Fundamentals of Basic Reservoir Engineering 2010

RESERVOIR ENGINEERING

The purpose of Reservoir engineering is economic optimization of the development and production of hydrocarbon reservoirs. This requires most representative solutions to the following aspects:

• Quantity of hydrocarbon in place

• Recoverable hydrocarbons reserves

• Rate of exploitation

The determination of these three quantities is the crux of reservoir engineering. RESERVOIR

A reservoir is a porous and permeable subsurface formation containing hydrocarbon accumulation. For a reservoir to be commercially exploitable, three basic requirements must be fulfilled:

• Sufficient void space generally called porosity to store oil and gas.

• Adequate connectivity, i.e. permeability to allow hydrocarbon fluids movement over large distances under pressure gradients.

• Accumulation in a trap of impervious cap rock, which should prevent upward migration of the oil and gas.

Accumulation of oil and gas in a reservoir

RESERVOIR ROCKS

These rocks are generally sedimentary rocks. Sedimentary rocks are rocks made up of sediments formed at the earth’s surface by debris or chemical precipitations. Sedimentary rocks are classified into two groups: clastic (the rocks of detrital origin) and non-clastic (sediments of biochemical or chemical precipitate origin.)

Clastics rocks

Rock type Particle diameter

Conglomerate Pebbles: 2 to 64 mm Sandstone Sand: 0.06 to 2 mm Siltstone Silt: 0.003 – 0.06 mm Shale Clay: < 0.003 mm Non-clastic

Rock type Composition

Limestone Calcite –CaCo3

Dolomite Dolomite Ca Mg( Co3) Sandstone Reservoirs

These reservoir rocks consist of quartz (Silica SiO2). These quartz grains cemented together form sandstone. Sandstones are very often stratified in a superimposed pattern. This results from successive deposition at the shore-line or in the form of fluvial or deltaic alluvia. A vertical cross section generally exhibits alternation deposits of sands, shaly sands, silts and shales.

Sandstone reservoirs are the widest spread hydrocarbon pools. Carbonate Reservoirs

The carbonate rocks limestone, dolomite, and chalk comprise about 20% of sedimentary rocks. Limestone composed mainly of the mineral calcite is concentrated by accumulation of the shells and skeletons of marine animals or by direct precipitation from mineral saturated waters. Dolomite is the double carbonate of calcium and magnesium. When dolomitization (replacement of calcium by magnesium) occurs, shrinkage of matrix is observed. Matrix porosities and permeabilities of carbonate rocks are typically low. But formation of vugs, channels, and other cavities add to storage capacity.

The most prolific hydrocarbon bearing carbonates are highly fractured. TRAPS

The trap is the place where oil and gas are barred from further movement. The traps can be classified as

• Structural traps: These traps are formed by uplifting and folding of the strata. When viewed from above, the dome is circular in shape, whereas the anticline is in an elongated fold.

• Stratigraphic traps: In these traps, trapping is due to variation in facies, The rock becomes impermeable laterally. Sandstone lenses, pinch outs and carbonate reefs are some of examples.

• Combination traps: A combination trap has a two or three elements

- a stratigraphic element causing the edge of permeability of the reservoir rock. - a structural element causing the deformation that combines with the

stratigraphic element to complete rock portion of the trap

- a down dip flow of formation water increasing the trapping effect. Examples: eroded anticlines, traps associated with salt dome,

Structural trap: oil and gas accumulation in a dome structure (After “Reservoir and Production Fundamentals”, Schlumberger, 1982)

Structural trap: oil and gas accumulation in an anticline

(After “Reservoir and Production Fundamentals”, Schlumberger, 1982)

Oil accumulation in a stratigraphic trap formed by a change in permeability (After “Reservoir and Production Fundamentals”, Schlumberger, 1982)

Combination trap

RESERVOIR PRESSURE

Reservoir pressure is a dominant variable condition that affects every petroleum reservoir. It is in the form of stored and available energy. It is one of the most important parameters of reservoir engineering calculations.

The fluids confined in the pores of the reservoir rock occur under certain degree of pressure, generally called reservoir pressure, fluid pressure or formation pressure. Since all the fluids are in contact with one another, they transmit pressures freely, and pressures measured on fluid are actually the pressures on all fluids. Reservoir pressure unless otherwise stated is generally thought of as the original or virgin pressure – the pressure that existed before the natural pressure equilibrium of the formation has been disturbed by any production. The original pressure can be measured directly only by the first producing the well drilled into the reservoir, for the pressure begins to decline as soon as oil and gas are withdrawn. When a producing well is shut in, the reservoir pressure begins to rise. This rise is rapid at first, and then gradually slows until finally the maximum pressure is reached. The maximum pressure is called the static bottom hole pressure, the shut in pressure or static formation pressure. The normal pressure distribution from surface through a reservoir structure is shown below:

ABNORMAL PRESSURES

Under certain depositional conditions, or because of earth movements, close to reservoir structure, fluid pressures may depart substantially from the normal range. Abnormal

pressures can occur, when some part of the overburden load is transmitted to the formation fluids. Abnormal pressures corresponding to gradients of 0.8 psi/ft to 0.9 psi/ft and approaching geostatic gradient (1.0 psi/ft) can be considered dangerously high. RESERVOIR TEMPERATURE The computation of primary recovery of hydrocarbon reservoirs is based on the assumption that the reservoir temperature remains constant. Thus, hydrocarbon recovery during primary phase is an isothermal process.

The average reservoir temperature is needed for laboratory analyses carried at reservoir conditions. Determining reservoir fluid properties such as viscosity, density, formation volume factor, and gas in solution, and reservoir rock-fluid interaction properties like capillary, relative permeability and resistivity measurements require a value for reservoir temperature. For EOR techniques such as chemical and miscible processes, temperature affects the phase behavior of injected and produced fluids, and thus the recovery. The feasibility of these processes must be determined by laboratory tests carried out at reservoir temperature. In EOR processes that employ heat injection, such as steam or in-situ combustion, the reservoir temperature is not constant and hydrocarbon recovery is not an isothermal process.

Reservoir temperature is usually measured at the bottom of the well or wells in a reservoir using a wireline temperature gauge. If a variation in temperature is detected across a reservoir after correcting for depth, an average value can be used for the constant reservoir temperature.

TEXTURE

The rock texture is related to those properties of rocks that concerns with grain to grain relations. Some of these properties are chemical composition, grain shape, grain roundness, grain size, sorting and grain orientation. The rock texture influence porosity, permeability, and the interstitial water saturation. Texture is studied by thin section analysis and visual inspection of hand specimens.

