Water Alternating Gas Injection Studies – Phase 1

Water Alternating Gas Injection Studies – Phase 1

D. H. Tehrani, A. Danesh, G. Henderson and M. Sohrabi

Department of Petroleum Engineering, Heriot-Watt University

Summary

The Department of Petroleum Engineering at Heriot-Watt University has been studying the water

alternating gas (WAG) injection processes, using experimental (micromodels) and theoretical

(network modelling) methods during the past 3 years. Last year we presented the results of the

micromodel studies on water-wet systems. This paper presents the results of the experiments on

oil-wet and mixed wet systems and compares them with those of the water-wet models. A sister

paper by K. S. Sorbie et al. will present the results of the network modelling studies.

Many of the oil reservoirs, including those in the North Sea, are approaching the end of their

waterflooding. At this stage a significant quantity of oil will still remain in the reservoir. It is

known that using the WAG injection some of that oil can be produced. Unfortunately, the

underlying physics of the three-phase flow is not well understood to allow reliable predictions to be

made for economic evaluation. WAG injection will involve drainage and imbibition processes

taking place sequentially. The three-phase relative permeability and capillary pressure functions

are, therefore, extremely complex. It is practically impossible to develop such functions for

realistic reservoir situations, using core displacement methods. The approach we have adopted is to

develop a mathematical network simulator, which covers all the significant physical flow processes

involved in the WAG injection. But to gain confidence that such a simulator can indeed reflect the

physics of the flow realistically, we test it against the actual physical micromodel observations. If

the predictions of the simulator agree with those observed in the micromodel, we can then operate

the simulator with real reservoir fluid data and basic rock properties in 3-D, to calculate the required

pore scale relative permeability functions, Fig.1. Observations made in the micromodel studies

have considerably improved our understanding of the underlying physical principles. This

knowledge is extremely valuable in formulation of our network model simulator.

Introduction

Waterflooding, gas injection and wateralternating-

gas injection (WAG) are wellestablished

methods for improving oil

recovery. In reservoirs that have been

waterflooded, it is still possible to recover a

significant quantity of the remaining oil by

injecting gas alternately with water. Gas can

occupy parts of the pore space that otherwise

would be occupied by oil, thereby mobilising

the remaining oil. Water, injected subsequently,

will displace some of the remaining oil and

gas, further reducing the residual oil saturation.

Repetition of the WAG injection process can

further improve the recovery of oil.

Christensen, Stenby and Skauge1 reported an

excellent review of some sixty fieldapplications

of WAG. Several field trials

have been reported as being successful, e.g., in

Kuparuk2, Snorre3 and Gulfaks fields4. Both

immiscible4-6 and miscible gases7 have been

used. A very large number of coreflood

experiments8-12 and analytical and numerical

simulations11,14 have been carried out. A

recent study has considered the WAG process

for improving the hydrocarbon recovery in

gas/condensate reservoirs13. Most of the

research work, conducted so far, has been on

either core flooding8,9,10 or numerical

simulation11,12, sometimes alongside field

trials. The relationship between the injection

gas/water ratio and oil recovery has been

empirically investigated using core displacement

experiments, often at low pressure and

generally with water wet cores8,10.

Micromodels were used as early as 1960 for

fluid displacement studies15. Some lowpressure

micromodel studies of three-phase

displacement have also been performed16,17.

However, as far as we know, no micromodel

visualisation of the WAG injection has been

carried out to directly observe the physical

processes taking place in the porous media,

using live oil, live water in equilibrium with

injection gas and models with different

wettability. Larsen et al.18 reported some

limited results of their WAG micromodel

studies.

