Fundamentalsof Basic Reservoir Engineering 2010

Fundamentals of Reservoir Engineering & Characterization 1

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

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


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



Structural trap: oil and gas accumulation in an anticline


Oil accumulation in a stratigraphic trap formed by a change in permeability


Combination trap

Oil


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.

100xVbVp

=φ


100xVb

VgVb

−=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

2ldπ

• 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 = njφ

Thickness weighted porosity Ø = J

jj

h

hφ

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

jj

A

Aφ

Volumetric weighted average porosity Ø = jj

jjj

hA

hAφ

Where n = total number of core samples

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

pALq

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

bgsc Lp

ppkAQ

µ2)( 2

22

1 −=

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.

Gas

Per

mea

bilit

y

Liquid permeability


=

==n

jj

n

jjj

avg

h

hkk

1

1

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

jj

av

kL

Lk

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

jj

n

jjj

avg

h

khk

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:

( )nnavg kkkkk1

321 ...=

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, VolumePore

oilofVolumeSo ..

....=

Gas saturation, VolumePore

gasofVolumeS g ..

....=


Water Saturation, VolumePore

waterofVolumeSw ..

....=

Sg + So + Sw = 1.0

Determination of saturation

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

1200oF. 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

=

==n

jjj

n

jjjj

h

SohSo

1

1

φ

φ

=

==n

jjj

n

jjjj

h

SwhSw

1

1

φ

φ


=

==n

jjj

n

jjjj

h

SghSg

1

1

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 = 2r.

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

2r. gw. cos = r2.h.ρw.g

gw = θρ

cos2... wghr

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 θσ cos2

h = )(

cos2

gw

gw

rg ρρθσ

−

Oil - Water System

Pc = r

ow θσ cos2

h = )(

cos2

ow

ow

rg ρρθσ

−

Where ρw = water density, gm/cm3

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,

φσkPc

J Sw 21645.0)( =

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∆Pc144

where Pc = capillary pressure,psia

ρ = density difference between wetting phase and non-wetting phase at

reservoir conditions, lb/ft3

h = height above the free water level, ft


Distribution of saturation in the reservoir


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:

Cap

illar

y P

ress

ure

H

eigh

t Abo

ve O

il-W

ater

Con

tact


Effect of grain size on Irreducible water saturation


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 = typermeabiliBase

typermeabiliEffective⋅

.


kro =kko

krg =k

k g

krw =k

kw

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* = orwi

wiw

SSSS−−

−1

Calculate the normalized relative permeability for the oil phase at different water

saturation

kro* = Swiro

ro

kk

)(

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

water saturation


krw*= orSrw

rw

kk

)(

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

jj

n

jjro

hk

hkk

1

1

)(

*)(

(krw*)avg =

=

=n

jj

n

ijrw

hk

hkk

1

1

)(

*)(

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:

wiorwww SSSSS +−−= )1(*

( k ro)Swi =

[ ]

=

=n

jj

n

jjSwiro

hk

khk

1

1

)(

)(

( k rw)Sor =

[ ]

=

=n

jj

n

jjSorrw

hk

khk

1

1

)(

)(

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

aRwRo

Fφ

==

n

RtRw

S w φ1=


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.


mf DDD )1(. φφ −+=

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.


mf VVVφφ −+= 11

or

tmtt f ∆−+∆=∆ ).1(. φφ

Where t = travel time in the transmitter/receiver interval

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.

Cement Bond Log


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.

Following table lists classification of organic compounds according to functional groups.


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 OAPI 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

0API 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

Undersaturated 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 ;

Vp

Vp

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;

0.1=RTPV

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.

)(

)( 21

C

C

S

TTP

PLog

ξξ −=

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()( 1r

Sr T

PLog −= 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.

)( )1()0( ff

C

S

ePP ω+=

Where f(0) = 5.92714-6.09648/(Tr)– 1.28862 ln(Tr) + 0.16934(Tr)6

f(1) = 15.2518-15.6875/(Tr)– 13.472 ln(Tr) + 0.43577(Tr)6

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.


Dry Gas Dry gas is primarily composed of methane and some intermediates such as nitrogen and

carbon dioxide. A typical phase diagram of a dry gas is given below

As evident from phase diagram the phase envelop is relatively tight and mostly located

below the ambient temperature. A dry gas does not contain any enough of heavier

molecule to form hydrocarbon liquid at the surface. Gas remains in single phase from

reservoir to separator. Water, however may condense at surface condition due to

cooling effect.

Wet Gas A wet gas exists solely as gas in the reservoir throughout the reduction in reservoir

pressure. However, liquid may form at separator due to its position within the phase

region. A typical phase diagram of wet gas system is given below;

Pressure

Temperature

Reservoir

Separator

Reservoir

Separator

C


The surface liquid is normally called as condensate. As no condensate is formed in the

reservoir, material balance equation for a dry gas is equally suitable for a wet gas.

Producing gas to condensate ratios are typically above 10,000 v/v.

Gas Condensate or Retrograde Gas In a typical gas condensate reservoir the reservoir temperature lies between critical point

and cricondentherm. The gas will drop out liquid by liquid by retrograde condensation in

the reservoir, when the pressure falls below the dew point. A typical gas condensate

phase diagram is shown below;

The phase diagram of a retrograde gas is somewhat smaller than that for oils because of

presence of less heavy hydrocarbons. However, presence of heavy hydrocarbons

(compared to a wet gas system) expands the phase envelope relative to a wet gas

phase envelope. Material balance equation developed for dry gases can be used for a

gas condensate reservoir as long as the reservoir pressure remains above the dew point.

Lowering of reservoir pressure, below dew point, results in gas to form free liquid in the

reservoir. The liquid will normally not flow and can not be produced. Hence,

condensation and loss of valuable compounds in reservoirs could be avoided by

maintaining the reservoir pressure above the fluid dew point by gas recycling. A

compositional material balance method should be used for gas condensate reservoir

system where pressure has fallen below dew point.

Volatile Oil Volatile oil contains relatively higher heavy molecules than a gas condensate system

that makes it to behave liquid-like at reservoir conditions. The phase envelope, as per

phase rule, is relatively wider than that of a gas condensate system, with a higher critical

temperature due to its larger concentration of heavy compounds.

Pressure

Temperature

C

Reservoir

Separator


A typical volatile oil phase diagram is shown below;

The vertical line shows the path taken by the isothermal pressure reduction during

depletion. A small reduction in the pressure below the bubble point causes the release of

a large amount of gas in the reservoir. Saturation pressure of volatile oils is high. Gases

produced below the bubble point, therefore, are quite rich and behave as retrograde

gases. The amount of liquid recovered from the gas constitutes a significant portion of

the total oil recovery. Compositional methods should be applied generally to study

volatile oil reservoirs.

Black Oil Black oil is the most common type of oil reserves. It consists of wide variety of chemical

species including large, heavy, nonvolatile molecules. Therefore, its phase envelope is

the widest of all the types of reservoir fluids, with its critical temperature well above the

reservoir temperature. A typical phase diagram of black oil is shown below

Reserv

2

3

Separator

C 1

Pressure

Temperatu

Separato

Reservoir Pressure

Temperature


In a black oil system the quality lines are broadly spaced at reservoir condition with

separator condition lying on relatively high quality lines. In atypical black oil system GOR

may decrease initially when the reservoir pressure falls below bubble point, as the

evolved gas remains immobile at very low saturation. The saturation pressure of black

oil is relatively low. Contribution of heavy compounds present in evolved gases in

reservoir to the total liquid recovery is not significant.

PVT Properties of Oil and Gas Knowledge of PVT is the first step in the study of any oil field as the information helps in

evaluating reserves, developing optimum recovery plan, and determining the quantity

and quality of produced fluids. In fact PVT parameters are required in every aspect of

reservoir engineering. Hence, accurate and reliable phase behaviour and volumetric

data are essential elements for proper management of petroleum reservoirs.

Most commonly information from black oil PVT tests are the oil formation volume factor,

Solution GOR, gas formation volume factor, as they are used to simplify engineering

calculations. Specifically, they allow for the introduction of surface volumes of gas, oil

and water into material-balance equation. Hence it would help if these terms are defined.

Oil Formation Volume Factor: It is defined as the number of reservoir barrels of oil and

dissolved gas that must be produced to obtain one stock tank barrel of stable oil at the

surface condition. Its unit is reservoir barrel/stock tank barrel.

Solution Gas Oil Ratio: It is defined as the number of standard cubic feet of gas

produced with each stock tank barrel of oil that was dissolved in the oil in the reservoir.

It’s unit is standard cubic feet/stack tank barrel.

Gas Formation Volume Factor:It is defined as volume in barrels that one standard

cubic foot of gas at the surface occupies as free gas in the reservoir. Its unit is reservoir

barrel/standard cubic feet.

Compositional studies are often conducted for gas condensate and volatile oil reservoirs,

where detailed informations on the fluid constituents are used to estimate fluid properties.

Only in special cases such as gas injection or miscible displacement, the compositional

approach is used for black oil reservoirs.

. Methods of Obtaining PVT data : There are primarily three methods by which PVT data are derived


1. Laboratory Measurements

2. Empirical PVT Correlations

3. EOS fluid Characterization

There are several PVT tests that are routinely conducted in the laboratory to study and

quantify the phase behaviour and properties of a reservoir fluid at simulated recovery

conditions.

Empirical correlations and charts, mainly reminiscence of days when hand calculations

were norm to predict PVT data, are still in vogue and much sought after.

A compositional phase behaviour model (EOS), can predict all the PVT data using only

the composition of the original reservoir fluid. However, the model first needs to be

evaluated and tuned against the measured PVT data prior to being used in reservoir

studies with confidence. With the advent of fast computers and robust algorithms

compositional data model are becoming very popular

Routine laboratory tests The majority of laboratory tests are depletion experiments, where the pressure of the

single phase test fluid is lowered in successive steps. The reduction of pressure results

in formation of a second phase, except in dry and wet gas mixtures. Hence type of

laboratory experiment to be conducted also depends upon the type of reservoir fluid.

Determination of fluid compositions is an important test on all reservoir fluid samples.

The gas and liquid phases are commonly analysed by gas chromatography and

distillation respectively.

Laboratory Tests for Dry Gas:In a dry gas reservoir system, no phase change occurs.

Hence, its composition remains the same. The only PVT test required for a dry gas is the

pressure-volume relation at the reservoir temperature and determination of specific

gravity, gas formation volume factor and isothermal compressibility.

Specific gravity = 96.28

Mg where Mg=molecular wt of gas

Bg = 0.02827 (Z T)/ P where Z is the compressibility factor, T and P is the reservoir temperature and pressure A typical gas formation volume factor graph is given below;


Isothermal Compressibility

TTg PZ

ZPPv

VC )(

11)(

1∂∂−=

∂∂−=

Laboratory Tests for Wet Gas:

PVT tests for a wet gas at reservoir conditions are similar to those for a dry gas.

Separate, tests are, however, needed to determine the amount and properties of

produced fluids at the surface conditions. The formation volume factor of a wet gas is

defined as the volume of the gas at reservoir conditions required to produce one unit

volume of the stock-tank liquid. The molecular weight and specific gravity of produced

condensate are also measured in the laboratory.

Laboratory Tests for Black Oil:

The phase transition of undersaturated oil during depletion can be best depicted as

given below. Let the reservoir pressure assumed to be higher than the bubble point

pressure. As the well is opened, pressure drops and as per theory of line solution most

of the pressure drop occurs near to the well bore. Away from the well bore, at Zone A,

which is far away from the well bore, the pressure is still higher than the bubble point

pressure. Hence oil expands as a single phase liquid.

Bg

Pressure

Bg Vs Pressure


The pressure at zone B, is just below the bubble point. Two phase region is formed.

However, the gas saturation is too small to allow its mobilization. The gas is assumed to

be in equilibrium with oil. This reservoir process is simulated in the laboratory at

reservoir temperature as constant composition flash vaporization. In the flash

vaporization the overall phase composition remains constant.

Zone C which is just ahead of the zone B, the gas bubbles coalesce together to form

bigger bubble, thereby, increasing gas saturation. Gas which was immobile in zone B,

now starts moving towards well bore in zone C. In the zone C the overall phase

composition doesn’t remain the same as gas moves out of the mixture. This reservoir

process is simulated in the laboratory at reservoir temperature as differential

vaporization. A series of flash tests at surface temperatures are also carried out to

simulate surface condition phase separation.

Constant Composition Expansion Tests: Constant composition expansion tests are carried out at reservoir temperature on gas

condensate or black oil to simulate the zone A and zone B as shown in above diagram.

The following important PVT properties are determined through these tests;

• Saturation Pressure (bubble point or dew point)

• Isothermal compressibility of the single phase fluid above bubble point.

• Compressibility factor of gas phase

• Total hydrocarbon volume as function of pressure.

Constant Composition expansion test can be schematically shown as following;


A typical PVT test data as reported by a laboratory for constant composition tests is

given below;

Pressure, psig Relative Volume Y function Density Reservoir pressure

---- ----

---- ---- ---- ---- ---- Bubble Point Pressure

----

---- ---- ---- ---- ---- ---- Atmospheric pressure

---- ----

Relative Volume is calculated as ratio of total volume at indicated pressure divided by

total volume at saturation pressure. Y dimensionless function is used to evaluate,

smoothen and extrapolate the laboratory data.

[ ] [ ]bbtb VVVpPPY /)(//)( −−=

Where Pb= Bubble point Pressure, Vb= volume at bubble point pressure and Vt= total

volume at pressure P.

Following plot of pressure vs relative volume helps in determining bubble point pressure

and isothermal compressibility.

Oil

Hg

P1>Pb P2>Pb P3=Pb P4<Pb P5<Pb P6<Pb

Hg

Gas

Oil Vt


The slope of the curve above the bubble point is a measure of the isothermal

compressibility of oil

Co = TPv

V)(

1∂∂−

Differential Liberation (Vaporization) Tests: In the differential vaporization or liberation test, the oil pressure is reduced below its

bubble point at the reservoir temperature by expanding the system volume. All the

evolved gases is then removed at constant pressure by reducing the equilibrium cell

volume. This procedure is repeated in 10 to 15 steps down to the atmospheric pressure.

This type of liberation is characterized by a varying composition of the total hydrocarbon

system. The experimental data obtained from the test include:

• Amount of gas in solution as a function of pressure

• The shrinkage in the oil volume as a function of pressure

• Properties of evolved gas including the composition of the liberated gas, the gas compressibility factor, and the gas specific gravity.

• Density of the remaining oil as a function of pressure A typical data set for differential vaporization is given below; Pressure Solution

GOR Relative Oil Volume

Relative total volume

Oil Density

Z factor

Bg Incremental Gas gravity

Pb ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Patm ---- ---- ---- ---- Gravity of residual oil at standard condition= ------

Pressure

Relative Volume

Pb

Bubble Point


• Relative volume is defined as volume of oil at indicated pressure per volume of residual oil at the standard condition

• Relative total volume is defined as volume of total oil plus liberated gas at indicated pressure per volume of residual oil at the standard condition.

• Bg is defined as the volume of gas at indicated pressure per volume at the standard conditions.

The differential liberation test is considered to better describe the separation process

taking place in the reservoir and is also considered to simulate the flowing behaviour of

hydrocarbon system at conditions above critical gas saturation

The test is started from bubble point pressure and the pressure is depleted till the

system pressure becomes atmospheric pressure. The test procedure can be

schematically shown as below;

Separator Test In the separator test, a known volume of the reservoir oil at its bubble point is flashed at

two or more stages, where the last stage represents the stock tank. For oils with high

gas in solution, more than one intermediate separator is often used. A field average

temperature is used for the separator tests. The experiment is carried out at number of

stages to determine the optimum field separation condition which gives lowest formation

volume factor and maximum stock tank oil. Operational limitation may, however, dictate

other pressure conditions in the field.

The behaviour of a reservoir oil during depletion is simulated by a combination of all

there types of tests discussed above. The reservoir oil remains single phase as long as

the pressure is above bubble point. The gas evolved just below the bubble point initially

Expelled Gas Expelled Gas

Oil

Gas

P>Pb P=Pb P<<Pb P<Pb


remains immobile in pores. These processes are simulated by constant composition

expansion test i.e. flash vaporization. The evolved gas begins to move away from the oil

as the gas saturation exceeds a critical value. The process then becomes similar to

differential liberation tests. A part of the gas, however, remains in contact with the oil in

well bore and their subsequent separation in the separator. A flash separation can only

simulate this process.

In material balance calculations and black oil simulation, the properties of fluid produced

at the surface are related to those at reservoir conditions by the results of separator tests,

and not those of differential liberation. The differential liberation test data are based on

the residual oil in the reservoir, whereas the volume factor and solution gas data are

based on the stock tank oil must be used in material balance equation and black oil

simulation. The corresponding values by differential test are almost always higher and

can lead to errors of 10 to 20% in the calculated oil in place and recoverable oil. Hence

following corrections are made in the Bo and Rs values.

Odb

ObFODO B

BBB =

Where BObF = Flash formation volume factor at bubble point BOdb = Differential formation volume factor at bubble point

−−=

Odb

ObFSidSifS B

BRsdRRR )(

Where Rsif= Solution GOR at Bubble point from flash Rsid = Solution GOR at bubble point from differential liberation Constant Volume Depletion Test: Constant volume depletion (CVD) experiments are performed on gas condensate and

volatile oil systems to simulate reservoir depletion performance and compositional

variation. It is commonly assumed that the condensate dropped out in pores remains

immobile. The depletion process is, therefore, simulated by CVD. The test consists of a

series of expansion followed by expelling the excess gas at constant pressure in such a

way that cell volume remains constant at the end of each stage. The expelled gas at

each pressure stage is collected and its composition, volume and compressibility factor

are determined. The condensate volume is also measured.

A schematic diagram of CVD test is given below


Laboratory Test for Volatile Oil

Pressure depletion in volatile oil is associated with high gas liberation. This gas phase

almost immediately becomes mobile. The differential test seems to simulate the process.

However, the mobile gas which is produced with oil behaves as a rich retrograde gas

and contributes significantly to the liquid production. None of the pressure depletion tests

commonly conducted in laboratories can simulate the fluid behaviour as occurs in the

field. Hence, PVT tests for volatile well are not well defined till now. However

compositional model after tuning with pressure volume data and amount of condensate

may mimic the phase behaviour to some extent.

Empirical Correlations

When a reservoir fluid study is unavailable, the engineer must rely on correlations to

estimate values of the physical properties of interest. The main properties which are

determined from empirical correlations are the bubble point, gas solubility, volume

factors, density, compressibility, and viscosity. The correlation typically matches the

employed experimental data with an average deviation of less than a few percent. It is

not unusual, however, to observe a much higher deviation when applied to other fluids.

There are many fluid property correlations. A number of these correlations have used

data of certain localities; hence, their application is limited. Some correlations have

received higher attention and acceptability than others. However no correlation has clear

superiority over other. Some of them have shown their reliability in various comparative

studies. Following table provides information on the range of data used in the

correlations to help selecting correlation for specific purpose.

