Chapter 11

1111Drive Mechanisms

CONTENTS

1 DEFINITION

2 NATURAL DRIVE MECHANISM TYPE

2.1 Depletion Drive Reservoirs

2.2 Water Drive

2.3 Compaction Drive

2.4 Gravity Drainage

2.5 Depletion Type Reservoirs

2.5.1 Solution Gas Drive

2.5.2 Gas Cap Drive

2.6 Water Drive Reservoirs

2.7 Combination Drives

3 RESERVOIR PERFORMANCE OF DIFFERENT

DRIVE SYSTEMS

3.1 Solution Gas Drive

3.1.1 Solution Gas Drive, Oil Production

3.1.2 Solution Gas Drive, Gas / Oil Ratio

3.1.3 Pressure

3.1.4 Water Production, Well Behaviour,

Expected Oil Recovery and Well Location

3.2 Gas Cap Drive

3.2.1 Oil Production

3.2.2 Pressure

3.2.3 Gas / Oil Ratio

3.2.4 Water Production, Well Behaviour,

Expected Oil Recovery and Well Locations

3.3 Water Drive

3.3.1 Rate Sensitity

3.3.2 Water Production, Oil Recovery

3.3.3 History Matching Aquifer Characteristics

3.3.4 Well Locations

4 SUMMARY

4.1 Pressure and Recovery

4.2 Gas / Oil Ratio

2

LEARNING OBJECTIVES

Having worked through this chapter the Student will be able to:

• Define reservoir drive mechanism.

• Describe briefly with the aid of sketches a depletion drive reservoir.

• Describe briefly with the aid of sketches a water drive reservoir.

• Describe briefly with the aid a sketches a gravity drainage.

• Describe briefly with the aid of sketches solution gas drive distinguishing

behaviour both above and below the bubble point.

• Describe briefly with the aid of sketches gas cap drive .

• Describe briefly with the aid of sketches the reservoir performance

characteristics of a solution gas drive reservoir.

• Describe briefly with the aid of sketches the reservoir performance

characteristics of a gas drive reservoir.

• Describe briefly with the aid of sketches the reservoir performance characteristics

of water drive reservoir.

• Describe briefly with the aid of sketches the rate sensitivity aspect of water

drive reservoir.

• Summarise the characteristics of solution gas drive, gas cap drive and water

drive reservoirs.

Institute of Petroleum Engineering, Heriot-Watt University 3


RESERVOIR DRIVE MECHANISMS

In the previous chapters we have considered the physical properties of the porous

media, the rock, within which the reservoir fluids are contained and the properties and

behaviour of the fluids. In this chapter we shall examine the various methods used to

calculate the performance of different reservoir types, we will introduce the various

drive mechanisms responsible for production of fluids from a hydrocarbon reservoir.

In this qualitative description of the way in which reservoirs produce their fluids we will

see how the various basic concepts come together to give understanding to the various

driving forces responsible for fluid production. One of the main preoccupation’s of

reservoir engineers is to determine the predominant drive mechanism, for dependant

on the drive mechanism different recoveries of oil can be achieved.

As well as presenting natural drive mechanisms we will also review various artificial

drive mechanisms.

1 DEFINITION

A reservoir drive mechanism is a source of energy for driving the fluids out through

the wellbore. It is not necessarily the energy lifting the fluids to the surface, although

in many cases, the same energy is capable of lifting the fluids to the surface.

2 NATURAL DRIVE MECHANISM TYPES

There are a number of drive mechanisms, but the two main drive mechanisms are

depletion drive and water drive. Other drive mechanisms to be considered are

compaction drive and gravity drive. These drive mechanisms are natural drive

energies and are not to be confused with artificial drive energies such as gas injection

and water injection.

2.1 Depletion Drive ReservoirsA depletion type reservoir is a reservoir in which the hydrocarbons contained are

NOT in contact with a large body of permeable water bearing sand. In a depletion

type reservoir the reservoir is virtually totally enclosed by porous media and the only

energy comes from the reservoir system itself. Figures 1 and 2 illustrate the types of

accumulations which can give rise to depletion drive characteristics.