GOOD SORTING POOR SORTING

(After “Fundamentals of Core analysis”, Core Lab, USA, 1989)

Porosity of a rock is the ratio of the pore volume to the bulk volume. In hydrocarbon reservoirs, the pore volume is the space available for oil, gas and water storage. Porosity is generally expressed as a percentage of bulk volume.

x

100

Vb

Vp

=

x

100

Vb

Vg

Vb

−

=

φ

Where Vp = pore volume Vg = grain volume Vb = bulk volume

Total or Absolute Porosity: It is the ratio of the volume of all the pores to the bulk volume of the material, regardless of whether or not, all the pores are interconnected. Effective porosity: It is the ratio of the interconnected pore volume to the bulk volume of the rock. The value of this parameter is used in all reservoir engineering calculations.

(After

“Fundamentals of Core analysis”, Core Lab, USA, 1989)

Porosity types

Basic porosity falls into two classes; one that relates to fabric or texture of the rock and other independent of it. Porosity in sands and sandstone varies primarily with grain size distribution and grain shapes and packing. Porosity in carbonate rock is much more variable in magnitude and depends largely on the post depositional processes of dolomitization, dissolution or cementation.

The porosity types identified in sandstones and carbonate are as follows:

• Fabric related pores are present at time of sediment accumulation and formed later by fabric controlled.

Sandstones: Intergranular, Intragranular. Microporosity Carbonates: Interparticle, Intraparticle. Intercrystalline

• Independent of rock fabric

Fracture porosity both in sandstones and carbonates These types are common in most of the reservoirs.

Sandstone Reservoirs: There are four basic types of porosity:

• Intergranular porosity: The interstitial pore spaces between the sand grains are the intergranular porosity which all sandstones possess initially. It ranges from 5% to 40%.

• Intragranular porosity: It is a product of dissolution of soluble material, principally carbonate particles, unstable rock fragments, feldspar and sulphate within the formation.

• Microporosity: Microporosity exists as small pores which are commonly associated with clay minerals

• Fracture porosity: It is generally artificially created in sandstones to improve the deliverability of any reservoir.

The factors which control sandstone porosity are:

• Mineralogical composition

• Burial history

• Grain size and sorting

• Paleotemperature

• Pressure history

• Pore water composition

• Carbonate cementation

• Secondary porosity Carbonate Reservoirs:

• Interparticle: Carbonate with a grain supported framework has a large (30%-40%) initial porosity.

• Intraparticle: These pores are the body cavities which may become sites of internal sedimentation and crystal filling.

• Moulding: The cavities are formed by solution of shells or destruction of other original components of the rock, creating moldic porosity.

• Intercrystalline: Coarse dolomites may show intercrystalline porosity caused by solution of non-replaced calcite.

• Fracture porosity Determination of porosity

The porosity is determined by core analysis or by well logging. Core analysis

In porosity any two of Vp, Vb, Vg are determined. In core analysis, the cylindrical plugs of either 1.0 inch or 1.5 inch diameter are cut from whole core and then first cleaned and dried.

Measurement of bulk volume

• Caliper method. The length and diameter of core plug is measured at different points of the core and averaged values are determined.

Vb = 4

2_l

d

π

• Measurement of the buoyancy exerted by mercury on the samples immersed in it.

The mercury based methods are not used for rocks containing fissures or macropores because of possibility of mercury penetration.

Measurement of pore volume

The pore volume can be measured:

• Helium expansion in the interconnected pores

• Measurement by weighing in a fluid filling the effective pores

• Measurement by mercury injection

The grain volume can also be determined by Helium expansion method.

Effect of pressure on porosity

Porosity decreases with increasing net overburden pressure. Reservoir rocks experience the lithostatic pressure and fluids pressure in the pores. The production of hydrocarbons

causes a decline in the fluid pressure in the pores resulting in compression of the rock, until a new equilibrium is attained.

Averaging of porosity

Arithmetic averaging of thickness average porosity: This method is used in cases when the reservoir rock shows large variation on porosity vertically but does not show great variations in porosity parallel to the bedding planes.

Arithmetic Average porosity Ø = n

j

φ

J j j h h

φ

Areal weighted or volumetric weighted average porosity: These averages are used in cases where the porosity in one portion of the reservoir is greatly different from that in another area because of sedimentation or depositional changes.

Areal weighted average porosity Ø =

j j j

A

A

φ

Volumetric weighted average porosity Ø =

j j j j j h A h A

φ

hj = thickness of core sample j or reservoir area j Øj = porosity of core sample j or reservoir area j Aj = reservoir area j

GRAIN DENSITY

The grain density of a rock is defined as the weight of the rock (exclusive of the weight of fluids contained in the pore space) divided by the volume of the solid rock material (exclusive of pore space). The density varies with the mineral composition of the rock and the state of hydration of the minerals. In complex lithologies containing inter-mixed limestone, dolomite, sandstones, and heavy minerals, grain density will vary vertically and horizontally. Even in formations described as homogeneous, measured densities often vary considerably from published values for pure components as tabulated below.

Minor amounts of secondary cement, such as calcite or siderite, will cause grain densities to exceed values shown in the table.

Component Approximate grain density (g/cm3)

Sandstone 2.65 Limestone 2.71 Dolomite 2.85-2.87 Anhydrite 2.98 Gypsum 2.3 Pyrite 5.0 Siderite 3.9 Clays 2.2-2.9

Grain density is important in core analysis on the account that it can be used as a quality control check of the core analysis measurements themselves.

PERMEABILITY

Permeability is a measure of the capacity of formation to transmit fluids. Its unit is Darcy, named after a French scientist Henry Darcy in 1856. One Darcy equals permeability that will permit a fluid of one centipoise viscosity to flow at a rate of one cubic centimeter per second through a cross-sectional area of one square centimeter when the pressure gradient is one atmosphere per centimeter. Generally permeabilities are given in millidarcies which is equal to (1/1000) of a Darcy. Its dimension is L2_.

K A ∆P ∆∆∆∆P = Press. Differential, atm

q = --- A = Cross Sectional Area, cm2 µ * L K = Permeability, darcy

q = Outlet Flow Rate, cc/sec µ = Fluid Viscosity, cp L = System Length, cm ∆∆∆∆ P q A L

Darcy law is used to determine permeability when the following conditions exist:

• Laminar flow

• No reaction between fluid and rock

• One phase present at 100 percent pore space saturation.

