Notes

11

Reservoir Fluids

Reservoir Fluids

Schlumberger 1999

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 inequilibrium. These are the gas-oil-contact, the oil-water-contact and thegas-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 thereservoir.

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 inthe reservoir there are many other parameters which are needed to fullydescribe the fluids.

22

Reservoir Fluids

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

Notes

Other gases can be found in wells, these include, helium, carbon dioxideand hydrogen sulphide. In most cases these occur as traces together withthe hydrocarbon and water normally found.The formation water is uniquely described by its salinity. This varies from500 ppm Chlorides to 250000ppm; a wide range.The major rock property involved in production is the permeability.

33

Reservoir Fluids

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 onthe reservoir pressure and temperature.

The formation water may be fresh or salty.

The amount and type of fluid produced dependson the initial reservoir pressure, rock propertiesand the drive mechanism.

Notes

Hydrocarbons vary widely in their properties. The first classification is byfraction of each component. This ranges from a dry gas which is mostlyC1 (methane) to tar which is mostly the heavier fractions. The black oilnormally found is between the two extremes, with some C1 and someheavier fractions.

The hydrocarbon extracted from reservoirs varies in composition fromplace to place. Fluids originating from the same source rock will besimilar but never exactly the same.

44

Reservoir Fluids

Hydrocarbon Composition

Typical hydrocarbons have the followingcomposition 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 carbonatoms in the molecular chain.

Notes

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

55

Reservoir Fluids

Hydrocarbon Structure

The majorconstituent ofhydrocarbonsis paraffin.

Notes

Oil is more complex than gas and has to be defined in a more completemanner. The Gas-Oil Ratio, GOR (symbol Rs) is a measure of how muchgas is in the oil and thus how light it is. This is measured at a specificpressure and temperature , for example the reservoir conditions.The API gravity is a weight. The definition equation given simply setsnumbers for given oils. The heaviest have the lowest API gravity. Theprice of oil depends on its API gravity, with the standard or referencecrudes being the black oils between 30 and 40 API.

66

Reservoir Fluids

Hydrocarbon ClassificationHydrocarbons are also defined by their weightand the Gas/Oil ratio. The table gives sometypical 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

Notes

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

77

Reservoir Fluids

Hydrocarbon Gas

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

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

Gases are classified by their specific gravitywhich is defined as:

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

Notes

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

88

Reservoir Fluids

Reservoir Pressure

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

Notes

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

99

Reservoir Fluids

Reservoir Pressure Calculation

Notes

1010

Reservoir Fluids

Reservoir Pressure Example

Notes

Temperature in wells depends on a regional gradient. There can be localhot spots where this is sharply increased. The temperature is measuredduring each logging run.Temperatures gradients are greatest near the edges of the plates andlowest near the centres of the old continental plates as these are thethickest points of the crust.

1111

Reservoir Fluids

Reservoir Temperature Gradient

The chart shows three possible temperaturegradients. The temperature can be determined ifthe depth is known.

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

Notes

The phase behaviour of the reservoir fluids are important as the fluid inthe reservoir will change as it is produced.The pressure and temperature are two quantities that can be easilymeasured. Thus it is useful to describe the fluids behaviour duringproduction in these terms. Experimentally it is easier to measure pressureand volume hence the classical experiment is done using these parametersat a constant temperature.

1212

Reservoir Fluids

Fluid Phases

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

In a reservoir oil and gas exist together atequilibrium, depending on the pressure andtemperature.

The behaviour of a reservoir fluid is analyzedusing the properties; Pressure, Temperature andVolume (PVT).

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

Pressure against volume keeping the temperature constant.

Notes

The easiest experiment is to keep the temperature constant, measuringvolumes and pressures.The fluid used is a pure, single component hydrocarbon. (This is notfound in a reservoir fluid which consists of a number of components.)Starting in the liquid and increasing the volume, the pressure dropsrapidly 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 apoint is reached where all the liquid has vaporised.This is the Dew Point.Increasing the volume beyond this point causes the pressure to drop, butmuch slower than with the liquid phase.

1313

Reservoir Fluids

PVT Experiment

Notes

This is a plot for the single hydrocarbon component used in theexperiment. 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 andtemperature.If it starts in the liquid and the pressure is reduced, keeping thetemperature constant, it will cross the vapour pressure curve and become agas. Starting as a liquid at constant pressure and increasing thetemperature will also change it to a gas. An example of this would beboiling water in an open container at sea level.

1414

Reservoir Fluids

Phase Diagram -singlecomponent

The experiment is conducted at differenttemperatures.The final plot of Pressure against Temperature ismade.The Vapour Pressure Curve represents theBubble Point and Dew Point.(For a single component they coincide.)