In figure 1 the hydrocarbons are enclosed in isolated sand lenses which have been

generated by a particular depositional environment. Over geological time the

hydrocarbons have found their way into the porous media. The surrounding rocks may

have permeability but it is so low as to prevent energy transfer from other sources.

In figure 2 is illustrated another depletion type reservoir where a mature reservoir has

been subjected to faulting, resulting in the isolation of a part of the reservoir from

the rest of the accumulation. In a total field system, such a situation can give rise to

parts of the reservoir having different drive mechanism characteristics.

4

Gas

Oil

Water

Figure 1 Depletion reservoir: No aquifer. Isolated sand lenses

Gas

Oil

Water

Figure 2 Depletion reservoir: Aquifer limited by faults



2.2 Water Drive

Gas

Oil

Water

Figure 3 Water drive: Active aquifer

A water drive reservoir is one in which the hydrocarbons are in contact with a large

volume of water bearing sand. There are two types of water drive reservoirs. There

are those where the driving energy comes primarily from the expansion of water as

the reservoir is produced, as shown in figure 3 The key issue here is the relative

size and mobility of the water of the supporting aquifer relative to the size of the

hydrocarbon accumulation.

Water drive may also be a result of artesian flow from an outcrop of the reservoir

formation, figure 4. In this situation either surface water or seawater feeds into the

outcrop and replenishes the water as it moves into the reservoir to replace the oil. The

key issues here are the mobility of the water in the aquifer and barriers to flow from

the outcrop to the reservoir. It is not often encountered, and the water drive arising

from the compressibility of an aquifer, figure 3, is the more common.

Outcropof sand

Oil well

Water flow

Figure 4 Reservoir having artesian water drive.

6

2.3 Compaction DriveFigure 5 illustrates another drive mechanism, compaction drive. Although not a common

drive energy, the characteristics of its occurrence can be dramatic. Compaction drive

occurs when the hydrocarbon formation is compacted as a result of the increase in the

net overburden stress as the reservoir pore pressure is reduced during production. The

nature of the rock or its degree of consolidation can give rise to the mechanism. For

example a shallow sand deposit which has not reached its minimum porosity level due

to consolidation can consolidate further as the net overburden stresses increase as fluids

are withdrawn. The impact of the further consolidation can give rise to subsidence at

the surface. This phenomena of compaction with increasing net overburden stress is

not restricted to unconsolidated sands, since chalk also demonstrates this phenomena.

One of the spectacular occurrences of compaction drive is that associated with the

Ekofisk Field, in the Norwegian sector of the North Sea. This is a very undersaturated

chalk reservoir. The field was developed on the basis of using depletion drive down

to near the bubble point and then to inject sea water to maintain pressure above the

bubble point. During this period of considerable pressure decline, the net overburden

stress was increasing, causing the formation to compact to an extent that subsidence

occurred at the seabed. In an offshore environment such uniform subsidence can go

undetected, as was the case for Ekofisk. The magnitude of the subsidence has been

such that major jacking up of the structures has been required.

Oil

New land

surface

Old land

surface

Figure 5 Compaction drive

2.4 Gravity DrainageGravitational segregation or gravity drainage can be considered as a drive mechanism.

Figure 6 illustrates a situation where the natural density segregation of the phases

can be responsible for moving the fluids to the well bore. Gravity drainage is where

the relative density forces associated with the fluids cause the fluids, the oil, to drain

down towards the production well. The tendency for the gas to migrate up and the oil

to drain down clearly will be influenced by the rate of flow of the fluids as indicated

by their relative permeabilities. Gravity drainage is generally associated with the

later stages of drive for reservoirs where other drive mechanisms have been the more



dominant energy in earlier years. Gravity drainage can be significant and effective

in steeply dipping reservoirs which are fractured.

Of the drive mechanisms mentioned the major drive mechanisms are depletion drive,

which are further classified into solution gas drive and gas cap drive and water drive.