The measured permeability at 100% saturation of a single phase is called the absolute permeability of the rock.

The following terms are generally used to specify the permeability: <1mD = Very low 1to 10 mD = Low 10 to 50 mD = Medium 50 to 200 mD =Good 200 to 500 mD = Very Good >500 mD = Excellent

The factors which control magnitude of permeability are:

• Shape and size of sand grains

• Lamination

• Cementation

• Fracturing and solution Permeability Anisotropy

Permeability is a directional quantity. The long axis of the grains aligns parallel in the direction of maximum velocity during the process of sediments deposition, thus providing the maximum cross-sectional area of the grains in a horizontal plane. This results in highest permeability parallel to long axis of the grains.

In most of reservoir rocks, permeability like porosity is reduced by increase in net overburden pressure.

Measurement of Permeability The permeability is measured by flowing a fluid of known viscosity µ through a core plug of measured dimensions (A and L) and then measuring flow rate q and pressure drop p. Darcy equation becomes

p A L q k ∆ =

µ

Absolute permeability is usually determined by flowing air through the core plug because of its convenience and to minimize rock-fluid interaction.

In using dry gas in measuring the permeability, the gas volumetric rate q varies with the pressure because the gas is a highly compressible fluid. Hence, the equation becomes

b g sc _Lp p p kA Q

µ

Where k = absolute permeability, Darcies µg = gas viscosity, cp

pb = base pressure ( atmospheric pressure), atm p1 = inlet pressure (upstream), atm.

p2 = outlet (down stream), atm. L = length of the core plug, cm A = cross-sectional area, cm2

Qsc = gas flow rate at standard conditions, cm3_/sec. Klinkenberg effect

Klikenberg (1941) compared the permeability results of measurements made with air as the flowing fluid as well as with a liquid as the flowing fluid. He observed that the air permeability is always greater than the liquid permeability. Klinkenberg postulated that liquids had a zero velocity at the sand grain surface while gases exhibited some finite velocity at the sand grain surface. And this slippage at the sand grain surface has resulted in higher flow rate for the gas at a given pressure differential. Further, he also found that as the mean pressure increased, the calculated permeability of the porous medium decreased. The magnitude of Klinkenberg effect varies with the core permeability and the type of gas used in the experiment. The resulting straight relationship can be expressed as:

Ka = KL + b[1/pm]

Where Ka = measured gas permeability pm = mean pressure

KL = equivalent liquid permeability b = slope of line

Further b = c KL where c is a constant which depends on the size of the pore openings and is inversely proportional to the radius of capillaries.

Klinkenberg effect

A comparison of absolute permeability and Klinkenberg permeability is given below: Gas Permeability, mD

(Ka) Klinkenberg Permeability, mD (KL) Ratio of KL/ Ka

0.18 0.12 0.66

1.00 0.68 0.68

10.0 7.80 0.78

100.0 88.0 0.88

1000.0 950.0 0.95

Averaging of absolute permeabilities

An adequate understanding of permeability distribution is critical to the reservoir performance prediction. Homogeneous reservoirs seldom exist. Because of existence of small scale heterogeneities, laboratory measured core plug permeabilities needs proper averaging for flow characteristics representation of the entire reservoir or its individual reservoir units.

There are three commonly used techniques:

• Weighted average permeability

• Harmonic average permeability

• Geometric average permeability

Weighted Average Permeability: Used to determine the average permeability of layered – parallel beds with different permeabilities.

G as P er m ea bi lit y Liquid permeability

= =

=

h

h

k

k

Where hj = thickness of layer j

Kj = absolute permeability of layer j

Harmonic Average Permeability: Used to average permeabities where permeability variations can occur laterally in a reservoir.

= = = _n j j n j j av k L L k 1 1

Where Lj = length of each bed

kj = absolute permeability of each bed

Geometric Average Permeability: Most representative averaging technique for a heterogeneous formation: = = = n j j n j j j avg h k h k 1 1 )) ln( ( exp

Where kj = permeability of core sample j hi = thickness of core sample j n = total number of samples

If the thickness of all the core samples is same, then the above equation becomes:

(

)

avg k k k k k = _{1 2 3}... 1

SATURATION

Fluid saturation is defined as the fraction of pore volume occupied by a particular fluid. Hence for reservoir fluids, mathematical expressions can be:

Oil saturation,

Volume

Pore

oil

of

Volume

S

..

..

..

=

Volume

Pore

gas

of

Volume

S

..

..

..

=

Water Saturation,

Volume

Pore

water

of

Volume

S

..

..

..

=

Fluid saturation in the laboratory is one of the least reliable reservoir property measurements. Factors that are likely to introduce errors into these measurements include invasion of the core by mud or mud filtrate during coring process, gas expansion during core recovery, and handling of the core during preservation and measurement. Some of the methods generally used for laboratory determination of fluid saturations are: Soxhlet distillation extraction/Dean-Stark method: In this method, oil is removed from the sample by extraction i.e. dissolved in suitable solvent; most commonly used toluene and xylene. A mixture of 80%acetone+20% methanol is frequently employed. Water is removed from the sample by distillation, then condensed to liquid which is caught in a trap and measured.

Retort method. It is atmospheric distillation in which rock sample is heated in stages to 1200o_{F. All the reservoir fluids are vaporized. The most commonly used system employs} electric heating and counter-current cooling with water.

Averaging of saturation data

The representative averaging of saturation data requires that the saturation values be weighted by both the interval thickness hj and interval porosity øj

= =

=

h

So

h

So

φ

φ

=

h

Sw

h

Sw

φ

φ

= =

=

h

Sg

h

Sg

φ

φ

Where the subscript j refers any individual measurement and hj represents the depth interval to which Øj, Soj, Sgj, Swj apply.

WETTABILITY

Wettability is defined as the tendency of one fluid to adhere or spread on a solid surface in presence of other immiscible fluids. The varying wetting characteristics of liquids for the solid can be observed by placing small drop of three liquids namely mercury, oil and water on clean glass plate.

The spreading tendency is expressed by measuring the angle of contact at the liquid-solid interface. This angle is called the contact angle . Wettablity can be determined in the laboratory by measuring the contact angle between a droplet of fluid and a flat surface of mineral crystal. Wettability has profound influence on distribution of fluids in the porous media and affects the ultimate recovery. Because of the attractive forces, the wetting phase tends to occupy the smaller pores of the rock and non-wetting phase occupies the more open channels.

In reservoirs, generally water is considered to be wetting fluid. However, the oil may be wetting especially for limestones.

