Pinczewski, 1987). The

modelling of explained our experimental results are underway.

14

The process under this study and the equation described above are for a 1-D system

but here, to show the result more clearly, we used a 2-D sub-domain. Considering the

symmetry in y-direction, this will not affect the results and conclusions of the study.

Figure 16A shows an example of CO2 concentration in the oil phase in the developed

model, second scenario, after 3000 sec. This image also shows the amount of

oil/water interface movement after this time. The corresponding CO2 concentration in

the water phase has been shown in Figure 16B. Comparison of these two Figures

highlights that the model correctly assign a higher CO2 concentration in oil than that

in water at the oil/water interface which are related to one another by Equation 1.

Figure 17 shows the displacement of the oil/CW interface versus time for the swelling

process of the first scenario, direct contact of oil and CO2 source (CW), Figure 15A.

Figure 18 shows the displacement of the oil/water interface versus time for the

swelling process of the second scenario, indirect contact of oil and CO2 source (CW),

Figure 15B. These two Figures, similarly to the experimental results, shown in Figure

9, demonstrate the initial swelling rate is high but later it slows down. There are two

groups of parameters that affect CO2 diffusion from CW into the oil phase. The first

group includes; contact area between oil and water and CO2 diffusion coefficient. The

increase in these parameters increases the swelling rate. Swelling increases the contact

area hence, increasing the diffusion rate. The Oil viscosity decreases by increasing

CO2 concentration in oil phase, (Holm, L. W. (1974), Miller, J. S. (1981), Barrufet M.

A., et al. (1996), Simon, R (1964)). MacManamey and Woollen, 1973, based on some

experimental data, presented an empirical correlation to express the increase in CO2

diffusion coefficient with a decrease in oil viscosity. The second group contains the

difference between concentration of CO2 in the oil and water phases (driving force)

and the length of oil phase. The former decreases whilst the latter increases with time,

both reduce the mass transfer rate and hence, swelling rate. The trend of Figures 17,

18 and 9 prove that the parameters in the second group win this competition in the

direction of reducing the swelling rate.

There is another important point that should be considered based on comparison of

the result of the first and second scenario: Although in this case DCO2-w is higher than

15

DCO2-o but the swelling time for the second scenario (2500 seconds for the base case

with 0.4 mm water barrier thickness) was not only significantly longer than that in the

first scenario (360 seconds for the same base case with 0.7 mm oil thickness) but also

longer than that corresponding to oil thickness of 1.1 mm, i.e., replacing water with

oil, as well (860 sec) highlighting the major negative impact of the water layer on

CO2 diffusion from CW to oil.

It should be noted that the swelling time which were reported above is based on the

required time for the interface to reach to 95% of its equilibrium position; the

remaining 5% interface movement required significantly longer time due to the

reduced diffusion gradient, i.e., driving force. Hence, the 95% of the final equilibrium

interface position is considered as equilibrium time.

Figure 19 shows the swelling curve of these three systems. Comparison of the curves

indicates that water barrier thickness is an important parameter in decreasing the CO2

diffusion rate from carbonated water into oil. Based on these data the swelling time of

the second scenario is the longest time, although the amount of swelling of the third

case, oil with thickness of 1.1 mm is higher and one expects more time to reach

equilibrium conditions.

CONCLUSIONS

Experimental work:

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

However this increase is higher in the secondary flood scenario.

2. The fluid flow displacement mechanism for both WI and CWI was both

piston-wise and film flow in different places of micromodel.

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%.

16

5. Although the oil recovery in the second test was less, the amount of CO2

storage (13.37%) is higher than the corresponding value in the first test

(12.94%) mainly due to higher CO2 solubility in oil compare to water

Modelling

1. We have successfully simulated the dynamic process of swelling of an oil

droplet separated from a CO2 source (carbonated water) by a water barrier as

well as when it is in direct contact with CW.

2. Although the DCO2-w used in this study is higher than DCO2-o but the swelling

time for the second scenario is significantly longer than that in the first

scenario highlighting the major negative impact of water barrier on CO2

diffusion from CW to oil.

3. The modelling results, similarly to the experimental results, show that the

initial swelling rate is high but later it slows down, mainly due to reduction of

driving force by time.