Gravity Drive typically is active during the final stages of a depletion reservoir.

Inactive aquifer

Closed in

InitialGOC

PresentGOC

WC

Z

1000

Gravity drive typically is active during the final stageof a depletion reservoir.

GasOilWater

Figure 6 Gravity drive

2.5. Depletion Type ReservoirsIn depletion drive reservoirs the energy comes from the expansion of the fluids in

the reservoir and its associated pore space. There are two types of depletion drive

reservoirs, solution gas drive reservoirs and gas cap drive reservoirs. In solution

gas drive reservoirs there are two stages of drive mechanism where different energies

are responsible for fluid production.

2.5.1. Solution Gas Drive

In solution gas drive reservoirs the initial condition is where the reservoir is

undersaturated, i.e. above the bubble point. Production of fluids down to the bubble

point is as a result of the effective compressibility of the system. When considering

pressure volume phase behaviour, in the chapter on phase behaviour, we observed

a small increase in volume of the oil for large reductions in pressure, for oil in the

undersaturated state. Associated connate water also has a compressibility as has the

pore space within which the fluids are contained. This combined compressibility

provides the drive mechanism for depletion drive above the bubble point. Perhaps

this part of the depletion drive should be called compressibility drive. The low

compressibility causes rapid pressure decline in this period and resulting low recovery.

Of the three compressibilities, although it is the oil compressibility which is the

larger, the impact of the other compressibility components, the water and the pores,

should not be neglected.

8

As pressure is reduced, oil expands due to compressibility and eventually gas comes

out of solution from the oil as the bubble point pressure of the fluid is reached. The

expanding gas provides the force to drive the oil hence the term solution gas drive.

It is sometimes called dissolved gas drive (Figure 7). Gas has a high compressibility

compared to liquid and therefore the pressure decline is reduced. Solution gas drive

only occurs once the bubble point pressure has been reached.

Initially no gas capand Oil above Pb

Figure 7 Solution gas drive reservoir

2.5.2. Gas Cap Drive

Another kind of depletion type is where there is already free gas in the reservoir,

accumulated at the top of the reservoir in the form of a gas cap (Figure 8), as

compared to the undersaturated initial condition for the previous solution gas drive

reservoir. This gas cap drive reservoir, as it is termed, receives its energy from the

high compressibility of the gas cap. Since there is a gas cap then the bottom hole

pressure will not be too far away from the bubble point pressure and therefore solution

gas drive could also be occurring. The gas cap provides the major source of energy

but there is also the expansion of oil and its dissolved gas and the gas coming out of

solution. The oil expansion term is very low and is within the errors in calculating the

two main energy sources. The two significant sources of driving energy are ;

(1) Gas cap expansion

(2) Expansion of gas coming out of solution



Gas cap

Gas cap expansionSolution gas liberation

With production -

Oil may be above Pb

Gas cap present initiallyOil at interface is at Pb

Oil

Figure 8 Gas cap drive reservoir

2.6 Water Drive ReservoirsWater drive reservoirs are also of two types. There is an edge water drive reservoir.

The reservoir is thin enough so that the water is in contact with the hydrocarbons at

the edge of the reservoir (Figure 9). The other type of water drive reservoir is the

bottom-water-drive reservoir; where the reservoir is so thick or the accumulation so

thin that the hydrocarbons are completely underlain by water (Figure 10).

Edge water

Figure 9 Edge water drive reservoir

10

Bottom water

Water coning

Figure 10 Bottom water drive reservoir

2.7 Combination Drives‘Pure’ types of reservoirs are those reservoirs where only one drive system operates, for

example, depletion drive only - no water drive or water drive only - no gas drive.

It is rare for reservoirs to fit conveniently into this simple characterisation. In many

of them a combination of drive mechanisms can be activate during the production

of fluids. Such reservoirs are called combination drives (Figure 11). In the case in

figure 11, which is not unusual, we have a gas cap with the oil accumulation underlain

by water providing potential water drive. So both free gas and water are in contact

with the oil. In such a reservoir some of the energy will come from the expansion

of the gas and some from the energy within the massive supporting aquifer and its

associated compressibility.

