petrophysict 3 reservoir Fluids

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Notes 1 Reservoir Fluids Reservoir Fluids © Schlumberger 1999

Transcript of petrophysict 3 reservoir Fluids

Page 1: petrophysict 3 reservoir Fluids

Notes

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Reservoir Fluids

Reservoir Fluids

© Schlumberger 1999

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Notes

Reservoir fluids need to be described in a different way from the rocks. The first definition is one of contacts, where the fluids would be in equilibrium. These are the gas-oil-contact, the oil-water-contact and the gas-water-contact. The latter is only possible in a well with gas and water (no oil).The second figure is the oil in place, the amount of hydrocarbon in the reservoir.The final figure is one of the hydrocarbon properties, the gas-oil-ratio; how much gas is in the oil. Due to the complexity of the hydrocarbons in the reservoir there are many other parameters which are needed to fully describe the fluids.

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Definitions

Oil in Place OIP The volume of oil in the

reservoir in barrels or cubic metres.

Gas/Oil Ratio GOR The gas content of the oil.

API Gravity API Oil gravity.

Fluid Contacts

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Notes

Other gases can be found in wells, these include, helium, carbon dioxide and hydrogen sulphide. In most cases these occur as traces together with the hydrocarbon and water normally found. The formation water is uniquely described by its salinity. This varies from 500 ppm Chlorides to 250000ppm; a wide range.The major rock property involved in production is the permeability.

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Fluids in a Reservoir

A reservoir normally contains either water or hydrocarbon or a mixture.

The hydrocarbon may be in the form of oil or gas.

The specific hydrocarbon produced depends on the reservoir pressure and temperature.

The formation water may be fresh or salty.

The amount and type of fluid produced depends on the initial reservoir pressure, rock properties and the drive mechanism.

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Notes

Hydrocarbons vary widely in their properties. The first classification is by fraction of each component. This ranges from a dry gas which is mostly C1 (methane) to tar which is mostly the heavier fractions. The black oil normally found is between the two extremes, with some C1 and some heavier fractions.The hydrocarbon extracted from reservoirs varies in composition from place to place. Fluids originating from the same source rock will be similar but never exactly the same.

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Hydrocarbon Composition

Typical hydrocarbons have the following composition in Mol Fraction

Hydrocarbon C1 C2 C3 C4 C5 C6+

Dry gas .88 .045 .045 .01 .01 .01

Condensate .72 .08 .04 .04 .04 .08

Volatile oil .6-.65 .08 .05 .04 .03 .15-.2

Black oil .41 .03 .05 .05 .04 .42

Heavy oil .11 .03 .01 .01 .04 .8

Tar/bitumen 1.0

The 'C' numbers indicated the number of carbon atoms in the molecular chain.

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Notes

Another way to describe the hydrocarbons is by the mixtures of the groups of hydrocarbon structure types. The three major groups are shown. The simplest and most abundant is the paraffin series, chains of carbon atoms with the hydrogen attached. The chemical formula for this type of structure is CnHn+2. The more complex ring structures, napthelenes and benzines occur in varying proportions.

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Hydrocarbon Structure

The major constituent of hydrocarbons is paraffin.

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Notes

Oil is more complex than gas and has to be defined in a more complete manner. The Gas-Oil Ratio, GOR (symbol Rs) is a measure of how much gas is in the oil and thus how light it is. This is measured at a specific pressure and temperature , for example the reservoir conditions.The API gravity is a weight. The definition equation given simply sets numbers for given oils. The heaviest have the lowest API gravity. The price of oil depends on its API gravity, with the standard or reference crudes being the black oils between 30 and 40 API.

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Hydrocarbon ClassificationHydrocarbons are also defined by their weight and the Gas/Oil ratio. The table gives some typical values:

GOR API Gravity

Wet gas 100mcf/b 50-70

Condensate 5-100mcf/b 50-70

Volatile oil 3000cf/b 40-50

Black oil 100-2500cf/b 30-40

Heavy oil 0 10-30

Tar/bitumen 0 <10

The specific gravity of an oil is defined as:

5.131..