Gas

Gas Gas

Gas

Condensate

P> Pdew P= Pdew P< Pdew P<< Pdew

Gas Gas

Gas


Correlation Standing Lasater Vasquez-Beggs

Glaso Marhoun

Pb, psia 130-7000 48-5780 15-6055 165-7142 130-3573 Temperature, OF

100-258 82-272 162-180 80-280 74-240

BO, bbl/STB 1.024-2.15 1.028-2.226 1.025-2.588 1.032-1.997 GOR, SCF/STB

20-1425 3-2905 0-2199 90-2637 26-1602

OAPI 16.5-63.8 17.9-51.1 15.3-59.5 22.3-48.1 19.4-44.6 Sg 0.59-0.95 0.574-1.22 0.511-1.351 0.650-1.276 0.752-1.367 Sep. Pressure, psia

265-465 15-605 60-565 415

Sep. Temp., OF

100 36-106 76-150 125

Before different correlations for the determination of physical properties are given, it is

advised to the reader to use only those empirical relations which satisfy the limitation

given in the above detail and also matches with the experimentally determined results.

Black Oil Physical Properties Correlation for Bubble point Pressure

Bubble point pressure Pb is defined as the highest pressure at which gas is first liberated

from the oil. The correlation to determine Pb are based on the fact that bubble point

pressure is a strong function of solution GOR RS, gas gravity gγ , Oil gravity OAPI, and

temperature T

Standing correlations Standing initially introduced a graphical correlation for determining the bubble point

pressure for Californian crude, and later expressed the graph by the following correlation

( )

−⊗

= 4.1102.1883.0

a

g

sb

RP γ

Where a = 0.00091T – 0.0125 (OAPI) Pb = Bubble Point Pressure, psia Rs = Solution GOR, SCF/STB T = Temperature, OF McCain suggested to replace gas gravity with separator gas i.e. excluding the gas from

stock tank would improve the accuracy of the equation.


Limitations:

• This correlation should be used with caution if non-hydrocarbon component are

also present.

• A deviation of about 15% is expected from this correlation.

Vasquez and Beggs Correlation Vasquez and Beggs pointed out that gas gravity depends upon separator pressure.

Hence, it used the gas gravity ( gnγ ) normalized to a separator pressure of 100 psig.

2

)10(1

C

a

gn

Sb

RCP

⊗

=

γ psia

( )( )

+= −

7.114log10912.51 5 S

So

ggn

PTAPIγγ

Where a = -C3 (API)/(T+460), T in OF

Coefficient API30 API>30 C1 27.64 56.06 C2 0.914328 0.84246 C3 11.172 10.393

TS = separator temperature,OF PS = separator pressure, psia This method has an absolute error of 12.7%. Glaso’s Correlation Glaso developed the correlation from studying 45 North Sea crude oil samples

[ ]2** )log(30218.0)log(7447.17669.1)log( bbb PPP −+= Where *

bP is a correlating number and is defined by

cObagsb APITRP )()()/(* γ=

Glaso’s correction for correlating number to account for non-hydrocarbon component

and stock-tank-oil paraffinicity is not widely used. As large variation was observed in the

tuned equation of state model prediction with that of Glaso’s corrected and uncorrected

bubble points as shown in the Figure Below;


Paraffinicity is characterized by Watson’s characterization factor. Marhoun’s Correlation Marhoun used 160 experimentally determined bubble point pressure from the PVT

analysis of 69 Middle Eastern oils to develop a correlation for estimating Pb.

edO

cg

bsb TaRP γγ= psia

Where, T = temperature, OR Oγ = Stock tank oil Sp. Gravity

gγ = Gas specific gravity

a = 5.38088E-3 b = 0.715082 c = -1.87784 d = 3.1437 e = 1.32657

An average absolute relative error of 3.66% is observed. 5. The Petrosky-Farshad Correlation The gas solubility equation of Petrosky-Farshad can be solved for bubble point pressure

051.1391)10(

727.1128439.0

577421.0

−

=

Xg

Sb

RP

γpsia

Where X = (7.916E-4)(OAPI)1.541-(4.561E-5)(T-460)1.3911

T = temperature, OR 6. Lasater Correlation Lasater used mole fraction yg of solution gas in the reservoir oil as main correlating

parameter;

C7+ Watson Characterisation Factor

Pb, psia PR EOS

Glaso uncorrected

Glaso Corrected


g

b

TAP

γ= psia

Where T= temperature in OR 57246.017664.11083918.0 g

y yA g ⊗⊗= when yg 0.6

31109.008.11083918.0 g

y yA g ⊗⊗= when yg > 0.6

1

1330001

−

+=S

Og R

My

γ

Rs = GOR, scf/STB M0 = Stock tank oil molecular weight

M0 = 9.5

6084−APIγ

…. Cragoe correlation

In summary significant variation will not be observed for most of the correlations for Pb.

However, Lasater and Standing correlations are recommended for general use and as a

starting point for developing reservoir-specific correlation.

Correlation for Solution GOR 1. Standing Correlation Standing correlation for solution GOR is given as follows;

2048.1

104.12.18

⊗

+= xgS

PR γ scf/STB

Where

X=0.0125 (OAPI)-0.00091(T-460) T=temperature, OR P = System Pressure, psia

gγ =solution gas specific gravity

This equation is valid for application at and below bubble point pressure. 2. Vasquez-Beggs correlation Vasquez-Beggs presented an improved empirical correlation for solution GOR using

5008 measured gas solubility data points. The correlation proposed is as follows


=

TAPI

CpCRo

CgsS 31 exp2γ

Where

( )( )

+= −

7.114log10912.51 5 S

So

ggn

PTAPIγγ

Coefficient API30 API>30 C1 0.0362 0.0178 C2 1.0937 1.1870 C3 25.7240 23.931 TS = separator temperature,OR

PS = separator pressure, psia Sutton and Farashad evaluated this correlation and found that predicted value had an

absolute error of 12.7%.

3. Glaso’s Correlation Glaso developed correlation from studying 45 North sea crude oil samples. The

proposed correlation is given below.

( )2255.1

*172.0

989.0

)()460

−= bgS P

TAPI

R γ scf/STB

Where, *bP is a correlating number and is defined by

xbP 10* =

and x =2.8869-[14.1811-3.3093log(p)]0.5

T=temperature, OR P = System Pressure, psia


Most of the other solution GOR correlations can be derived from bubble point

correlations as explained in Bubble point section.

Correlation for Formation Volume Factor The oil formation volume factor of saturated oil has been correlated by a number of

investigators using the gas in solution RS, gas gravity, oil gravity and reservoir

temperature as the correlating parameters.


1. Standing Correlation Standing initially presented a graphical correlation for estimating the oil formation volume

factor, and later expressed the graph by the following correlation.

BO=0.9759+0.00012[RS( gγ / Oγ )0.5+1.25T]1.2 bbl/STB

T=temperature, OR

Oγ = Specific gravity of oil


RS = Solution GOR, scf/STB The correlation is based on Californian crude sample. 2. Vasquez-Beggs Correlation Vasquez-Beggs developed a relationship for determining BO as a function of RS, Oγ , gγ

and T. The proposed correlation is based on 6000 measurements of BO at various pressures.

[ ]Sgs

SO RCCAPI

TRCB 32

0

1 )520(1 +

−++=

γ bbl/STB

Where

( )( )

+= −

7.114log10912.51 5 S

So

ggn

PTAPIγγ

TS = separator temperature,OR PS = separator pressure, psia

T=temperature, OR RS= Solution GOR


Coefficient API30 API>30 C1 4.677E-4 4.670E-4 C2 1.751E-5 1.100E-5 C3 -1.811E-8 1.337E-9

3. Glaso’s Correlation Glaso proposed the following relation based on North Sea crude oil BO = 1.0+10A bbl/STB

Where A= -6.58511+2.91329 log( *

obB ) – 0.27683 ( log( *obB ))2

*obB is a correlating number as is defined as *obB = [Rs( gγ / Oγ )0.526 ]+0.968(T-460)


T = temperature, OR

gγ = solution gas specific gravity

Oγ = Specific gravity of Stock tank oil 4. Marhoun’s Correlation Marhoun developed an equation for BO by the use of non-linear multiple regression analysis on 160 experimental data points and is given as below; B0 = 0.497069+0.862963E-3 T+0.182594E-2 F+0.318099E-5(F)2 bbl/STB Where c

Obg

aSRF γγ=

a = 0.742390 b = 0.323294 c = -1.202040 5. Material Balance Equation BO is defined as

O

gSOO

RB

ργγ 0136.04.62 +

=

where O =density of the oil at the specified pressure and temperature, lb/ft3

gγ = solution gas specific gravity

Oγ = Specific gravity of Stock tank oil RS = Solution GOR, scf/STB Error in calculating BO using material balance equation will depend upon the accuracy of

input variables ( gγ , Oγ and Rs) and the method of calculating O. All the correlations for

BO determination give approximately the same accuracy.

Sutton and Farshad’s comparative study of these correlation suggests that Standing

correlation is slightly better for Bob <1.4 and Glaso’s correlation is best for Bob >1.4.

The Standing and the Vasquez-Beggs correlations suggest that a plot of BO vs. RS

should correlate almost linearly. Hence this plot should be used for checking the

consistency of reported PVT data from a differential liberation plot.

Correlation for isothermal Compressibility Coefficient for Crude Oil Isothermal compressibility coefficients are required to solve many reservoir engineering

problems, including transient fluid flow problems; material balance equation and they are


also required in the determination of physical properties of undersaturated oil.

Compressibility is defined as;

T

O pv

VC

=

δδ1

Strictly speaking, the compressibility of an oil mixture is defined only for pressures

greater than the bubble point pressure. If oil is at bubble point pressure, the

compressibility can be determined and defined only for a positive change in pressure.

Implicit in the definition of compressibility is the fact that mass remains the same.

However, as the pressure is reduced below bubble point pressure gas comes out of oil

and as a result mass of the original system for which compressibility is to be determined

doesn’t remain the same.

Compressibility Factor for Saturated Oil Perrine introduced a definition for the compressibility of a saturated oil that include the

shrinkage effect of saturated-oil, p

BO

δδ

, and the expansion effect of gas coming out of

solution, T

sg p

RB

δδ

T

S

O

g

T

O

OO p

RB

B

PB

BC

+

−=δ

δδ

δ615.511

Compressibility Factor for Under Saturated Oil 1. The Vasquez-Beggs Correlation After studying a total of 4036 experimental data point for compressibility. Vasquez-

Beggs gave following equation for undersaturated compressibility of oil

Co = A/p psi-1

Where A=10-55Rsb + 17.2(T-460)-1180gs+12.61 OAPI

( )( )

+= −

7.114log10912.51 5 S

So

ggs

PTAPIγγ

T = Temperature, OR P = Pressure above bubble point, psia Rsb = Slolution GOR at the bubble point pressure TS = Separator temperature, OR PS = Separator pressure, psia gγ = Solution gas specific gravity


2. Standing Correlation Standing gave a graphical correlation for undersaturated Co that can be represented by

−−−−−+

= −

938.12))(4141.7(1.79)(004347.0

exp10 6

b

bobO PPE

PPC

ρ psi-1

Where ob = oil density, lbm/ft3

Any of the above correlations can be used for C0 determination. However, caution

should be exercised while calculating C0 for volatile oil where Co > 20X10-6 . In case of

volatile oil simple polynomial fit of the relative volume data, Vro = Vo/Vob from a PVT

report should be used for an accurate Co rather than using correlations.

Polynomial fit should be done as follows;

Vro = Ao+A1P+A2P2

2

21

21 )2(pApAA

pAAC

OO ++

+−=

Correlation for Oil Viscosity The live oil viscosity depends upon the solution gas content. Oil Viscosity decreases with

rising pressure as the solution gas increases, upto the bubble point pressure. There are

few empirical correlations to determine the viscosity of saturated and undersaturated

crude oil which accounts for the effect of dissolved gas and pressure on the viscosity of

dead oil.

Correlation for determining dead Oil Viscosity (od) For empirical correlation, the dead oil viscosity is determined first. The dead oil is

defined at atmospheric pressure and at any fixed system temperature without dissolved

gas.

1. Beal Correlation Beal presented a graphical correlation to determine dead oil viscosity, if the oAPI gravity

of the crude oil and the temperature are known. Standing presented this in the form of

mathematical equation for determining dead oil viscosity, od, at 14.7 psia and

temperature T, in oR;

a

APIod T

E

−

++=260

36078.132.0

53.4γµ cp


Where

+

= APIa µ33.8

43.0

10 2. Beggs and Robinson Correlation Beggs and Robinson presented an empirical relation for dead oil viscosity based on 460

dead-oil viscosity measurement

110 −= xodµ

where

163.1

)02023.00324.3(10T

xAPIγ−

=

Temperature T is in oF 3. Glaso Correlation Glaso developed empirical relation for dead oil viscosity base on crude oil samples of

North Sea.

( ) aAPIod TE )(log10141.3 444.3 γµ −+=

Where A = 10.313 log(T)-36.447 Temperature T is in oF 4. Kartoatmodjo and Schmidt Correlation In its empirical form this correlation is a combination of all three previous ones and can

be expressed as; )9718.26)log(7526.5(8177.2 )(log()8160( −−+= T

APIod TE µµ Temperature T is in oF Dead-oil viscosity is one of the most unreliable properties to predict with correlations

primarily because of the large effect that oil type (paraffinicity, aromaticity, and

asphaltene content) has on viscosity.

Correlation for determining live saturated Oil Viscosity The original approach by Chew and Connaly for correlating saturated oil viscosity in

terms of dead oil viscosity and solution GOR is still widely used. Most of other

correlations have in fact used the same concept in development of the relationship;

Chew and Connally gave the empirical relation as follows

( ) 21

Aodo A µµ = cp


This correlation is valid for GOR less than 1000 scf/STB. The functional relations for A1

and A2 reported by various authors differ somewhat, but most are best fit equations of

Chew and Connally’s tabulated results

1. Beggs and Robinson Correlation

A1=10.715(RS+100)-0.515

A2= 5.44(RS+150)-0.338

2. Bergman log(A1)= 4.768-0.8359 log(RS+300)

A2= 0.555 + 3005.133

+sR

3. Standing

2)72.2()44.7(

1 10 ss REREA −+−−=

SSS RERERE

A)374.3()51.1()562.8(2 10

062.010

25.010

68.0−−− ++=

4. Al-Khfaji et. Al. This correlation extended the Chew-Connally correlation to high GOR (upto 2000

scf/STB) 40

30

201 0631.04065.05657.02824.0247.0 AAAAA O +−++=

40

30

202 01008.00736.007667.00546.0894.0 AAAAA O +−++=

Where AO= log10(Rs) RS = Solution GOR, scf/STB Correlation for determining live undersaturated Oil Viscosity Oil viscosity at pressure above the bubble point is estimated by first calculating the oil

viscosity at its bubble point and then adjusting the bubble point viscosity to higher

pressure.

1. Vasquez-Beggs Correlation Vasquez-Beggs proposed follwing correlation for determining live viscosity above bubble

point pressure by analyzing 3593 data points

m

bob P

P

= µµ 0

Where


m= 2.6 P1.187 EXP[-11.513-(8.98E-5)p] 2. Abdul-Majeed et. al. correlation

[ ])log(11.12106.510 bPpAobO

−+−+= µµ Where )(log0092545.0001194.0)(log89941.09311.1 2

SAPIAPIS RRA γγ +−−= Gas Physical properties A gas is defined as a homogeneous fluid of low density and viscosity without a definite

volume. Gas occupies the volume of its container without regards to its shape and size.

Knowledge of pressure-volume-temperature relationship and other physical and

chemical properties of gases is essential for solving problems in natural reservoir

engineering. Following section would provide few empirical relations to calculate

important gas properties.

1. Compressibility factor (Z) The compressibility factor is an important variable used to calculate gas density and gas

formation volume factor. To determine this factor Standing and Katz used the law of

corresponding states and came out with a graphical method for determining Z factor

from pseudo reduced pressure and pseudo reduced temperature. The particular graph is

shown below;

This graph is still widely used in the oil industry because of its accuracy and simplicity.

Standing and Katz developed the z factor based on mixtures of hydrocarbon gases with

molecular weights less than 40.However, natural gases often contain non-hydrocarbon


components such as CO2 and H2S etc. At non hydrocarbon gas content values below

5%, there is negligible effect on the Z factor. Higher concentration of non hydrocarbons

gases can cause substantial error when calculating z factor. Wichert and Aziz presented

a simple gas compressibility correction procedure to compensate for the presence of

CO2 and H2S. This method suggests the following adjustment to the pseudo critical

properties used to determine Z factor from standing and Katz chart..

ε−= pcpc TT '

ε)1(22

''

SHSHpc

pcpcpc yyT

TPP

−+=

)(15)(120 0.45.06.19.022 sHsH yyAA −+−=ε

22 COsH yyA +=

Where Tpc=Pseudo critical temperature, oR, Ppc = pseudo critical pressure, '

pcT =corrected

pseudo critical temperature, oR, 'pcP =corrected pseudo critical pressure and = pseudo

critical temperature adjustment factor. Following three empirical equations have been widely used in the oil industry for the

determination of Z factor.

• Hall – Yarborough method

• Dranchuk-Abu-Kassem

• Dranchuk-Purvis-Robinson

These empirical equations require iterative processes to get the z factor. Hence, it is

best used through computer programming. In this section only solution of Hall-Yarborugh

method would be explained.

Hall Yarborough method proposed the following mathematical equation to calculate z

factor;

))1(2.1exp(06125.0 2t

Y

tPZ pr −−

=

Where Ppr = Pseudo reduced pressure T= reciprocal of pseudo reduced temperature, i.e. Tpc/T And Y is the reduced density which is obtained as the solution of following equation;


0)3()2()1(

1)( 423

432

=+−−

++++= XYXYXY

YYYYXYF

Where ])1(2.1exp[06125.01 2ttPX pr −−−=

)58.476.976.14(2 32 tttX +−=

)4.422.2427.90(3 32 tttX +−= X4=(2.18+2.82t)

Procedure followed to solve the equation; Step 1. An appropriate initial guess for Yn is made. Where n is an iteration counter.

An appropriate initial guess is given as

[ ]2)1(2.1exp0125.0 ttPY prn −−=

Step 2: Initial value of Y is substituted in the function F(Y). Unless the initial value is the

correct solution the function will have non zero value.

Step 3: A new improved estimate of Y i.e. Yn+1 is calculated from the following

expression

)()((

'1

K

Knn

YFYF

YY −=+

Step 4; The procedure is repeated several times till absolute value of (Yn-Yn+1) becomes

smaller than 10-12

Step 5: The correct value of Y is then used to evaluate z Correlation for Gas viscosity 1. Lee et.al. Lee et. al. presented a semi empirical equation to calculate gas viscosity. The equation

can not be used for sour gas is given below;

= −

Yg

g XK4.62

exp10 4 ρµ cp

Where )19209/()02.04.9( 5.1 TMTMK gg +++=

gMTX 01.0)/986(5.3 ++=

XY 2.04.2 −=


g = Gas density at reservoir pressure and temperature, lbm/ft3

T = Reservoir Temperature, oR Mg = Apparent molecular weight of the gas mixture 2. Carr et. al. This correlation requires the knowledge of the gas composition and the viscosity of each

component at atmospheric pressure and reservoir temperature

=

==n

jjj

n

JJjj

ga

My

My

1

1

µµ

Where n is the number of component in the gas yj=mole fraction of component j

j = viscosity of component j Mj=Molecular weight of component j EOS Fluid Characterization

An equation of state is an algebraic expression that can represent the phase behaviour

of a multi-component mixture both in the two phase envelope and outside the phase

envelop i.e. outside the bimodal curve. The same EOS can be used to calculate the

properties of all the phase. Phase equilibriums are calculated with an EOS by satisfying

the condition of chemical equilibrium. For a two phase system, the chemical potential of

each component in the liquid phase must be equal to the chemical potential each

component in the liquid phase. A component material balance is also required to solve

vapour/liquid equilibrium problems. Solving phase equilibrium with an EOS is a trial and

error procedure, requiring considerable computation. With the advent of powerful

convergence techniques, nevertheless, solution of EOS has become robust and faster.