To do reservoir development planning, for

possible implementation of a WAG scheme,

the operator needs reliable performance and

hydrocarbon recovery prediction, to use for

economic evaluation. To achieve this, good

simulation incorporating proper reservoir fluid

and rock description is needed. This requires

accurate sets of relative permeability and

capillary pressure functions in a three-phase

fluid flow regime. But it is impractical to

measure these for all the different rock types

and fluids present in a reservoir and describe

them in terms of IFT which, itself is a function

of fluid composition and pressure. We are

attempting to develop a 3-phase 3-D

mathematical network simulator, which has in

it all the significant physical flow processes

involved in WAG injection, formulated as

accurately as possible. But to gain confidence

that such a simulator can indeed reflect physics

of the flow realistically, we test it against a

series of WAG experiments performed using

micromodels. We can conduct the actual WAG

injection, observe and record the flow

processes and measure the model fluid

saturations and recoveries. To enable us to

magnify and view the pore scale images and to

analyse the fluid flow, we have had to use 2-D

glass micromodels and model fluids with

known properties. Although the results will not

be directly applicable to any real reservoir,

they can be used to verify the accuracy of the

predictions made by our network model

simulator. We will then run the pore scale

simulator to predict the fluid distributions and

the recoveries for a given set of pore geometry,

wettability and fluid properties. If these agree

with those observed and measured in the

micromodel (Figs. 2 to 5), we shall then have

enough confidence, to operate it with real

reservoir fluids and rock properties in 3-D

mode, to calculate the required pore scale

relative permeability and capillary pressure

functions (Fig. 1). These will later be upscaled

for use in the numerical reservoir scale

simulation.

Objective

The objective of the current micromodel

studies is to improve our understanding of the

physical principles underlying such processes

taking place in porous media and to develop a

network model simulator that can produce

complex three-phase relative permeability and

capillary pressure functions. Observing and

recording the fluid flow behaviour within the

micromodel during the WAG injection process

will help achieve this. The video record of the

fluid displacements is used to obtain

qualitative and quantitative information on

three-phase fluid flow during WAG injection.

These will then be used to compare with the

results of the network model, which will

attempt to simulate the same processes, using

the micromodel fluids and geometrical data. If

the simulated results match the fluid

distribution and the recovery data obtained by

the experiments reasonably well, then it can be

confidently used to simulate and obtain the

three-phase relative permeability and capillary

pressure functions, using realistic reservoir

rock and fluid properties in three-dimensional

space, Fig. 1.

Experimental Facilities, Test Fluids and

Procedure

These have been described in our report to the

DTI IOR Seminar of June 200019.

Wettability Alteration

Strongly water-wet micromodelThe procedure for preparation of water-wet

micromodel is described in Ref. 19.Strongly oil-wet micromodel

Wettability of the glass micromodel was

changed from strongly water-wet to strongly

oil-wet by ageing the model in a North-sea

crude oil. After cleaning the model with

copious amounts of distilled water and acetone

successively, the micromodel was completely

saturated with 2 % (wt./wt.) CaCl2 brine. The

model was then allowed to reach the state of

ionic equilibrium for one week at 100oF. Then

the crude oil was injected continuously until no

brine remained in the pores, and proceeded

with ageing for three weeks. To examine the

degree and stability of the oil wetness achieved

after ageing, blue water was slowly injected

into the micromodel. Fig.3a shows magnified

image of a section of the oil-wet micromodel,

after initial waterflooding. Examining the fluid

interfacial curvatures of the pictures and

checking them in sequence of slides once a

day, over a period of one week, proved no sign

of change of oil-wetness. As the effective time

needed to conduct a micromodel experiment

was shorter than a week; we gained confidence

in the stability of the achieved oil wetness.Mixed-wet micromodel

Starting with the oil-wet micromodel, a dark

blue-dyed water solution was prepared.

Having the micromodel completely saturated

with oil; the highly concentrated dye solution

was injected into the micromodel. As a result,

some of the oil-filled pores were displaced with

dyed water. The injection of dyed water

continued for 24 hours. Then the micromodel

was sealed for 48 hours. In the type of mixedwet

model we obtained, some pores were

water-wet while some others were oil-wet or

neutral-wet. Fig.4.b shows a magnified picture

of a small section of a mixed-wet micromodel

in which all three types of water-wet, oil-wet

and neutral-wet pores can be identified from

the shape of the water/oil interfaces.