5.141−=°

grspAPI

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Notes

Natural gas is a much simple fluid than oil as it is essentially one component. Gas specific gravity with respect to air should not be confused with the specific gravity with respect to water.

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Hydrocarbon Gas

Natural gas is mostly (60-80%) methane, CH4. Some heavier gases make up the rest.

Gas can contain impurities such as Hydrogen Sulphide, H2S and Carbon Dioxide, CO2.

Gases are classified by their specific gravity which is defined as:

"The ratio of the density of the gas to that of air at the same temperature and pressure".

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Notes

The pressure in the reservoir is controlled by the aquifer as it is assumed that it is, somewhere, connected to surface. This means that the pressure in the water is effectively continuous controlled by the pressure gradient. The pressure gradient depends on the salinity of the water, the temperature and the regional tectonic stresses. It is usually constant over a large area. The pressures in the oil and gas depend on the gradients (densities) of these fluids. The difference in gradients with the water gradient depends on the specific gravity with respect to water.

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Reservoir Pressure

Reservoir Pressures are normally controlled by the gradient in the aquifer.High pressures exist in some reservoirs.

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Notes

The static pressures anywhere in the reservoir can be calculated using these formula. The calculation starts at the bottom of the zone in the water, specifically at the OWC. The pressure here is simply the depth times the water gradient.The pressure at the GOC is the pressure at the OWC minus the pressure du to the oil column. This is given by the thickness of the oil column times the water gradient times the specific gravity of the oil. A similar calculation can be made for the gas zone.

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Reservoir Pressure Calculation

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Notes

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Reservoir Pressure Example

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Notes

Temperature in wells depends on a regional gradient. There can be local “hot spots” where this is sharply increased. The temperature is measured during each logging run.Temperatures gradients are greatest near the edges of the plates and lowest near the centres of the old continental plates as these are the thickest points of the crust.

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Reservoir Temperature Gradient

The chart shows three possible temperature gradients. The temperature can be determined if the depth is known.

High temperatures exist in some places. Local knowledge is important.

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Notes

The phase behaviour of the reservoir fluids are important as the fluid in the reservoir will change as it is produced.The pressure and temperature are two quantities that can be easily measured. Thus it is useful to describe the fluids behaviour during production in these terms. Experimentally it is easier to measure pressure and volume hence the classical experiment is done using these parameters at a constant temperature.

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Fluid Phases

A fluid phase is a physically distinct state, e.g.: gas or oil.

In a reservoir oil and gas exist together at equilibrium, depending on the pressure and temperature.

The behaviour of a reservoir fluid is analyzed using the properties; Pressure, Temperature and Volume (PVT).

There are two simple ways of showing this:Pressure against temperature keeping the volume constant.

Pressure against volume keeping the temperature constant.

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Notes

The easiest experiment is to keep the temperature constant, measuring volumes and pressures.The fluid used is a pure, single component hydrocarbon. (This is not found in a reservoir fluid which consists of a number of components.)Starting in the liquid and increasing the volume, the pressure drops rapidly with small changes in volume until the first bubble of gas occurs.This is the Bubble Point.Further increase in the volume causes no change in the pressure until a point is reached where all the liquid has vaporised.This is the Dew Point.Increasing the volume beyond this point causes the pressure to drop, but much slower than with the liquid phase.

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PVT Experiment

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Notes

This is a plot for the single hydrocarbon component used in the experiment. The Vapour pressure curve terminates in the Critical Point. This is a unique point for any substance, pure or a mixture. The plot describes how this fluid behaves with changing pressure and temperature. If it starts in the liquid and the pressure is reduced, keeping the temperature constant, it will cross the vapour pressure curve and become a gas. Starting as a liquid at constant pressure and increasing the temperature will also change it to a gas. An example of this would be boiling water in an open container at sea level.

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Phase Diagram -single component

The experiment is conducted at different temperatures.The final plot of Pressure against Temperature is made.The Vapour Pressure Curve represents the Bubble Point and Dew Point. (For a single component they coincide.)