Gas Cap

Oil zone

Water Water50 % Depleted

Original condition

Gas Cap

Oil zone

Water Water

Figure 11 Combination water and gas - cap drive

Sometimes it may be only water drive in the above situations. If the hydrocarbons

are taken out at a rate such that for every volume of oil removed water readily moves

in to replace the oil, then the reservoir is driven completely by water. On the other



hand there may be only depletion drive. If the water does not move in to replace the

oil, then only the gas cap would expand to provide the drive.

3 RESERVOIR PERFORMANCE OF DIFFERENT DRIVE SYSTEMS

Having considered the basic aspects of the drive types we will now examine their

respective characteristics in relation to production, recovery and pressure decline issues.

The performance of different types of reservoirs in relation to the daily production,

gas/oil ratio and water production can give some indication of the type of drive

mechanism operative in the reservoir.

3.1 Solution Gas Drive In the first part of solution gas drive, in what we termed compressibility drive, within the

reservoir no production of gas occurs and the fluid moves as a result of decompression

of the three components oil, water and pore space. The pressure reduction is rapid in

relation to volumes produced. The gas to oil ratio produced at the surface is constant

since the reservoir at this stage is above its bubble point pressure.

Once the bubble point is reached gas comes out of solution. Initially the gas bubbles

are small and isolated. The size and number of the bubbles increase until they reach

a critical saturation when they form a continuous phase and become mobile. At this

stage the gas has relative permeability. The impact of the first bubbles of gas on the

oil is very significant. The relative permeability to the oil is reduced by the presence

of the non wetting gas. (See gas-oil relative permeabilties in chapter 7. Figure 44) As

the increase in saturation of gas increases at the expense of oil saturation, the relative

permeabilties move in the same directions giving rise to reduced well productivity to

oil and increased productivity to gas, figure 12. That is the oil relative permeability

decreases and the gas relative permeability increases. The gas although providing

the displacing medium is effectively leaking out of the system. Not only does the gas

progress to the wellbore, depending on vertical permeability characteristics it will

move vertically and may form a secondary gas cap. If this occurs it can contribute

to the drive energy. Well location and rate of production can be used to encourage

gas to migrate to form such a gas cap as against being lost through production from

the wellbore.

Vertical gasmigration

Gas relative permeability

Oil relative permeability

Rs<

Rsi Rs<

RsiRs<

Rsi

Figure 12 Schematic of solution gas drive.

12

We will now review the various production profiles, specific to the drive mechanisms

but before doing so we will review the various phases of production.

Time

Pro

du

ctio

n

Production

build up

Plateau phase

Decline phase

Abandonment0

Figure 13 Phases in production.

Production Phases (figure 13)

The first phase, production build up, which may exist or not depending on the drilling

strategy is the increased production as wells are brought on stream. Clearly, as in some

cases, wells might be predrilled through a template and then all brought on stream

together when connected to production facilities, such a build up of production will,

therefore, not occur.

The next stage represents the period when the productivity of the production facility

is at its design capacity and the wells are throttled back to limit their productivity.

This period is called the plateau phase when production is maintained at the design

capacity of the facilities. Typical production rates for the plateau period cannot be

presented since it depends on the techno-economics of the field. Clearly for a field

with a very large front loaded capital investment there is an incentive to have a high

production rate during the plateau phase , say 20% of the STOIIP, whereas for a

lower cost onshore field 5% might be acceptable. Governments will also impose

their considerations on this aspect as well.

A time will come when the reservoir is no longer able to deliver fluids to match the

facilities capacity and the field goes into the decline phase. This phase can be delayed

by methods to increase production. Such methods could include artificial lift, where

the effort required to lift the fluids from the reservoir is carried out by a downhole

pump or by using gas lift to reduce the density of the fluid system in the well.