The laboratory studies have indicated that preferentially wettability of the rock is largely controlled by the compounds adsorbed at the surface of the rock.

CAPILLARY PRESSURE

Surface and interfacial tension result from molecular forces that cause the surface of a liquid to assume the smallest possible size and to act like a membrane under tension.

Capillarity is the rise or depression of liquids in a fine tube resulting from surface tension and wetting preferences. Consider a capillary tube of radius ‘r’ placed in large open vessel containing water. The water will rise in tube, until the total force acting to pull liquid upward is balanced by the weight of the column of liquid being supported in the tube.

Fup = 2 r. gw. cos

Fdown = r2_{.h. (ρw - ρair).g}

Since density of air is negligible in comparison to density of water Fdown = r2_.h.ρw.g

At equilibrium Fup = Fdown 2 r. gw. cos = r2_.h.ρw.g gw =

θ

ρ

In porous medium, even when two or more fluids are present at the same subsea elevation and are in state of pressure equilibrium, they are not at the same pressure. This is primarily because of differences in the mutual attraction between rock and fluids (adhesion tension). This difference in pressure between two phases in equilibrium at the same subsea elevation is the capillary pressure between two phases. The fluid with the greatest tendency to wet the rock will have the lowest pressure.

Pc = pnw - pw

The pressure excess in the non-wetting fluid is the capillary pressure, and this quantity is a function of saturation.

Gas - Liquid system Pc = r gw

θ

σ

)

(

cos

2

rg

ρ

ρ

θ

σ

−

Oil - Water System Pc = r ow

θ

σ

ρ

ρ

θ

σ

ρ0 = oil density, gm/cm3

gw = gas-water surface tension, dynes/cm ow = oil-water surface tension, dynes/cm r = capillary radius, cm

= contact angle h = capillary rise, cm

g =- acceleration due to gravity, cm/sec2 Pc = capillary pressure, dynes/cm2

Laboratory determination of capillary pressure data

Three methods are generally used for determination of capillary data on rock samples:

• Purcell’s method/Mercury injection method: The core plug cleaned and dried with pore volume determined is first subjected to vacuum after pore volume determination. The mercury is injected into it in increasing pressure stages. At each stage, the volume of mercury intruded is recorded. The capillary pressure is the absolute pressure of mercury.

• Restored state method: The core plug saturated with brine in placed on a porous plate saturated with brine. Air is injected at increasing pressure stages. A

capillary tube is used to measure the volume of water expelled from the core. The capillary pressure is the relative pressure of the air.

• Centrifuge method: In the centrifuge method, an artificial gravity using the density difference between the two fluids creates a capillary pressure gradient all along the plug and thus a saturation variation from the top to the bottom.

Converting laboratory capillary pressure data to reservoir conditions

Since the laboratory measurements are not conducted using reservoir fluids, the lab results must be corrected to reservoir condition using the relationship:

PcRes = PcLab( Res/ Lab) Where

PcRes = capillary pressure at reservoir conditions, psi PcLab = capillary pressure at laboratory conditions, psi Res = interfacial tension at reservoir conditions, dynes/cm

Lab = interfacial tension at laboratory conditions, dynes/cm Averaging of capillary pressure data

Leverett (1942) proposed a means of converting all capillary – pressure data to a universal curve using the dimensionless function of saturation known as J-function,

φ

σ

k

Pc

J

=

0

.

21645

Where J(sw) = Leverett J-function Pc = capillary pressyre, psi = interfacial tension dynes/cm k = permeability, mD

Ø= porosity, fraction

Each capillary pressure curve gives a J-function curve. The average J-curve is generated. Using this curve, a Pc-Sw can be plotted for a given sample if its k and Ø are known.

.

The Leverett J-Function for unconsolidated sands (After Leverett,1941)

Initial saturation distribution in a reservoir

An important application of capillary pressure data relates to the fluid distribution in a virgin reservoir. The capillary pressure - saturation data can be converted into height – saturation relation ship as given below:

h =

ρ

Pc 144

where Pc = capillary pressure,psia

ρ = density difference between wetting phase and non-wetting phase at reservoir conditions, lb/ft3

Distribution of saturation in the reservoir

(After “Reservoir and Production Fundamentals”, Schlumberger, 1982)

The transition is the vertical thickness over which the water saturation changes 100% saturation to irreducible water saturation, Swi.

The water oil contact is the uppermost depth in the reservoir where a 100% water saturation exists. At free water level, there is zero capillary pressure from reservoir engineering standpoint.

Irreducible water saturation

Irreducible water saturation is the minimum saturation that can be induced by displacement. At this stage, the wetting phase becomes discontinuous. This minimum saturation corresponds to smallest mean radius of curvature and maximum capillary pressure.

Grain size has remarkable influence on irreducuible water saturation: C ap ill ar y P re ss ur e H ei gh t A bo ve O il-W at er C on ta ct

Effect of grain size on Irreducible water saturation

(After “Reservoir and Production Fundamentals”, Schlumberger, 1982)

RELATIVE PERMEABILITY

Production of hydrocarbons involves simultaneous flow of two or three fluids in the reservoir rock. In this multiphase flow, each fluid tends to interfere with the flow of the others.

Absolute permeability relates to permeability with one fluid present at 100 percent saturation. It is also called as specific permeability or base permeability.

Effective permeability is the permeability to a given phase when more than one phase saturates the porous medium. The effective permeability is a function of saturation.

Relative permeability to a given phase is defined as the ratio of effective permeability to the absolute or, in some cases, a base permeability. Relative

permeability is also a function of saturation.

Relative permeability = ty permeabili Base ty permeabili Effective ⋅ .

kro = k k_o krg = k k_g krw = k k_w

It is a dimensionless term and generally reported in fraction or percentage.

For an oil-water reservoir, the base permeability, k is taken as effective permeability to oil at irreducible water saturation. For a gas reservoir, the base permeability will be effective permeability to gas in the presence of irreducible water.

Imbibition versus Drainage

In relative permeability studies, the terms imbibition and drainage are commonly referred.

If the wetting phase is decreasing, that phase is draining and the curve is called a drainage curve.

If the wetting phase is increasing or being imbibed during the test, the curve is referred to as an imbibition curve.