Before we deal with the subject on EOS, knowledge of few concepts like equilibrium

constant flash calculations etc. are must

Equilibrium Constant For a multicomponent system, such as petroleum fluids, the composition, pressure, and

temperature uniquely define the system phase behaviour. The equilibrium constant Ki, of


a component i is defined as the ratio of the mole fraction of the component in the gas

phase, yi, to the mole fraction of the same component in the liquid phase, xi

Ki = yi/xi

For a real solution, the equilibrium constant are not only function of pressure and

temperature but also the composition of the hydrocarbon phases. In compositional

modeling, the engineering objective is to determine the physical properties of the

individual gas and liquid phases. Consequently, the equilibrium constants which indicate

partitioning of each component between the liquid and gas phases must be known.

Hence it is appropriate to introduce flash calculation, which is the workhorse of most

EOS application

Two-Phase Flash Calculation The two-phase calculation consists of defining the amounts and composition of

equilibrium phases, given the pressure and temperature, and overall composition. An

inherent obstacle to solving the problem, is not knowing, whether mixture may exist as

single phases or split into two or more phases.

The two phase split calculation (Rachford-Rice procedure) can result in either a solution

yielding equilibrium phase composition or a trivial solution. Even when the results appear

physically consistent, a rigorous check of the solution with the phase stability test may

be required. Mathematically the two phase flash calculation is solved by satisfying the

equal fugacity and material balance constraint with a successive substitution or Newton

Raphson algorithm.

The component and phase material balance constraints state that n total moles of feed

with composition zi distribute into nv moles of vapour with composition yi and nL moles of

liquidwith composition xi

The material balance constraint can be written as

n = nv+nL nzi = nvyi +nLxi

Let FV = vapour mole fraction = )( VL

v

nnn+

Hence Zi = FVyi + (1-FV) xi Additionally , the mole fraction of equilibrium phases and the overall mixture sum to unity


===

==n

ii

n

ii

n

ii Zxy

111

This constraint can be expressed as

0)(1

=−=

n

iii xy

Since ki = yi/xi

H(Fv) = =−=

n

iii xy

1

)( 0)1(1

)1(

1

=−+

−

=

n

i iv

ii

kFkz

The above equation is referred to Rachford-Rice equation. With feed composition and k

values known, the only remaining unknown is Fv . H(FV) has asymptotes at Fv =1/(1-ki).

This can be shown in the following graphs;

Muskat and McDowell proposed a solution to the phase split calculation by assuming Ci

= 1/(ki-1), wher Ci = ∞ for ki=1. They proposed following form of the function H(Fv)

H(Fv) = =+

0iv

i

CFZ

Where +−=

2)( iv

i

v CFz

Fh

δδ

Using modified regula falsi method solution converges for FV.

Having solved for Fv, phase compositions in different phases are calculated as

1)1( +−

=iv

ii KF

zx

FvMin FV Max

H(Fv)


1)1( +−

=iv

iii KF

kzy

The composition calculation requires value of ki at the pressure, temperature, and

composition of each phase. There are several methods to determine phase equilibrium

constants, including use of charts. Recommended way, however, is to determine

through equation of state by rigorously checking for stability by minimum fugacity energy

constraint for individual component.

The need for EOS rose when it was established that the equality of fugacity of each

component throughout all phases to be the requirement for chemical equilibrium in multi

component systems. , The fugacity coefficient iφ is defined as;

∞

−

−

=

≠V nVTii ZdVVRT

nP

RTj

ln/1

ln1,,

δδφ

The fugacity coefficient can, therefore be determined from the above with an aid of

equation of state (EOS). Equation of states is basically developed for pure components.

However by employing some mixing rules to determine their parameters for mixtures, it

can be used for multi component mixtures. The mixing rules are considered to describe

the prevailing forces between molecules of different substances forming the mixtures. It

is the capability of EOS and the associated mixing rules determines the success of

phase equilibrium prediction.

Before deliberating on procedure for determining phase behaviour at different pressure

through equation of state, it would be pertinent here to deliberate on types of EOS.

Equation of States Vander Waal’s first proposed the following equation of state by considering the

intermolecular attractive and repulsive forces;

( ) RTbvVa

P =−

+ 2

Where, a/v2 and b represent the attractive and repulsive terms respectively and v is the

molar volume. As the pressure approached infinity, the molar volume becomes equal to


b. Hence, b is also considered as an apparent volume of the molecules and is less than

molar volume v.

The above equation in terms of compressibility factor takes the cubic equation form; 0)1( 23 =−++− ABAZZBZ Where The dimensionless parameter A and B are defined as

2)(RTaP

A ≡

RTbP

B ≡

Hence Vander Waals type of EOS is referred as cubic EOS. A typical response of Van

der Waals EOS is shown below;

Based on the response equation of state can be divided into two main group: cubic and

non cubic. Cubic equation have three roots when T≤ Tc (Critical temperature) and only

one root when T> Tc. At T=Tc, there are three equal roots.

Following figure depicts the deficiency which most of the cubic equation of state exhibit.

Volume

Tc

T1

T3

Pressure


As can be seen the EOS are poor in predicting the under saturated liquid density.

Whereas, they can predict the gas phase volume and density remarkably well. A number

of EOS has been proposed by different authors. Notable among them are, Peng

Robinson (PR) EOS, Zudkevitch-Joffe modification of Redlih-Kwong (ZJRK) EOS,

Soave-Redlich-Kwong (SRK) EOS etc.. However, none of them can be singled out as

the most superior equation to best predict all properties at all conditions. A number of

comparative studies have, however, showed that certain equations exhibit a higher

overall accuracy.

Peng Robinson (PR) EOS and Soave-Redlich-Kwong (SRK) EOS take the general form

of ;

22 )1( cbcvbva

bvRT

p−++

−−

=

When c=1, the above equation becomes the Peng Robinson (PR) EOS and when c=0, it

becomes the Soave-Redlich-Kwong (SRK) EOS.

22 2 bvbva

bvRT

p−+

−−

= - PR EOS

vbv

abv

RTp

+−

−= 2 - SRK EOS

C

Volume

Tc

T1

T3

Pressure EOS Observed


For pure components, the parameter a and b are expressed in terms of the critical

properties and accentric factor ();

αcaa =

( ) ccac pRTa /Ω=

CT

Tk −+= 1(1α

ccb pRTb /Ω= Let A = ap/(RT)2 B= bp/RT By putting compressibility factor Z= pv/RT, THE general EOS becomes [ ] ( )[ ] 0)21()()1( 23223 =+−−+−+−+−− BBcABcBciBAZcBZZ For multi component system parameters a and b are defined using the following mixing

rule;

−== j

jijji

ii adxaxa )1(1

=i

iibxb

where dij is an empirically determined interaction coefficient. Fugacity coefficient is given by

∞

−

−

=

≠V nVTii ZdVVRT

nP

RTj

ln/1

ln1,,

δδφ

Solving and using EOS results in following general expression for fugacity

++

−−

−−−−−=

BZBZ

bb

a

adxa

BA

BZZbb i

jijjii

i1

2

12

ln)1(2

1)ln()1(ln

δδ

δδφ

T The derivation is complicated and beyond the scope of the training programme. Parameters ba ΩΩ , are determined from the critical condition.

At the critical point, the compressibility factor will have three real and equal roots.

(Z-Zc)3 = 0 EOS c δδδδ1 δδδδ2 ΩΩΩΩa ΩΩΩΩb Zc

Peng Robinson 1 1- 2 1+ 2 0.45724 0.07780 0.307

SRK 0 0 1 0.42747 0.08664 0.333


The cubic EOS yields three real roots in the two phase region. The one having lowest z

factor is taken for liquid fraction and highest is taken for vapour phase. The in between z

factor is discarded.

To make the EOS more reliable in predicting liquid phase volume and densities,

Peneloux et.al proposed volume translation technique. A volume translation technique

modifies the molar volume of the system v predicted by the equation of state as follows;

Vcor = v-c

= ii rxc

cii Btr = ti is the dimensionless individual translation value for each component.

c

cbc P

RTB Ω=

Volume translation is found to have no effect on the equilibrium conditions. Therefore, it

doesn’t alter saturation pressure, saturation temperature, equilibrium composition etc.

However, it will modify the molar volumes, compressibility factors and densities of the

fluid.

Solution Algorithm for Phase Split Calculation through EOS To know the mole fraction of a component “i” in the liquid and vapour phase,

compressibility factor for liquid and vapour at that pressure and temperature is must. To

determine the compressibility factor, Z, in the liquid or gas phase, the appropriate EOS

can be solved either by direct or iterative methods. These equations are cubic equations

that yield a single root in the single phase region and three real roots in the two phase

region. The largest root of the cubic equation corresponds to the vapour phase and the

smallest root corresponds to that liquid phase.

The following is the step by step procedure to calculate equilibrium constant and hence

split mole fraction in vapour and liquid phase;

1. The input data required for this calculation are the system pressure, p, temperature,

T and over all system composition.

2. The flash calculation is initialized by estimating a set of k values for each component

in the mixture.


( )( )[ ]

( )PciP

TTwk ciiOld

i

)/(1137.5exp −+= ---- Wilson Equation

3. With estimated ki value Rachford-Rice equation is solved for Fv, with the search for

Fv always lying between Fvmin and Fvmax.

Fvmin = 01

1

max

<− K

and FVmax = 11

1

min

>− K

4. With the determined value of Fv composition of each component in liquid and vapour

phase is determined. Now the next step would be know whether the determined

phase composition is stable or not.

5. Having calculate xi and yi , cubic equation is solved . [ ] ( )[ ] 0)21()()1( 23223 =+−−+−+−+−− BBcABcBciBAZcBZZ 6. Out of the three roots, the middle z value is discarded. Lowest z value is designated

as liquid phase compressibility factor ZL and highest Z value is designated as vapour

phase compressibility factor, ZV . With the help of ZL and ZV liquid phase fugacity and

vapour phase fugacity is determined.

++

−−

−−−−−=

BZBZ

bb

a

adxa

BA

BZZbb

L

Lijijji

LLi

Li1

2

12

ln)1(2

1)ln()1(ln

δδ

δδφ

++

−−

−−−−−=

BZBZ

bb

a

adxa

BA

BZZbb

V

Vijijji

VVi

Vi1

2

12

ln)1(2

1)ln()1(ln

δδ

δδφ

7. Using fugacity value, new equilibrium constant, k, is determined

Vi

Li

i

iNewi x

yk

φφ

==

8. Following convergence criteria is tested

=

−≤−n

iOldi

Newi

kk

1

122 10)1(

9. If the condition at step 7 is not satisfied. With the new k value the procedure from

step 3 is repeated. Till the condition is met

10. Following three types of converged solution we can get


a. A physically acceptable solution is found with o ≤ FV ≤ 1. When Fv=0 , it

correspondence to bubble point condition, when Fv=1 it correspondence to

dew point condition when o ≤ FV ≤ 1, it corresponds two phase condition.

b. A physically unacceptable solution is found, when FV <0 or Fv>1, when the

calculated equilibrium constant satisfy the equal fugacity condition and the

mathematical material balance equation.

c. A so called trivial solution when k value equals one i.e. xi = yi =zi

The solution “a” is usually correct solution. However, two phase condition stability should

be further analysed with the Gibbs tangent plane criterion for minima of Gibbs energy.

Gibbs tangent plane criterion is very complex and computer intensive and beyond the

scope of this training programme. The trivial solution at c should be checked with phase

stability test to find whether the mixture is in single phase.


Introduction The aim of well testing is to get information about a well and about a reservoir. Once the presence of hydrocarbon-bearing-formation is established and obtained its

porosity, thickness and hydrocarbon saturation. Well test analysis helps to get the

answer of three most important questions;

a. What is the volume of hydrocarbon in the reservoir system?

b. At what rate the available hydrocarbon fluid should be produced at the surface?

c. How much of the fluid can be recovered?

Besides it also provides information about following reservoir parameters;

1. Interwell flow capacity of a reservoir

2. static well pressure

3. Extent of well damage

4. Distance to nearest boundary

5. Detecting heterogeneity with in the pay zone.

Answer to the questions and information of reservoir parameters will establish the

commercial viability of the prospect and is the task of reservoir engineer.

Well test analysis is a branch of reservoir engineering. It uses the pressures and rates

under a standard condition for the determination of parameters which influences the fluid

flow through porous media e.g. permeability, fault, fluid contacts etc. Measuring the

variation in pressure versus time and interpreting them give data on the reservoir and

well.

There are few special pressure transient tests, which, can be used to determine the

areal extent of a reservoir and to estimate the volumes of fluid in place. In case of

composite systems like in-situ combustion, steam flooding or polymer flooding, these


well tests can accurately predict the swept zone parameters, enabling the engineers to

determine the efficacy of the processes. Pressure measurements can also be

interpreted to yield quantitative estimation of the well condition, so the efficacy of

stimulation treatments on well productivity can be evaluated.

Well tests do not directly provide estimates of permeability, well condition, pore volume

etc. Measurement must be analyzed and interpreted using a number of laws of fluid

mechanics to arrive at the desired result.

Diffusivity Equation The fundamental basis of transient flow theory is the diffusivity equation, a differential

equation that must be satisfied when fluid flows through porous body under isothermal

conditions. When Darcy’s law is applied to continuity equation, an equation, which, is

developed from conservation of mass principle, it gets transformed to diffusivity equation

that governs the pressure distribution for flow through porous media. The derivation of

the equation is based on two laws and one equation of state which are;

• Darcy law

pgradk

Vµ

−=

It is assumed that Darcy’s law governs the fluid flow. Darcy’s law is not applicable

macroscopically throughout the flow period. It is applicable microscopically during the

time interval when the various parameters and flow rate can be considered constant.

The gravitational forces are neglected.

• Material Balance

It is assumed that mass of fluid contained in the reservoir volume unit is equal to the

difference between the amount of fluid input and the output during the time interval.

0)( =+∇ OSt

V ρφδδρ

• Equation of State

The gravity of the fluid varies with pressure and the variation is equivalent to the

compressibility of the fluid


Te pC )(

1∂∂= ρ

ρ

The following section will derive first the continuity equation based on material balance.

Before that an attempt is made in the following section to derive a mathematical

formulation of what actually happens in a reservoir when a well is flowed, following

simple model and assumptions are needed. It is assumed that;

• A vertical well of radius rw intercepts a horizontal formation of constant thickness

h and of infinite extent.

• The formation is having uniform porosity φ and isotropic permeability K.

• Constant viscosity .

• Constant total compressibility Ct

• The rock properties are not time dependent.

Under these conditions the flow is radial.

Let us assume two dimensional flow in the x-y plane and consider a control volume of

infinitesimal dimensions shown in fig. below. Let us assume that the dimensions of the

control volume are x and y with unit depth perpendicular to the plane of the paper. Let

us also assume that gravitational effect is negligible here.

Let G be the mass flux and Gx and Gy be the component of G in X and Y direction,

respectively.

The various equations reflecting the conservation of mass principle for the volume

element shown in fig above are;

Outflow= (Gy + xy

yGy δδ )∂

∂ + (Gx + yx

xGx δδ )∂

∂

yxt

δδφρ∂

∂ )(

(Gy + xyy

Gy δδ )∂

∂

(Gx + yxx

Gx δδ )∂

∂

xδ

yδ

yδ

xδ

y

x


Inflow = Increase of Storage = Application of the conservation of mass principle will yield

0)( =

∂∂+

∂∂+

∂∂

tyGy

xGx φρ

For three dimension space this equation can be written as

0)( =

∂∂+

∂∂+

∂∂+

∂∂

tzGz

yGy

xGx φρ

For steady flow the above equation can be written in vector notation as

0=∇G For constant density and no pore volume change in time (G = .v) the above equation

can be written as;

0=∇v Where v is the Darcy flow, normal to unit cross section area of the flow. The above equation is called as continuity equation. The appropriate differential equation is obtained by combining the continuity equation,

the flux (Darcy) Law, and an equation of state. Ignoring gravitational effects Darcy law is

given by

v = - pk ∇µ

Substituting this in the continuity equation we have

typk

yxpk

x ∂∂=

∂∂

∂∂+

∂∂

∂∂ )(φρ

µρ

µρ ---- eqn. (A)

Assuming constant compressibility we can write

xp

cxp

∂∂=

∂∂

)(1ρ

Substituting this in eqn. (A) we get

tp

cyp

xpk

cypk

yxpk

x ∂∂=

∂∂+

∂∂+

∂∂

∂∂+

∂∂

∂∂ )(

)(22

φµµµ

yδ xδ

yxt

δδφρ∂

∂ )(


The above equation is a non linear partial differential equation. If we ignore the second

degree term because of its very-very small value then becomes

tp

cypk

yxpk

x ∂∂=

∂∂

∂∂+

∂∂

∂∂ )(

)(φµµ

This equation is a linear equation provided that is a constant. If K and are constant,

then classical methods of solution can be used to obtain the pressure distribution. The

above equation, under these assumptions can be written as

tp

kc

yp

xp

∂∂=

∂∂+

∂∂

)(2

2

2

2 φµ

The above equation is popularly known as diffusivity equation and defines the movement

of fluid into, out of and through the rock pore spaces. The expression suggests that the

pressure disturbance or perturbation diffuses rather than propagates. Had the

perturbation effect propagated in the reservoir, the expression would have been the

second order differential equation versus time.

In a cylindrical coordinate system, the diffusivity equation is represented as;

tp

kcp

rrp

rrr ∂

∂=∂∂+

∂∂

∂∂ φµ

θ 2

2

2

1)(

1

In a radial system, to which most of practical field solutions are arrived at is given as

below;

tp

kc

rp

rrp t

∂∂=

∂∂+

∂∂ φµ

0002637.011

2

2

in field unit

The term tc

kφµ

0002637.0 is called the diffusivity of the medium. It is a measure of how fast

the pressure perturbation will diffuse in the reservoir.

The same set of differential equation arises in many other contexts, and is not unusual to

obtain solution for flow through porous media by mere change in notation. The notable

other contexts are diffusion, diffusion and chemical reactions, and electrical problems

etc..

The solution of the above equation relies on the concepts of dimensionless pressure and

dimensionless time. The basic advantage of these groups is that they permit us to


understand the structure of the solution of interest without consideration of the specific

values of formation properties, fluid properties, or flow rates. The general solution of

diffusivity equation in dimensionless form is given as

)()(),( 0 DoDDD rsBIrsAKsrp += Where; s is the Laplace transform variable with respect to tD and I0(x) and Ko(x) is the modified

Bessel functions of the first and second kind of order 0 respectively. A and B are

constants.

The line source solution of the above equation in the dimensionless form can be written

as

−−=

D

DiD t

rEp

421 2

Using the following dimensionless factors;

)],([2.141

trppqB

khp iD −=

µ

w

D rr

r =

trc

kt

wtD ∆=

2

0002637.0φµ

Selecting a definition of dimensionless pressure is a difficult task. Basically the selection

depends on the wellbore condition-constant rate or constant well bore pressure.

Commonly used dimensionless groups follow from the seminal work of van Everdingen

and Hurst.

The general expression for pressure which is given as;

( ) )4

(4

,2

ktr

Ekh

qBtrpp ii

−−=−π

µ

The above equation suggests that the whole reservoir is affected due to perturbation

created by flow of fluid. However, the practicality of the above expression lies in the fact

that it used to locate the compressible zone w.r.t time within the reservoir. The pressure

drop in the well mainly reflects the reservoir properties in the compressible zone.