EXPERIMENTAL RESULTS

Experiments with strongly water-wet model

The results of these experiments were reported

in detail in our June 2000 report19. However,

some of the results will be shown here for

comparison with the oil-wet and mixed-wet

model results. Fig. 2 presents a few pictures of

one section (of ten) from the middle of the

micromodel. It is interesting to note the

distributions of the fluids under ‘initial’

conditions, Fig. 2b, where the ‘connate water’

is not only in form of films on the pore surface

and in small pore throats, but also in clusters of

large pores surrounded by small throats. It is

also interesting to see that after waterflooding,

Fig. 2c, water has risen in the corners and on

the sides of the pores, squeezing the oil out,

rather than displacing it piston wise. These

can, of course, be all explained remembering

that the model is water wet, the velocity is low

(1.2 m/d, as in real reservoirs) and the flow is

capillary dominated. Seeing the videos and

observing the WAG cycles are indeed very

revealing and improve our understanding of the

processes considerably. Finally, the last

picture of a five-cycle WAG, Fig 2d, depicts

how the fluids have been redistributed and

extra oil has been produced. Fig 5 shows that

an extra 10% of additional oil has been

produced after the first three cycles of WAG

injection, in water-wet model. Moreover, the

additional recovery in subsequent cycles has

been very small.

Experiments with strongly oil-wet model

Initially the oil-wet model was saturated with

oil, with no ‘connate water’ present. Water

flooding has displaced a significant quantity of

oil, this time by piston wise displacement,

Fig.3a. Video films and magnified pictures,

not shown here, clearly showed that a thin film

of oil stays on the walls of the pores and apart

from the clusters of pores, which are

surrounded with small pore throats, the other

pores have been very efficiently displaced by

water. Fig.3c shows that even a good quantity

of the oil, which was trapped in the abovementioned

clusters, has been produced. Fig. 5

shows that about 22% of extra oil have been

recovered after three WAG injection cycles.

Experiments with mixed-wet models

A series of experiments were carried out with

mixed-wet models of different degrees of oil

wetness. About 1200 interfaces, each

indicating a different degree of wettability,

were counted and the degree of wettability was

determined, Fig. 4b. Fig. 4 depicts the

experimental results of a section of the

micromodel, in which the number of oil-wet

pores was almost, equal to the number of

water-wet wet pores. Here the water-wet pores

exhibit the behaviour we observed in the

strongly water-wet model and oil-wet pores

behave as in strongly oil-wet model. However,

the interaction between the pores of different

wettability results in a recovery behaviour,

which does not show a completely

intermediate trend. Fig. 5 illustrates that

production of extra oil goes on beyond the

third cycle and eventually surpasses that of the

oil-wet model. In this case the additional

recovery, after five WAG cycles, was about

27% of the initial oil-in-place.

Conclusions

The results of the reported experiments, which

were performed in micromodels of different

wettability, were very revealing. They provide

an excellent basis for checking and verifying

the formulation of our network model

simulator (see a separate paper presented to

this seminar on network modelling results).

The algorithm, shown in Fig. 1, describes the

strategy of this research project leading to

acquisition of an improved tool for

determination of the saturation functions.

These functions are of utmost importance in

making prediction of real reservoir performance

under WAG injection operation.

Nomenclature

Sorw = residual oil saturation to waterflood

SorWAG = residual oil saturation after 5 cycles

of WAG injection.

Acknowledgements

The WAG project at Heriot-Watt U. is equally

sponsored by: The UK Department of Trade

and Industry, BP plc, Marathon International

(GB) Ltd, Mobil (North Sea) Ltd, Norsk Hydro

a.s.a, SAGA Petroleum a.s.a, and Total Oil

Marine plc, which is gratefully acknowledged.