There comes a time when the productivity of the reservoir is no longer able to

generate revenues to cover the costs of running the field, This abandonment time

again is influenced by the size and nature of the operation. Clearly a single, stripper

well, carrying very little operational costs, can be allowed to produce down to very

low rates. A well, as part of a very high cost offshore environment however, could

be abandoned at a relatively high rate when perhaps the water proportion becomes

too high or the productivity in relation to all production is not sufficient to meet the

associated well and production costs.

We will now review the performance characteristics of the various mechanisms in

light of the forgoing production phases.



3.1.1 Solution Gas Drive, Oil Production ( Figure 14 )After a well is drilled and production starts for a solution gas drive reservoir, the

pressure drops in the vicinity of the well. The initially pressure drop is rapid as flow

results from the low compressibility of the system above the bubble point. Pressure

continues to decline and solution gas drive becomes effective as gas comes out of

solution. Mobility of gas occurs and the reduced mobility to oil and resulting decreasing

oil relative permeability further causes the pressure to decline and productivity to oil

flow decrease. Initially when all wells are on stream the oil production is high but

the production rapidly declines and there is a short plateau and decline phase until

an economic limit is reached.

Time-Year

Reservoir

Pressure

Reservoir

Pressure

Oil

Prod

Oil

Prod

G.O.R

G.O.R

Figure 14 Production for solution gas drive

A good analogy for this type of reservoir is the champagne bottle opened by a champion

to spray the contents over enthusiastic supporters - a short lived high production

scenario followed by rapid decline!

3.1.2 Solution Gas Drive, Gas/Oil RatioThe distinctive characteristic of the solution gas drive mechanism is related to the

producing gas to oil ratio. When the reservoir is first produced the GOR being

produced may be low corresponding to the RSi value of the reservoir liquid. If the

reservoir is highly undersaturated there will be a period when a constant producing

GOR occurs 1-2 in figure 15.

When the bubble point is reached in the near well vicinity, the initial gas which

comes out of solution is immobile and therefore oil entering the wellbore is short of

the previous level of solution gas. Theoretically at the surface the producing GOR

level is less than the original GOR 2-3 in figure 15.

14

As the pressure further reduces the released gas becomes mobile and moves at a

velocity greater than its associated oil due to the relative permeability effects. Oil

enters the well bore, with its below bubble point solution GOR value, but also gas

enters the well bore from oil which has not yet arrived. The net effect is that at the

surface the producing GOR increases rapidly as free gas within the reservoir, which

has come out of solution, moves ahead of the oil 3-4 in figure 15.

As the pressure continues to decline the productivity of the well continues to decline

from the combined impact of reducing relative permeability and drop in bottom hole

pressure. The production GOR goes though a maximum as oil eventually is produced

into the well bore with a low solution GOR and the associated gas which has come

out of solution has progressed much faster to the well and contributed to earlier gas

production 4-5 in figure 15.

Pressure

Pro

du

cin

g G

OR

.

Pb

GOR constantabove bubblepoint pressure

Rsi1 2

3

4

5

Figure 15 Producing GOR for solution gas drive reservoir

When the pressure drops below the bubble point throughout the reservoir a secondary

gas cap may be produced and some wells have the potential of becoming gas

producers.

3.1.3 PressureAt first the pressure is high but as production continues the pressure makes a rapid

decline.

3.1.4 Water Production, Well Behaviour, Expected Oil Recovery and Well

LocationSince by definition there is little water present in the reservoir there should be no

water production to speak of. Because of the rapid pressure drop artificial lift will

be required at an early stage in the life of the reservoir. The expected oil recovery

from these types of reservoirs is low and could be between 5 and 30% of the original

oil-in-place. Abandonment of the reservoir will depend on the level of the GOR

and the lack of reservoir pressure to enable production. Well locations for this drive

mechanism are chosen to encourage vertical migration of the gas, therefore the wells

producing zones are located structurally low, but not too close to any water contact

which might generate water through water coning. Figure 16.



Secondarygas cap

Oil water contact

Figure 16 Well location for solution gas drive reservoir.