NOMENCLATURE

2COC = CO2 concentration [mol m-3

]

OCOC −2= CO2 concentration in the oil phase [mol m

-3]

WCOC −2= CO2 concentration in the water phase [mol m

-3]

2COD = Diffusion coefficient of CO2 in oil or water [m2 s

-1]

owCOK /2− = water/oil-CO2 partition coefficient [-]

Lo= Oil thickness [m]

Lw= The shielding water thickness separating oil and CW [m]

2COMw = CO2 molecular weight [kg mol-1

]

So= saturation of oil [%]

Sw= saturation of water [%]

t = time [s]

)(tx = length [m]

2COρ = CO2 density [kg m-3

]

ACKNOWLEDGEMENTS

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

Engineering at Heriot-Watt University is supported equally by: Total Exploration and

Production UK, StatoilHydro, Dong Energy and the UK BERR (former DTI) which is

17

gratefully acknowledged. The authors wish to thank the COMSOL support team for

helping us with their mathematical package.

REFERENCES

Barrufet, M. A., Said El-Sayed K., Tantawy S. M., Gustavo A. Iglesias-Silva, ‘’

Liquid Viscosities of Carbon Dioxide + Hydrocarbons from 310 K to 403 K’’ Journal

of Chemical and Engineering Data, Vol. 41, No. 3, 1996.

Baviere, M. ‘’Basic Concepts in Enhanced Oil Recovery Processes’’ Elsevier Applied

Science, 1991

Bijeljic B. R., Muggeridge A. H., Blunt M. J.’’ Effect of Composition on

Waterblocking for Multicomponent Gas floods’’ SPE 77697, SPE annual Technical

Conference and Exhibition held in San Antonio, Texas, 29 Sep-2Oct 2002.

Campbell B. T., Orr, Jr F. M. ‘’Flow Visualization for CO2/Crude-Oil

Displacements’’ SPE 11958, Oct 1985.

Do H.D., Pinczewski W.V. ‘’ diffusion controlled swelling of reservoir oil by indirect

contact with injection gas’’ Chemical engineering science Vol.48, No18, PP. 3243-

3252, 1993.

Dodds, W. S. Stutzman, L. F. and Sollami, B. J. ’’Carbon Dioxide Solubility in

Water, ’’industrial and engineering chemistry vol. 1, no. 1, 1956.

Grogan A.T., Pinczewski W.V.,’’ The Role of Molecular Diffusion Processes in

Tertiary C02 Flooding’’ JPT May 1987 and SPE 12706.

Holm, L. W. and Josendal, V. A.’’ Mechanisms of Oil Displacement By Carbon

Dioxide’’ SPE 4736, Dec 1974.

IEA Energy Technology Essentials http://www.iea.org/textbase/techno/essentials.htm

IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared

by Working Group III of the Intergovernmental Panel on Climate Change [Metz, B.,

O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)]. Cambridge

University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.

Geoscience Issues:’’ A technological pathway for combating climate change, CO2

capture and storage in the subsurface’’.

McManamey, W.J. and Woolen, J.M.: ‘’The diffusivity of carbon Dioxide in organic

Liquids at 25°C and 50°C,’’ AIChE J. (May 1973) 19, No. 3, 667-69.

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.

18

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

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

2007.

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.

Miller, J. S. and Jones, R. A. ‘’A laboratory study to determine physical

characteristics of heavy oil after CO2 saturation’’ SPE/DOE 9789 April 1981.

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

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

UK Production Data Release, Department for Business, Enterprise and Regulatory

Reform Energy Group, released data 01April 2008.

https://www.og.dti.gov.uk/pprs/pprsindex.htm

Table 1: Dimensional Characteristic of the Micromodel.

Height

/cm

Width

/cm

MM PV

/cm3

Ave. Pore depth

/ mµ

Pore Dia. Range

/ mµ

4 0.7 0.01 50 30-500

Table 2: Oil saturation within micromodel at different times for the first test.

Time

(hours)

Oil Saturation

(%)

0.00 66.5

0.11 61.6

0.33 48.4

0.68 49.2

3.00 50.6

19.28 54.4

41.25 56.9

55.55 56

79.15 54

Table 3: Oil saturation within micromodel at different times for the second test.

Time

(hours)

Oil Saturation

(%)

0.00 72.3

0.50 44.8

4.70 47.1

6.28 49.6

23.13 57.1

70.38 58.6

19

100.23 57.9

Table 4: Volume of the oil droplet in Figure 12 at different times.

Time

(hours)

Pixel No of

oil droplet

0.00 10846

1.53 11561

3.50 12022

5.43 12176

21.97 12928

26.40 12963

29.98 13053

45.85 13176

72.27 13197

93.17 13271

Table 5: Estimated CO2 storage in the micromodel for both tests.

