Drive Mechanisms

Notes

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Basic Petroleum EngineeringSchlumberger

Drive Mechanisms

Drive MechanismsWater Drive

Gas Cap driveSolution Gas Drive

Drive problemsSecondary Recovery

© JJ Consulting 1997

Notes

There is also the gravity drive.

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Drive Mechanisms

A virgin reservoir has a pressure controlled by the local gradient.

Hydrocarbons will flow if the reservoir pressure is sufficient to drive the fluids to the surface (otherwise they have to be pumped).

As the fluid is produced reservoir pressure drops.The rate of pressure drop is controlled by the Reservoir Drive Mechanism.

Drive Mechanism depends on the rate at which fluid expands to fill the space vacated by the produced fluid.

Main Reservoir Drive Mechanism types are:

Water drive.

Gas cap drive.

Gas solution drive

Notes

Water has two advantages , firstly there is water in the hydrocarbon zone in the form of irreducible water with which it can join and hence clean around the grains. Secondly capillary pressure helps the water up the small pore channels.

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Water Invasion 1

Water invading an oil zone, moves close to the grain surface, pushing the oil out of its way in a piston-like fashion.

The capillary pressure gradient forces water to move ahead faster in the smaller pore channels.

Notes

There will always be some oil left in the rock, 100% recovery is impossible.

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Water Invasion 2

The remaining thread of oil becomes smaller.

It finally breaks into smaller pieces.

As a result, some drops of oil are left behind in the channel.

Notes

The (normally) large volume of the water system gives additional assistance to this type of drive. The hydrocarbon is pushed out as its pressure drops, while the pressure in the water remains higher hence the water will move to force the oil out.

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Water Drive

Water moves up to fill the "space" vacated by the oil as it is produced.

Notes

The production of water will invariably increase. The amount of water finally produced depends on capabilities of the surface production facilities and the economics of the process. It can be as much as 98%.

Gas production is simply that associated with the oil and depends on the gas-oil ratio.

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Water Drive 2

This type of drive usually keeps the reservoir pressure fairly constant.

After the initial “dry” oil production, water may be produced. The amount of produced water increases as the volume of oil in the reservoir decreases.

Dissolved gas in the oil is released to form produced gas.

Water Production

Notes

The very high mobility of gas (low viscosity) means that it goes down the large pore channels bypassing the smaller ones. Once past a zone the gas will continue leaving the oil trapped; it will not be produced.

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Gas Invasion

Gas is more mobile than oil and takes the path of least resistance along the centre of the larger channels.

As a result, oil is left behind in the smaller, less permeable, channels.

Notes

The main type of gas drive is the gas cap drive. The gas cap expansion forces the oil out.

The gas cap needs to be large for this type of drive to succeed.

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Gas Cap Drive

Gas from the gas cap expands to fill the space vacated by the produced oil.

Notes

As the gas cap expands the pressure drops hence the drive efficiency goes down. In addition there is always breakthrough of the free gas and production at an apparent high GOR.

The reservoir pressure will go down quickly.

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Gas Cap Drive 2

As oil production declines, gas production increases.

Rapid pressure drop at the start of production.

Notes

This type of drive uses the energy of expansion of the gas dissolved in the oil as there is no appreciable water or gas cap drive. This is very inefficient as there on a little possible expansion. In addition the reservoir rapidly drops below bubble point in the reservoir itself. This means that gas comes out of solution in the reservoir. This will create problems for production and eventually the reservoir will die.

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Solution Gas Drive

After some time the oil in the reservoir is below the bubble point.

Notes

The slide shows the rapid decline in all the parameters in the reservoir, pressure, production. The GOR also declines as the gas is produced.

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Solution Gas Drive 2

An initial high oil production is followed by a rapid decline.

The Gas/Oil ratio has a peak corresponding to the higher permeability to gas. The reservoir pressure exhibits a fast decline.

Notes

The slide compares the total cumulative production of the various drive mechanisms against the reservoir pressure. The water drive keeps the pressure high and hence is the most efficient at production the reservoir fluids.

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Drives General

A water drive can recover up to 60% of the oil in place.

A gas cap drive can recover only 40% with a greater reduction in pressure.A solution gas drive has a low recovery.

Notes

Coning is caused by producing the reservoir at a drawdown that is too high and also having perforations that are too long. The water (or gas) is drawn to the perforated interval and produced. This problem can usually be fixed.

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conesupwards

Drive Problems

Water Drive:Water can cone upwards and be produced through the lower perforations.

Gas Cap Drive:Gas can cone downwards and be produced through the upper perforations.Pressure is rapidly lost as the gas expands.