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Notes

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Phase diagram Oil

The Pressure/Temperature (PT) phase diagram for an oil reservoir:Point 'A' is the initial reservoir condition of pressure and

temperature.If the reservoir is produced at a constant temperature

until the fluid reaches the wellbore, the line to Point 'B' is drawn. This represents the flow of fluid from the reservoir to the borehole. The fluid travelling to surface now drops in both temperature and pressure arriving at he "separatorconditions" (s) with a final volume of oil and gas.

Reservoirs do not have simple single-component hydrocarbons. Their Pressure/Temperature diagrams are more complex.The Bubble Point and Dew Point curves still meet at the critical point.There is now an envelope where two phases, oil and gas, exist in equilibrium. This is due to there being both heavy and light components in the fluid.This typical diagram is used to describe how the oil at reservoir conditions behaves when it is produced to surface.

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Notes

Gas condensates, as the name suggests, start as a gas and condense out some liquid. This type of gas reservoir is commercially very good as the liquid can easily be sold.This type of fluid is very dynamic and is difficult to produce efficiently. The surface production system is more complex than for an oil.

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Phase Diagram Condensate/Gas

Point 'C' is at the initial reservoir conditions. The reservoir is produced at a constant temperature from C to D. Fluids flowing up the well now drop in temperature and pressure, crossing the Dew point line and liquid condenses out.

At separator conditions (s) the result in both liquid and gas on the surface.

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Notes

This is the final diagram for the reservoir fluids. This is a dry gas which never enters the envelope under any normal producing conditions as there are no heavy components. There are some gases classed as ‘wet’ gas. This refers to some liquid being produced at surface, as with a condensate. However there is only an minimal amount.

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Gas Reservoir

In a gas reservoir the initial point is A. Producing the well to separator conditions B does not change the fluid produced.

The point B is still in the "gas region" and hence dry gas is produced.

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Notes

Downhole, pressures and temperatures are high, on surface they are much lower hence the fluids will change in volume.Some gas comes out of the oil, the amount depending on the gas-oil ratio.Water will only have dissolved gas in a gas well near the gas-water contact. In general water produces water.

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Hydrocarbon Volumes

Fluids at bottom hole conditions produce different fluids at surface:Oil becomes oil plus gas.Gas usually stays as gas unless it is a Condensate.Water stays as water with occasionally some dissolved gas.

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Notes

The volume change has to be quantified. Surface volumes are measured (production rates); these need to be converted to downhole conditions in order to compute how much has been produced at reservoir conditions and hence how much is left.Bw is around 1, as water is nearly incompressible. Bo is measured in a PVT laboratory experiment, it is just over 1, a typical value would be 1.2.Bg can be measured in the laboratory or using empirical charts. This figure depends very much on the pressure and is always very small of the order of 10-3.

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FVF Oil and Gas

There is a change in volume between downhole conditions and the surface.

The volume of the fluid at reference conditions is described by the Formation Volume Factor:

FVF =

Bo = formation volume factor for oil.Bw = formation volume factor for water.Bg = formation volume factor for gas.

Volume at downhole Conditions

Volume at reference Conditions

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Notes

The porosity has to be split between the fluids occupying the pore space. Saturation is the name given to the fraction of a given fluid. The total of the fluids present must be 1 (or 100%).The normal representation is as a percentage, in equations a fraction must be used.

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Saturation

Formation saturation is defined as the fraction of its pore volume (porosity) occupied by a given fluid.

Saturation =

DefinitionsSw = water saturation.So = oil saturation.Sg = gas saturation.Sh = hydrocarbon saturation = So + Sg

Saturations are expressed as percentages or fractions, e.g. Water saturation of 75% in a reservoir with porosity of 20% contains water equivalent to 15% of its volume.

Volume of a specific fluid pore volume

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Notes

The graphical representation shows the simple porosity model split now between water and hydrocarbon. The volume of a fluid is the porosity times the saturation.Hence the volume of water Vw = φ*Sw, that of oil Vo = φ*So , and that of gas, Vg = φ*Sg.

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Saturation Definition

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Notes

Wettability is caused by surface tension forces between the fluid molecules. Most reservoirs are water wet, mainly because the water was there first, the rocks being deposited in water. The hydrocarbon which migrated in at a later date displaces most of the water but rarely wets the rock as the surface tension forces in the water are stronger.The simple experiment in the figure shows a drop of water on a glass slide, a similar diagram could be drawn for the opposite case using, for example, mercury in place of water.