That is what a well test enables us to i.e.;

• characterize the average properties far away from the well

• detect facies heterogeneity

• identify permeability barriers.

• define composite system

Before we delve on further on well test analysis it would be appropriate to define various

regime and type of flows. Based on their boundary condition of the flow the diffusivity

equation has been solved and solution has been provided w.r.t time.

Transient State Condition Transient state which is also named as unsteady state as the condition at which rate of

change of pressure with respect to time at position with in the compressible zone due to

perturbation effect is not zero or constant.

Mathematically it can be expressed as

p = f (r,t)

),( trftp =

∂∂

Both are function of time and distance Pseudo Steady State or Semi Steady State Condition It’s the condition which follows transient state. The compressible zone has reached to

the reservoir boundary (no flow boundary), and due to no support outside the boundary

of the reservoir in the form of fluid influx, the pressure declines linearly w.r.t time.

Mathematically this is defined as

0=∂∂

rp

at r= re i.e. no influx

tConstp

tan=∂∂

for all r and t

Steady State Condition In a steady state condition the pressure at every location in the reservoir remains

constant i.e. it does not change with time

Mathematically this can be expressed as

0=∂∂

tp

for all r and t

p= Pe constant at r= re


Radius of Investigation Since the pressure variation in a well test represents the properties of the part of

reservoir involved in the compressible zone. It is important to locate the compressible

zone and this is what is involved in the concept of radius of investigation. However,

caution should be exercised in finding out radius of investigation due to the fact that

radius of investigation is actually a circular system with a pseudo-steady pressure

distribution hence is not meant for locating compressible zone with in transient state

where pressure p and rate of change of pressure w.r.t. time is a function of time and

distance.

The expression for radius of investigation is given as;

t

i ckt

rφµ

032.0= in field units

Well Bore Storage A well test begins with a change in production rates. Because the flow rate is usually

controlled at the well head, the compressible fluids in the wellbore do not allow an

immediate transmission of the pressure disturbance down to the surface. As a result of

compressibility of the fluid column, inequality in the surface and sandface flow rates

occurs resulting in accumulation of mass in the wellbore. The phenomenon is known as

wellbore storage. This can be graphically shown as below;

For a typical drawdown and buildup tests, the well bore storage phenomenon is known

as unloading and afterflow, respectively. In either case, during the initial stages of the

Well Head Flow Rate

Bottom Hole Flow rate qB

qt

Wellbore Storage Effect

Time


test, there is a variable rate at the sandface which invalidates the assumption of constant

production rate for which the solution of the diffusivity equation has been arrived.

Mathematical model

For a radial and constant flow rate in an infinitely large reservoir the flow model in

dimensionless pressure term can be given as;

D

D

D

DD

DD tp

rp

rrr ∂

∂=

∂∂

∂∂1

Near to the well bore

1][ 1 −=∂∂

=DrD

D

rp

However because of well bore storage effect the expression near to sand face becomes

DrD

D qsfrp

D−=

∂∂

=1][

During the initial stages of well testing, the ratio of sand face flow rate and well head flow

rate from material balance and compressibility factor can be given as;

DD

wDD

wh

sf qsfdt

dpC

q

q=−= 1

where

2

894.0

wt

sD rch

CC

φ=

This makes the dimensionless pressure expression near to the well bore;

11

−∂

∂=

∂∂

= D

wDD

rD

D

tp

Crp

D

In case of a drawdown test, the initially produced fluids are being unloaded from a well

bore with very or no flow at the sand face. That makes 0][ 1 =∂∂

=DrD

D

rp

a sense. i.e.

1=∂

∂

D

wDD t

pC

Integrating and taking logs both side of equality, we get DwDD tpC logloglog =+ in a dimensional form


C

qBtp

24=∆

Significance of the above relation is that, should the early data points (plotted in terms of

coordinates Dplog and Dtlog ) exhibit a unit slope line, then most fluid produced

originates from the well bore. As the test progresses, the sand face rate is significantly

increased the term log pwD increases. As the storage effect diminishes log pwD is

described by the flow equation for constant production rate for a drawdown. For a build-

up similar methodology and expression exists.

Hence, it can be deduced that the deviation from unit slope line marks the end of well

bore storage effect. This is a very important observation for a reservoir engineer, as it

would be possible to devote more on quality data representing solution of flow model.

In a linear plot of del(p) vs. time, slope of the straight line is used to compute well bore

storage effect

i.e.

slope

qBc

⊗=

24

The straight line should pass through the origin. There can be several reasons for it not

to pass through the origin;

• a shut in pressure error

• a shut in time error

t

p∆

End of Well Bore Storage


If such error happens, should be corrected by offsetting the data. However, caution

should be exercised in case of following cases;

• Time duration between two consecutive measurements is very high.

• Variable well bore storage due to gas

• Fluid segregation in the well.

Skin Factor Originally the skin factor response was introduced to incorporate the noted difference

between measured pressure response and predicted pressure response by diffusivity

equation model. The measured pressure responses were usually lower than the

predicted pressure. Van-Everdingen and Hurst suggested that the extra pressure drop

reflects a small region of low permeability (damage) around the well bore. In fact they

are credited for introducing the term skin factor to the oil industry.

Skin factor makes the vicinity of well bore characteristics different from those in the

reservoir as a result of drilling and well treatment operation. It reflects the connection

between the reservoir and the well. The difference in pressure drop in the vicinity of the

well bore can be interpreted in several ways;

• By using infinitesimal skin and is defined by s. If sp∆ is the pressure drop due

to skin

+−

−= 23.3log151.1 2

wt

wfi

rck

m

ppS

φµ in field units

µqB

pkhS S

2.141∆

=

• By finite Thickness Skin

KS

K

rs

rw

Ks


W

S

S rr

kk

S ln1

−=

Above equation shows that damage corresponds to a positive skin, and, improvement in

the flow due to well bore treatment corresponds to negative skin. It should be noted that

the negative value of skin may go upto maximum -5. Reporting of skin lower than this

value would have to be doubly sure by reservoir engineers from model verification.

Secondly, +ve skin are reported in the literature as high as +500. However, it is

cautioned that any value greater than +10 should be doubly verified from model

response.

• Effective Radius

The effective radius method consists in replacing the real well with a radius rw and skin

by S by a fictitious well with radius rws

)exp( Srr wws −=

In case of a gravel pack, the effective radius of the well should normally fall between the

screen radius and the under reaming radius. An effective radius that is less than the liner

radius would mean that the gravel pack is particularly ineffective.

As, could be understood from previous section that the skin represented an additional

pressure drop located in the vicinity of the well bore. The additional pressure drop was

explained for understanding due to variation in permeability in an area near to the well

bore. However, the skin concept could be generalized in more practical aspects of well

bore flow phenomena. For example;

P real

P with effective radius

rS rW

Ks < k


• Skin can be used in representing pressure drop due to partial perforation

• Inclination of a well improves the flow in the vicinity of the well bore, which can be

represented as negative skin.

• It can be used as –ve skin to represent the flow characteristic improvement in

hydraulically fractured well.

• Injection of fluid (water or Polymer) into the reservoir creates a composite zone of

different mobility ratio. It causes additional pressure drop that can also

considered as skin.

• In gas well, Darcy law breaks down at high velocity of flow. At high flow velocities,

pressure drop in porous media increases more than predicted linearly with

increasing rate. This extra pressure drop is accounted for by rate dependent skin.

Interpretation Methods Well test can be effectively used to know reservoir flow characteristics, as the pressure

variation near a well bore reflects the reservoir properties in the compressible zone.

Hence well tests are used by reservoir engineers to know a number of reservoir flow

parameters which decides the exploration, development and exploitation of a reservoir.

A number of different methods are used to analyze a well test. However, they can be

classified broadly into two heads;

• Methods using the Type curves

• Conventional methods.

Inside each of the groups the above methods depend on the type of well, reservoir and

reservoir boundaries

Type Curves Type curves are basically a graphical representation of the theoretical response during a

test of an interpretation model that represents the well and the reservoir being tested.

Most of the type curves are for drawdown well test response.

These type curves first appeared in seventies in the form of sets of curves using

dimensionless parameters. From 1983 on, type curve methods were greatly improved as


they were used in conjunction with the pressure derivative. With the advent of powerful

computers and programming use of Type curve has become very easy to use and

interpret. We would limit the introduction of Type curves only for vertical wells completed

in an infinite reservoir.

There are several kinds of Type curves commercially available. Few notable among

them are;

• Agrawal et. al. Type curve

• Mckinley Type curve

• Earlougher and Kersch Type curves

• Gringarten et. al. Type curve.

However, the most widely used Type curves in the oil industry is that of Gringarten et. al.

curves as they are most complete and practical to use. Hence a brief introduction about

Gringarten et. al. curves and methodology for use is given;

Gringarten et. al. Curves Gringarten et. al. Type curve represents the variation in pressure versus time for a

specific reservoir-well configuration. It is calculated using an analytical model and

expressed in dimensionless variables. In the form of

)],([2.141

trppqB

khp iD −=

µ

w

D rr

r =

trc

kt

wtD ∆= 2

0002637.0φµ

2

894.0

wt

sD rch

CC

φ=


In a vertical well in an infinite homogeneous reservoir the dimensionless pressure

variations depend on three factors: time, wellbore storage and skin. i.e.

( )SCtpp DDDD ,,= with Gringarten using the form below;

))2exp(,( SCCt

pp DD

DDD =

Interpretation Method The interpretation method using type curves involves the following steps;

• The pressure drop with respect to the initial pressure should be plotted on a

tracing paper lying on the type curve, using the same scale as that of Type curve.

Keeping the two coordinates axes parallel, the tracing paper is shifted to a

X axis


position on the type curve that represents the best fit of the measurement. Only

translational movement is allowed keeping the two grid parallel.

• To evaluate reservoir parameters, a match point is selected anywhere on the

overlapping position of the curves, and the coordinates of the common point on

both sheets are recorded. Once the match is obtained, the coordinates of the

match point are used to compute formation flow capacity, kh and storavity

constant tChφ . The specification of the type curve where the measured points

match, they correspond to a value of )2exp( SCD

( )( )M

MD

Pp

qBkh∆

= µ2.141

( )

MD

D

M

Ct

tkhC

∆=

µ000295.0

( )

D

D

CSC

S)2exp(

ln21=

What about Build-up Interpretation Using Type Curve? Types curves were established for constant flow rate production i.e. drawdown. Hence

Type curve analysis for build-up should be done with caution.

In following condition only, type curve should be used to interpret build-up data.

Condition 1: Build-up duration should be very-very small compared to production

duration of the well.

Condition2 : Build-up duration should be smaller than the duration of the last production

period before shut-in.

Other than the above condition, it would be incorrect to use for Build-up interpretation

without incorporating certain changes. The effect of short production time can be seen

in a flattening out of the type curve, the build-up curve under the drawdown curve. Force

match between the build-up data and a draw down curve would result in a type curve

located too high on the set of curves and therefore in inaccurate results.


The most useful method of using drawdown type curves for build-up is Agrawal’s method.

It consists of plotting each measurement versus an equivalent time et∆ as defined below

instead of t∆ .

p

e

tt

tt

∆+

∆=∆1

There is a condition to be satisfied before which this equivalent time can be used in

Gringarten Type curve or any Type curve. The condition is; the semi-log straight line

should have reached during the previous drawdown before build-up.

Advantages of Type Curves lie in the fact that it allows the interpreter to make a

diagnosis about the type of reservoir and understand the flow regimes. It also allows the

interpreter to use the flow concept regime in a conventional interpretation method with

ease and confidence. However, assumption of constant well bore storage effect in a

Type curve puts severe limitation to the interpretation.

Conventional Method of Well Test Interpretation This particular section will study the response of flow/pressure behaviour at constant

rate (drawdown) or when rate is zero (Build up).

Drawdown test The solution of diffusivity equation in the transient pressure regime is given as;

Type curve from Type curve set

Type curve calculated for a shut-in well


+−+=− S

rck

tkh

qBpp

wtwfi 87.023.3loglog

6.1622φµ

µ

Hence, if pressure measured at the bottom of well bore is plotted against log of time, it

would result in a straight line with slope, m

kh

qBm

µ6.162= and

+−

−= 23.3log151.1

21

wt

hri

rck

mpp

Sφµ

This slope m can be used for calculating flow capacity, kh of a reservoir and skin. P1hr is

the pressure at 1hr from the start of drawdown test, read from the straight line equation.

Transient state is of short duration. If the test is extended and the compressible zone is

allowed to travel and reach the boundary of the reservoir, the flow regime changes to

pseudo steady state regime in absence of any support from the outer boundary. The

solution of pressure response in a drawdown test in a pseudo-steady state is given as;

+++=− S

CrA

khqB

thAc

qBPp

Awtwfi 87.0

2458.2loglog

6.162234.02

µφ

The above equation suggests that a plot of pressure against time in the pseudo-steady

state region would result in a straight line whose slope is given as;

hAc

qBm

tφ234.0=

hAφ is nothing but pore volume of the reservoir. If this is represented as Vp, then

mCqB

Vt

p

234.0−= ft3

This particular test is called Reservoir Limit Test (RLT). Point should be remembered

that RLT is valid for only for pseudo-steady state only and not for steady state. There are

different ways to calculate the pore volume in a steady state condition.

Build-up Test: Horner’s Method Most of the information from a well test comes from the interpretation of a pressure

build-up. The reason is the fluctuation in the production rate which is inherent to the

production. Fluctuation may cause large variation in bottom hole pressure during draw

down test. This is not the case in a build-up test. In a build up test, the well is allowed to

flow at sufficiently large time to allow the flowing pressure almost constant.


Subsequently, the well is closed and the continuous recording of bottom hole shut in

pressure is done till the surface tubing shut-in pressure stabilizes.

The equation and analysis method was given by Horner.

The following expression for pressure is given ;

)log(6.162

)(t

tT

khqB

tpp pwsi ∆

∆+=∆− µ

The value of pressure measured at the bottom is plotted versus the logarithm of t

tTp

∆∆+

,

on a graph, once the wellbore storage effect has ended a straight line with a slope of m

can be observed

kh

qBm

µ6.162=

This helps to know the flow capacity (kh) of the well. The thickness h is called the

effective thickness and is obtained by subtracting the noncontributing length from gross

thickness of the formation encountered in the well. Skin is determined from the following

expression;

+−

∆∆+

+−

= 23.3log)log(151.12

1

wt

pwfHr

rck

t

tT

m

ppS

φµ

time

Tp

Pws

t∆


log of t

tTp

∆∆+

is considered negligible while determining skin through Horner’s method

and p1Hr, must be calculated from the Horner straight line at hrt 1=∆

Extrapolated Pressure

If the slope of the Horner’s straight line is extrapolated at t

tTp

∆∆+

=1 (i.e. when ∞∆t ),

the value of the pressure read, is called initial reservoir pressure (P*) in most initial tests,

where amount of fluid produced before shut-in is usually negligible compared with the

amount in place. The idea is that if the build-up would have been continued for infinitely

long time, the pressure would have stabilized to initial reservoir pressure. However,

when substantial amount of oil has been produced, the value of P* is not the reservoir

pressure existing at that point of time, rather this value is used to calculate the average

reservoir pressure. There are conditions, when the value of P* is found to be less than

average reservoir pressure −−

P ! So reservoir engineers should use this value with great

caution and understanding.

Miller Dyes and Hutchinson Method of Build-Up

Horner showed that build-up varies linearly with log(t

tTp

∆∆+

). When Tp >>> t∆ , the

term tTp ∆+ can be approximated as PT . Physically it means that the pressure drop due

to previous production is neglected.


Hence the Horner’s equation becomes )ln(ln6.162

pwsi Ttkh

qBpp −∆−=− µ

This equation was proposed by Miller, Dyes and Hutchinson and the particular method

of build up is called MDH method.

Pressure Shapes and Interpretation Methods in Various Characteristic Boundaries When compressible zone created by the perturbation reaches reservoir boundary, it is

perceived as a characteristic response in the pressure at the well. This nature of the

response in the well bore pressure depends upon the characteristics of the boundary.

Few of the characteristic responses observed in different types of boundaries are

explained below;

Linear Sealing Fault The boundary condition corresponding to linear fault is the linear no-flow boundary.

Linear sealing fault and disappearing facies, unconformities are few of the examples of

the characteristic boundaries. In such type of situation two different straight line

segments are seen with slopes having approximate ratio of 2:1 in the semi-log straight

line. The flow capacity and the skin should be calculated on the basis of first line.

However, P* should be calculated based on the second straight line in case of only one

fault. Flow capacity in both the drawdown and the build-up should be calculated based

on the following data;

m

qBkh

µ6.162=

Skin in drawdown

time

Tp

Pws

t∆

p∆ pMDH∆


+−

−= 23.3log151.1 2

wt

ihri

rck

mpp

Sφµ

Skin in build-up

+−

−= 23.3log151.1

2

1

wt

wfHr

rck

m

ppS

φµ

Gray suggested that the distance to the fault or barrier can be approximated using the

following equation.

t

t

ctk

Dφµ

∆= 0328.0

Where; D = Distance to the barrier or fault, ft K = Formation permeability, mD φ = Porosity, fraction = Fluid viscosity, cP ct =Total compressibility, psi-1

=∆ tt End of first straight line segment, hr If the two barrier/faults are approximately the same distance, the characteristic doubling

of slope will not be seen in the plot. In such case after the initial straight line is seen, the

slope of the second line would increase to more than two times. In such case the second

line suggests presence of more than one fault.

In a type curve the derivative of the slopes goes up from 0.5 to 1.

Pressure Build-up Data from a Well Producing from a Long Narrow Reservoir Such as Channel Sand The pressure transient data collected from a well producing from a long narrow reservoir

as shown below have characteristics that show combination of radial flow and linear flow.

During radial flow the pressure varies as logarithm of time. In a linear flow the pressure

varies linearly with square root of time. The channel can be due to number cases such

as;

1. Two parallel sealing faults.

2. a sedimentary deposit channels.

3. two parallel lateral variations in facies. etc.

w

d


The channel is defined by its width w and by the distance, d, from the well to one of its

edges.

During a well test inside a channel, following characteristics in the pressure patterns are

observed;

• A semi-log straight line with stabilization of derivative at 0.5 is observed.

• As the compressible zone reaches the first edge of the channel, fault effect is

seen. The boundary has exactly the same effect as sealing fault in an infinite

reservoir. The slope of the line doubles. This is observed only when the well is

very off centered in the channel.

• When the compressible zone reaches the two edges of the channel, it expands

linearly parallel to the edges of the channel. The pressure varies linearly with

square root time. Plot of pressure vs. t shows a straight line suggesting of a

channel.

A plot of P vs. ttt ∆−∆+ should be made in case of build-up. If the late time data

becomes a straight line on this plot it along with doubling of slope in radial flow indicates

channel reservoir. P* is determined from the linear plot by extrapolating ttt ∆−∆+

to 0.

Linear flow is used to determine the width of the channel and the eccentricity of the well

The width of linear channel can be calculated by

tch

qBmm

wφ

1

2

638.0= ft :for a oil well

m1 = slope of ( pws vs.

