ABSTRACT

The field experience in Western Canada has shown that

the primary depletion behaviour of several heavy oil fields is

anomalous and inconsistent with conventional theories. It is

believed that at least foamy oil flow effects cause a part of

this anomaly. It has been theorised that during primary

production, the solution gas released from heavy oil does not

disengage from the liquid immediately but remains dispersed

in the form of small gas bubbles which tend to flow with the

oil. This paper presents an experimental study of solution

gas drive in foamy oil systems.

Primary depletion tests were conducted in a two meters

long sand-pack using several different oils to evaluate the

effects of different process parameters, such as oil viscosity

and pressure decline rate. The results show that the

performance of solution gas drive depends on the pressure

decline rate (or drawdown pressure) imposed on the system.

Experiments, in which the pressure at the production port

was decreased very slowly, resulted in low recovery factors.

When the pressure at the production port was reduced

rapidly, high recovery factors were obtained. It was

observed that a large pressure gradient developed and

persisted in fast decline experiments while in slow decline

experiments the pressure gradient remained very small. The

results suggest that a different drive mechanism, which may

be called foamy solution gas drive, becomes operative in fast

depletion tests.

The oil viscosity was found to have only a modest effect on

the recovery factors observed in fast pressure decline

experiments. However, the critical rate of pressure decline

needed to maintain the foamy drive mechanism was viscosity

dependent; increasing sharply with decreasing oil viscosity.

The results also showed that, other factors being the same,

the presence of asphaltenes did not affect recovery factors in

high rate solution-gas-drive tests.

This paper is to be presented at the 1999 CSPG and Petroleum Society Joint Convention, Digging Deeper, Finding a Better Bottom Line,in Calgary, Alberta, Canada, June 14 18, 1999. Discussion of this paper is invited and may be presented at the meeting if filed inwriting with the technical program chairman prior to the conclusion of the meeting. This paper and any discussion filed will be consideredfor publication in Petroleum Society journals. Publication rights are reserved. This is a pre-print and subject to correction.

THE PETROLEUM SOCIETY PAPER 99-44

Laboratory Evaluation of SolutionGas Drive Recovery Factors in Foamy

Heavy Oil Reservoirs

B.B. MainiPetroleum Recovery Institute

2INTRODUCTION

Cold production of heavy oil has become an attractive

heavy oil production method past few years. Although cold

production has been very successful in many heavy oil pools,

it is not risk free. The final primary recovery factors differ

widely among reservoirs having similar permeability and

viscosity characteristics. Even within the same reservoir,

some wells are better producers while others perform rathe

poorly. The reasons for such performance differences remain

obscure. Numerical simulation of primary production

(Loughead and Saltuklaroglu; 1992) suggests that the wells,

which perform poorly, are showing the normal solution gas

drive behaviour while the wells which are prolific producers

are anomalous. Several reasons have been suggested for

higher than expected productivity and unexpectedly high

primary recovery factors. These include formation of

wormholes around the well, increased permeability due to

sand dilation, and foamy oil flow. The first two appear to be

responsible for higher than expected production rates and the

foamy oil flow is thought to be the main reason for high

primary recovery factors (Maini, Sarma and George; 1993).

Advances in horizontal well technology have removed some

of the uncertainty from cold heavy oil production. Long

horizontal wells lead to economically attractive (high)

production rates even in the absence of wormholes and other

unusual effects. However, the uncertainty concerning the final

primary recovery factor remains due to a lack of understanding

of the factors needed for anomalously high recovery.

Currently we do not know what reservoir characteristics are

conducive to foamy oil flow. Furthermore, we also do not

know which production practices promote foamy oil flow and

which ones tend to suppress it. It is very difficult to make

reliable predictions of oil reserves added by a new well until

sufficient production has occurred to establish a decline rate.

This paper presents the results of an experimental study

aimed at developing an improved understanding of the solution

gas drive process in foamy heavy oil reservoirs. The main

objective was to evaluate the possible range of primary

recovery factors under different operating conditions. Solution

gas drive experiments were carried out in 200 cm long sand-

packs using several different foamy oils.

EQUIPMENT MATERIALS AND METHODS

Apparatus

The equipment used for laboratory scale solution drive

experiments is shown schematically in Figure 1. A two metre

long coreholder with six intermediate pressure taps was used to

confine the sand pack. These pressure taps (spaced 33

centimetres apart from one another) were used for dynamic

monitoring of the pressure distribution during the primary

depletion tests. The dimensions of the core holder and the

properties of the sand-pack used in primary depletion tests are

listed in Table 1.

Recombined oil (also referred to as "live oil") was prepared by

saturating the oil with methane gas in the recombination

equipment connected to the inlet end of the coreholder. A

schematic lay-out of the recombination equipment is also

provided in Figure 1.

A back pressure regulator was used for controlling the

pressure at the production port of the sand pack. The back

pressure was held constant in some tests while in others, a mass

flow controller connected to the gas dome of the back pressure

regulator was used to continuously decrease the pressure at the

production port of the sand-pack.

Produced oil flowed into a small pressure vessel placed on

an electronic balance for monitoring of the oil production rate.