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Wettability

The wettability defines how a fluid adheres to the surface (or rock in the reservoir) when there are two fluids present, e.g. water and air.

The angle measured through the water is the "contact angle".

If it is less than 90° the rock is water wet; greater than 90° the rock is oil wet.

Most reservoir rocks are water wet.

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Notes

There is always water in the hydrocarbon zone. This water is “stuck” to the rocks by surface tension forces, it is “wetting” the rocks. The water will never be produced under normal production conditions, hence the term irreducible.The amount of irreducible water depends on the grain size and on the mixture of grains. A rock with a mixture of small grains and large grains can have water in the small grains and oil in the pore space associated with the large grains.

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Irreducible Water Saturation

In a formation the minimum saturation induced by displacement is where the wetting phase becomes discontinuous.In normal water-wet rocks, this is the irreducible water saturation, Swirr.Large grained rocks have a low irreducible water saturation compared to small-grained formations because the capillary pressure is smaller.

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Notes

The capillary pressure experiment is a simple one. It is often conducted using a number of glass tubes to determine the controlling factor which is the radius of the capillary tube. The smaller the tube the greater the height of the water and hence the capillary pressure.

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Capillary Forces

In a simple water and air system the wettability gives rise to a curved interface between the two fluids.

This experiment has a glass tube attached to a reservoir of water. The water "wets" the

glass. This causes the pressure on the concave side (water) to exceed that on the convex side (air). This excess pressure is the capillary pressure.

Pc = capillary pressure.σ = surface tension.q = contact angle. rcap = radius of capillary tube.

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Notes

In a reservoir the pore spaces act as capillary tubes pulling the water up into the oil column. There is a capillary transition zone at the oil-water contact. There would also be one at the gas-water contact in a gas reservoir. However there is no such phenomena at the gas-oil contact in normal circumstances as the oil does not wet the rock.

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Capillary Forces and Rocks

In a reservoir the two fluids are oil and water which are immiscible hence they exhibit capillary pressure phenomena.This is seen by the rise in the water above the point where the capillary pressure is zero.

The height depends on the density difference and the radius of the capillaries.

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Notes

The transition zone is a phenomenon seen in all reservoirs. The thickness of this zone varies from less that the resolution of the standard tool to very long, hundreds of feet. The size of the pores also controls the permeability, small pores mean low permeability. Hence a long transition zone suggests a low permeability formation.

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Transition Zone

The phenomenon of capillary pressure gives rise to the transition zone in a reservoir between the water zone and the oil zone.The rock can be thought of as a bundle of capillary tubes.The length of the zone depends on the pore size and the density difference between the two fluids.

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Notes

The four stages are 100% water, oil and water mixture, residual oil and irreducible water.The first stage represents a water zone only. The last represents an oil zone. The residual oil stage is a reservoir that has been completely produced.The other stage is an intermediate stage, either a production stage or somewhere in the transition zone.

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Relative Permeability

Take a core 100% water-saturated. (A)Force oil into the core until irreducible water saturation is attained (Swirr). (A-> C -> D)Reverse the process: force water into the core until the residual saturation is attained. (B)During the process, measure the relative permeabilities to water and oil.

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Notes

Initially, the core permeability will be the absolute permeability as there is only one fluid at 100% saturation.The relative permeability of water will drop to zero when Swirr is reached because no more water will move.The relative permeability to oil will rise but never reach the absolute permeability because there is still water in the pores.When water is forced in, the relative permeability of water will rise but not reach the absolute value for the same reason.

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Relative Permeability Experiment

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Notes

There are also the secondary drives, gravity drive, compaction and fluid expansion. In reality all reservoirs have both primary and secondary mechanisms.

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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

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Notes

Water has three 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.Finally the water is often of very large extent and hence the pressure in the reservoir remains high for a long time.

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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.

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Notes

There will always be some oil left in the rock, 100% recovery is impossible.This residual oil fraction, Sor, is important as it controls the amount of recoverable oil.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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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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.

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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.

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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