∆∆+

t

tt plog ) psi/cycle

m2 = slope of (pws vs. ttt ∆−∆+ ) q = oil flow rate, STB/D B = oil formation volume factor, bbl/STB H = net pay thickness, ft φ = porosity, fraction Ct = total compressibility, psi-1


)1(

02.2 .1

2 w

avg

Sh

PqTZm

mw

−=

φft :for a gas well

Where

Q = Gas rate, mscf/day T = Reservoir Temperature, oR Pavg = Average pressure in the neighborhood of the well Z = Gas deviation factor Sw = connate water saturation

Pressure Build-up Data from a Hydraulically Fractured Well Natural fractures are distributed homogeneously in the reservoir. Artificially fractures are,

however, located in the vicinity of the well bore. They are created by the operations

carried out on the well. They are an effective technique for increasing the productivity of

damaged wells or wells producing from low-flow-capacity formation.

Fractures can be created both in vertical and horizontal direction. At depths of less than

1000m it is possible to create horizontal fractures. However, at great depths, the

overburden weight makes the fractures develop only along vertical planes.

Flow around an Artificially Fractured Well The presence of an artificial fracture modifies the flows near the well bore considerable.

However because of the short distance extension of the fracture, these fractures have

finite conductivities, unlike natural fractures which have infinite conductivities.

In an artificially fractured well, initially, there is a fracture linear flow. This period is quite

short and is normally dominated by wellbore storage. Flow from the reservoir causes the

matrix to contribute to the flow of fluid to the fracture. This period is featured by linear

flows in both fractures and the formation and the fracture tip still has not affected the flow

behaviour of the well. These bilinear flow regimes are experienced only by fractures of

finite conductivity. Bilinear flow is followed by linear flow. During the start of this flow

period, the flow behaviour starts getting affected by the fracture tip. There is a linear flow

from matrix to the fracture. This flow is very often seen during testing of artificially

fractured wells. Finally, at, long times the pseudo-radial flow is reached by all fractured

systems regardless of the fracture conductivity or damage. The system developed for


the radial homogeneous system is equally applicable for interpreting data of this flow

period, albeit with minor modification.

Flow Model for Each Flow Pattern a. Linear flow in the Fracture The flow exists theoretically at the very beginning of the test. During this flow most of the

fluids produced at the well come from expansion in the fracture. The flow is linear. The

pressure varies linearly with t

The variation can be expressed as

Dxfr

D tC

P ηπ2=

or

ftf

wfi Ckt

whqB

pp)(

128.8φµ=−

Fracture

Xf


where

2

0002637.0

ftDxf xc

ktt

φµ=

η is the ratio of diffusivity inside the fracture and diffusivity in the reservoir.

And Cr is the relative conductivity and is expressed as

kx

wkC

f

fr =

The greater the relative conductivity of the fracture more effective and pronounce this

flow regime is seen on the plot. A fracture with relative conductivity of over 100 behaves

as if it had infinite conductivity. At low fracture conductivity, linear flow regime is not seen.

The concept of relative conductivity explains why the smaller the formation permeability,

the more effective the hydraulic fracturing is.

b. Bilinear Flow It is called bilinear because it corresponds to two simultaneous linear flows;

• an incompressible linear flow in the fracture

• a compressible linear flow in the formation

Bilinear flow lasts as long as the ends of the fracture do not affect the flows. This

flow period occurs only in case of finite fracture conductivity cases and where there is no

well bore storage distortion. In this flow regime, the pressure behaviour is featured by

the linear relationship when data are plotted by using the pw and t1/4 coordinates

4/14/12/ )()(

1.44t

kcChqB

pfWt

irf φµ

µ=∆

The equation suggests that slope of the bilinear plot would lead to the estimation of kfw

and fracture half length. However, it should also be noted that determination of fracture

characteristics by this method requires knowledge of reservoir properties.

c. Linear Flow in the Formation This flow is very often visible during testing of artificially fractured well. It is an integral

part of the conventional analysis methods of these tests. The flow regime occurs in the


fracture itself and in the formation proper. This type flow is exhibited by only highly

conductive fractures (Cr > 100). This flow period if exists, should be used for calculation

of fracture properties. It is characterized by a linear variation of the pressure versus t

The flow is characterized by following expression

DxfD tp π=

or kx

tch

qBpp

ftwfi φ

µ064.4=−

d. Pseudo Radial Flow At long time and end of bilinear and linear flows, pseudo-radial flow regime starts. The

reason why it is called pseudo radial flow is that flow period is not fully radial (Russel and

Truitt). Nevertheless, all curves approach a common value of maximum slope which is

dependent on the length of the fracture penetration. Raghvan et. al. constructed a graph

of correction factors fc , which must be used to obtain the correct permeability factor.

i.e. cH fkk = Russel-Truitt Method of Permeability Determination from Pseudo Radial Flow Russel Truitt method for the determination of true permeability of the reservoir is given

below;

The graph is a plot between R=(Measured slope of build-up data/theoretical slope of

build up data) versus ( Lf/D=fracture length/spacing between wells). A prototype of slope

is shown below and is not to the scale;

Procedure

R

Lf/D

Russel-Truitt Plot for slope Correction


For an oil well, the equation relating fracture length with reservoir test parameter is given

as;

Rch

qBmm

Lt

f φ1

2

638.0=

where

Lf = fracture length (tip to tip), ft M1 = slope of Pwf Vs log t∆ plot psi/cycle for drawdown

slope of Pws Vs log

∆∆+

t

tt plog plot psi/cycle for drawdown

M2 = slope of the pwf vs t∆ for drawdown

slope of the pws vs ttt ∆−∆+ for build up φ = porosity, fraction R = Correction factor from Russel-Truitt plot

Steps to solve: Step 1. : Assume an Lf value

Step 2. : Calculate Lf/D value

Step 3. : From the graph of Russel-Truitt calculate R

Step 4. : Calculate Lf from the equation

Step 5 : The assumed value and the calculated value if found equal gives the correct

value of fracture length. Otherwise, repeat the iterative process.

Step 6: Put the value of R in following equation to know correct value of permeability of

the formation

1

6.162m

RqBkh

µ=

Flow Pattern in a Closed Reservoir When the reservoir is limited by no-flow boundaries it is called closed reservoir i.e. when;

0=∂∂

rp

at r= re i.e. no influx

tConstp

tan=∂∂

for all r and t


The beauty of this pseudo-steady state regime is that it helps to define the drainage area

of a well. Drainage area may be due to;

• physical barriers: sealing faults, disappearing facies, etc.

• production from neighboring wells: The boundary between two wells is

proportional to the pore volume drained by each well

Solution of diffusivity equation in the pseudo-steady state regime is given as below;

)2458.2

ln(21

ln21

22

AwDAD Cr

Atp ++= π

or

+++=− S

CrA

khqB

thAc

qBpp

Awtwfi 87.0

2458.2loglog

6.162234.02

µφ

Where

Ac

ktt

tDA φµ

0002637.0=

A = is the drainage area of the well CA = is a shape factor that depends on the shape of reservoir and

the position of the well in it. A table with shape factor corresponding to different well configuration is shown below;


Method to Calculate Shape Factor As evident from the pseudo-steady state equation, a plot of pressure vs time on linear

scale would result in a straight line with slope mL as shown in the figure below;

The slope ML is used to determine the drainage area or the pore volume drained hφA.

Lt hMC

qBA

234.0=

The value of CA can be calculated in the following way;

[ ]mPPmm

C inithrL

A /)(303.2exp456.5 1 −−⊗=

where,

m is from radial transient flow and mL is determined from linear plot

CA value should be compared with the chart to find out the drainage shape. Determination of Average Reservoir Pressure When the compressible zone reaches real no-flow physical boundaries during build-up,

the pressure in the drainage area becomes uniform and constant. The pressure is called

the average pressure of the drainage area.

Matthews, Brons and Hazebroek (MBH) method

Matthews, Brons and Hazebroek calculated AC

ktt

t

ppDA φµ

0002637.0= for various reservoir

well configuration and plotted against m

PPPDMBH

)(303.2 * −= . One of the plot for

rectangular area is shown below;

Pressure

Slope=ML

Elapsed time

Pinit


Where

tp is the production time

P* is the extrapolated pressure from the semi log straight line

m= slope of the semi-log straight line

A= drainage area.

Steps to calculate average reservoir pressure Step 1: From the known drainage area, tpDA is calculated

AC

ktt

t

ppDA φµ

0002637.0=

Step2 : From the curve shown above m

PPPDMBH

)(303.2 * −= is calculated based on the

reservoir well configuration, which can be known from CA.


Step 3: From known m and P* average reservoir pressure is calculated. Deitz Method to Calculate Average Reservoir Pressure Following steps have been suggested for the calculation of average reservoir pressure.

Step 1: P* is calculated from semi-log staright line.

Step 2.: Vi is calculated based on following equation

TOT

TOTii Q

VQV =

Where,

VTOT can be calculated from geological structure map.

QTOT is the total rate from the sand

Step 3: From Vi area A can be calculate by dividing by average thickness.

Step 4: tDA can be calculated as follows

AC

ktt

tDA φµ

0002637.0=

Step 5: Value of St∆ i.e. start of pseudo-steady state time can be calculated from the

following equation;

DAAS

sp tCt

tt=

∆∆+

Step 6: The value of pressure at St∆ read from Horner plot gives the value of average

reservoir pressure.

P* P


Russel Method for BUP Interpretation Some time well bore storage effect affects or distorts the Horner plot so that we don’t get

the Horner straight line which is characteristic of radial flow. This makes the BUP

interpretation useless. Russel suggested a solution to this problem by following method.

Step-1 : Plot

tC

p

∆−

∆1

1 versus log of t∆

Where )()( tPtpp wfws −∆=∆

Step 2: Vale of C should be chosen such that the plot we get a straight line

Step 3 : Slope of the straight Russel line would give the permeability value.

slope

qBkh

µ6.162=

Step 4: Skin should be calculated as follows

+−

∆−

−= 23.3

)(log

)

11

(

)(151.1

2

1

wt

wfhr

rCk

slopetC

PPS

φµ

Horizontal Well Testing Procedures Horizontal well testing is complex and on many occasions it is difficult to interpret.

Detailed discussion would require an exhaustive treatise. Hence, the discussion would

Correct C

C too small

C too large


be limited to only the fundamentals so that one can apply in solving actual field related

problem. There are four transient flow regimes that are theoretically possible with a

build-up or drawdown test in a horizontal well. They are as follows;

Early Time Radial Flow The flow is radial and is equivalent to that of a fully penetrating vertical well in an infinite

reservoir.

Intermediate Time Linear Flow A horizontal well will generally be long compared to the formation thickness; a period of

linear flow may develop once the pressure transient reaches the upper and lower

boundaries.

Late Time Radial Flow If the horizontal well length is sufficiently small as compared to the reservoir size, a

second radial flow known as a pseudo-radial flow will develop at late times.

Late Time Linear Flow This flow period occurs when the pressure transient reaches the lateral extremities of the

reservoir. The intermediate time linear flow and late-time linear flow period develops only

for reservoir of finite width. The identification of these flow regimes is critical to the

proper interpretation of a horizontal well test.

Pressure Response Equations for Different Flow Regime Early time Radial

+−

=− s

rC

tkk

Lkk

qBPP

wt

yv

yv

wfi 868.023.3log6.162

2φµµ

for Drawdown

+

∆∆+=− 1log

6.162 γµt

tT

Lkk

qBPP

WyZ

wsi for BUP

Where


SrC

KKt

LCtk

KK

hL

wt

yv

wt

x

X

v 869.0227.3log)log(023.2log221 ++

−−

−

=

φµφµγ

Intermediate Time Linear FLow

++

=− )(

2.141128.8Ss

KKL

qBCK

tLh

qBPP Z

Vytywfi

µφµ

for Drawdown

Where 838.1180lnln25.0ln −

⊗−

+

=

hZ

SinK

K

rh

S w

V

y

wZ

+∆=− 3

128.8 γφ

µty

wsi CKt

hLqB

PP for Build-up

Where

+

= 023.2log

6.16223 LC

tk

kkh

qB

t

x

yx φµµγ

Late Time Radial Flow

++−

=− )(

2.141]023.2[

6.1622

SsKKL

qBLC

tkhkk

qBPP Z

Vyt

x

yxwfi

µφµ

µ for drawdown

∆∆+=−t

tT

hkk

qBPP

yx

wsi log6.162 µ

for Build Up

Late Time Linear FLow

)(2.141

2128.8

SSSkkL

qBckt

hxqB

PP zx

vytyewfi +++=− µ

φµ

for Draw down

∆−=− )(

128.8tt

CKhhqB

PPtyx

wsi φµ

for Build-up

Gas Well Testing


The gas well testing differs from a well testing fundamentally. The basis on which the

diffusivity equation was derived doesn’t hold good for gas. Unlike oil, gas viscosity and

compressibility vary widely with pressure. Darcy equation for gas flow can be written as;

pZ

p

rr

TP

khTq

R

Wf

P

P g

w

eSC

scg ∂⊗= µ

π2

)ln(

2

The general trend for Z

p

gµ versus pressure is given as follows;

Region I :

Region I which is less than 2000 psi, the pressure function Z

p

gµ shows linear

relationship with pressure. Hence Zgµ

1 can be taken as constant at low pressure, in

that case

Z

PPp

Zp

g

wfRP

P g

R

wfµµ

22

2−

=∂

Hence Darcy equation for gas at low pressure <2000 psi becomes

( )

)75.0(ln(

703.0 22

srr

ZT

PPkhq

w

eg

wfRg

+−

−=

µ

At high velocity flow Forcheimer modified the above Darcy equation to include the rate

dependent skin

Zp

gµ

P, Psi

I

III II

2000 3000


( )

)75.0(ln(

703.0 22

sDqrr

ZT

PPkhq

w

eg

wfRg

++−

−=

µ

Region II In region II, where the pressure is in between 2000 to 3000 psi the pressure function

shows distinct curvature. In this region, the concept of pseudo pressure should be used.

Pseudo pressure is defined as ;

∆= PZ

PP

gµψ 2

)(

Flow equation becomes

( )

)75.0(ln(

703.0

sDqrr

T

khq

w

e

wfRg

++−

−=

ψψ

Region III

Which is a high pressure region, higher than 3000 psi, the pressure function Z

p

gµ is

constant. Hence

)(2

2 wfRg

P

P g

PPZ

Pp

ZpR

wf

−=∂ µµ

Darcy equation becomes

( )

)75.0(ln(

406.1

sDqrr

T

PPZ

Pkh

q

gw

e

wfRg

g

++−

−

=µ

Hence, while interpreting gas well test data, use of correct type of pressure function

must be remembered.

Absolute Open Flow Potential To know the absolute open flow potential (AOFP) of a gas well is one of the most

important parameter for predicting gas production profile. The AOFP is defined as the

theoretical production flow rate of a well reached with the bottom hole pressure equal to


atmospheric pressure. This measurement is done in the pseudo-steady state region.

Well is allowed to flow through three different gas rates. AOFP is calculated in the

following way;

In the pseudo-steady state region, the flow equation can be expressed as 1. Pressure less than 2000 222

ggWfR BqAqPP +=−

Where

+−= s

rr

kh

ZTA

w

eg 75.0ln703.0

µ

Dkh

ZTB g

703.0

µ=

2. Pressure greater than 3000 2

ggWfR BqAqPP +=−

Where

+−= s

rr

khP

ZTA

w

e

Avg

g 75.0ln406.1

µ

DkhP

ZTB

Avg

g

.406.1

µ=

2

wfRavg

PPp

+=

3. Pressure in between 2000 to 3000 psi 2)()( ggwfR BqAqPP +=−ψψ

Where

+−= s

rr

khT

Aw

e 75.0ln703.0

Dkh

TB

703.0=


AOFP is defined as

B

BAAAOFP a

2

)(42 ψψ −++−=

Composite System In-situ combustion process, steam flooding process, polymer flooding process etc., give

rise to composite system, where mobility contrast exist within the reservoir. A steam

flood or in-situ combustion process is modeled as a two-region reservoir, with an inner

swept region surrounding the injection well and an infinitely large unswept region beyond

the front. Figure below shows a typical composite system.

Mobility contrast which exists in between the region I & II is used to model the fluid flow

in such type of composite system. This acts as basis for determination of the swept

volume using pressure transient model. The swept volume adjacent to an injection well

is considered to have both well bore storage and a skin effect. This swept volume has

different permeability, porosity and compressibility of the reservoir fluid then the zone II

ahead of it. A complication of non uniform temperature i.e. adiabatic condition does arise

while modeling a combustion system or a steam flooding, which is just opposite to the

assumption used for derivation of diffusivity equation. In an in-situ combustion process

the temperature in the region adjacent to the well bore will be that of injected air whereas

near to the combustion front it would be as high as 10000 F whereas, in case of steam

flood temperature adjacent to well bore, the temperature would be that of steam while,

that of farthest away near to outer boundary of the swept region, it would be equal to the

reservoir temperature. The solution to modeling such type of problem is found by

assuming swept region to exist at some mean temperature.

I

II Well Bore

Top View


Modeling of the Fluid Flow in a Composite System In any composite system, as explained in the previous paragraph, there will be swept

region from the injection sand face to the displacement front as shown in fig above.

Region-I will be dominated by the injected fluid which can be steam in case steam

flooding, injected air in case of forward in-situ combustion or polymer slug in case of

polymer flooding. Region-II is the zone representing the zone ahead of the displacement

front.

Modeling of the fluid flow in a composite system includes following assumptions;

1. The formation is horizontal, uniform thickness and is homogeneous.

2. The front is of infinitesimal thickness in the radial direction.

3. Flow is radial, and gravity and capillarity effects are negligible.

4. During the well test (Fall-off or Injectivity test) the front is considered to be

stationary.

5. The region behind the front contains only gas in case of in-situ combustion or

steam in case of steam flooding.

6. The fluid is slightly compressible.

The diffusivity equation derivation methodology is same as that of homogeneous system

as explained earlier while, deriving the expression for homogeneous system. In

dimensionless form, the diffusivity equation for two different regions can be written as

shown in the following paragraphs. The reason why the diffusivity equation is written in

dimensionless form is that, it permits to understand the structure of the solutions of

interest without consideration of the specific values of formation properties, fluid

properties or flow rate. The objective here is to obtain a solution that contains no

parameters.

Region-I

D

D

D

DD

DD tP

rP

rrr ∂

∂=

∂∂

∂∂ 111

--- (1)

Region-II

D

D

D

DD

DD tP

rP

rrr ∂

∂=

∂∂

∂∂ 221 η --- (2)

Where :-


PD1 = )(2

11

1 PPqB

hki −

µπ

& PD2 = )(2

22

2 PPqB

hki −

µπ

211

1

1 WtD

rC

tkt

µφ= & rD =

Wrr

21

=tt c

kc

kφµφµ

η

Eqn. 1 and 2 along with initial and boundary conditions, can be solved analytically in

cylindrical coordinates using, Laplace inverter to generate dimensionless bottom hole

pressure data, Pwd, as a function of dimensionless time, tD. The simulation of Pwf function

against time t shows a semi log straight line on a semilog plot for region – I (Swept

region) followed by a break at the front with another straight line having different slope

for region-II. The semilog slope of the first line as shown in fig below gives an idea

about the permeability and skin of the swept zone.

mqB

khµ6.162=

and

+

−

−= 23.3log1513.1

21

wt

hrw

rck

mPP

sφµ

Where m is the slope and P1hr is the extrapolated pressure at one hour shut-in time for

the semilog straight line. The parameter B, , Ø and Ct corresponds to rock and fluid

properties in the swept volume and rw is the radius of the well.