The produced gas was collected in a large pressure vessel

connected to the oil collection vessel. The gas production rate

was monitored by measuring the increase in pressure of the gas

collection vessel.

An automated data acquisition system was employed for

reliable and dynamic recording of the oil production rate, gas

production rate and the values of gauge pressure at seven

different points along the length of the sand pack.

MATERIALS

Oils

3A synthetic mineral oil and four different crude oils were

used in the primary depletion tests. These are briefly described

below.

PAO-100 Oil

This solids-free, clear and colourless synthetic (poly-butene)

oil was supplied by Nye Inc. of New Bedford, Massachusetts.

At room temperature, it had a density of 0.85 g/mL and a

viscosity of 2520 mPa.s.

Crest Hill Oil

Of the five different crude oils used in this study, this was

the lightest. The wellhead sample obtained from the field was

cleaned by ultra-centrifugation to remove water and suspended

solids. The cleaned oil had a density of 0.928 at 20oC and its

viscosity was 250 mPa.s at 20oC.

Hamaca Oil

This 9.4o API crude oil was supplied by Intevep S.A. of

Venezuela. Tests with this oil were conducted an elevated

temperature of 67oC. At the test temperature it had a density of

0.976 g/mL and a viscosity of 3300 mPa.s.

Boscan Oil

This 10o API crude oil was supplied by Intevep S.A. of

Venezuela. Tests with this oil were conducted at a temperature

of 77oC. At the test temperature, its viscosity was 560 mPa.s

and density was 0.973 g/mL.

Gases

Technical grade methane was used for preparing live oil in

most of the tests. However, in tests with the Boscan oil a

simulated reservoir gas was used. In addition to methane, it

contained 0.8% nitrogen, 3.9% ethane, 1.2 % CO2, 4.7%

propane and 1.9% butanes.

Sand

Clean, round grain, 140 to 200 mesh size, silica sand was

used in preparing the sand-packs. It was supplied by Agsco

Corporation of Wheeling, Illinois.

TEST PROCEDURES

Preparation of Live Oil

Live oil was prepared by recombining the cleaned gas-free

oil with methane (or the simulated separator gas) at the selected

saturation pressure. This was achieved by spraying the oil

through a gas cap in a large capacity high pressure cell, as

shown schematically in Figure 1. The solution gas oil ratio

(GOR) was evaluated periodically during the recombination

process by withdrawing live oil samples and measuring their

gas content. Equilibrium was assumed when three consecutive

samples taken at least 8 hours apart showed the same solution

GOR. Generally, it took about seven days of mixing to reach

equilibrium.

Preparation of Sand-Pack

The sand pack was prepared by wet packing the sand into

the sand-pack holder. The holder was mildly vibrated during

the packing. The sand was confined by application of 7 MPa

overburden pressure. After packing, the sand was flushed with

acetone and it was dried by flowing nitrogen through it.

The pore volume of the pack was measured by evacuating it

to a high vacuum and then filling it with a metered volume of

water. The absolute permeability of the sand-pack was

measured by flowing water through it at constant flow rate and

measuring the pressure drop.

Live oil was then injected into the sand-pack to displace the

water. A back pressure equal to the saturation pressure of live

oil was maintained at the outlet port during this step. The oil

flood was continued to about 1.5 pore volumes of oil injection.

Solution Gas Drive Test

The solution gas drive tests started with the sand-pack fully

saturated with live oil and a small connate water saturation.

The pressure at the outlet end was reduced in a pre-

programmed manner using the back pressure regulator. The

effluent fluids from the sand-pack were passed to a small

pressure vessel, which acted as the gas separator. The released

gas was collected in a large gas tank. The cumulative weight of

oil produced and the cumulative volume of gas collected were

4recorded periodically. The in-situ pressure at seven different

locations in the sand-pack was also recorded periodically. The

depletion test was continued until the pressure within the sand-

pack declined to a low (near atmospheric) value and the

production of oil and gas stopped.

RESULTS AND DISCUSSION

SOLUTION GAS DRIVE TESTS WITH PAO-100 OIL

Four solution gas drive tests were carried out at room

temperature with the synthetic mineral oil, PAO-100 and

methane. This poly-alkene oil was totally free of asphaltenes.

The live oil was prepared at 4.8 MPa (700 psi) pressure and

room temperature (23oC). All tests started with the sand-pack

fully saturated with live oil and connate water saturation. Table

2 summarises the results obtained with this system.

Figure 2 shows the production and pressure drop history of a

test in which the maximum possible pressure drawdown was

applied by abruptly opening the production port to the

atmospheric pressure.. Initially the oil production rate was

very high while the gas production rate was low. The high oil

production rate continued for about 20 hours and then declined

gradually. The rate of gas production increased sharply after

about 15 hours and began to decline gradually after about 30

hours. The test was continued for 135 hours. The total volume

of oil produced was 275 mL. This represents a recovery factor

of 26.8% of the original oil in place (OOIP).