3.2 Gas Cap DriveWhereas for a solution gas drive reservoir where we have a reservoir initially in an

undersaturated state, for a gas cap drive reservoir, figure 7, the initial condition is a

reservoir with a gas cap. Since the gas oil contact will be at the bubble point pressure

the pressures within the oil accumulation will not be higher than this only so far as

relates to the density gradient of the fluid. It is the gas cap, with its considerable

compressibility, which provides the drive energy for such fields, hence the name.

To get flow in the wells it is likely that gas will come out of solution in the near well

bore vicinity and therefore some degree of solution gas drive will also take place. A

good analogy for this type of reservoir is the plastic chemical dispenser fitted with a

pump to maintain gas pressure above the dispensed liquid.

Gas Cap

Oil zone

Water Water50 % Depleted

Original condition

Gas Cap

Oil zoneWater Water

Figure 17 Gas-cap drive

16

3.2.1 Oil ProductionThe producing characteristics for a gas cap drive reservoir are illustrated in Figure 18.

Although the production may be high as in the solution gas drive, the oil production

still has a significant decline but not as rapid as for solution gas drive. This decline in

oil production is due to the reducing pressure in the reservoir but also from the impact

of solution gas drive on the relative permeability around the well bore. If the well is

allowed to produce at too fast a rate, the very favourable mobility characteristics of the

gas, arising from its low viscosity compared to the oil, are such that preferential flow

can cause gas breakthrough into the wells and the well is then lost to oil production.

Indeed it is this condition which will determine well abandonment.

3.2.2 PressureWith an associated gas cap a loss of volume of fluids from the reservoir is associated

with a relatively low drop in pressure because of the high compressibility of the gas.

In solution gas drive much of the driving gas is produced, but with a gas cap the fluid

remains till later in the life of the reservoir. The pressure drop for a gas cap system

therefore declines slowly over the years. The decline will depend on the relative

size of the gas cap to the oil accumulation. A small gas cap would be 10% of the oil

volume whereas a large gas cap would be 50% of the volume.

Time-Year

Pre

ssure

Oil

Pro

d (

1000)

OilProdRate

G.O

.R

Pressure

G.O.R

0

0 0

1 2 3 4 5 6 7

BSW %20

10

Gas Breakthrough

5

10

250

500

2500

5000

Figure 18 Reservoir performance gas - cap drive.

3.2.3 Gas/Oil RatioDuring the early stages of replacement of oil by gas a 100% replacement takes place.

Later on gas by-passes oil and a reduced displacement efficiency. In the early stages

the GOR remains relatively steady increasing slowly as the impact of solution gas

drive generates gas from oil still to reach the well bore. The increasing mobility of

the gas is such that there is an increasing GOR both from dissolved gas and by-pass

gas and eventually the well goes to gas as the gas cap breaks through.



3.2.4 Water Production, Well Behaviour, Expected Oil Recovery and Well

LocationsLike solution gas drive there should be negligible water production. The life of the

reservoir is largely a function of the size of gas cap but it is likely to be a long flowing

life. The expected oil recovery for such a system is of the order of 20 to 40% of the

original oil-in-place. The well locations, similar to solution gas drive, are such that

the production interval for the wells should be situated away from the gas oil contact

but not too close to the water oil contact to risk water coning.

3.3 Water DriveThe majority of water drive reservoirs predominantly get their drive energy from the

compressibility of the aquifer system. The effectiveness of water drive depends on

the ability of the aquifer to replace the volume of the produced oil. The key issues

with a water drive reservoir are therefore the size of the aquifer and permeability.

This is because the only way for a low compressibility system to be effective is

for its relative size to the oil accumulation to be large, and the permeability of the

aquifer to water to enable flow though the aquifer and into the oil zone. These key

issues set a considerable challenge to the reservoir engineer since to predict water

drive behaviour, requires such information, which in pre production periods can

only be obtained from exploration activity to determine the extent and properties of

the aquifer. It is difficult to obtain justification to expend such exploration costs in

determining the size of a water accumulation!