Water – Oil relative permeability curve

leaving In oil-water system, oil and water relative permeabilities are plotted as functions of water saturation. At irreducible water saturation, Swi, the relative permeability to water, krw is zero and oil permeability with respect to oil kro is a value less than unity. This is due to reduction in oil permeability due to presence of water. At Swi, only oil can flow. As water saturation increases, relative permeability to water increases and oil permeabity decreases. The maximum water saturation is reached at the residual oil saturation (Sor). Residual oil saturation is left in the smaller channels when the interfacial tension causes the thread of oil to break; behind oil in droplets which tend to assume spherical form and when gradient pressure is not sufficient to deform the bubble enough to pass through the smaller pore openings.

0

0 Swi Sor 1 Sw

Gas–Oil relative permeability curve

The gas relative permeability krg remains zero until the critical gas saturation Sgc is reached. At Sgc, there is enough accumulation of gas for its mobility. As gas saturation increases, the gas relative permeability increases. The gas relative permeability will achieve maximum value at residual oil saturation. The oil permeability decreases from unity to lesser values as the gas saturation increases finally reaching a value of zero at the residual oil saturation plus irreducible water saturation.

0

0 Sgc Sorg 1 Sg

Laboratory methods for measuring relative permeability

Two major laboratory methods have evolved to measure relative permeability. These are referred to as the steady-state and nonsteady-state techniques.

krel

1

krel 1

STEADY STATE: The steady-state test, the older of the two methods, is made at low flow rates. Most research groups prefer data obtained from this test. Two fluids are injected simultaneously into a core sample and the water saturation is increased slowly. This simulates the slow increase in water saturation that would occur in the formation between the injection and producing wells. Saturation increase is monitored by measuring the gain in weight occurring in the sample or by X-ray technique.

NONSTEADY STATE: The nonsteady-state technique uses viscous oil and is normally

made at a higher flow rate than that present in the reservoir. It is this higher rate that sometimes yields pessimistic estimates of recovery from rocks of intermediate wettability.

Normalisation and averaging of relative permeability data

There is a wide variation observed in relative permeability results of experiments conducted on core plugs of a reservoir rock. To use this data for reservoir engineering calculations, the proper averaging or normalization of relative permeability data obtained on individual rock samples is essential so that the effects of different water saturations and residual oil saturations are removed. The normalized relative permeability data is then denormalised for different portions of reservoir as per the measured irreducible water saturation and residual oil saturation.

The following steps are required for averaging of oil and water relative permeability curves.

1. Starting with Swi, chose several values of Sw and calculate Sw* for each set of relative permeability curve

Sw* = or wi wi w S S S S − − − 1

Calculate the normalized relative permeability for the oil phase at different water saturation kro* = Swi ro ro k k ) (

3. Calculate the normalized relative permeability of the water phase at different water saturation

krw*= or S rw rw

k

k

)

(

4. Make a linear plot of the normalized kro*, krw* versus Sw* for all the core samples. Obtain a single pair of normalized relative permeability curve by selecting

arbitrary values of Sw* and calculate the average of kro* and krw* using the following relationships (kro*)avg = = = n j j n j ro j

hk

hkk

)

(

*)

(

Where n = total number of core samples hj = thickness of sample j

kj = absolute permeability of sample j

6. Denormalise the average curve to reflect actual reservoir and conditions of Swi and Sor; using the following equations:

wi or w w w S S S S S = *(1− − )+ (kro)Swi =

[

]

hk

k

hk

)

(

)

(

[

]

hk

k

hk

)

(

)

(

Where (kro)Swi and (krw)Sor are the average relative permeability of oil and water at irreducible water saturation and residual oil saturation respectively.

WELL LOGGING

A well log is the continuous recording of the characteristics of the hole drilled formation, as a function of depth.

Well logs are recorded at the various stages in well under drilling. The drilling is interrupted during the log recording. The data is recorded and transmitted to the surface instantaneously. Well logs are essential tools for enhanced reservoir evaluation.

Electric Logs

Spontaneous potential

The SP log is the difference in electric potential between a fixed electrode at the surface and a moving electrode in the borehole. It is measured in millivolts, and there is no absolute zero; only changes in potential are recorded.

Two types of potential may contribute to the SP effect. These are the electrochemical potential (Ec) and the electro kinetic potential (Ek).

The electro kinetic potential (Ek) is produced by the flow of mud filtrate through a porous and permeable formation. The electrochemical potential (Ec) results from the transfer of ions from a more concentrated electrolyte (usually the uninvaded zone in the formation) to a less concentrated electrolyte (usually mud in the bore hole).

The SP log is used in the identification of permeable beds and the location of their boundaries, and for determination of formation water resistivity in the uninvaded zone (Rw).

A deflection is observed opposite the reservoir rock compared with a “base line” of the shale. These deflections are due to different salinities of the reservoir water and the drilling mud.

Resistivity log

Resistivity logs measure and record the resistance offered by the rocks surrounding the bore hole to the passage of the electric current. A system of electrodes sends an electric current into the formation. The apparent resistivity of the reservoir is measured in ohms per meter. The resistivity logs may be divided into conventional or non focused devices, focused tools and induction systems.

The Laterolog systems contain an array of electrodes to focus the survey current and force it to flow laterally into the formations surrounding the borehole. The effective depth of laterolog investigation is controlled by the extent to which the surveying current is focused.

The induction log measures the conductivity of the rocks surrounding the borehole by inducing an electric current through them. The tool consists of a transmitter and a receiver coil. A constant, high frequency alternating current is sent through the transmitter coils. This generates an alternating magnetic field which induces secondary currents (also known as eddy currents) in the rocks surrounding the borehole. These currents flow in circular paths coaxial with the transmitter coils through the surrounding rocks. The resulting magnetic field, in turn induces signals in the receiver coils. These signals are proportional to the conductivity of the formations from which resistivity is derived and recorded on the log.

The resistivity recorded is a function of the porosity and saturation (water/hydrocarbons). The rock matrices are insulating and the hydrocarbons have high resistivity, whereas the resistivity of the water decreases with increasing salinity. The resistivity can differentiate the water from hydrocarbons.

Empirical equations m a Rw Ro F

φ

φ

Where

Ro = resistivity of rocks 100% saturated with water of resistivity Rw. F = formation factor

a = tortuosity coefficient m = cementation factor n = saturation exponent

Rt = calculated resistivity of rock at water saturation Sw.