Figure 2 also includes the pressure history of three different

locations in the sand-pack. The pressure at the outlet end

declined sharply and remained low throughout the depletion

test. The small positive value of the outlet end pressure was

caused by the pressure drop in the production tubing. The

pressure at the mid-point and the far end declined rapidly to

about 3.5 MPa (500 psi) and then bounced back a little as the

solution gas was released. The differential pressure between

the far end and the production end, which is the force that

drives the oil toward the production port, reached a peak of

over 3.5 MPa and remained high during the first phase of oil

production. It was noted that the pressure drop declined slowly

during the final phase of pressure depletion but a measurable

pressure drop was present even at the end of the test.

The gas production behaviour is shown in the lower half of

Figure 2 as plots of the cumulative volume of gas produced and

the cumulative gas oil ratio (GOR) versus the volume of oil

produced. It is seen that the produced GOR remains below the

solution GOR during the initial phase of production.

The results of a slow depletion test in which the pressure at

the outlet port was reduced linearly over a period of 10 days

are shown in Figure 3. The reduced speed of pressure decline

had a very detrimental effect on the oil recovery performance.

The final volume of oil produced in this test was only 120 mL

which represents a recovery level of 11.7% of OOIP. Another

noticeable difference was in the pressure drop behaviour. The

pressure difference between the far end and the outlet end

remained very low. Only for a brief period, during which the

pressure at the outlet port decreased from 3.9 MPa (565 psi) to

2.4 MPa (350 psi), was there a readable pressure difference

between the far end and the production end. Figure 3 also

shows the cumulative GOR behaviour. During the initial

period the cumulative GOR was only slightly below the

solution GOR.

Effect of Pressure Decline rate:

Figure 4 shows the effect of pressure decline rate on oil

recovery. Here the cumulative volume of oil produced is

plotted against the mid-point pressure. It is seen that the

recovery efficiency diminishes as the rate of pressure decline at

the outlet becomes slower. A similar plot for gas production is

shown in Figure 5. It shows that the gas production behaviour

is much less sensitive to the rate of pressure decline. It should

be mentioned that these tests were done during the period over

which the experimental techniques were still being developed

and improved. In particular, the technique used for monitoring

the cumulative volume of produced gas was not sensitive

enough to provide reliable data during the initial production

period.

The pronounced effect of pressure decline rate on oil

recovery in this synthetic mineral oil system was somewhat

surprising. It shows that the solution gas drive parameters,

such as the critical gas saturation and the oil gas relative

permeability curves, may have changed with the imposed

5pressure decline rate. It was later found that, although the oil

was asphaltene free, its foaminess was comparable to crude

oils.

SOLUTION GAS DRIVE TESTS WITH CREST HILL

OIL

Four solution gas drive tests were carried out at room

temperature with the recombined Crest Hill oil. This live oil

was also prepared at 4.8 MPa (700 psi) pressure and room

temperature. The initial oil saturation of the sand-pack in this

case was 87%. Table 3 provides a summary of these tests.

In the first test, the maximum possible pressure drawdown

was applied by abruptly opening the production port to the

atmospheric pressure. The cumulative production of oil and

gas, recorded periodically, is shown in Figure 6. Initially the

oil production rate was very high while the gas production rate

was low. This high rate oil production continued for about two

hours and then declined rapidly. The rate of gas production

increased sharply after about 1.5 hours and began to decline

gradually after 2.5 hours. The test was continued for 20 hours

even though the pressure had declined to a low value after 8

hours of production. The total volume of oil produced was 306

ml. This represents a recovery factor of 31% of the OOIP.

Figure 6 also includes the pressure readings at three different

locations in the sand-pack. The pressure at the outlet end

declined sharply and remained low throughout the depletion

test. The pressure readings at the mid-point and the far end of

the sand-pack show an interesting feature of the solution gas

drive experiment. Soon after the outlet port was opened, the

pressure at these locations dropped very rapidly. This rapid

decline in the pressure was caused by the expansion of a low

compressibility liquid phase. What is interesting is the low

value reached before the pressure started bouncing back due to

release of the solution gas. The fluid pressure at both locations

dropped down to about 2.1 MPa (300 psi), before the release of

solution gas started providing pressure maintenance. Thus a

high value of super-saturation was needed to initiate gas

release.

The pressure at the far end continued to increase for almost

one hour. Apparently the release of gas from solution did not

occur very rapidly and may have been limited by slow rate of

diffusion. The differential pressure between the far end and the

outlet end, which drives the oil toward the production port,

reached a peak of over 3.5 MPa and remained high during the

first phase of oil production. This pressure difference declined

slowly during the final phase of pressure depletion. However a

measurable pressure gradient was present even at the end of the

test.

In Figure 7 the gas production behaviour is shown by

plotting the cumulative volume of gas produced and the

cumulative GOR against the volume of oil produced. It is seen

that the produced GOR remains below the solution GOR

during a substantial part of the oil production. About two

thirds of the oil is produced before the cumulative GOR

becomes higher than the solution GOR. Figure 7 also shows

that the cumulative gas production increases almost linearly

with the cumulative volume of oil produced for more than half

of the oil production after which the gas production increases

sharply. Therefore it is apparent that the free flow of gas as a

separate phase does not start until at least half of the total oil

production has occurred.