Gas Solution Drive:

Gas production can occur in the reservoir, skin damage.

Very short-lived.

Notes

Most modern reservoirs have some sort of secondary recovery built into their management from their initial production. The aim of all these schemes is to maintain the pressure in the reservoir as high as possible for as long as possible.

The main problem with heavy oil is its high viscosity. Reduction of the viscosity is achieved by heating the fluid, hence the steam injection and the in-situ combustion or by adding CO2. This substance reduces the viscosity of the oil by two orders of magnitude, for example from 500 centipoise to 5.

Polymer injection adds polymers to the injection water to increase the viscosity of this fluid. Ordinary water has a much lower viscosity and hence does not sweep the heavy oil efficiently.

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Secondary Recovery 1

Secondary recovery covers a range of techniques used to augment the natural drive of a reservoir or boost production at a later stage in the life of a reservoir.A field often needs enhanced oil recovery (EOR) techniques to maximise its production.

Common recovery methods are:Water injection.

Gas injection.

In difficult reservoirs, such as those containing heavy oil, more advanced recovery methods are used:

Steam flood.Polymer injection. .

CO2 injection.In-situ combustion.

Notes

Water can come from the sea water, or a nearby and different aquifer. The injectors are set in patterns depending on the permeability of the reservoir.

Gas often comes from produced can which can be compressed and re-injected into the gas cap.

Both types of injection can operate at the same time.

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Secondary Recovery 2 water injection

gas injection

Notes

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Water Injection

The simplest ( and cheapest) of the techniques

Water is injected into a nearby well forcing the oil out

The water can either be:

sea water

Recycled produced water

From an aquifer different to that of the reservoir

The pattern of injectors depends on the permeability of the reservoir rock and the possibility of problems

Five and nine spot are common

Notes

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Material Balance

Material Balance

Oil Volumes

General Equation

Simplified Equation

Reservoir Simulation

Notes

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Oil volume

Oil Volume

gas cap expansion

released gas volume

oil volume

rock/water expansion

net water influx

The original oil volume is replaced by the expansion of the other system components

- gas

- water

- rock

A reservoir contains an original volume of oil, as this oil is removed the other components of the system move/expand to fill the space vacated.

This is described by the drawing. It is not to scale as the gas will expand much more than the rock and water.

Notes

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Gas Cap Expansion

When oil is produced the gas gap expands to replace part of the oil.

The gas cap may shrink if the gas produced is a significant fraction of the initial amount.

G − Gpc( )Bgc − GBgci

G - original gas cap in place

Gpc - cumulative gas produced from the gas cap, scf

Bgc - gas formation volume factor at current pressure RB/scf

Bgci - gas formation volume factor at the original pressure

Notes

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Released Gas VolumeGas cap expansion is always accompanied by the release of gas from the reservoir oil

The gas originally in solution can be placed in three categories

still in solution

produced from the reservoir

released from solution but still in the reservoir

The equation for the reservoir volume of released gas is:

NRsi − N − Np( )Rs − Gps[ ] Bgs

This is the difference between the original gas in solution and the current gas in solution. Subtracting the gas produced gives the released gas still in the reservoir.

N - original oil in place

Np - cumulative oil produced

Rsi - initial solution gas oil retio

Rs - solution gas-oil ratio at current pressure

Gps - cumulative gas produced

Bgs - current solution gas formation volume factor

Notes

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Oil Volume

N − N p( )Bo

The reservoir volume of oil remaining at reservoir conditions is:

N - original oil in place

Np - oil produced

Bo - oil formation volume factor

Notes

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Rock and Connate Water Expansion

c f

NBoi

1 − Swi( )

pi − p( )

Rock and connate (original formation water) expansion are combined in one term for convenience

rock expansion =

connate water expansion =

combining both expressions gives

Rock and water expansion =

cw Swi

NBoi

1− Swi( )

pi − p( )

c f + cwSwi( ) NBoi

1 − Swi( )

pi − p)( )

cf - formation compressibility (1/psi)

pi - initial formation pressure

p - current reservoir pressure

cw - water compressibility

Swi - initial water saturation

Notes

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Water Influx

The volume of water influx cannot be computed from pressure and fluid properties as has been done for the other fluids.