Notes

1515

Reservoir Fluids

Phase diagram Oil

The Pressure/Temperature (PT) phase diagram for an oilreservoir: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 theborehole. The fluid travelling to surface now drops in bothtemperature and pressure arriving at he "separator conditions"(s) with a final volume of oil and gas.

Reservoirs do not have simple single-component hydrocarbons. TheirPressure/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 inequilibrium. This is due to there being both heavy and light componentsin the fluid.This typical diagram is used to describe how the oil at reservoir conditionsbehaves when it is produced to surface.

Notes

Gas condensates, as the name suggests, start as a gas and condense outsome liquid. This type of gas reservoir is commercially very good as theliquid 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.

1616

Reservoir Fluids

Phase Diagram Condensate/Gas

Point 'C' is at the initial reservoir conditions. Thereservoir is produced at a constant temperaturefrom C to D. Fluids flowing up the well now dropin temperature and pressure, crossing the Dewpoint line and liquid condenses out.

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

Notes

This is the final diagram for the reservoir fluids. This is a dry gas whichnever enters the envelope under any normal producing conditions as thereare no heavy components.There are some gases classed as wet gas. This refers to some liquidbeing produced at surface, as with a condensate. However there is only anminimal amount.

1717

Reservoir Fluids

Gas Reservoir

In a gas reservoir the initial point is A. Producingthe well to separator conditions B does notchange the fluid produced.

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

Notes

Downhole, pressures and temperatures are high, on surface they are muchlower 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-watercontact. In general water produces water.

1818

Reservoir Fluids

Hydrocarbon Volumes

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

Notes

The volume change has to be quantified. Surface volumes are measured(production rates); these need to be converted to downhole conditions inorder to compute how much has been produced at reservoir conditions andhence how much is left.Bw is around 1, as water is nearly incompressible. Bo is measured in aPVT 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. Thisfigure depends very much on the pressure and is always very small of theorder of 10-3.

1919

Reservoir Fluids

FVF Oil and Gas

There is a change in volume between downhole conditions and the surface.The volume of the fluid at reference conditions isdescribed 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

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 ofthe fluids present must be 1 (or 100%).The normal representation is as a percentage, in equations a fraction mustbe used.

2020

Reservoir Fluids

Saturation

Formation saturation is defined as the fraction ofits pore volume (porosity) occupied by a givenfluid.

Saturation =

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

Saturations are expressed as percentages orfractions, e.g.Water saturation of 75% in a reservoir withporosity of 20% contains water equivalent to15% of its volume.

Volume of a specific fluid pore volume

Notes

The graphical representation shows the simple porosity model split nowbetween water and hydrocarbon.The volume of a fluid is the porosity times the saturation.

Hence the volume of water Vw = f*Sw, that of oil Vo = f*So , and thatof gas, Vg = f*Sg.

2121

Reservoir Fluids

Saturation Definition

Notes

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

2222

Reservoir Fluids

Wettability

The wettability defines how a fluid adheres to thesurface (or rock in the reservoir) when there aretwo 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; greaterthan 90 the rock is oil wet.

Most reservoir rocks are water wet.

Notes

There is always water in the hydrocarbon zone. This water is stuck tothe rocks by surface tension forces, it is wetting the rocks. The waterwill never be produced under normal production conditions, hence theterm irreducible.The amount of irreducible water depends on the grain size and on themixture of grains. A rock with a mixture of small grains and large grainscan have water in the small grains and oil in the pore space associatedwith the large grains.

2323

Reservoir Fluids

Irreducible Water Saturation

In a formation the minimum saturation inducedby displacement is where the wetting phasebecomes discontinuous.In normal water-wet rocks, this is the irreduciblewater saturation, Swirr.Large grained rocks have a low irreducible watersaturation compared to small-grained formationsbecause the capillary pressure is smaller.

Notes

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

2424

Reservoir Fluids

Capillary Forces

In a simple water and air system the wettabilitygives rise to a curved interface between the twofluids.

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.s = surface tension.q = contact angle.rcap = radius of capillary tube.

Notes

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

2525

Reservoir Fluids

Capillary Forces and Rocks

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

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

Notes

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

2626

Reservoir Fluids

Transition Zone

The phenomenon of capillary pressure gives riseto the transition zone in a reservoir between thewater zone and the oil zone.The rock can be thought of as a bundle ofcapillary tubes.The length of the zone depends on the pore sizeand the density difference between the two fluids.

Notes

The four stages are 100% water, oil and water mixture, residual oil andirreducible water.The first stage represents a water zone only. The last represents an oilzone. The residual oil stage is a reservoir that has been completelyproduced.The other stage is an intermediate stage, either a production stage orsomewhere in the transition zone.

2727

Reservoir Fluids

Relative Permeability

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

Notes

Initially, the core permeability will be the absolute permeability as thereis only one fluid at 100% saturation.The relative permeability of water will drop to zero when Swirr is reachedbecause no more water will move.The relative permeability to oil will rise but never reach the absolutepermeability because there is still water in the pores.When water is forced in, the relative permeability of water will rise butnot reach the absolute value for the same reason.