In the second test, the pressure at the production port was

decreased linearly over a period of five hours. The history of

cumulative oil and gas production as well as the pressure

history are shown in Figure 8. In this case the pressure at all

three locations dropped down to about 3.5 MPa (500 psi)

before any significant volume of oil was produced. As in the

previous test, the release of solution gas started only after a

substantial supersaturation had occurred. A brief period during

which the pressure at the mid point and at the far end was

increasing was observed in this test also. By comparing these

results with the previous test, it was noted that the degree of

supersaturation generated before solution gas was released was

much lower in this test.

The final volume of oil produced in this test was 312 ml

which represents about 32% of OOIP. Thus the recovery level

achieved in this test was similar to that obtained in the previous

test. During the period in which oil was produced at relatively

high rate, the pressure drop between the far end and the outlet

port remained high. Most of the pressure drop was between the

mid-point and the outlet end.

6In the third test, the pressure at the outlet port was reduced

linearly over a period of 4.5 days. The results are shown in

Figure 9. The reduced speed of pressure decline had a

detrimental effect on the oil recovery performance. The final

volume of oil produced in this test was only 70 mL which

represents a recovery level of 7% of OOIP. Another noticeable

difference was in the pressure drop behaviour. The pressure

drop between the far end and the production end remained very

low. Only for a brief period, during which the pressure at the

production port decreased from 4.27 MPa (610 psi) to 3.72

MPa (530), was there a measurable pressure difference

between the far end and the production end. The maximum

value of this pressure drop was only 80 kPa (11.5 psi). Thus a

large pressure gradient capable of mobilizing the oil at high

rate was never generated.

Variable Rate Pressure Decline at the Production Port:

In this test, a variable rate pressure decline was obtained by

allowing the dome gas of the back pressure regulator to expand

at constant volumetric rate using a Ruska pump. This

produced a hyperbolic pressure decline which was continued to

about 1.4 MPa (200 psi). The pressure at the outlet port was

then suddenly reduced to near atmospheric pressure. The

pressure and production history of this test are shown in Figure

10. This test reveals some interesting characteristics of the

process. Toward the end of hyperbolic decline, the oil

production was levelling off and it appears that its continuation

would have resulted in very little additional oil recovery. The

pressure data show that a substantial pressure gradient

developed below 4.2 MPa (600 psi). However, the decreasing

pace of pressure reduction resulted in diminishing pressure

gradient and toward the end of the hyperbolic decline the

pressure gradient was too small to be measured. It appears that

by this time, the gas phase had become continuous and it was

flowing out of the sand-pack with little or no accompanying oil.

The sudden decrease of production port pressure to a low value

changed this picture. There was a brief period of high rate gas

production during which only a small amount of oil was

produced. This was followed by substantial oil production at

relatively high rate, with only a small amount of gas

production. The pressure gradient in the sand-pack was

relatively high during this period of oil production.

These results suggest that the flow mechanism changed

dramatically after the outlet pressure was reduced suddenly.

The gas was flowing as a continuous phase at this point and the

existing free gas was able to flow out quickly after the pressure

reduction. This resulted in a sharp reduction in the local

pressure at all points within the sand-pack which induced a

release of the solution gas. However, this released solution gas

did not flow out at a rapid rate due, we think, to the formation

of a foamy dispersion during the rapid release of the solution

gas.

Figure 11 shows the GOR behaviour for this test. The

earlier part of the test is consistent with previous tests. The

initial oil production occurs at GOR below the solution GOR.

The oil production beyond 150 mL was after the sudden

reduction in pressure at the outlet port. During most of this

production, the cumulative GOR declined. Very little gas was

produced with oil in this phase of the test.

Effect of Pressure Decline rate:

Figure 12 compares the cumulative oil versus mid-point

pressure curves for the four tests using Crest Hill Oil. It is

apparent that the pressure decline rate has a dramatic effect on

the recovery behaviour. The abnormal shapes for the sudden

pressure release test and the 5 hours test are caused by the

bounce back in pressure at the mid-point. At the same level of

decline, the fast experiments produce much more oil compared

to the slow (4.5 days) experiment. The variable rate

experiment falls in between the fast and slow tests.

The gas production curves, shown in Figure 13, again show

that different drive mechanisms may be involved in the fast and

slow tests. At any level of pressure decline, the fast tests result

in lower gas production. Therefore, some mechanism is

present in the fast pressure decline tests to trap a larger portion

of the released gas within the sand pack. We suggest that this

mechanism is related to the formation of a foamy dispersion of

gas.

SOLUTION GAS DRIVE TESTS WITH HAMACA OIL

Four primary depletion tests were conducted with the

Hamaca oil at the reservoir temperature of 66oC. The results

are summarised in Table 4. The same 200 cm long sand-pack

7(used in the previously described tests with Crest Hill oil) was

used. The sand-pack was initially saturated with water at room

temperature. It was subsequently heated to 66oC. The volume

of water expelled by heating (to 66oC) was 25 mL. Live oil

was prepared by saturating the Hamaca crude with technical

grade methane at 66oC and 7 MPa (1000 psi). The solution

GOR of the recombined oil was 16.5 standard mL of gas per

mL of the oil. Live oil was injected into the sand-pack to

displace the water at 66oC. Initial oil saturation achieved was

94%. The initial volume of live oil in the sand-pack was 987

mL.