After the semilog straight line, the system starts to react to the radial discontinuity at a

distance where the front lies or where the mobility contrast is highest. The zone near to

front behaves like an impermeable boundary due to the high mobility contrast. As a

result pressure rises above the semilog straight line as seen in fig above. During the


transition period, the system behaves or approximates pseudo steady state flow as

shown by the Cartesian plot in fig.below . This region of pseudo steady state can be

used to calculate the swept zone rock pore volume. The pore volume is related to the

slope of the pseudo steady state Cartesian straight line as follows;

mC

BIV

t

ga

*

**234.0−=

Where Ia is injection rate, Bg is the air or steam formation volume factor, Ct is the total

compressibility of the swept region and m is the Cartesian slope. The above calculation

of swept region for in-situ combustion or steam flooding is easy said than done. Because,

the above calculation is for isothermal condition whereas, in in-situ combustion or steam

flooding the process is non-isothermal. To solve for the swept pore volume, permeability

and skin formation volume factor Bg and the total compressibility Ct which are

temperature and pressure dependent, have to be estimated from the average pressure

and average temperature of the swept zone(region-I). Once the swept volume is known,

calculation of the fuel concentration for a combustion process or the cumulative heat

loss from a steam flood is possible.

Procedure for calculation of K, s and fuel concentration in a swept zone (In-situ combustion process) The basic procedure is to calculate the average reservoir pressure, temperature and the

swept volume simultaneously. Also the permeability thickness, and skin factor, s, can not

be calculated because the air properties, Bg and Cg are not known until the average

reservoir temperature and pressure is found. The procedure for in-situ combustion

process is explained as given below;

Pressure

Slope=ML

Elapsed time

Pinit


• Plot the pressure and time data on a semi-log and Cartesian plot.

• Estimate the average reservoir pressure behind the front from the early time

flattening of the semi-log plot.

• From the Cartesian slope find out the slope of pseudo-steady state straight line,

m1.

• Calculate dimensionless time, t2θ for in-situ combustion process from the

following formula;

( )

tCh

Kt

bOB

OBb

2

2

)1(

2

−=

ρφαθ

where KOB = overburden thermal conductivity h = Thickness of the pay zone, ft α = Thermal diffusivity of the cap rock t = total injection time bC)(ρ = effective specific heat of the swept region.

• Calculate thermal heat efficiency as follows

+−= )(1

21)( 2

2

22 2

terfcet

ttE t

h θπ

θθ

θ θ

• Assume average temperature behind the front

• Find Bg and Cg.

• Calculate swept volume as follows

g

ga

Cm

BIV

1

=

• Calculate total volume behind the front φV

Vb =

• Calculate the average temperature, −T as follows

rb

faaaF

cah

f CV

TTCFH

tIE

TT))(1(

)()(

ρφ

ρ

−

−+

+=−

• Assume different average temperature and repeat the process till the subsequent

swept volume do not change

• With the value of Bg and Cg calculate permeability thickness and skin


m

qBkh

µ6.162=

+

−

−= 23.3log1513.1

21

wt

hrw

rck

mPP

sφµ

• Calculate fuel concentration

1VF

tIC

aF

am

φ= where FaF is air fuel ratio.

Procedure for calculation of K, s and cumulative heat loss in a swept zone (Steam flood process) An important factor for a steam flood is the amount of heat that has been lost to the

overburden. Knowledge of the steam swept volume from a pressure transient well test

enables calculation of the heat loss. The procedure for the steam flood is simpler than

the in-situ combustion because the average reservoir temperature is known.

• Plot the pressure-time data on a semi log graph and Cartesian graph.

• Find the average reservoir pressure behind the front from early time flattening of

the semi log curve. From the steam table estimate the average swept zone

temperature. Find the slope of the early time semi log straight line. Calculate

the permeability thickness in the swept region

m

qBkh

µ6.162=

• From the semi log graph calculate the skin factor

+

−

−= 23.3log1513.1 2

1

wt

hrw

rck

mPP

sφµ

• From the Cartesian plot find the slope m1 of the pseudo steady state straight line

• Calculate swept volume, V1

g

gss

Cm

BIV

11 =

• Heat loss can be calculated as follows

( )

[ ]swws

Th HHtq

VHE

Γ+Γ−=

)1(1

φρρ

where Γ =Steam quality qs = steam feed water H = Enthalpy


( Hρ )T = Total heat content of the swept zone This brings to an end to the well test concept applied to the in-situ and steam flooding

processes. It is evident from the above analysis that the pressure transient fall off well

test of thermal injection wells based on the above mentioned model produces potentially

useful results. However, it is pertinent to mention here that the accuracy of the result will

depend upon how accurately we identify the transient and pseudo steady state period in

the swept zone. The case mentioned above is an ideal one. Accurate determination of

different region requires derivative analysis of the pressure w.r.t. time.

MANAGEMENT OF OIL WELL TEST After having discovered oil/gas pool, it becomes critical to know reliable information

about in Situ reservoir conditions. A proper understanding of the reservoir and fluid

properties is essential for cost effective and efficient development planning. Having

spent enormous amount on exploratory and a. delineation drilling activity to prove up the

reserves, it is negligible to leave the well without establishing data that will be required

for planning the exploitation of the reserves. There ate numerous cases where operators

have had to reenter or redrill a well or, worse still, have installed ill-designed facilities

and preceded with an uneconomic development as a result of inadequately planned,

insufficiently long, poorly supervised or misinterpreted well tests. It is pertinent here to

note the difference between conventional major fields and frontier marginal fields is that

large capital investment has to be made for frontier/marginal field’s development based

almost completely on exploration and delineation well data. While the conventional field

development cases, the data can be refined in a phased manner using the latest drilling

and production results and for frontier marginal field development cases require a

commitment to spend majority of funds long before any production history is available. It

amounts to that the data obtained from exploration and appraisal wells must be

comprehensive and of the best quality possible.

WELL TESTS GENERAL Well testing is a process used by the petroleum industry to solve problems and answer

questions related to the operations and economic evaluation of hydrocarbon reservoirs

and their associated wells. Two general conditions exist within the industry with respect

to the nature of well testing activities.


One most popular connotation in terms of the type and frequency of test occurrence, is

that a well test is an observation of a well's productivity i.e. production or injection rate as

a function of bottom hole or surface flowing pressure.

The second connotation of well testing, as seen mainly through the eyes of engineering

segment of the industry is that a well test is a definition and quantification of the

parameters which control a well's productivity, i.e. static drainage. area, pressure,

permeability, skin, etc. The advantages of second approach to well testing includes:

The ability to determine the accuracy of a well's observed productivity.

The ability to determine the stability of a well's observed productivity.

The ability to determine the impact of changing the parameters which control the

productivity of a well or an entire reservoir.

RESERVOIR ROCK PROPERTIES Well tests can give reliable estimates of reservoir rock properties such as :

Capacity (Kh) : For predicting well productivity, estimating net pay open to flow,

correlating with core data, predicting reservoir stratification and establishing fracture,

stimulation requirements.

Skin(s) : used for estimating well Bore damage and essential for predicting well

productivity and evaluating stimulation potential and results.

Drawdown (Delta P) : used for defining productivity index of the well and evaluating well

bore conditions.

Production Characteristics: These are needed for production forecasting, designing

well completions and sizing top side facilities in particular the following data is needed.

• Inflow Performance Curve or Absolute Flow Potential: For gas wells essential for

production forecasting.

• Tubing Performance Curve: needed to size production tubing and gathering

system.

• Sand Production: Important in designing production and injection well

completions specifically gravel packs.


• Potential Problems: Waxes, sulphur, scaling, corrosion, and hydrates needed for

designing well completions and facilities.

The types of information available from pressure transient tests along with

economicaJ1y significant benefits of obtaining this information are presented in Tables.

Most of these tests are of productivity observation variety, but could be easily and

economically converted to pressure transient test variety with significant potential value

to the industry.

To recapitulate and summarize what has been talked of in the preceding sections, the

data generated from well tests and their utility is summed up below.

DATA REQUIREMENT AND DATA GENERATED FROM WELL TESTS

Most of the data required for evaluation and valuation of a reservoir would be generated

from well tests. The main data requirement expected from a production test programme

is summarized below with their utility and relative importance of such data.

FLUIDS

It is of utmost importance to identify and obtain representative samples of fluid contents

of the reservoir be they oil, gas, condensate or water. These are needed for geological

modeling, predicting fluid contacts, recovery prediction, and formulation of reservoir

depletion plan, production facility design and PVT behavior of the reservoir fluids.

RESERVOIR BOUNDARIES AND HETEROGENITIES

Comprehensive well test data sometimes can provide valuable information about nature

and size of the reservoir being tested. Specific information obtainable from well tests is

fractures, limit of reservoir like pinch outs, nearby gas cap, nearby faults, nearby aquifer,

stratification and inter-block communication. These are the areas of uncertainty can

usually be estimated by an extended production testing by investigating for several days.

When there is doubt about the size of the reserves, extended production testing is the

only answer to gain confidence on the reserves for development decision.


COST EFFECTIVENESS AND PROPOSED MANAGEMENT OF WELL TESTS

It is frequently impractical and not at all times to get all of the data indicated above owing

to various logistic problems. Certain guidelines as per their rank in importance is

indicated in Table. A technical recommendation and management decision has to be

made as to whether to spend the time and money needed to obtain certain items of

information. The recommendations have to be purely based on the need of the situation.

For instance a reservoir boundary is suspected from seismic and other geological

information which is critical to estimate minimum reserves size needed for development,

an extended test should be considered. It would be difficult to calculate cost

effectiveness for petroleum engineer to quantify the cost of not knowing the correct

reservoir fluid compositional analysis, because this missing data will have an impact on

the recovery predictions. The depletion plan the facilities design and ultimately on the

project cash flow. The development plan may turnout to be either too optimistic or

pessimistic. The facilities accordingly will be either under designed or over-designed.

This situation would result into non-optimization

of exploitation strategy. Now-a-days, sophisticated computer modeling tools are

available which would help ' in checking sensitivity of the project cash flow to certain key

assumptions. This can help to quantify cost effectiveness of obtaining certain data but

will not provide the total answer. The bad development would mean recovering less oil

and gas than what would have been expected but how much and at what cost? Under

these conditions, a judicious decision has to be taken depending on the situation, as to

what data is a must and rank remaining information as needs. Thus meeting the

requirement of cost effectiveness.

The problems arise for testing sour oil/gas wells because of concern associated with

high costs and risks in testing. Normally, there will be reluctance to test these wells even

if they are tested, the duration will be for a short time because the completions might not

be designed to overcome the bad effects,. This situation would result into missing of vital

reservoir information which would result into more assumptions.

TESTING GUIDELINES

Having been convinced of the importance of the data generated from well tests, the

following guidelines are given for obtaining the data through various means.


WIRELINE FORMATION TESTING

The repeat formation tester (RFT) is a well tried and proven testing tool which can

provide valuable information quicker at less time than DST or conventional production

tests. The pressures are very useful in identifying different reservoirs, depletion levels of

the reservoirs and geological zones.

DRILLSTEM AND SHORT TERM PRODUCTION TESTING

It is a short term test conducted in a well. These can be run in open hole under

cemented casing under tubing and permanent packers. Successful well testing in frontier

wells consists of finding the correct balance between two opposing needs - obtaining

maximum collection of relevant data with minimum amount of expensive rig and support

costs.

FLOW AND BUILD-UP PERIODS

Adequate pretest planning is required for estimating number and length of flow and

build-up periods. If log, core, wire line formation test or nearby offset well data is

sufficient, flowing and build-up periods can be specifically specified using fluid flow

equation, i.e. by determining stabilization time. While designing the test period the

following should be kept in mind.

• The time required to eliminate well bore storage effects for both drawdown and

build-up testing.

• The time required for semi-log analysis techniques to be applicable.

• The time when flow conditions change from transient to semi-steady-state,

expected flow rates under both flow regimes and radius of investigations at

different times.

In the absence of any specifically designed tests, the following guidelines are suggested.

Initial flow of 15-30 minutes is required to allow equalization of the filtrate invaded

zone back to static reservoir pressure.

It should be followed by 1.0 to 2.0 hours shut-in to" obtain reliable estimates of

initial reservoir pressure and temperature gradients should be seen.


Clean up period should continue until the tubing head pressures and

temperatures, gas-oil ratios, water rate are reasonable stable.

If high drawdown are required to get intended test rates the choke size should be

progressively increased to safeguard against sand production.

Highly productive zones can be produced at high rates immediately to obtain

high tubing head temperatures to minimize hydrate formation and to accelerate

clean-up.

Clean-up rate should be more than the planned test rates to facilitate opening up

of maximum number of perforations.

The response of the well to choke sizes should be well conceived during clean

up, so that a suitable choke size can be chosen before putting the flow through

separators.

Frequent changes of chokes should be avoided which would make analysis

difficult if not useless.

OIL WELL TESTING

• Three flow periods are ideal to maximize reservoir data if there is time

constraint, two rates may be adequate.

• The drawdown to be created should be up to 40% - 50% of reservoir

pressure.

• At least four hours of stabilized flow rate should be adequate to get reliable

data.

• If specific information is needed like sand failure, casing, etc. the drawdown

should be higher to know the sensitivity of drawdown to sand cut.

• If due to operational constraints, the pressure. Build-up study is not amenable

for Horner’s Method, data should be interpreted by log-log curve matching

technique to get the feel of reservoir properties.

GAS WELL TESTING

Gas well testing should be essentially multi-rate flow tests (4 chokes) to obtain

reasonable estimates of flow performance and rate dependent skin effect.


Flow after flow tests or Back-Pressure tests be preferred if the reservoir

permeability is large.

Modified isochronal be chosen if permeability is low.

The build-up time should be approximately twice the cumulative flow time of flow

and clean up time.

If enough details available the time needed for applying semi-log analysis

technique can be applied.

If possible, the well should be dosed-in down hole to minimize well bore storage

effects.

CONCLUDING REMARKS

Well test engineering is the process of successfully deriving useful valuable information

from well tests in the form of problem diagnosis and or reservoir valuation. The tasks

required to perform well test engineering can be grouped into three categories:

l. Planning and Designing

2. Monitoring and Control

3. Interpretation and Diagnosis.

These activities have to be carefully and judiciously planned, executed and Interpreted,

the task of finding a model which adequately represents the physical situation existing in

the wells and reservoirs being tested and quantifying the parameters which are critical

parameters in planning,

development, predicting reservoir depletion and managing the reservoir during the

producing life to get best out of the reservoir.

To conclude, well tests would be able to generate very useful information by which the

"Definition" and "Evaluation" of the reservoir could be accomplished in a very meaningful

manner thereby leading to draw a rational development strategy. As it is amply clear that

reservoir is unbelievably complex and impossible to define completely, to arrive at a

diagnosis of the system, one has to rely on –

A few physical deterministic facts.

Production statistics often of doubtful reliability.


Samples representing approximately one billilanths of the reservoir.

Statistical averaging techniques (often misapplied)

Stylized mathematical equations derived from assumptions which may only remotely

represent reservoir conditions. Because of tilt: above limitations, the results of the

reservoir engineering calculations would be of probabilistic nature. It should be the effort

to get as much as

Deterministic values, so the assumptions would be fewer. To work in this direction and

achieve the objective of accomplishing more reliable and maximum data, properly

planned well tests is the only answer. Whatever data that is considered for defining and

evaluating the reservoir, should bear reality so that the success of the venture would not

be jeopardized.

RESERVOIR FLUID SAMPLING

OBJECTIVE OF RESERVOIR FLUID SAMPLING:

Objective of reservoir fluid sampling is to get oil & gas in the same composition and state

in which it exist in the reservoir. The specific procedure used to obtain representative

fluid depends upon the composition of fluid, its state and the mechanical equipment

used at well site. Obtaining a proper sample is as important as subsequent laboratory

tests, yet a few engineers understand the advantages & the limitations of the several

methods that are commonly used in the sample.

It may be well to consider several general facts involved in getting sample of oil & gas

that are representative of reservoir fluids. In the first place there is no assurance that any

sample obtained from one well is representative of the fluid throughout the reservoir.

Theoretically the effective gravitational force of earth causes differences in composition

of oil lying at different elevations within a reservoirs (compositional variation due to

gravity segregation). Also, the reservoir fluid may vary in composition between the

locations having same structural elevations because of moment of rock strata

comprising the reservoir during geologic time. Both kinds of compositional variation have

been observed in oil field. When reservoir is relatively small if properly taken sample

from one well can be representative of entire reservoir but if the reservoir is large and

complex, samples from several wells may be required. Large variations in fluid


composition often occurs in a very thick formation, in areally large reservoirs or in

reservoirs subject to recent tectonic disturbances. A fluid sampling program is therefore

to be planned to collect sufficient reservoir fluid samples from different area alongwith

trapping depth in reservoir to know the fluid’s behaviour in the entire reservoir. When

the objective is to obtain sample of original reservoir fluid, it is important to take sample

in the earliest production life of the reservoir or atleast before the formation pressure has

dropped below the reservoir fluid’s saturation pressure.

The other important thing is to know to what extent the fluid in the tubing is

representative of reservoir fluid in the region of the well being sampled. This is very

important factor because all the methods make use either directly or indirectly of fluids

obtained from the well tubing. Two reasons why the fluid flowing in the tubing might not

be representative of reservoir fluid are:

1) Dual completion and simultaneous production of fluids of different zone from same

string.

2) Presence of liquid and gas in intimate contact in the same zone may result in two-

phase flow and result into non-representative sampling.

CONDITIONING OF THE WELL FOR SAMPLING:

The objective of well conditioning is to replace the non-representative reservoir fluid

located around the wellbore by displacing it into the well with original reservoir fluid from

the more distant parts of the reservoir. Simply shutting-in the well to restore the pressure

around the well bore will not necessarily bring the fluid in the affected area to its original

condition or composition. It is necessary to flow the well at a low flow rate to allow the

altered oil to be displaced by representative reservoir oil.

Conditioning the well before sampling is almost always necessary and is especially

important when the reservoir fluid is saturated at prevailing reservoir pressure. This is

because the reduction in pressure around well bore, which results from producing the

wells, can alter the fluid composition before it reaches the well bore and well string.

• Conditioning of flowing oil wells:


To collect representative reservoir fluid from a selected oil well it is necessary that the

well should be new with minimum gas saturation and should not be producing free water.

Before collecting the sample it is necessary to see that the well is producing with the

flowing bottom hole pressures much above the saturation pressure so that there is no

change in the state or composition of in- place oil. A flowing well must be subjected to

reduction in flow rates by a multi-bean test (by systematic reduction of bean sizes). A

stabilized oil & gas rates, water-cut and bottom sediments should be recorded with each

bean.

When the gas-oil ratio remains constant after the first reduction in flow rate bean size),

flow of an undersaturated oil into well bore is indicated. This means that there is no

change in phase state and composition of in-place reservoir oil entering into tubing. In

this event the well can be considered to be conditioned.

When gas oil ratio decreases after rate reduction, the presence of the gas saturation in

the formation around wellbore is indicated. The gas saturation can results from a) coning

of gas cap gas into oil bearing formation around the well bore; b) flowing bottom hole

pressure being less that saturation pressure. In this condition the well is conditioned by

reducing the producing rate by stages. The stage-wise reductions in flowing rate is

continued until minimum stabilized GOR is reached and when further reduction in rate

do not affect the gas oil ratio this indicates that the non-representative oil around the

wellbore has been replaced by representative in-place oil flowing in from a greater

distance in the reservoir and the well can be assumed as conditioned for sampling.