2828

Reservoir Fluids

Relative PermeabilityExperiment

Notes

There are also the secondary drives, gravity drive, compaction and fluidexpansion. In reality all reservoirs have both primary and secondarymechanisms.

2929

Reservoir Fluids

Drive Mechanisms

A virgin reservoir has a pressure controlled bythe local gradient.Hydrocarbons will flow if the reservoir pressureis 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 theReservoir Drive Mechanism.Drive Mechanism depends on the rate at whichfluid 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 three advantages , firstly there is water in the hydrocarbon zonein the form of irreducible water with which it can join and hence cleanaround the grains. Secondly capillary pressure helps the water up thesmall pore channels.Finally the water is often of very large extent and hence the pressure inthe reservoir remains high for a long time.

3030

Reservoir Fluids

Water Invasion 1

Water invading an oil zone,moves close to the grainsurface, pushing the oil outof its way in a piston-like fashion.

The capillary pressuregradient forces water tomove ahead faster in thesmaller pore channels.

Notes

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

3131

Reservoir Fluids

Water Invasion 2

The remainingthread of oilbecomes smaller.

It finally breaksinto smaller pieces.

As a result, somedrops of oil are leftbehind in thechannel.

Notes

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

3232

Reservoir Fluids

Water Drive

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

Notes

The production of water will invariably increase. The amount of waterfinally produced depends on capabilities of the surface productionfacilities 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 thegas-oil ratio.

3333

Reservoir Fluids

Water Drive 2

This type of drive usually keeps the reservoir pressure fairly constant.After the initial dry oil production, water maybe produced. The amount of produced waterincreases as the volume of oil in the reservoirdecreases.Dissolved gas in the oil is released to formproduced gas.

Notes

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

3434

Reservoir Fluids

Gas Invasion

Gas is more mobile than oil and takes the path ofleast resistance along the centre of the largerchannels.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 expansionforces the oil out.The gas cap needs to be large for this type of drive to succeed.

3535

Reservoir Fluids

Gas Cap Drive

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

Notes

As the gas cap expands the pressure drops hence the drive efficiency goesdown. In addition there is always breakthrough of the free gas andproduction at an apparent high GOR.The reservoir pressure will go down quickly.

3636

Reservoir Fluids

Gas Cap Drive 2

As oil production declines, gas productionincreases.

Rapid pressure drop at the start of production.

Notes

This type of drive uses the energy of expansion of the gas dissolved in theoil as there is no appreciable water or gas cap drive. This is veryinefficient as there on a little possible expansion. In addition the reservoirrapidly drops below bubble point in the reservoir itself. This means thatgas comes out of solution in the reservoir. This will create problems forproduction and eventually the reservoir will die.

3737

Reservoir Fluids

Solution Gas Drive

After some time the oil in the reservoir is belowthe 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.

3838

Reservoir Fluids

Solution Gas Drive 2

An initial high oil production is followed by arapid decline.The Gas/Oil ratio has a peak corresponding tothe higher permeability to gas.The reservoir pressure exhibits a fast decline.

Notes

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

3939

Reservoir Fluids

Drives General

A water drive can recover up to 60% of the oil inplace.A gas cap drive can recover only 40% with agreater reduction in pressure.A solution gas drive has a low recovery.

Notes

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

4040

Reservoir Fluids

Drive Problems

Water Drive:Water can cone upwardsand be produced throughthe lower perforations.

Gas Cap Drive:Gas can cone downwardsand be produced throughthe upper perforations.Pressure is rapidly lost asthe gas expands.

Gas Solution Drive:Gas production can occurin the reservoir, skindamage.Very short-lived.

Notes

Most modern reservoirs have some sort of secondary recovery built intotheir management from their initial production. The aim of all theseschemes is to maintain the pressure in the reservoir as high as possible foras long as possible.The main problem with heavy oil is its high viscosity. Reduction of theviscosity is achieved by heating the fluid, hence the steam injection andthe in-situ combustion or by adding CO2. This substance reduces theviscosity of the oil by two orders of magnitude, for example from 500centipoise to 5.Polymer injection adds polymers to the injection water to increase theviscosity of this fluid. Ordinary water has a much lower viscosity andhence does not sweep the heavy oil efficiently.

4141

Reservoir Fluids

Secondary Recovery 1

Secondary recovery covers a range of techniquesused to augment the natural drive of a reservoiror boost production at a later stage in the life of areservoir.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 containingheavy oil, more advanced recovery methods areused:

Steam flood.Polymer injection. .CO2 injection.In-situ combustion.

Notes

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

4242

Reservoir Fluids

Secondary Recovery 2waterinjection

gas injection