The first test employed maximum pressure drawdown, i.e.

the outlet pressure was reduced to near atmospheric value at

the start of the test. This test exhibited very good solution gas

drive performance. The final volume of oil produced was

262.3 mL, which represents 26.6% of original oil in place.

Figure 14 shows a plot of the cumulative oil and gas produced

versus time. The rate of oil production started at a high level

and declined gradually. About half of the total production

occurred in first four hours of the test. The test was continued

for 70 hours, at which time the pressure at the far end of the

sand-pack had declined to 172 kPa (25 psi). The final volume

of gas recovered was 15.73 L, or 96.6% of the initial solution

gas in the system.

Figure 15 shows the pressure history at three different

locations in the sand-pack. In this figure, the solid line

represents the pressure at the outlet face of the sand. Although,

the pressure at the production point was dropped to near

atmospheric level instantaneously, the pressure at the outlet

face of the sand did not drop to this level immediately.

Because of the pressure drop in the tubing used to connect the

sand-pack outlet port to the oil collection vessel, pressure at the

outlet face of the sand initially remained near 2 MPa (285 psi)

level and then slowly declined to the near atmospheric

pressure. The dotted curve represents the pressure at the

middle of the sand-pack and the dashed curve represents the

pressure at the far end. These two curves show the effect of

gas nucleation kinetics. The pressure at these locations drops

rapidly as the outlet is opened, but later shows a brief recovery

period during which the pressure increases with time. This

brief period of increasing pressure is caused by the relatively

slow rate of gas evolution. It takes some time for the gas to

come out of solution in response to the decreased pressure in

the liquid phase. The figure also shows that high pressure

gradients develop in the sand-pack to mobilize the oil and gas.

Most of the oil was produced during the period in which the

difference between the far end pressure and the outlet end

pressure remained high.

The second test involved a very slow depletion in which the

outlet pressure was reduced to near atmospheric value over a

period of 22 days. The production behaviour observed in this

test was remarkably different from the fast drawdown test. As

shown in Figure 16, the total volume of oil recovered was only

50.6 mL which represents a recovery factor of 5.1 percent.

The volume of gas recovered was 16.5 litres which is nearly

100% of the solution gas originally in the system.

An interesting feature of this test was that, within the

accuracy of the pressure transducers (~1 psi), the pressure at

different points in the sand-pack declined in tandem. In other

words, during most of the recorded test history, the pressure

difference between the far end and the outlet end was smaller

than the measurement error.

It was noted that a large fraction of the oil production

occurred early in the test when the pressure was still high. The

oil production versus time plot displays two distinct zones.

The first zone shows relatively high production rate and lasts

till the pressure drops below 6.3 MPa (900 psi). The second

zone shows relatively low rate of oil production.

Figure 17 shows a plot of the volume of gas produced from

the sand-pack against the pressure at the mid-point of the sand-

pack. A straight line can be fitted over most of the pressure

decline, showing that the gas release was similar to what would

be observed in a differential liberation test conducted in a

phase behaviour cell. This also suggests that the gas was

flowing freely as a continuous phase. The oil production curve

shows two distinct zones; one before the linear increase in gas

production started and one during the continuous gas

production phase.

Figure 18 shows the GOR history. It is seen that the GOR

stayed below the solution GOR level during the initial

production period during which the oil production rate was

relatively high. Subsequently it increased to much higher

8levels.

The overall behaviour of this test is consistent with the

conventional picture of solution gas drive in viscous oil

systems. The initial oil production is at GOR below the

solution GOR due to trapping of the evolved gas by the sand.

Once the critical gas saturation is reached in the sand, free gas

flow starts and GOR rises above the solution GOR and

continues to increase. The final solution gas drive recovery

factor remains low.

The depletion time was reduced to 8 days in the third test.

The solution gas drive behaviour observed in this test was very

similar to the behaviour of the 22 days decline. It appeared to

fit the conventional solution gas drive model and showed little

or no foamy oil flow effects.

In the next test the pressure decline period was reduced to

24 hours. The behaviour observed in this test was similar to

that observed in the first test, in which the pressure at the outlet

was reduced to near atmospheric value instantaneously. It can

be suggested that significant foamy oil flow effects were

involved in this test and the maximum drawdown test.

Figure 19 presents a plot of the cumulative oil production

against the pressure at the mid-point of the sand-pack for all

four tests. It is noted that two types of behaviour are displayed.

In the two slow depletion tests (22 days and 8 days) the rate of

oil production slows down considerably as the pressure at the

mid point declines below 5.6 MPa (800 psi). In the two fast

depletion cases (maximum drawdown and 24 hours decline),

the oil production continues down to very low pressure levels.

The slow test (22 days decline) may be representing a limiting

case in which the behaviour is very close to what would be

expected in the conventional solution gas drive. The

experimental data also suggest that a critical pressure

drawdown rate may be involved. Experiments conducted at

slower decline rates follow the conventional solution gas drive

model with little or no foamy oil effects. Experiments

conducted at rates faster than this critical value display

significant foamy oil effects.

