Chapter 11
Content
Drive Mechanisms
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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
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 characteristics of a gas drive reservoir. the reservoir performance
• •
•
•
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.
•
•
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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 Reservoirs
A 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.
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Gas Oil Water
Figure 1 Depletion reservoir: No aquifer. Isolated sand lenses
Gas Oil Water
Figure 2 Depletion reservoir: Aquifer limited by faults
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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.
Outcrop of sand
Oil well
Water flow
Figure 4 Reservoir having artesian water drive.
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2.3 Compaction Drive
Figure 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.
Old land surface
New land surface
Oil
Figure 5 Compaction drive
2.4 Gravity Drainage
Gravitational 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
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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.
Closed in 1000
Z
Initial GOC Present GOC /WC
Gas Oil Water
Inactive aquifer Gravity drive typically is active during the final stage of a depletion reservoir.
Figure 6 Gravity drive
2.5. Depletion Type Reservoirs
In 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.
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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 cap and 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) (2) Gas cap expansion Expansion of gas coming out of solution
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Gas cap present initially Oil at interface is at Pb
Gas cap
Oil
Oil may be above Pb With production - Gas cap expansion Solution gas liberation
Figure 8 Gas cap drive reservoir
2.6 Water Drive Reservoirs
Water 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
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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 Original condition Water
Gas Cap
Oil zone Water 50 % Depleted 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
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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 gas migration
Gas relative permeability
Rs< Rsi
Rs< Rsi
Rs< Rsi
Oil relative permeability
Figure 12 Schematic of solution gas drive.
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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.
Plateau phase
Production
Decline phase Production build up Abandonment Time
0
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.
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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.
Oil G.O.R Prod
Reservoir Pressure
Oil Prod
G.O.R
Reservoir Pressure
Time-Year
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 Ratio
The 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.
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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.
Producing GOR.
GOR constant above bubble point pressure Rsi 1 2 3
4
5
Pb Pressure
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 Pressure
At 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 Location
Since 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.
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Secondary gas cap
Oil water contact
Figure 16 Well location for solution gas drive reservoir.
3.2 Gas Cap Drive
Whereas 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
Water
Oil zone Original condition
Water
Gas Cap
Oil zone Water 50 % Depleted Water
Figure 17 Gas-cap drive
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3.2.1 Oil Production
The 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 Pressure
With 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.
Oil Prod (1000)
500
G.O.R
Pressure 5000 Pressure Gas Break through Oil Prod Rate 2500 G.O.R BSW % 20 10 0 1 2 3 4 5 6 7
10
250
5
0 0
Time-Year
Figure 18 Reservoir performance gas - cap drive.
3.2.3 Gas/Oil Ratio
During 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.
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3.2.4 Water Production, Well Behaviour, Expected Oil Recovery and Well Locations
Like 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 Drive
The 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.
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Outcrop of sand
Oil well
Water flow
Pi
Reservoir pressure
Oil production rate
Rsi
Production GOR
Water production Time
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.
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Pi
Oil production rate
Rsi
Production GOR
Reservoir pressure
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.
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2000 10000
BSW
GOR 500
Reservoir pressure Ps psi B/d PROD Oil production GOR 25 Bsw Water 0 69 70 71 72 73 74 75 50 Water production 0 250 Producing gas / oil ratio
1000 5000 Reservoir pressure 0 Oil production rate 0
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
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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 Locations
Well 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.
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SOLUTION GAS DRIVE RESERVOIRS Characteristics
1. Reservoir Pressure 2. Gas/Oil Ratio 3. Production Rate 4. Water Production 5. Well Behaviour 6. Expected Oil Recovery
Trend
Declines rapidly and continuously First low then rises to a maximum and then drops First high, then decreases rapidly and continues to decline None Requires artificial lift at early stages 5-30% of original oil-in-place
GAS CAP DRIVE RESERVOIRS Characteristics
1. Reservoir Pressure 2. Gas/oil ratio 3. Production Rate 4. Water Production 5. Well Behaviour Cap 6. Expected Oil Recovery
Trend
Falls slowly and continuously Rises continuously First high, then declines gradually Absent or negligible Long flowing life depending on size of gas cap 20 to 40% of original oil-in-place
WATER DRIVE RESERVOIRS Characteristics
1. Reservoir Pressure 2. Gas/Oil Ratio 3. Water Production 4. Well Behaviour 5. Expected Oil Recovery
Trend
Remains high Remains steady Starts early and increases to appreciable amounts Flow until water production gets excessive up to 60% original oil-in-place.
Figures 22 and 23 give the pressure and gas-oil ratio trends for various drive mechanism types
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Reservoir pressure trends for reservoirs under various drives. 100 Reservoir pressure - percent of original
80 Water drive 60 Gas cap drive
40
20
Dissolved gas drive 0 20 40 60 80 Oil produced - percent of original oil in place 100
0
Figure 22
Reservoir gas - oil ratio trends for reservoirs under various drives. 5 4 Dissolved gas drive GOR MCF /BBL 3 Gas cap drive
2
1 Water drive 0 0 20 40 60 80 Oil produced - percent of original oil in place 100
Figure 23
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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
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 characteristics of a gas drive reservoir. the reservoir performance
• •
•
•
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.