3.3.1. Rate Sensitivity.The characteristic features of natural water drive reservoirs are strongly influenced by

the rate sensitivity of these reservoirs. If oil production from the formation is greater

than the replacement flow of the aquifer then the reservoir pressure will drop and

another drive mechanism will contribute to flow, for example solution gas drive.

Three sketches below illustrate the various types of production profiles for different

aquifer types and the influence of rate sensitivity. In figure 19 we have the artesian

type aquifer where there is communication to surface water though an outcrop. In

this case if oil is produced at a rate less than the aquifer can move water into the oil

zone, then the reservoir pressure, as measured at the original oil water contact, remains

constant. The producing gas-oil ratio also remains constant since the reservoir is

undersaturated. These reservoirs will enable a plateau phase, however as in all water

drive reservoirs the decline of the reservoirs is not due to productivity loss through

pressure decline but the production of water. The encroaching aquifer with perhaps

its favourable mobility will preferentially move through the oil zone and if there

are high permeability layers will move through these. Eventually the water-cut, the

proportion of water to total production becomes too high and the well is abandoned

to oil production.

18

Pi

Rsi

Reservoir pressure

Oil production rate

Water production

Time

ProductionGOR

Outcrop

of sand

Oil well

Water flow

Figure 19 Producing characteristics for artesian water drive.

Figure 20 illustrates a more typical water drive reservoir where the drive energy comes

from the compressibility of the aquifer system. In this case if the oil withdrawal

rate is less then the rate of water encroachment from the aquifer then the reservoir

pressure will slowly decline, reflecting the decompression of the total system , the

oil reservoir and the aquifer. Clearly this pressure decline is related to the size of

the aquifer. The larger the aquifer the slower the pressure decline. As with all water

drive reservoirs productivity of the wells remains high resulting from the maintained

pressure, however the productivity of the well to oil reduces as water breakthrough

occurs. So a characteristic of water drive reservoirs is the increasing water production

alongside decreasing oil production.



Pi

Rsi

Reservoirpressure

Oil production rate

ProductionGOR

Water production

Time

Figure 20 Producing characteristics for water drive (confined aquifer).

Figure 21 illustrates the rate sensitive aspect of water drive reservoirs. If the oil

withdrawal rate is higher than the water influx rate from the aquifer then the oil

reservoir pressure will drop at a rate greater than would be the case with aquifer

support alone, as the compressibility of the oil reservoirs supports the flow. If this

pressure drops below the bubble point then solution gas drive will occur, as evidenced

by an increase in the gas-oil ratio. Cutting back oil production to a rate to less than

the water encroachment rate restores the system to water drive, with the gas-oil ratio

going back to its undersaturated level.

When two drive mechanisms function as above then we have what is termed

combination drive ( water drive and solution gas drive).

Water drive reservoirs have good pressure support. The decline in oil production is

related to increasing water production as against pressure decline.

20

200010000

1000 5000

0 0 0

500

250

GOR

69 70 71 72 73 74 750

Reservoir pressure

Oil production

Water

GOR

Bsw

Ps

PROD

Wa

ter

pro

duction

25

50

BSW

Pro

ducin

g g

as / o

il ra

tio

Reserv

oir p

ressure

p

si

Oil

pro

duction r

ate

B

/d

Figure 21 Reservoir performance - Water drive.

3.3.2 Water Production, Oil Recovery

Because there is a large aquifer associated with the oil reservoir unlike depletion

drive systems, water production starts early and increases to appreciable amounts.

This water production is produced at the expense of oil and continues to increase

until the oil/water ratio is uneconomical. Total fluid production remains reasonably

steady. The expected oil recovery from a water drive reservoir is likely to be from 35

to 60% of the original oil-in-place. Clearly these recovery factors depend on a range

of related aspects , including reservoir characteristics for example the heterogeneity

as demonstrated by large permeability variations in the formation.