Figure 20 shows a plot of cumulative gas production against

the pressure at the mid-point of the sand-pack. In the slower

experiments the volume of gas produced rises at somewhat

faster rate. When the volume of gas produced is plotted against

the cumulative oil production, the contrast between the two

mechanisms becomes very easy to see (see Figure 21). In the

slow depletion tests, a lot of gas is produced without much

accompanying oil production. The critical gas saturation in

these slow tests appears to be low (less than 3 percent) while in

the fast experiments it appears to be high (higher than 10

percent).

Figure 22 shows a plot of the cumulative GOR against the

volume of oil produced. It is readily seen that the GOR rises

very rapidly in the two slow tests but remains relatively low in

the two fast depletion tests. Plots of the producing GOR

against the cumulative oil production give the same message.

Figure 23 shows a plot of producing GOR against the

pressure at the mid-point of the sand-pack. It is seen that the

slow decline tests lead to very high producing GOR. The GOR

increases till the pressure has declined to about 2.8 MPa (400

psi) and decreases beyond that.

SOLUTION GAS DRIVE TESTS WITH BOSCAN OIL

A sample of oil from Boscan reservoir was obtained from

Intevep, S.A. of Venezuela. The Boscan reservoir has a very

large structural closure which ranges from 1100 metres subsea

to 2925 metres subsea. However, the most productive part lies

between 2000 metres and 2500 metres subsea, with a mid-point

datum of 2240 metres subsea. At this level the reservoir has a

temperature of 76.7 oC. The reservoir produces heavy oil of

10.0 oAPI gravity. The solution GOR in the reservoir is 23

(SCC/mL) and the bubble point pressure is estimated to be 9.5

MPa (1350 psi).

Seven solution gas drive tests were carried out with this oil.

These tests were conducted at the reservoir temperature of

76.7oC and 7 MPa (1000 psi) saturation pressure. The

saturation pressure used was lower than the actual reservoir

bubble point pressure due to the limitations of our equipment.

The first three tests were conducted with methane as the

solution gas. A simulated Boscan solution gas was used in the

next four tests. Table 5 summarizes the displacement

performance of all seven tests.

Solution Gas Drive Tests with Methane as the Solution

9Gas:

Three tests were conducted with pure methane as the

solution gas. The first test was conducted at the highest

pressure decline rate. The outlet pressure was reduced from 7

MPa (1000 psi) to near atmospheric pressure over a time

period of 1.5 days. Even at this high decline rate the pressure at

different locations within the sand-pack showed only small

differences. High differential pressure normally associated with

foam formation did not develop with this system at this decline

rate. The final solution gas drive recovery at this decline rate

was 177 mL of oil which represents a recovery factor of 18.7

%OOIP. The recovery factors were lower at slower rates of

pressure decline; being 10.7 % in the 3 days decline and 11.2

% in the 15 days decline.

Figure 24 compares the oil recovery performance at

different decline rate by plotting the cumulative volume of oil

produced against the pressure at the mid-point of the sand-

pack. It is seen that the fast depletion produces much more oil

during the second half of depletion. The gas production

behaviour is shown in Figure 25. As would be expected, the

final volume of gas produced was more or less same in all three

tests. However, at intermediate levels of depletion, the slowest

decline gave highest cumulative gas production. These results

clearly show that in faster decline tests, a larger fraction of the

released gas is retained in the sand-pack.

Solution Gas Drive Tests with Simulated Boscan Gas.

Four depletion tests were carried out with the simulated

Boscan gas. The first test was a fast depletion in which the

outlet port was abruptly opened to the atmospheric pressure. It

provided a relatively high level of oil recovery, at 32.9

%OOIP. It was also the only test in which a large differential

pressure developed between the mid-point and the outlet end of

the sand-pack. The recovery level declined as the rate of

pressure depletion was made slower. Figure 26 compares the

oil recovery performance at four different depletion rates. It is

readily seen that the recovery performance becomes steadily

worse as the rate of pressure decline is made slower. Except

for the sudden decline case, only a small differential pressure

between the two ends of the sand-pack was observed. In the 8

days decline, the pressure remained virtually uniform in the

200 cm long sand-pack. Therefore, this decline rate may close

to the limiting slow rate behaviour.

The gas production behaviour at different decline rates is

compared in Figure 27. As in the tests with methane, a

reduction in the rate of pressure decline causes more gas to be

produced at intermediate levels of depletion.

Effect of Gas Composition on Solution Gas Drive

Performance:

Figure 28 compares the solution gas drive performance

obtained with methane and the simulated Boscan gas at similar

rate of pressure decline. Surprisingly, the performance

observed with methane as the solution gas was somewhat

superior even though the pressure decline rate was marginally

faster in the test with the simulated Boscan gas and the solution

GOR was significantly higher in the case of simulated Boscan

gas. As seen in the gas production comparison (Figure 29), the

test with simulated gas produced higher cumulative volume of

gas at any depletion level.