When the gas-oil ratio increases after rate reduction, the simultaneous production of a

gas from a gas bearing zone and oil from an oil-bearing zone is indicated. The increased

gas-oil ratio could be caused by subsidence of an oil zone. Although a representative

sample of the reservoir oil can often be obtained, it is better to use a well which does not

indicate oil coning, because it is difficult to determine when the well is adequately

conditioned.

• Conditioning Gas-Condensate wells:

The procedure for conditioning a gas-condensate well prior to sampling is based upon

interpreting the changes in the gas-condensate ratio that result from reducing the

producing rate in a series of steps. When the pressure on a gas – condensate type fluid

is reduced below its dew point pressure, a liquid phase is formed. As a result the vapour


phase, which is the fluid produced, will have a lower concentration of condensable

hydrocarbon. This loss of condensable hydrocarbon results initially in an increase in the

producing gas-oil ratio. Since the largest part of the pressure drop occurs in the area

close to the wellbore, retrograde liquid saturation in that area can build-up enough to

allow the liquid to become mobile. This mobile liquid can cause unpredictable but

significant short-term changes in the gas-condensate ratio to accompany changes in the

producing rate.

The well is conditioned by placing it on a producing schedule consisting of a series of

successively lower rates. After each rate reduction, flow is continued until the gas –

condensate becomes stabilized. The trend of the stabilized gas-condensate will

generally be found to decrease as the rate is decreased. The well is considered to be

conditioned when the stabilized gas-oil ratio does not change when the producing rate

changes.

• Conditioning wells producing a near critical fluid:

The reservoir which contains a near critical reservoir fluid presents specially difficult

problems in well conditioning. When the pressure on this type of fluid drops below

saturation pressure, usually both of the phases which form are mobile and therefore,

flow the well. The rates of production of the two phases, however, are usually in the

production that results in a well effluent which is not the same as the reservoir fluid

composition. The well effluent can contain either too much or too little gas in combination

with the liquid hydrocarbon phase.

Conditioning the well is accomplished by flowing at a succession of slower rates for the

purpose of removing the non-representative hydrocarbon phases. The problem lies in

determining when the non-representative fluids have been produced. Production from

near-critical reservoir, however, often will exhibit a relatively small change in gas oil ratio

even though the well effluent has undergone significant changes in composition. When

early production information indicate a near-critical reservoir field, sampling should be

conducted as soon as possible after the well has been completed. Samples taken after

the reservoir pressure has declined only a small amount below original saturation

pressure are in many cases, virtually useless for determining the original reservoir fluid


properties and cannot be used in laboratory tests designed to predict fluid properties at

later stages of reservoir depletion.

FLUID MEASUREMENTS DURING THE WELL CONDITIONING:

Well conditioning involves bottomhole pressure and temperature measurements and

repeated measurements of tubing pressure and temperature, the rates of oil, gas &

water flow through the separator, separator pressure & temperature, stock tank oil

production and bottom sediments & water production rate.

SAMPLING TECHNIQUES:

There are essentially three sampling techniques for obtaining reservoir fluid samples for

analysis of pressure, volume and temperature (PVT ) relations.

These are commonly known as:

1. Bottom hole sampling (Sub-surface sampling)

2. Recombination sampling (Surface sampling)

3. Split-stream sampling (well head sampling)

• Sub-Surface Sampling Method (B.H.S.method)

The sub-surface method consists of lowering a sampling device, usually called a

“ Bottom Hole Sampling” down the well to a pre-selected depth. A sample of the fluid at

that depth is trapped in a pressure tight section of the sampler. The sampler is brought

to the surface where the sample is transferred to a suitable container for conveyance to

the laboratory.

Different types of sampler used for bottom hole sampling are:

1) Ruska Subsurface Sampler

2) Flopetrol type sampler

3) Leutart type sampler

4) Kuster type sampler

5) Oil-Phase single phase bottom hole sampler


After the well has been conditioned for subsurface sampling, the location of water level

will be estimated by plotting the pressure as determined from the pressure survey,

versus depth and sampling point will therefore be selected, steps towards well

preparation must be followed prior to the performance of sampling routines. The

procedure for preparing the well indicates that it should have been producing with a

stabilized gas oil ratio. It also suggests that the well be as new as possible, so as to

minimized free gas saturation.

Three representative bottom hole samples of 600 cc should be trapped. A schematic

well testing and sampling diagram of an oil well is given in Fig.1. As per schematic

diagram the subsurface samples are trapped after shut-in gradient survey. The gradient

survey indicates the oil-gas and oil-water contacts in the tubing. After the gradient survey

the samplers are lowered upto the desired depth and samplers are trapped by Crack

Opening process to get the most representative samples. Duplication of samples is

always recommended for comparison purpose and to provide one good sample if the

container leaks during transportation. It is recommended to trap three samples at a time

for better accuracy.

• Surface Sampling Method:

This method is generally satisfactory for nearly all types of reservoir fluids. It is based on

the fact that when the well is producing in a steady state flow condition, the fluid at the

surface condition is representative of the fluid in Bottom hole condition near the

perforation. Therefore, the sampling can be carried out at the surface.

It consists of taking samples of equilibrium oil or condensate and gas from conventional

field separator while making accurate measurements of separator oil and gas producing

rates, which prevail at the time of sampling. One separator is usually used but when

multistage separator is used the samples are collected from the high-pressure separator.

The separator gas and oil /condensate samples are subsequently recombined in

laboratory to produce the reservoir fluid and the accuracy of field gas-oil ratio or gas-

condensate measurements as the case may be. The oil/condensate and gas samples

should be taken at the same time to ensure that the separation parameters did not


change during sampling. The recombination method of sampling is as good as the

bottom hole sampling techniques for reservoirs where flowing bottom hole pressures

exceed the bubble point pressures in case of oil reservoirs.

• Split-Stream Sampling Method

The split-stream sampling method is primarily used in sampling of gas condensate wells.

A smaller diameter tube is inserted in the middle of flow stream. Part of the flow is

diverted to this tube into either an auxiliary separator or sampling bottles. In most cases,

this sample is obtained by inserting the tube in the tubing to a depth of 8 or 10 ft below

the surface or the flow stream just upstream of the separator. The split-stream method of

sampling loses its accuracy with high liquid content fluids. It is difficult to ensure the

proper entry of gas and liquid into the sampling fluid for high flowing liquid-gas ratio.

WIRELINE OPERATIONS & SURFACE HOOKUP Basically the surface hook-up consist of the following:-

1. Lubricator Assembly complete with stuffing Box.

2. Blow out Preventor

3. Miscellaneous items such as Floor blocks, Weight Indicator, Line Wiper,

Tool Trap etc.

STUFFING BOX AND SHEAVE WHEEL The wire is passed over the stuffing box

sheave and through packing in the Stuffing box. These

stuffing boxes are composed of a steel body with a quick union at the lower end and

packing

at the upper end. A pulley support of strong

light alloy is mounted on low friction bearings

and can turn 3600 around the stuffing box axis.

A large diameter pullet, which reduces fatigue

Stress in the line, revolves on a double ball

Bearing.


To Thread the wire initially through the packing, the following procedures should be

followed:

• Thread the blow out plug retainer, blow out plug and then the packing.

• Place the packing, blow out plug and plug retainer into the stuffing box.

• Pull approximately 10’ wire and cut before threading the stuffing box for normal

use.

Make up the plug retainer not to compress the packing around the wire in the

stuffing box. Adjustments may have to be made during the course of operations.

LUBRICATOR ASSEMBLY

Lubricator assembly for normal operations consist of three

sections of 8 feet each joined by self aligning unions. The top of this

lubricator riser has a self aligning unions to accommodate stuffing

box and at the bottom to connect with 3 ¾” O.D. lower riser sections.

One release valve is attached at the bottom section. The lubricator

clamp is fastened approximately 1/3 of the way up the centre

section. The wire line clamp is fastened to the lower end of

lubricator.

TOOL TRAP

Tool trap is placed between well head adopter and B.O.P. It prevent the tool loss during

any snapping of the wire line in the lubricator during pulling out process.


BLOW OUT PREVENTOR

The BOP is hoisted by means of block and tackle suspended from the Gin pole and

lowered into position on the tree connection. Manually operated or Hydraulically

operated B.O.P.’s are available. The blind rams pressed against the piano wire

sufficiently to seal off any pressure below the rams. If need be, pressure can be

equalized above and below the rams. It is important that the two rams be operated

simultaneously.

TELESCOPING GIN POLE

Gin pole is used to raise the lubricator to the top of the wire line B.O.P. maintaining this

position while “breaking off and making up” operations. It is very important that the gin

pole be

I. Securely fixed at bottom.

II. Be properly bound to the tree with load binder and chain.

III. Kept vertical all times.

Rope blocks and rope are used to obtain the mechanical advantage to lift and lower the

lubricator with ease. For a mechanical advantage of 3:1 or 4:1, normally a block of two

pulleys is used.

LOAD CELL: The load cell senses the weight of the "pull" which includes the combined

weight of the suspended Wireline in the well, the tool string and the "drag". These can be

used with UNITED 's Gauges and measuring meters.


WEIGHT INDICATORS:

During wire line jobs, it is necessary to load the measuring line to its maximum safe load.

Among the various types that have been developed are:

• Mechanical

• Hydraulic

• Electronic

These instruments are calibrated in pounds and indicate the total load or line tension at

the point on the line which actuates the weight indicator. On the downward trip, the

weight indicator should be watched for the following reasons:

• Indicates weights of the tools and wire in the hole until fluid level is passed when

there will be slight lessening of weight and also a definite reduction in velocity.

• Fluid level in tubing can be ascertained.

• Complete loss in the weight indicate the following:

1. Parted wire

2. Indicator failure

3. Running into an obstruction in tubing.

The Gauges registers the weight as sensed by the Load Cell and available in

following scales.


English Metric 0 to 2,000 lbs 0 to 1,000 kg 0 to 4,000 lbs 0 to 2,000 kg 0 to 6,000 lbs 0 to 3,000 kg 0 to 10,000 lbs 0 to 5,000 kg

FLOOR BLOCK or HAY PULLEYS :

Floor block is necessary to bring the measuring line down to a position where it may be

handled with ease (Horizontal) from the tree to the wire line unit as well as bringing the

point of pull from the top of lubricator to the base of the lubricator. These are available in

following sizes.

• 7-in. Sheave

• 12-in. Sheave

• 16-in. Sheave


WIRE LINE CLAMP:

The wire line clamp is used to clamp the wire line without damage while raising or

lowering the lubricator or may be used during fishing operations to hold wire showing

through the B.O.P.

MEASURING DEVICE:

One of the very important wire line accessories that is always used when performing any

type of wire line work is the measuring device. The reasons for its importance is that

operator must know the location of his tool with relation to the well head. The lubrication

of the tool as it approaches the well head when being pulled out is of utmost importance

so that operator can slow down its speed and bring it to a stop before running into well

head stuffing box, possibly breaking the measuring line, resulting into a fishing job and

perhaps damage the down hole equipment.

A very common design of mechanical device that has proved very accurate, rugged and

reliable is one in which the line is held in slippage free contact with an accurately ground,

hardened measuring wheel driving a counter or odometer which registers in linear units

the length of measuring line which has contacted the measuring wheel. The measuring

device is normally mounted on a movable support so that it is free to move vertically

and laterally guided by the measuring line as it is unspoiled from a reel on its way to the

well head.


WELL HEAD ADOPTER Well head adopter is placed over the X-mas tree by

removing of the bull plug. Lower end is compatible

with flange of the tree & threaded portion facilitate

the connection of B.O.P. or lubricator by hand union

connection.

WIRE LINE TOOLS

The wire line tool string is necessary for sufficient surface control of the running, pulling

and operation of the down hole tools. They can be on solid steel measuring line. As

assembly of tools is used to deliver surface controlled impact either upward or downward

to lock or unlock controls set in the well.

The wire line tools are means of:

• Attaching the subsurface controls to the wire line socket.

• Adding the weight required to sink the tools in different gravity well fluids with the

stem.

• Securing a hammering effect with jars.

• Obtaining flexibility through the knuckle joint.

• Attaching the required running or pulling tools.

Wire line tools generally consist of :

Rope socket, Stem, Jars, Running or pulling tool, Paraffin scratcher and cutter,

Impresson block, Go devils, Hydrostatic baler, Spear or wire retriever, blind box.


ROPE SOCKET: 1 ½” rope socket is designed to connect the slick line 0.092”, 0.082”

to the down hole string. The following procedure is recommended

for tying knot.

• Take the wire already threaded through stuffing box. Pull

the wire by 15 feet to enable plenty of wire to work

with(Ensure to kink or sharp bend occurs)

• The rope socket body, spring and then thimble are threaded

onto the wire.

• The spool is then held firmly in vice or clamp

• The free end is then passed behind the spool and tension is

held on the main wire.

• The free end is then wrapped tightly around the tensioned

end until 8 -10 turns are made.

• The erection of wrap should be suddenly reversed and free

end turned from side to side till fatigue effect breaks off

close to the knot.

• The knot is complete, pull the wire through the rope socket until the spring,

thumble, spool are uptight inside the body.

STEM

(Roller Stem)

Lead Filled Stem


The wire line stem is supplied in three different lengths of 2’, 3’ & 5’. The function

of the stem is to add a moving mass to accurate the action of jars. The effectiveness of

the impact delivered by the jars may be increased by increasing total weight of stems

used. The stems is available in three different category as per the need of the

operations.

• Solid bar stem.

• Roller stem.

• Lead filled stem.

HYDRAULIC JARS

Hydraulic jars are designed for upward jarring. The impact of the stroke is

proportional to the strain of the wire line and to the weight of the stem used. Since

hydraulic jar do not permit, downward jarring, mechanical jars are run in conjunction with

hydraulic jars. Hydraulic jar is placed between stem and mechanical jars.

MECHANICAL JARS Mechanical jars are of spang type or tubular type. The jar utilizes the weight of the stems

connected immediately above it to deliver effective jarring impacts to the tool or

equipment below it . The jarring impact can be delivered both upward & downward. The

effectiveness of the impact largely depends on the weight of the stem and length of the

stroke used: however the size and straightness of tubing, size and depth of tool, density

and viscosity of fluid in tubing, well pressure are factors must be considered. Tubular

jars are mainly used during fishing for wire lost in the hole.

KNUCKLE JOINT


Knuckle joint has a ball swivel action in its mid section. Its purpose is to provide flexibility

to the string of tools and also to enable the tools to pass through crooked tubing or

deviated well. The knuckle joint is usually placed below the jars. In extreme crooked

tubing, knuckle joint may be used in between stem and jar and also below the jar.

PARAFFIN CUTTER: Paraffin cutter is circular at base with a sharp cutting edge and is primarily used to

remove paraffin and scale deposits from the tubing wall. The outside diameter is tubing

drift and can be used to gauge tubing. Paraffin cutter is lowered after allowing the well to

flow through choke. The tool allows wax to flow through when cut from the walls of

tubing.

PARAFFIN SCRATCHER:

Paraffin scratcher is usually a 5/8” rod with small hole spiraled around the rod so that

wire may be inserted horizontally to ensure that the walls of the tubing are clean and full

gauge, the paraffin cutter is run after the scratcher.

IMPRESSION BLOCK:

Impression block is simply a lead filled cylinder with a pin through the leaded section to

prevent loosing the lead. A downward tap against fish will give an impression of the fish

top. This impression helps operator to identify the type of the tool to be used for fishing.

Be sure impression block is made with one pouring of lead. When no imprint is made on

lead, it is assumed that the blocked section in tubing is sand.

SETTING UP OF WIRE LINE UNIT

On arrival at the well, the unit should be positioned in the following manner:

• The operator must be able to see the stuffing box and floor block from wire line

unit controls.

• If in truck mounted unit, the truck should be braked and substantial chocks

should be placed behind the rear wheels to prevent movement of unit while in

operation.


Once the rope socket is made and lubricator sections are assembled, string of tools are

connected and passed through the bottom end of the lubricator so that tool top is visible

at the other end of lubricator. The rope socket is made up on the tool string. Any free

wire between the rope socket and stuffing box is then drawn carefully back through the

stuffing box until the self aligning union can be made up to join the stuffing box to the top

of the lubricator( at no stage wire should get crimped or bent). The wire is then brought

out side the lubricator and clamped.

Gin pole assembly helps in hoisting the lubricator on top of the BOP. The Gin pole

assembly is mounted in the following ways:-

Ensure first that the telescopic section slide freely within one another.

Make sure that the pulleys and hoisting rope are unraveled and ready for use.

Hook the top pulley back to the eye in the top section of the Gin pole.

Place the Gin pole in the vertical position ensuring that the base of the Gin pole

is resting over any of the nuts in the cross flange. Gin pole should not obstruct

operation of any valve.

Then it must be securely chained and boomed.

The Gin pole is then extended ensuring that the extended sections are securely

pinned to prevent sudden retraction when loaded with the lubricator weight.

The lubricator pulley should be maintained at ground level and then connected

to the clamp in the lubricator.

The lubricator complete with stuffing box and tools is then hoisted by pulling the free end

of the rope. The lubricator is hoisted to its vertical position above the BOP next the floor

block is shackled to the weight indicator transducer. The weight indicator transducer is

chained securely to the tree. The floor block should be close to the foot of tree.

With the floor block in place, the wire is passed through it and the wire is tensioned by

wire line unit taking up the slack wire. The wire line clamp is removed carefully. The bore

of the lubricator is then pushed off centre by the helper so that the gentle release of the

break on the unit will lower the string to the tubing hanger flange and odometer on the

unit is made Zero-Zero.


The tools for the particular wire line job to be under taken are attached to the bottom of

the standard string of tools. The complete set of the tools are raised into the lubricator

and the end of the lubricator is lowered into the top of BOP and self aligning union is

made up. The bleed valve is slowly opened ensuring no sudden pressure surge is

placed in the lubricator. When the pressure is equalized between tubing and lubricator,

the master valve can be opened rapidly. At this point high lubricating oil is applied to the

wire on the spool and also the wire leading up to floor sheave- this lubricates the stuffing

box packing facilitating easy passage of wire.

At this point weight indicator should be adjusted to Zero. Going down the hole should be

steady, keeping watchful eye on weight indicator. The unit should be braked immediately

at the point of any obstruction so as to avoid coiling up or kink in the wire. The weight of

the string of tools should be accurately noted before latching on any fishing neck in the

mandrel or D-nipple. Loss in weight or gain in weight gives an indication whether the

equipment is set in the nipple or retrieved out of the nipple. Any substantial loss in

weight is alarming as it indicates loss of complete or part of the string of tools.

WIRELINE WINCHES

Wire line winches generally use the hydraulic circuit and are packed in two separate

sections. One skid contains wireline reel and controls, and other section diesel engine,

hydraulic pump and tanks. The hoses with quick couplings connect the two sections.

To operate the unit proceed as follows:

1. Place control valve in stop position.

2. Move reel select lever to the front or rear position as desired.

3. Shift 4-speed transmission to desired gear.

4. Release the brake lever from reel being used.

5. Control forward or reverse movement of the selected reel by mean of reel

control valve.

6. Adjust tension on wireline by means of system pressure knob on panel. This

relief valve can be set at a low pressure and then the wireline can be fed into

the hole which operator maintains the control valve in “up” position. The control

valve works as an effective brake system and the operator can slowly increase

the system pressure setting as more wire feeds into the hole.

7. Adjust engine throttle to suit load conditions.


Truck Mounted Wire-line Unit


• Slick line units designed and built for all sizes of wire such as 0.082", 0.092",

0.108" and 3/16" diameters.