Radioactivity Logs

Gamma ray log (GR)

This log records the natural radioactivity of formations. The radioactivity arises from the presence of uranium(U), thorium(Th) and potassium (K40_{) in the rocks. These elements} continuously emit gamma rays, which are short bursts of high energy radiation similar to x-rays. Gamma rays are capable of penetrating a few inches of rock, and a fraction of

those that originate close to the borehole traverse the hole and can be detected by a suitable gamma-ray sensor. The detector gives a discrete electrical pulse for each gamma ray detected, and the parameter logged is the number of pulses recorded per unit of time by the detector. The GR log is useful in detecting shale beds. Non radioactive minerals like coal may be detected by their characteristically low gamma response. This log is used for correlation of formations in cased holes.

Neutron log

In neutron logging the formations surrounding the borehole are bombarded by high energy neutrons from an artificial source carried on the device. Neutrons are electrically neutral particles with a mass almost identical to that of a hydrogen atom. Upon leaving the source the neutrons enter the formations and collide with nuclei in the rocks forming the borehole wall. With each collision a neutron loses some of its energy. The amount of energy lost per collision depends on the relative mass of the nucleus with which the neutron collides. The greatest energy loss occurs when the neutron strikes a nucleus of practically equal mass, ie. a hydrogen nucleus. Collisions with heavy nuclei do not slow the neutron down very much. Thus the slowing down of neutrons depends largely on the amount of hydrogen in the formation. The sonde emits fast neutrons which bombard the formation giving rise to slow neutrons, The neutron count rates increase with decreasing hydrogen content (low porosity in clean formations) and decrease with increasing hydrogen content (high porosity in clean formations).

Formation Density Compensated (FDC) Log

The Formation Density Compensated (FDC) Log records the bulk density ( b) of the formation surrounding the borehole. Gamma rays are beamed at the formations by the source. These enter the formations and undergo multiple collisions with the electrons in the frocks, as the result of which they energy and become scattered in all directions. This is known as Compton scattering. Some of the scattered gamma rays return to the borehole and are recorded by the detectors on the device. The intensity of the returned radiation is proportional to the number of electrons in the formation, and provides a measure of the electron density of the material. Electron density is approximately is equal to the bulk density of the rocks and this is recorded in gm/cm3_.

m

f

D

D

D

=

φ

.

+

(

1

−

φ

)

Where D = total density read on log Df = fluid density (filtrate)

Dm = density of rock matrix

The Borehole Compensated Sonic Log (BHC)

The sonic or acoustic log provides a continuous record of the time taken, in milliseconds per foot (µsec/ft), by a compressional sound wave to travel through one foot of formation. Known as the interval transit time, this is the reciprocal of the compressional wave velocity (Vp).

The velocity of sound through a given formation is a function of its lithology and porosity. Dense, low porosity rocks are characterized by high matrix velocities (Vm), while porous and less dense formations are characterized by low Vm, values.

m f V V V

φ

φ

φ

φ

Some other logs

Caliper log

This log system with arms furnishes the borehole diameter and helps in identifications of caving, constrictions etc.

Dipmeter log

This is the simultaneous recording of four microlaterolog curves along four 90 degree generating lines in a plane normal to the bore hole axis. The difference in the four curves gives the value of dip and its direction.

Cement bond log (CBL)

This log system is a continuous cased hole recording of the amplitude of the acoustic signal versus depth. The analysis of signals provides information on the presence and bonding the cement to the casing and to the formation

• In the presence of cement, the signal is weak because cement attenuates the vibrations of the metal.

• In the absence of cement, the casing vibrates freely generating a strong signal.

Introduction

The chemistry of hydrocarbon reservoir fluids is very complex. Some estimates suggest that perhaps 3,000 organic compounds can exist in a single reservoir fluid. These compounds contain a variety of substance of diverse chemical nature that includes hydrocarbons and non hydrocarbons. Hydrocarbons range from methane to substances that may contain more than 100 carbon atoms. Non-hydrocarbons include substances such as N2, CO2, H2S, S, H2O, He and even traces of Hg, etc.

The physical properties of these mixtures depend primarily on composition and temperature & pressure conditions. Reservoir temperature usually can be assumed constant, however as the oil and gas are produced, reservoir pressure decreases and the remaining hydrocarbon mixtures change in composition, volumetric properties, and phase behaviour. Understanding of this behaviour is very important for a petroleum engineer as it is of prime consideration in the development and management of reservoirs that would maximize the profits.

With this objective, this particular chapter on reservoir fluid behaviour would familiarize the reader about reservoir fluid composition, phase behaviour properties, types of reservoir fluid, various reservoir fluid characteristics and empirical methods for its determination, various types of laboratory experiment, application of reservoir fluid characteristics and equation of state. At the end of this chapter reader should be able to apply these concepts in solving practical engineering problems.

Reservoir Fluid Composition

The empirical formula CnH2n+hSaNbOc can be used to classify nearly all compounds found in crude oil. The largest portion of crude oil is composed of hydrocarbons with carbon number n, ranging from 1 to about 60, and h numbers ranging from +2 for low molecular weight paraffin hydrocarbons to -20 for high molecular-weight organic compounds.

Occasionally, sulphur, nitrogen and oxygen substitutions occur in high molecular weight organic compounds with a, b and c usually ranging from 1 to 3.

Those hydrocarbons which contain only two elements, hydrogen and carbon are of two types aliphatic and aromatic. Aliphatic hydrocarbons are further divided into alkanes (CnH2n+2), alkenes (CnH2n), alkynes (CnH2n-2), and their cyclic analogs.

The series of straight chain alkanes show a smooth gradation of physical properties. As molecular size increases, each additional CH2 group contributes a fairly constant increment to boiling point and specific gravity. The boiling and melting points of alkanes are fairly low because of symmetrical nature of molecules. Chemically, alkanes are unreactive at ordinary temperature. Hence, naturally occurring petroleum deposits mainly consist of alkanes.

The physical properties of alkenes and alkynes are very much like the physical properties of alkanes. However, because of double and triple bonds, alkenes and alkynes are more reactive than alkanes. Hence, alkenes and alkynes are not usually found in naturally occurring hydrocarbon deposits.

Cycloalkanes and cycloalkenes are about as reactive chemically as their open chain analogs. Different members of cyclic group exhibit different chemical reactivities. Aromatic hydrocarbons show gradation in their physical properties with increase in molecular weight and they have the same stability as the carbon-carbon single bond found in alkanes.

There are many families of organic compounds other than alkanes, alkenes, alkynes and their cyclic analogs which, contains atoms other than carbon and hydrogen e.g. sulphur, nitrogen and oxygen etc. Mercaptans, alkyl sulphides, aldehydes, ketones, resins and asphaltenes belong to this category of organic compounds.