EFFECT OF PRESSURE DECLINE RATE

All of the oil-gas systems investigated, more or less, show a

similar influence of pressure decline rate on the oil recovery

performance. Highest recovery factors were observed in

experiments involving the fastest pressure decline rate while

the lowest recoveries were obtained with the slowest pressure

decline rate. The difference between the recovery levels at fast

decline rate and very slow decline rate was at least a factor of

two, often much larger. The mechanism responsible for such a

pronounced effect of pressure decline rate is not fully clear. It

could be related to the decline rate dependence of critical gas

saturation. The critical gas saturation would be highest at the

fastest pressure decline rate (Sheng and Maini, 1996). This

increase in the critical gas saturation is caused by nucleation of

gas bubbles at a much larger number of nucleation sites.

Because of larger supersaturation created in the faster decline

rate experiment, more nucleation sites can become active.

Although the above mentioned mechanism involving

progressive activation of nucleation sites can explain many of

the observed results, another possibility is suggested by the

experimental observations. High pressure gradients, often

10

exceeding 50 kPa/m, were observed in fast depletion tests

while the pressure gradient in slow depletions was always very

small. It is possible that the dispersed flow of gas is created by

the high pressure gradient. If the pressure gradient is large

enough to mobilise the isolated gas bubbles, the gas bubbles

will start migrating with the flowing oil and may divide into

smaller bubbles during the flow. The pressure gradient based

mechanism for the generation of dispersed flow can also

explain why the foamy solution gas drive occurs even at slower

decline rates when the oil viscosity increases; the pressure

gradients are higher in high viscosity systems.

EFFECT OF OIL VISCOSITY

The viscosity of the four oils used in this study ranged from

250 mPa.s to 3300 mPa.s. The viscosity appears to be an

important factor in the solution gas drive process. However, its

effect on the primary recovery factors observed in these

experiments is very different from what would be expected

from the conventional solution gas drive theory. The recovery

factors obtained in the fast pressure decline experiments were

virtually independent of viscosity.

The most significant effect of oil viscosity appeared to be

reflected in the effect of pressure decline rate. With low

viscosity oil the transition to conventional solution gas drive

behaviour occurs at relatively higher rate of pressure decline.

As the oil viscosity increases, the transition point shifts to

slower pressure decline rates.

ROLE OF ASPHALTENES

A comparison of the solution gas drive behaviour of PAO-

100 oil with that of the Hamaca oil can be used to infer the

effect of asphaltenes. These two oils have very similar

viscosity and exhibit similar solution gas drive recovery in high

rate depletions. Therefore, it appears that the presence or

absence of asphaltenes has little or no effect on recovery

factors in high rate solution gas drive tests. However,

additional tests are needed to confirm this observation.

FIELD IMPLICATIONS

The laboratory scale depletion tests with all four oils have

one feature in common. The solution gas drive performance is

relatively poor at slow pressure decline rates. The recovery

factors for slow depletion tests are in the range of 5 to 10

%OOIP. The GOR behaviour of slow depletion tests is

consistent with conventional solution gas drive theory in that it

increases rapidly with declining pressure. The fast depletion

tests, in contrast, exhibit low GOR throughout the depletion

and result in much higher recovery factors. The field

observations in foamy oil reservoirs show that GOR remains

low even after the pressure has declined to less than half the

bubble point pressure. This would suggest that the solution gas

drive mechanism in the field is similar to that observed in the

fast depletion tests in the laboratory. The problem is that the

depletion rates needed to induce the foamy solution gas drive

in laboratory experiments are much faster than the field rates.

Direct extrapolation of the laboratory tests to the field would

suggest that foamy solution gas drive should not occur in the

field.

This conflict between the laboratory tests and the field

observations can be resolved by suggesting that the flow

behaviour is governed not by the rate of pressure change with

time but by the pressure gradient that develops in the sand. It

was noted that the recovery factors were higher whenever the

depletion test produced large pressure gradient. The pressure

gradients present in the field case can be much higher than the

pressure gradients observed in the slow depletion experiments,

especially when sand is produced with the oil. Allowing 1-3%

sand to enter the wellbore with the fluids can result in

propagation of a front of sharp pressure gradients away from

the wellbore (Geilikman et al., 1994). These sharp pressure

gradients occur at the advancing edge of the dilated zone and

may be a key factor in making the foamy solution gas drive

possible in the field. It is not known how far from the wellbore

the dilated zone can propagate. However, it is likely that the

effectiveness of this mechanism will diminish as the front

moves further away from the wellbore.

Foamy oil flow behaviour can have serious implications on

how such reservoirs should be developed and operated. The

optimum well spacing for foamy solution gas drive may be

much smaller than that needed for conventional solution gas

drive. The drawdown pressure for maintaining the optimum

performance may also be different. The laboratory tests

suggest that drive energy can be wasted in slow depletions

11

that do not induce foamy drive. Therefore, it would be

advisable to develop foamy oil reservoirs at a smaller well

spacing and to apply maximum drawdown pressure at the

onset of production and maintain it thereafter.

CONCLUSIONS

1. Foamy oil flow appears to play an important role in the

solution gas drive process with viscous oils. However,

high depletion rates were needed to induce foamy oil flow

in laboratory experiments.

2. The solution gas drive recovery factor increased

dramatically as the rate of pressure decline was increased.

3. Relatively high pressure gradients were observed in fast

depletion tests that produced high recovery factors.

4. The pressure gradient remained very low in slow depletion

tests.