3.3.3. History Matching Aquifer Characteristics.Predicting the behaviour of water drive reservoirs in particular the rate of water

encroachment is not straightforward. The topic is covered in a later chapter, but a

significant perspective as mentioned previously is that data is required of the aquifer

to carry out the calculations. In particular the size and geometry of the aquifer and its

permeability and compressibility characteristics. Since such information is generally

not available during the exploration and development phase, the characteristics of the

aquifer are only determined once production has been operational and the support from

the aquifer can be calculated from production and pressure data. (History Matching).

Getting such information may require producing a significant proportion of the

formation say 5% of the STOIIP. RFT surveys have provided a very effective way of

determining the aquifer strength as well as the communicating layers of the formation.

Pressure depth surveys taken in an open hole development well after production has

started will give indications of pressure support in the formation

Because water drive, through pressure maintenance provides the most optimistic

recoveries, artificial water drive is often part of the development strategy because of

the uncertainties of the pressure support from the associated aquifer. In the North Sea

for example many reservoirs have associated aquifers. The risk of not knowing either



the extent or activity of the aquifers is such that many operators are using artificial

water drive systems to maintain pressure so that solution gas drive does not occur

with the consequent loss of oil production.

3.3.4. Well LocationsWell locations for water drive reservoirs are such that they should be located high in

the structure to delay water breakthrough.

4 SUMMARY

The following summaries and tables give the main features associated with the

various drive mechanisms.

4.1 Pressure and Recovery

Water-drive -pressure declines slowly and abandonment occurs when the water cut

is too-high at around 50% of recovery, but depends on local factors.

Gas-cap drive - the pressure shows a marked decline and economic pressures

are reached around 20% of the original pressure when about 30% of the oil is

recovered.

Solution- gas drive - the pressure drops more sharply and at 10% of the pressure

reaches, an uneconomical level of recovery at about 10% of the oil-in-place.

4.2 Gas/Oil Ratio

Water drive - the curve for a water drive system shows a gas/oil ratio that remains

constant. Variations from this indicate support from solution gas drive or other

drive mechanisms

Gas-cap drive - for this drive the gas/oil ratio increases slowly and continuously.

Solution- gas drive - the curve for a solution gas drive reservoir shows that the

gas/oil ratio increases sharply at first then later declines.

22

SOLUTION GAS DRIVE RESERVOIRS

Characteristics Trend1. Reservoir Pressure Declines rapidly and continuously

2. Gas/Oil Ratio First low then rises to a maximum and

then drops

3. Production Rate First high, then decreases rapidly and

continues to decline

4. Water Production None

5. Well Behaviour Requires artificial lift at early stages

6. Expected Oil Recovery 5-30% of original oil-in-place

GAS CAP DRIVE RESERVOIRS

Characteristics Trend1. Reservoir Pressure Falls slowly and continuously

2. Gas/oil ratio Rises continuously

3. Production Rate First high, then declines gradually

4. Water Production Absent or negligible

5. Well Behaviour Cap Long flowing life depending on size of gas cap

6. Expected Oil Recovery 20 to 40% of original oil-in-place

WATER DRIVE RESERVOIRS

Characteristics Trend1. Reservoir Pressure Remains high

2. Gas/Oil Ratio Remains steady

3. Water Production Starts early and increases to appreciable

amounts

4. Well Behaviour Flow until water production gets excessive

5. Expected Oil Recovery up to 60% original oil-in-place.

Figures 22 and 23 give the pressure and gas-oil ratio trends for various drive

mechanism types



100

80

60

40

20

00 20 40 60 80 100

Water drive

Gas cap drive

Dissolvedgas drive

Re

se

rvo

ir p

ressu

re -

pe

rce

nt

of

orig

ina

l

Oil produced - percent of original oil in place

Reservoir pressure trends for reservoirs under various drives.

Figure 22

5

4

3

2

1

00 20 40 60 80 100

Water drive

Gas cap driveDissolvedgas drive

GO

R M

CF

/B

BL

Oil produced - percent of original oil in place

Reservoir gas - oil ratio trends for reservoirs under various drives.

Figure 23