Class of Compound Functional Group Alkane >C-C< Alkene >C=C< Alkyne -C C- Alcohol -OH Ether -O- Halide F, Cl, Br, I Aldehide C H Ketone >C=O Carbolylic Acid C OH Amine -NH2 Nitro Compound + N O -Nitrile -C N Organo Metallic -C-Metal Classification of Oil

As seen in the classifications of organic compounds, hydrocarbon liquids may be composed of several thousands of components. A complete chemical analysis for the identification and measurement of constituents is very difficult and expensive, if not an impossible task. Less complete types of analyses are often not useful for determining its physical characteristics. Difficulty in classifying oils by the chemical composition of their constituents has led to widespread use of simpler, less technical classification. Few of the classifications are given below;

1. Paraffins, naphthenes and aromatics as group (PNA): Chains of hydrocarbon segments, branched(iso) or unbranched (normal) types of hydrocarbons are termed as paraffins, Naphthenes are similar to paraffins with the exception of containing one or more cyclic structures and aromatics are cyclic benzene type of compounds (six carbon atoms ring).

2. Paraffin base, asphalt base and mixed base oil. 3. Classification based on O_{API of oil etc.}

Highly detailed information on the constituents of reservoir fluid is of not very use in exploration and production processes. Reservoir fluids are commonly identified by their constituents individually to hexanes, and lumping all the compounds heavier than hexane as C7+. A typical oilfield molar composition for reservoir fluid is given below; Composition and Properties of Several Reservoir Fluids**

Component Dry

Gas Wet Gas Gas condensate Near Critical Oil

Volatile

Oil Black Oil

CO2 0.10 1.41 2.37 1.30 0.93 0.02 N2 2.07 0.25 0.31 0.56 0.21 0.34 C1 86.12 92.46 73.19 69.44 58.77 34.62 C2 5.91 3.18 7.80 7.88 7.57 4.11 C3 3.58 1.01 3.55 4.26 4.09 1.01 i-C4 1.72 0.28 0.71 0.89 0.91 0.76 n-C4 0.24 1.45 2.14 2.09 0.49 i-C5 0.13 0.64 0.90 0.77 0.43 n-C5 0.5 0.08 0.68 1.13 1.15 0.21 C6 0.14 1.09 1.46 1.75 1.61 C7 0.82 8.21 10.04 21.76 56.40 Properties Mc7+ 130 184 219 228 274 C7+ 0.763 0.816 0.839 0.858 0.920 GOR, scf/STB 105,000 5,450 3,650 1,490 300 0_{API 57 49 45 38 24} g 0.61 0.70 0.71 0.70 0.63

** Type of reservoir fluids would be explained in the subsequent chapter. Phase Behaviour

Hydrocarbon system exhibit multiphase behaviour over wide ranges of pressure and temperatures e.g. Methane, often a predominant component of natural gases and petroleum reservoir fluids, is a gas, nC5 and hydrocarbons as heavy as nC15 may be in the liquid state, and normal paraffin heavier than nC15 may be in the solid state at room temperature. However, the mixture of these hydrocarbons may be in a gaseous or liquid state at the pressures and temperatures often encountered in petroleum reservoirs. A reservoir oil (liquid phase) may form gas (vapour phase) during depletion. The evolved gas initially remains dispersed in the oil phase before forming large mobile cluster.

The mixture may also become solid at certain temperature and pressure (WAX). It has also been found that in some hydrocarbon mixtures, when pressure is increased at constant temperature, the liquid phase vaporizes.

Hence, it would be very pertinent to define phase. The term phase defines any homogeneous and physically distinct part of a system which is separated from other parts of the system by a definite bounding surface. A particular phase need not be continuous. The terms vapour and liquid are referred to the less and the more dense phases of a fluid at equilibrium. By definition liquid is a saturated entity in the presence of vapour and vapour is a saturated entity in the presence of liquid.

The study of effect of variation in temperature and pressure on the physical characteristics of the naturally occurring hydrocarbons to establish phase relationship is termed as phase behaviour. Phase behaviour focuses only on the state of equilibrium, where no changes will occur with time if the system is left at the prevailing constant pressure and temperature. A system reaches equilibrium when it attains its minimum energy level (minimum Gibbs energy level-it will be discussed later). The assumption of equilibrium between fluid phases in contact in a reservoir is a valid assumption in most engineering application. Fluids at equilibrium are also referred as saturated fluids, as we observe during gas liberation below bubble point.

Hydrocarbon accumulations are invariably associated with formation water that exists in the hydrocarbon zone as interstitial water, and as aquifers. The formation water has little or no effect on the phase behaviour of hydrocarbons. Hence in phase behaviour study of

GOR

Pressure Saturated

oil

hydrocarbon system we will be concentrating on the equilibrium of state of oil and vapour.

Phase behaviour of a hydrocarbon mixture at reservoir and surface conditions is determined by its chemical composition and the prevailing temperature and pressure. The study of this phase behaviour is of prime importance for petroleum engineers as it is of prime consideration in the development and management of reservoirs that would maximize the profits.

Phase behaviour of a pure compound

The word “pure” refers to a single component system and is considered to be the simplest type of hydrocarbon system and they are not found in nature. The idea behind presenting the phase behaviour of a single component system is to develop a qualitative understanding of the relationship between temperature, pressure and volume of pure component which would provide an excellent basis of understanding of the phase behaviour of complex hydrocarbon mixtures.

Pressure-Temperature Diagram: The phase behaviour of a pure compound is shown by a pressure–temperature diagram as shown below;

The line BD in the above figure is the solid-liquid equilibrium line, which is also known as the melting point curve. Line AB is the solid-vapour equilibrium line or the sublimation curve. The line BC is commonly known as the vapour pressure curve, which separates

Critical Point Vapour Solid Temperature D A C Triple Point Liquid Pressure B

the liquid phase from the vapour phase. The locus of the point on this line represents vapour and liquid phases which can coexist at equilibrium. Any fluid at any other pressure temperature within this region is an undersaturated single phase. The fluid above and to the left of the line BC is referred to as a compressed or undersaturated liquid, whereas that below and to the right of this line is called a superheated vapour or gas.