First test (CWI as secondary

recovery method)

Second test (CWI as

tertiary recovery method)

Oil Saturation (%) 54 57.9

Water Saturation (%) 46 42.1

CO2 percentage in the oil

phase (%) (So*18%)

9.72 10.42

CO2 percentage in the

water phase (%) (Sw*7%)

3.22 2.95

Percentage of CO2 in the

micomodel (%) 12.94 13.37

20

P

u

m

p

3

CW

P

u

m

p

2

P

u

m

p

1

P

water

water

P

P

water/oil

l fill

Gas

PP

PP

P

Figure 1: Schematic Diagram of the Micromodel Rig

Figure 2: Schematic Diagram of the Optical System (Mehran Sohrabi 2000).

Windows

Micromodel oven

Fluid storage oven

Pumps

21

Figure 3: The etched plate and the cover plate are brought together to form an

enclosed pore space through which fluids can be displaced (Mehran Sohrabi 2000).

Figure 4: The whole micromodel including two triangle sections fully saturated with

degassed blue dyed water.

22

Figure 5: A magnified section of micromodel fully saturated with degassed blue dyed

water.

Figure 6: Initial oil saturation (n-Decane) in the same selected frame shown in the

Figure 5.

Water

Grain, glass

Oil

23

Figure 7: Fluid distribution in the same selected frame shown in the Figure 5, after

0.33 hrs of CWI, secondary recovery method.

Figure 8: Fluid distribution in the same selected frame shown in the Figure 5, after 79

hrs of CWI, secondary recovery method.

Snapped Oil ganglion

Bypassed oil droplet

24

A: Soi B: CWI after 0.68 hrs

C: CWI after 19.28 hrs D: CWI after 79.15 hr

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

recovery process during CWI as a secondary recovery method.

CW

25

48

50

52

54

56

58

60

62

64

66

68

0 20 40 60 80

Time (h)

So

(%

)

Figure 10: Oil saturation versus time during CWI as a secondary recovery method.

43

48

53

58

63

68

73

78

0 20 40 60 80 100

Time (h)

So

(%

)

CWI WI produced oil

Figure 11: Oil saturation versus time during CWI as a tertiary recovery method.

Main Swelling Second displacement

1st displacement

2.3%

26

Figure 12: Swelling of an oil droplet due to diffusion of CO2 from CW into oil phase

(n-Decane).

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 13: Volume of the oil droplet in Figure 12 versus time.

22.4 % Swelling

A: t=0 B: t=5.43 hrs C: t=93.17 hrs

0.477 mm 0.135 mm

27

(A)

(B)

Figure 14: An oil drop trapped in a dead-end pore surrounded by (A) flowing

carbonated water (CW), direct contact (B) water and CW flowing next to the water

phase, indirect contact.

(A)

(B)

Figure 15: CO2 concentration profiles during CWI for the (A) first scenario (Figure

14.A), direct contact, and (B) second scenario (Figure 14.B), indirect contact.

Water

Oil

CW

Flow

Oil

CW

Flow

CW W Oil

X1

CO2

X2

CW Oil

CO2

X1

28

(A)

(B)

Figure 16: CO2 concentration profile in the A) oil phase B) water phase after 3000

sec. Oil swells due to diffusion of CO2 from carbonated water into oil through water.

Initial oil length Initial water length

Oil length during swelling Length of water after

swelling of oil

Initial position of oil/carbonated

water interface

Movement of oil/water interface

due to swelling of oil phase

29

1st Scenario

0.0E+00

5.0E-05

1.0E-04

1.5E-04

2.0E-04

2.5E-04

3.0E-04

3.5E-04

4.0E-04

0 100 200 300 400 500 600 700 800

Time (sec)

Dis

pla

cem

en

t (m

)

Swelling

Figure 17: The oil/CW interface displacement for swelling of an oil droplet versus

time in the first scenario, Figure 15.A, direct contact of oil and CW

2nd Scenario

0.E+00

5.E-05

1.E-04

2.E-04

2.E-04

3.E-04

3.E-04

4.E-04

4.E-04

0 1000 2000 3000 4000 5000 6000 7000

Time (sec)

Dis

pla

cem

en

t o

f o

il/w

ate

r in

terf

ace

(m)

Swelling

Figure 18: The oil/W interface displacement for swelling of an oil droplet versus time

in the second scenario, Figure 15.B, indirect contact of oil and CW,

30

0.E+00

1.E-04

2.E-04

3.E-04

4.E-04

5.E-04

6.E-04

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

Time (sec)

Dis

pla

cem

en

t (m

)

1st scenario, Lo= 0.7mm

2nd Scenario Lo= 0.7, Lw=0.4mm

Lo=1.1 mm

Figure 19: swelling of oil in first and second scenario and the impact of water barrier

on reduction of swelling rate.