5. The oil viscosity was found to have only a minor effect on

the recovery factors observed in very fast pressure decline

experiments and very slow pressure decline experiments.

6. The critical rate of pressure decline at which the solution

gas drive performance was still at the high end depended

on the oil viscosity.

7. Other factors being the same, the presence of asphaltenes

does not affect recovery factors in high rate solution gas

drive tests.

ACKNOWLEDGEMENTS

The contribution of Mr. F. Nicola in maintaining the

apparatus and carrying out the experiments is gratefully

acknowledged. The author is also grateful to Mr. Roy Woo

for providing the data acquisition program.

REFERENCES

1. Geilikman, M.B., Dusseault, M.B. and Dullien, F.A.L.

(1994); "Sand Production and Yield Propagation Around

Wellbores", paper CIM 94-89 presented at the CIM

1994 Annual Technical Conference, Calgary, Alberta,

June 12-15.

2. Loughead, D.J. and Saltuklaroglu, M. (1992):

"Lloydminster Heavy Oil Production: Why So Unusual?",

paper presented at the Ninth Annual Heavy Oil and Oil

Sands Symposium, Calgary, Alberta (Mar. 11).

3. Maini, B.B., Sarma, H.K., and George, A.E. (1993):

"Significance of Foamy-Oil Behaviour in Primary

Production of Heavy Oils," JCPT, 32, No. 9 (Nov.).

4. Sheng, J.J. and Maini, B.B. (1996); "Foamy Oil Flow in

Primary Production of Heavy Oil - A Literature Review",

PRI Report 1995/96-7, February 1996.

12

Table 1: Properties of the Sand-Pack Used in Depletion Tests.

Length (cm) 200

Cross-Sectional Area (cm2) 16.1

Sand Grain Size (Mesh) 140-200

Porosity (fraction) 0.33

Permeability (m2) 3.33

Table 2: Summary of solution gas drive tests with PAO-100 oil

Test

#1

Test #2 Test #3 Test #4

Pressure decline period Sudde

n

4.5

Days

10

Days

17

Days

Original Oil In Place (mL) 1025 1025 1025 1025

Solution GOR (SCC/mL) 15 15 15 15

Live Oil Viscosity (mPa.s) 1530 1530 1530 1530

Final Volume of Oil

Produced (mL)

275 196 120 74

Recovery Factor %OOIP 26.8 19.1 11.7 7.2

Table 3: Summary of solution gas drive tests with Crest Hill oil

Test

#1

Test

#2

Test

#3

Test #4

Pressure decline periodSudd

en

5

Hours

4.5

Days

2 Days

(Variable

Rate)

Original Oil In Place

(mL)

983 983 983 983

Solution GOR

(SCC/mL)

17.5 17.5 17.5 17.5

Live Oil Viscosity

(mPa.s)

124 124 124 124

Final Volume of Oil

Produced (mL)

306 312 70 261

Recovery Factor

%OOIP

31.1 31.7 7.1 26.6

Table 4: Summary of solution gas drive tests with Hamaca oil

Test

#1

Test

#2

Test

#3

Test

#4

Pressure decline period Sudde

n

22

Days

8

Days

1 Day

Original Oil In Place (mL) 987 987 987 987

13

Solution GOR (SCC/mL) 16.5 16.5 16.5 16.5

Live Oil Viscosity (mPa.s) 750 750 750 750

Final Volume of Oil

Produced (mL)

262.3 50.6 51.7 228

Recovery Factor %OOIP 26.6 5.1 5.2 23.1

14

TABLE 5: SUMMARY OF PRIMARY DEPLETION TESTS WITH BOSCAN OIL

Test # 1 2 3 4 5 6 7

Test Temperature (oC) 77 77 77 77 77 77 77

Saturation Pressure (psi)1000 1000 1000 1000 1000 1000 1000

Solution GOR (mL/mL) 16.5 16.5 16.5 19.7 19.7 19.7 19.7

Live Oil Viscosity (mPa.s) 325 325 325 295 295 295 295

Pore Volume (mL) 1119 1119 1119 1119 1119 1119 1190

Initial Oil in Place (mL at

test condition)

1022 1022 1022 1022 1022 1022 1022

Initial Oil in Place (mL at

room condition)

945 945 945 945 945 945 945

Pressure Decline Period

(Days)

1.5 3 15 Sudden 1.3 2.5 8

Outlet Pressure Decline

Rate (psi/hour)

25.8 13.6 2.74 Sudden 32.3 16.5 5.44

Final Volume of Oil

Produced (mL at 23 oC)

177 101 105.5 310.7 138.4 104.4 69.3

Recovery Factor (%OOIP)18.7 10.7 11.2 32.9 14.6 11.0 7.3

Table 6: Effect of Oil Viscosity on Primary Recovery Factor in Fast Pressure Decline Tests

Oil Viscosity at Test Temperature (mPa.s) Recovery Factor (% OOIP)

Crest Hill 250 31.0

PAO-100 2520 26.8

Boscan 560 32.9

Hamaca 3300 26.6

Gas Used Methane Methane Methane Simulated

Mixture

Simulated

Mixture

Simulated

Mixture

Simulated

Mixture