The point C is called critical point and the corresponding pressure and temperature is called critical pressure and critical temperature respectively. All the differences between the phases are reduced as the system approaches critical point. Since the term liquid and vapour phase refers to more dense and less dense phases of a fluid at equilibrium, the density of both liquid and vapour becomes equal at critical point, making it difficult to distinguish between liquid and vapour phases. A typical plot of variation of saturated fluid density with temperature is given below;

Pressure-Volume Diagram: The pressure-volume diagram of pure substance is shown below C Critical Point Density Temperature Saturated Liquid Saturated Vapour

Consider the compressed liquid at point A, at a temperature below the critical temperature. The reduction of fluid pressure at constant temperature would increase its volume. As the liquid is relatively incompressible the fluid expansion is small until the vapour pressure is reached, at point B, where the first bubble evolves from the liquid. This point is called bubble point. Further reduction of pressure would result in changing the liquid into the vapour phase. For a pure substance the pressure remains constant and equal to the vapour pressure, a consequence of phase rule, until the last drop of the liquid vapourises. This point where the vapour is in equilibrium with an infinitesimal amount of liquid is called the dew point.

The locus of the system bubble points at various temperatures, which separates liquid phase from two phase forms the bubble point curve, whereas the locus of dew points of the system which separates two phase from vapour phase forms dew point curve. This is very important concept in numerical fluid modeling, as the point of intersection of these two curves defines critical point of the system-a point of discontinuity in phase identification. Mathematically, point of inflection of PV line at critical point is defined as ; V p V p 2 2 0 ∂ ∂ = = ∂ ∂

This critical criterion was developed in 1873 by Vander Walls and is enforced in equation of state. Critical Point C E D B A

Two Phase Region

T1 T2 TC T3 F G Pressure Volume Temperature : T1 < T2 <TC < T3

Principle of Corresponding States:

Real gases fail to obey the ideal gas equation exactly. For exactly one mole of an ideal gas;

=

1

.

0

RT

PV

Plotting the experimentally determined value of (PV/RT) for exactly one mole of various real gases as a function of pressure, P, shows a deviation from the ideality.

The deviation from ideal behaviour is large at high pressure and low temperature. The reason for this deviation is the intermolecular force of attraction at elevated pressure. Hence equation PV=RT is extended to real system by including a compressibility factor, Z as

PV=ZRT

The compressibility factor depends only on the ratio of temperature to the critical temperature, reduced temperature, Tr and the ratio of pressure to critical pressure, the reduced pressure, Pr. This approach is based on a very important concept, known as the

principle of corresponding states, which states that substances behave similarly when they are at the same relative proximity to their critical points.

Application of the corresponding state principle to the vapour pressure of pure compounds, follows a similar trend. The logarithm of vapour pressure of pure compounds approximately varies linearly with the reciprocal of temperature as shown below; i.e.

)

(

)

(

T

T

P

P

Log

=

ξ

−

ξ

where PS _{is the vapour pressure and 1 & 2 are constants for each substance. At the} critical point; PS_{/PC = T/TC =1, Hence 1 = 2}

i.e.

(

)

(

1

1

)

T

P

Log

=

ξ

−

If the principle of corresponding state were exact, the vapour pressure curves of all the compounds, plotted in the reduced form should have the same slope equal to 1 falling on the same line. In practice, this does not occur. The deviation of models based on the two parameter corresponding states principle is due to differences in molecular structures of various compounds, resulting in different intermolecular forces. Hence necessity of a third parameter is felt, in addition to the reduced temperature and pressure, which would concur to the molecular structure. The acentric factor ( ) has been accepted as the third parameter in generating generalized correlations, based on the corresponding state principle, particularly those related to fluid phase equilibria. In fact the vapour pressure of pure compounds can be reliably estimated using the Lee and Kesler correlation, which is based on three parameter corresponding state.

(f(0) f(1)) C S

e

P

P

₌

Phase Behaviour of a Multicomponent Mixture

The phase behaviour of a multi component mixture is not as simple as that of a pure component. It is more elaborate than that of a pure component. The complexity compounds as component with widely different structures and molecular sizes comprise the system. However, reservoir fluids are mainly composed of hydrocarbons with similar structures. Hence their phase behaviour is not generally complex. Two important differences between pure and multicomponent systems are (i) the saturated P-T diagram is represented by a phase envelope rather than by a vapor-pressure curve as the separation between bubble point and dew point increases with the contrast of system component, and (ii) the critical temperature and critical pressure no longer define the extent of the two phase region. Two phase can exist upto cricondentherm and cricondenbar beyond critical temperature and critical pressure.

Pure Component Multicomponent

Pressure-volume diagram of a multicomponent reservoir fluid is schematically shown below;

Contrary to a pure system, in a multicomponent system the system pressure decreases during an isothermal expansion between its bubble and dew points. At the bubble point (A), the composition of the liquid is essentially equal to the overall composition of the mixture. However, the infinitesimal amount of gas which is liberated is richer in the more volatile component. Similarly at the dew point the composition of the vapour is essentially equal to the over all composition of the mixture with infinitesimal amount of liquid is richer in the least volatile component.

Critical Point Temperature Liquid Solid Pressure Vapour C Two Phase Pressure Temperature T2 T1 T3 A B Pressure Volume

Phase diagram of a mixture is determined by its composition. Figure shown below is that of ethane-heptane system. The critical temperature of different mixture lies between the critical temperature of the two pure compounds. However, the critical pressure exceeds the value of both components as pure, in most cases.

The greater the difference between the critical points of the two components, the higher the mixture critical pressure would be.

Retrograde Condensation: In a multicomponent phase diagram as shown below, vapour and liquid phases coexist at any pressure-temperature condition within the phase envelope. The different liquid/mixture volumetric ratios are conventionally shown as dashed lines which are called quality lines. The quality lines come very close towards each other near critical point of the system. Hence small pressure or temperature changes at a region near the critical point cause major phase changes.

If the reservoir hydrocarbon system is at point A, reduction of pressure for vapor like fluid at point A, forms the first drop of liquid at point B. Further reduction of pressure will result in further condensation, as indicated by quality lines. This phenomenon of condensation with decrease in pressure is called retrograde condensation. The condensation will cease at some point, point D, and the condensed phase will re-vaporize again. The shaded region of the phase diagram is called retrograde region. This is an important phenomenon which is generally observed in gas condensate wells.

Classification of Reservoirs and Reservoir Fluids

A typical phase diagram of a reservoir hydrocarbon system can be used to describe various types of reservoir fluids. Identification of types of reservoir fluids is necessary and must for production and reservoir engineer, as different types of fluid require different approaches for exploitation.

How to classify reservoir types? Location of reservoir temperature on the phase diagram can be used to classify reservoir fluids. There are five types of reservoir fluids; dry gas, wet gas, gas condensate (retrograde gas), volatile oil and black oil.