The influx can be inferred from a knowledge of the other terms in the general material balance equation

We − WpBwNet water influx =

We - cumulative water influx

Wp - cumulative produced water

Bw - water formation volume factor

Notes

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General Material Balance Equation

Original Oil Volume =

Gas cap Expansion +

Released Gas volume +

Oil volume +

Rock and Water Expansion +

Net Water Influx

NBoi = G − G pc( )Bgc − GB gci +

NRsi − N − N p( )Rs − Gps[ ]Bgs +

N − N p( )Bo + c f + cw Swi( ) NBoi

1− Swi

p i − p( )+

We − Wp Bw

This is the complete equation made up of the terms from the previous pages. Most of the items in the equation are measured, Bo, Rs etc.

This general equation assumes everything that could happen does. In practice there are always simplifications, for example there may be no gas cap.

Notes

N initial oil in place

m (initial gas cap volume)/(initial oil volume)

Np cumulative oil production on surface

Rp cumulative gas oil ratio

Rsi initial gas oil ratio

Rs gas oil ratio after pressure drop (ie production)

Boi initial oil FVF

Bo oil FVF after production

Bgi initial FVF gas

Bg gas FVF after production

Sw original connate water saturation

cw water compressibility

cf total pore space compressibility

The objective here is to make a “simple” term for each specific item.

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Simplified Material balance

F = NpBo + (Rp − Rs )Bg + Wp Bw

E0 = (B0 − B0i) + (Rsi − Rs )Bg

Eg = B0i (Bg

Bgi

−1)

E f , w = (1 − m)B0 i(cw Sw + c f

1− Sw

)∆p

F = N Eo + mEg + E f ,w( ) + WeBw

Underground withdrawal

Original oil and dissolved gas expansion

Gas cap expansion

Expansion of connate water

Material balance equation

Notes

Taking the final equation of the previous page and assuming no gas cap and no water movement results in a very simple linear equation.

A plot of the observed production, F, against the oil factor, Eo should give a straight line whose slope is the original oil in place.

If the slope if not straight the assumptions of no other fluid interaction are wrong. One possibility is water influx leading to the equation at the bottom, where another linear equation is created, and both N and We are found.

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Simplified Equation

F = NEo

F

Eo

= N +We

Eo

Assuming no initial gas cap and negligible water influx

The observed production is a linear function ofthe the expansion of the oil plus the dissolved gas

If the plot is non linear it could mean water influx

This linear equation will take this into account

Notes

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Gas cap drive

In a gas cap drive the equation reduces to

this can be solved for m if the initial oil in place N in known.

If both N and m are unknown the equation is rewritten as

a ‘best fit’ solution for both N and m is then found on a linear plot

F = N Eo + mEg( )

F

Eo

= N + mNEg

Eo

This form of the equation assumes a gas cap drive mechanism with no water.

A plot of F against (Eo +mEg) will give the value for m, the size of the gas cap.

The equation can also be used to solve for both N and m if they are unknown.

This type of approach is a good way of obtaining the reserves figures.

Notes

A reservoir simulation is a modern way of using material balance together with a description of the reservoir to properly manage the resources.

It requires a large amount of data and the work of a number of disciplines to get the best possible answer.

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Objective of Reservoir Simulation

The objective is to create a live description of the reservoir

The inputs are

geology - lithology, units, core data, maps

reservoir engineering - flow systems, fluid behaviour, and PVT analysis

petrophysics - log interpretation, reservoir parameters, zoning

geophysics - areal extent, large scale features

Notes

One of the major steps in the simulation is the creation of the reservoir model. The process uses data from well logs and tests and seismic surveys to paint a picture of the part of the system under study. This can vary from a small part of the reservoir to an entire field.

The more complex the model the more information that is required.

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Model Building

A model of the formation is created using all the available information.

This model is divided into blocks.Each block is described by its properties, porosity, permeability, saturations, fluid properties, pressures and so on.The objective is to create a complete description of the reservoir.

Notes

The procedure outlined is a crude approximation of the work involved. Before even this flow chart there is the vital stage of data collection.

Reservoir characterisation is the process of making a detailed analysis of the log and core data.

The model is then constructed from this and test data.

The history match checks the models validity by comparing the predicted past with the actual past in terms of pressures and production.

The reservoir management plan can only be made if the history match has worked.

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Reservoir Simulation Procedure

Reservoir

Characterisation

Model Construction

Model Validation

History Match

Prediction of Future Performance

Prepare Reservoir Management Plan

Notes

The example shows the match of water and gas rates over a period of a few years. In general the match is good. If there were large deviations the model has to be reviewed and the process rerun. A single pass of a history match can take over a day to run.

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History Match

A match is made of the rates and pressures measured over time with those predicted by the computer model. If the match is good reservoir management plans can be made. If the match is poor the model has to be reviewed.

Documents

Drive Mechanisms