•
•
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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 Reservoirs
A 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.
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Gas Oil Water
Figure 1 Depletion reservoir: No aquifer. Isolated sand lenses
Gas Oil Water
Figure 2 Depletion reservoir: Aquifer limited by faults
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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.
Outcrop of sand
Oil well
Water flow
Figure 4 Reservoir having artesian water drive.
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2.3 Compaction Drive
Figure 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.
Old land surface
New land surface
Oil
Figure 5 Compaction drive
2.4 Gravity Drainage
Gravitational 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
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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.
Closed in 1000
Z
Initial GOC Present GOC /WC
Gas Oil Water
Inactive aquifer Gravity drive typically is active during the final stage of a depletion reservoir.
Figure 6 Gravity drive
2.5. Depletion Type Reservoirs
In 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.
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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 cap and 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) (2) Gas cap expansion Expansion of gas coming out of solution
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Gas cap present initially Oil at interface is at Pb
Gas cap
Oil
Oil may be above Pb With production - Gas cap expansion Solution gas liberation
Figure 8 Gas cap drive reservoir
2.6 Water Drive Reservoirs
Water 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
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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 Original condition Water
Gas Cap
Oil zone Water 50 % Depleted 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
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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 gas migration
Gas relative permeability
Rs< Rsi
Rs< Rsi
Rs< Rsi
Oil relative permeability
Figure 12 Schematic of solution gas drive.
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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.
Plateau phase
Production
Decline phase Production build up Abandonment Time
0
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.
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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.
Oil G.O.R Prod
Reservoir Pressure
Oil Prod
G.O.R
Reservoir Pressure
Time-Year
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 Ratio
The 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.
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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.
Producing GOR.
GOR constant above bubble point pressure Rsi 1 2 3
4
5
Pb Pressure
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 Pressure
At 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 Location
Since 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.
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Secondary gas cap
Oil water contact
Figure 16 Well location for solution gas drive reservoir.
3.2 Gas Cap Drive
Whereas 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
Water
Oil zone Original condition
Water
Gas Cap
Oil zone Water 50 % Depleted Water
Figure 17 Gas-cap drive
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3.2.1 Oil Production
The 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 Pressure
With 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.
Oil Prod (1000)
500
G.O.R
Pressure 5000 Pressure Gas Break through Oil Prod Rate 2500 G.O.R BSW % 20 10 0 1 2 3 4 5 6 7
10
250
5
0 0
Time-Year
Figure 18 Reservoir performance gas - cap drive.
3.2.3 Gas/Oil Ratio
During 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.
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3.2.4 Water Production, Well Behaviour, Expected Oil Recovery and Well Locations
Like 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 Drive
The 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.
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Outcrop of sand
Oil well
Water flow
Pi
Reservoir pressure
Oil production rate
Rsi
Production GOR
Water production Time
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.
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Pi
Oil production rate
Rsi
Production GOR
Reservoir pressure
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.
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2000 10000
BSW
GOR 500
Reservoir pressure Ps psi B/d PROD Oil production GOR 25 Bsw Water 0 69 70 71 72 73 74 75 50 Water production 0 250 Producing gas / oil ratio
1000 5000 Reservoir pressure 0 Oil production rate 0
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
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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 Locations
Well 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.
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SOLUTION GAS DRIVE RESERVOIRS Characteristics
1. Reservoir Pressure 2. Gas/Oil Ratio 3. Production Rate 4. Water Production 5. Well Behaviour 6. Expected Oil Recovery
Trend
Declines rapidly and continuously First low then rises to a maximum and then drops First high, then decreases rapidly and continues to decline None Requires artificial lift at early stages 5-30% of original oil-in-place
GAS CAP DRIVE RESERVOIRS Characteristics
1. Reservoir Pressure 2. Gas/oil ratio 3. Production Rate 4. Water Production 5. Well Behaviour Cap 6. Expected Oil Recovery
Trend
Falls slowly and continuously Rises continuously First high, then declines gradually Absent or negligible Long flowing life depending on size of gas cap 20 to 40% of original oil-in-place
WATER DRIVE RESERVOIRS Characteristics
1. Reservoir Pressure 2. Gas/Oil Ratio 3. Water Production 4. Well Behaviour 5. Expected Oil Recovery
Trend
Remains high Remains steady Starts early and increases to appreciable amounts Flow until water production gets excessive up to 60% original oil-in-place.
Figures 22 and 23 give the pressure and gas-oil ratio trends for various drive mechanism types
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Reservoir pressure trends for reservoirs under various drives. 100 Reservoir pressure - percent of original
80 Water drive 60 Gas cap drive
40
20
Dissolved gas drive 0 20 40 60 80 Oil produced - percent of original oil in place 100
0
Figure 22
Reservoir gas - oil ratio trends for reservoirs under various drives. 5 4 Dissolved gas drive GOR MCF /BBL 3 Gas cap drive
2
1 Water drive 0 0 20 40 60 80 Oil produced - percent of original oil in place 100
Figure 23
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