• Steardy pipe cage with compact and heavy-duty base skids and suitable lifting

eyes.

• Line speed available from 2700 ft/min at surface to 1200 ft/min. at 20,000 ft.

Also, line pull available from 2800 lbs at surface to 5500 lbs at 20,000 ft.

• Smooth and reliable hydraulic open and closed loop system as per customer's

choice.

• Level wind feature allows the operator to guide incoming line evenly on the reel.

• Pressure compensated hydraulic control to maintain the drum R.P.M. at varying

loads.

• Precision RPM control from the operator console.

• Pressure compensation feature which ensures that line speed will remain same

regardless of changes in load.

• Isolating valve in the suction line for trouble free maintenance.

• Suitable relief valves provided in the hydraulic system to avoid accident.

• Fail safe break to stop the drum automatically in the event of any failure in the

hydraulic system or engine shut down.

• Triplex roller chain drive for smooth transferring of power to the reel drum.

• Single lever system for raising, lowering or stopping in the well if required.

Positive breaking of wireline tool is effected when the operation lever is in

neutral position.

• Lock system to keep drum in steady position for long time in lowered condition

of instrument.

• Quick release coupling for easy mounting of hydraulic hoses.

• Dual brake band to act on both sides of the drum which can be operated by

hand or by foot as the convenience of the operator.

WIRELINE SERVICE TOOLS

PARAFFIN SCRATCHERS: Paraffin scratchers are wire line service tools used in

flowing wells to loosen paraffin from the tubing string I.D. Paraffin scratchers consist of a

rod with a fishing neck and a pin thread connection on the upper end. Holes

perpendicular to the center line are drilled through the rod below the fishing neck.


Required length of 0.092” diameter wire are inserted through the holes to form a brush-

like tool. The length of the wire can be easily changed to accommodate different tubing

I.D.’s.

IMPRESSION BLOCK: Impression block are wire line service tools used to take

impression of objects in the tubing string. Impression block consist of a steel housing

with a pin thread connection and a fishing neck on the upper end and a molded lead

insert held in the lower end by steel pins. These tools are mainly used during fishing to

determine the shape and position of the object being retrieved.

WIRELINE GRABS: Wireline grabs wire line service tools used to retrieve wireline from

the tubing string. Wireline grabs consist of a housing with a fishing neck and a pin thread

connection on yhe upper end and either two or three flexible, barbed prongs on the

lower end. The wireline grab O.D. corresponds to the driff diameter of the tubing string.

WIRELINE SAFETY Lubricator and Stuffing Box:

1. The packing nut of stuffing box should not be very loose as it will start leaking.

Tighten it to the limit that wire needs some pull to go across it.

2. Make up all unions completely, and ensure that the ‘O’ rings are not damaged

before making up a union.

3. Needle Valve: Ensure that it is open before installing lubricator or while removing

it.

4. Never climb or hammer a lubricator when it is under pressure.

5. Never stand below the lubricator while rigging up/ down, always clamp the wire.

6. Open Crown valve slowly till lubricator is pressurized.

7. All tool string and control devices/ pressure bombs should be accommodated in

the lubricator.

BLOW OUT PREVENTOR (BOP):

1. Check ram movement before installing. you need to use it for emergency and a

jammed ram then is not desirable.

2. Install pup-joint on well top adaptor. fit BOP, close ram, crack open crown valve

and check for leakage in pup-joint connection and across rams.


3. Always use equalizer valve to equilise across rams. Attempts to open rams shall

damage the ram elements which shall not seal against pressure later.

WIRELINE WINCH:

1. Ensure that the reel skid is properly secured before undertaking a wireline job.

2. Check the condition of the wire. Corrosion & pitting will render it weak and may

snap while doing the job.

3. Never get rough trying to engage gears- you may end up breaking the gear pin or

gear.

4. Keep the reel skid clean & free of rags, hand tools etc.

5. Ensure that depth meter is working okay.

6. Don’t leave wireline unit unattended while pulling out or running in.

7. Take care of moving parts – it can be dangerous especially with loose clothings.

8. Prior to starting the engine check:

A. Engine Oil

B. Diesel

C. Hydraulic Oil

D. Hose connections are properly made up

9. After finishing a job ensure that wire or drum is coated with grease to avoid

corrosion.

WEIGHT INDICATOR:

i. Check the gap of the load cell.

ii. Ensure it is securely tied to rigid place with stronger rope.

iii. Check for its working off the indicator before proceeding with the job.

WIRELINE:

i. When cutting wire make sure that neither end can fly out.

ii. When leaving wireline string in hole, close BOP, clamp the wire & put markers on

the wire between well head & winch.

iii. Make sure that there is enough wire on the drum to reach the total depth of the

well.


GENERAL PRACTICES TO BE FOLLOWED:

• Write down length, OD & description of the components of strings prior to running

in.

• When running in a well for the first time check string weight frequently.

• While scaling X-mas tree your foot hold and hand holds before going up. Never

stand or grasp valve handles they may turn.

• When releasing pressure from lubricator turn head away and open your mouth to

prevent damage to your ear drums.

• Before closing the crown valve after pulling out ensure that the string is in

lubricator.

• Count the number of turns to close the valve.

• Don’t bleed it from lubricator, it shall spray all around, check bleeding

arrangement lest it may lead to fire. Prefer a long bleed pipe away from the rating.

• Inform concerned process complex about closure and opening details.

• Advice concerned people for not closing master/ crown valves when bottom hole

survey is in progress.

Total Well Management II A Methodology for Maximizing Oil Production and Minimizing Operating Costs.

Oilfield operators continually need to verify that their wells are being produced at the

optimum capacity and in a cost effective manner. An integrated analysis of the pumping

system is required to reduce operating costs, increase oil production and increase net

income. The integrated analysis of the pumping system must include the performance

and interaction of all the elements: the prime mover, surface equipment, well bore

equipment, down hole pump, down hole gas separator and the reservoir. This integrated

analysis methodology is called Total Well Management, TWM. The TWM analysis is

made based on data obtained at the surface without entering the well bore and yields an

accurate representation of the conditions that exist on the surface, within the well bore

and within the reservoir. TWM examples of rod pumped wells, ESP pumped wells, PC

pumped wells and other well analyses are presented.

Echometer Digital Well Analyzer

• Acoustic Liquid Level Instrument

• Pressure Transient Tester


• Dynamometer

• Motor Power/Current Analysis

The Well Analyzer is a portable computerized instrument for obtaining a complete well analysis.

The Well Analyzer is an integrated artificial lift data acquisition and diagnostic system

that allows an operator to maximize oil and gas production and minimize operating

expense. Well productivity, reservoir pressure, overall efficiency, equipment loading and

well performance are derived from the combination of measurements of surface

pressure, acoustic liquid level, dynamometer, power and pressure transient response.

This portable system is based on a precision analog to digital converter controlled by a

notebook computer with Windows-based application. The Well Analyzer acquires,

stores, processes, displays and manages the data at the well site to give an immediate

analysis of the well's operating condition.


Acoustic Liquid Level Tests : The Echometer Well Analyzer is used in conjunction

with a gas gun/microphone assembly to determine the liquid level depth in a well.

Normally, the liquid level depth is determined in the casing annulus, but also, the liquid

level depth can be measured inside tubing in gas wells. An acoustic pulse is generated

at the surface of the well. The acoustic pulse travels through the gas and is reflected by

changes in area including

tubing collars and the

liquid level. The

software automatically

processes this acoustic

data to determine

liquid level depth.

Concurrent with the

acoustic liquid level

depth measurement,

an initial and two-

minute build-up casing

pressure tests are

performed. The casing

pressure build-up

measurement allows calculation of the casing annulus gas flow rate and the gradient of

the gaseous liquid column if free gas is bubbling up through the liquid. Software

calculates the producing bottomhole pressure, maximum production rates, pump intake

pressure, casing annulus gas flow rate and other parameters. This single-shot acoustic

liquid level depth test is displayed as shown so the operator can visualize and

understand the performance of the well.

Pressure Transient Tester

The Well Analyzer can be used with special software to obtain pressure buildup data.

The operator programs the Well Analyzer to acquire data at a specified rate in either

shots per hour or shots per log time cycle. Advanced analog to digital converters,

precision pressure sensors and reliable remote fire gas guns allow acquisition of


accurate data, which is

used to calculate

bottomhole pressures.

Numerous diagnostic

and analysis plots are

available including

casing pressure vs. time,

liquid level vs. time,

bottomhole pressure vs.

time, log-log with

derivative, Horner plot,

MDH plot and radial flow

type curves. Real time

viewing of the data insures that the wells are returned to production as soon as the test

objectives have been reached.

Dynamometer

A dynamometer analysis

allows an operator to

determine the loadings

and performance of a

beam pump system. Rod

loadings, beam loadings,

gear box loadings, pump

performance and

downhole gas separator

performance can be

determined. An easy-to-

install compact polished

rod transducer is

attached to the polished rod below the carrier bar in a few seconds. The polished rod

transducer offers safe and easy acquisition of load and position data with sufficient

accuracy for most analysis. A quantitative horseshoe load cell that is installed between


the carrier bar and the polished rod clamp allows the acquisition of load with precise

accuracy. An accelerometer within the transducers provides a reliable technique to

determine polished rod position. With both dynamometers, a surface dynamometer card

and a downhole pump card are calculated and displayed. Traveling valve and standing

valve tests can be performed. When using a horseshoe transducer, a permissible load

diagram and torque analysis are available. A motor current sensor allows acquisition of

motor current data with the dynamometer data for balancing and motor size and motor

performance analysis.

Motor Power Analysis

motor power/current sensor measures both power and current. The power and current

data is processed to determine electrical costs, overall electrical efficiency, gear box

torque, power factor, motor loading and other electrical parameters. The minimum size

motor is recommended. To balance a well, the operator simply inputs the weight of the

counter-weights to be moved and the program calculates the distance that the counter-

weights should be moved. For examples of power and torque analyses.as Gun /

Microphone Assemblies

The Echometer Well Analyzer can be used with a variety of gas guns/microphone

assemblies. The gas gun generates an acoustic pulse which travels down the casing

annulus gas and is reflected by collars and the liquid level. The reflected acoustic pulse

is converted into an electrical signal by the gas gun microphone. A remote fire gas gun is

normally supplied with the Well Analyzer and is necessary for unattended pressure

transient data acquisition. A manual fire 1,500 PSI compact gas gun can be operated in

the explosion or implosion mode. High pressure gas from the well can be released into

the compact gas gun to create the initial pulse so that an external gas supply is not

required. 5,000 and 15,000 PSI gas guns are available for high-pressure applications.

Precision pressure transducers with a wide range of pressure ratings are available for

use with the various gas guns


Data Processing

All well data and acquired data are stored on the Well Analyzer notebook computer. The

acquired data can be recalled, viewed and analyzed in conjunction with the well data to

perform a complete well analysis. The analysis can be printed. Software can be loaded

on office computers to allow viewing of field data. The software can be downloaded from

the web if desired.

Specifications and Dimensions

The Well Analyzer is a state-of-the-art instrument using sigma-delta analog to digital

converters, precision sensors, shielded cables and user-friendly Windows software. The

total weight of the complete Well Analyzer system is 75 lbs. (35 Kg). The complete Well

Analyzer system is shipped in two packages having approximate dimensions of 20" x

20" x 20" each. The instrument is compact, rugged and designed to be used in hot, cold,

humid and dry conditions. Additional information about dimensions and weights can be

supplied depending upon the particular options desired.


Drive mechanisms are the ways in which the oil and gas can be displaced and produced

in a reservoir. Primary recovery refers to production of hydrocarbons by any of the

natural drive mechanisms (also referred as natural energy) existing in the reservoir.

Gas and oil reservoirs behave differently depending on the phase in which the fluid

occurs at the existing pressure and temperature of the reservoir upon discovery, during

depletion and upon abandonment. Their drive mechanisms are different.

Reservoir oil is a mixture of the heavier hydrocarbon components (Heptane+) which are

normally liquid at atmospheric condition, and production results from a mechanism

utilizing existing pressure.

Reservoir gas is a mixture of the lighter components and is producible on the merits of

its non-ideal gas behavior and sometimes of the limited water drive.

OIL RESERVOIR

Oil can be recovered from the pore space of rock only to the extent that the volume

occupied by the oil is replaced with a like volume. Several mechanisms are possible:

• Expansion of undersaturated oil above the bubble point

• Expansion of the rock and of connate water

• Expansion of gas released from solution in the oil below the bubble point

• Invasion of the original oil bearing reservoir by the expansion of the gas from a

free gas cap.

• Invasion of the original oil bearing reservoir by the expansion of the water from

an adjacent or underlying aquifer.

Since all replacement processes are related to expansion mechanism, a reduction in

pressure in the original oil zone is essential. Assuming constant temperature and

composition, the solubility of natural gas in the crude oil in a reservoir is dependent on

pressure, the quantity of gas in a solution increases with increasing pressure.

!


A crude oil is said to be saturated with gas at any temperature if upon slight reduction of

pressure, some gas is released from solution.

Categories of drive mechanisms

• Solution or dissolved gas drive or depletion drive

• Gas cap drive

• Water drive

• Combination drive

• Gravity drainage drive

• Liquid expansion and rock compaction drive

Where one drive mechanism is dominant, the reservoir may be said to be operating

under a particular “drive”.

SOLUTION OR DISSOLVED GAS DRIVE OR DEPLETION DRIVE RESERVOIRS

Gas flows more easily than oil because of its low density, less viscosity and does not

adhere to the pore space surfaces in the rock. Once gas starts to flow, pressure drops

faster and more amounts of gas is formed from lighter hydrocarbons in the liquid. With

small additional amounts of oil produced from the reservoir, small additional increases in

gas space are created. Gas thus flows much more easily while oil flows with greater

increasing difficulty. More often, recovery during this primary process is only some few

percent.

Dissolved gas drive reservoir

(After Clark, N.J., Elements of Petroleum Reservoirs, SPE, 1969)


The depletion drive mechanism is characterized by a rapid pressure decline to oil bubble

point pressure at which pressure free gas is evolved in the reservoir.

In brief, the characteristic trends occurring during the production life of dissolved gas

drive reservoir can be summarized as:

Characteristics Trend

Reservoir pressure Declines rapidly and continuously

Surface Gas-Oil ratio First low , then rises to maximum and then drops

Water production None

Well behavior Requires pumping at early stage

Expected Oil recovery 5 to 30%

Production data of a solution gas drive reservoir


Negligible or no water is produced from a dissolved gas reservoir because they are

geologically closed reservoirs filled with oil and non-producible connate water.

Development scenarios

Well may be spaced on a regular pattern with low structural relief formed by pinch out or

faulting.

Completion interval should be low.


With high relief structures, regular patterns with wells placed down dip in order to allow

gas cap to form and oil to segregate by gravity.

Factors influencing depletion drive performance

The factors which modify depletion drive performance and its ultimate recovery are:

• Reservoir pressure

• Reservoir fluid viscosity

• Gas in solution in reservoir oil

• Presence of connate water phase

• Practice of gas recycling and injection ratio

• Presence and formation of gas cap and its expansion

• Well spacing

GAS CAP DRIVE RESERVOIRS

Gas cap drive reservoirs are characterized by the presence at the top of structure a

relatively large gas cap, underlain by oil. In natural drive, the gas cap expansion is the

result of reservoir pressure decline. As the oil state is very close to saturation, free gas is

evolved through out the oil zone by liberation of dissolved gas from the oil. This is an

important phenomenon which conditions actually the efficiency of this drive. Effectively in

large gas cap reservoirs, the liberation of dissolved gas is really placed at gas oil contact

and does not affect the whole oil zone. In such cases, the gas cap drive is frontal drive,

relatively stable whether gravity segregation is efficient or not.

Gas cap drive reservoir



Gas drive is generally unstable because of viscous fingering developed by the relatively

high mobility of gas versus oil.

For small gas cap reservoirs, the liberation of dissolved gas takes place through out the

entire oil zone, leading to a combination of solution gas and frontal drive. With poor

gravity segregation effects, the producing gas oil ratio increases sharply creating more

rapid pressure decline and more free gas in the oil zone.

For the reasons, recoveries by gas cap drive are between 20% to 40% depending on the

size of gas cap, the effectiveness of gravity segregation and limitation of producing rates

(gravity segregation and gas encroachment by coning are effectively rate sensitive).

In brief, the characteristic trends occurring during the production life of gas cap gas drive

reservoir can be summarized as:

Production data of a gas cap drive reservoir



Reservoir pressure Declines slowly and continuously

Surface Gas-Oil ratio Increases in values of gas – oil ratio with the

advancement of gas cap in the producing intervals of up-

structure wells

Water production Nil or negligible

Expected Oil recovery 20% to 40%


WATER DRIVE RESERVOIRS

It was expected during a long period in the petroleum industry that water drive – natural

or forced was the most efficient drive mechanism. If a reservoir is underlain by, or is

continuous with a large body of water saturated rock (an aquifer), then reduction

in pressure in the oil zone will cause a reduction in pressure in the aquifer.

An efficient water driven reservoir requires a large aquifer body with a high degree of

transmissivity allowing large volumes of water to move across the oil-water contact in

response to small pressure drop.

Water drive reservoir


The degree to which reservoir pressure is maintained in a water drive reservoir depends

upon the relation between rate of oil, gas and water production and rate at which the

water at which water can advance through the aquifer and through the reservoir rock

both bottom water and edge water.

In brief, the characteristic trends occurring during the production life of water drive

reservoir can be summarized as:



Reservoir pressure Remains high

Surface Gas-Oil ratio Remains low

Water production Starts early and increases continuously

Expected Oil recovery 35% to 75%

Production data of water drive reservoir


Basic development scenarios

Wells may be spaced in a regular pattern in thick, but low angle dipping beds.

Completion intervals should be high on structure to permit long producing life while oil is

being displaced updip.

Wells may be spaced in an irregular pattern in thin, but high angle dipping beds.

Completion intervals should be high on structure to avoid encroachment of water from

downdip.

COMBINATION DRIVE MECHANISM

In principle. Oil reservoirs can be classified according to their geological information or

producing mechanism. In reality, reservoirs are seldom found which can be made to fit

exactly into either type of classification discussed above. The most commonly observed

production mechanism is the case in which both water and free gas are available to


some degree to enter the reservoir and displace oil towards the well as production

occurs.

Combination drive reservoir

GRAVITY – DRAINAGE-DRIVE MECHANISM

Gravitational segregation or gravity drainage by itself can be classified as a drive

mechanism. However, it is considered rather as a modification of all types of drives.

After the reservoir has been put on production and fluids natural distribution is disturbed,

gravitational segregation is the tendency due to the force of gravity for gas, oil and water

to return to a distribution in the reservoir according to their densities. Gravity drainage

can play a major role in the oil recovery from a reservoir.

In brief, the characteristic trends occurring during the production life of reservoir

operating largely under gravity drainage producing mechanism can be summarized as:


Reservoir pressure Variable pressure decline mainly governed by gas

conservation.

Surface Gas-Oil ratio Low in structurally low wells and high in structurally high

wells,

Water production Nil or Negligible


Expected Oil recovery Varies widely. High in cases of good gravitational

segregation and well producing rates tuned to derive

maximum advantage of gravitational forces.

Oil saturation near the well bore plays major role in exploitation of gravity drainage

reservoir. Near well bore high oil saturation helps in better ultimate recovery.

LIQUID EXPANSION DRIVE

In the initial producing stage of undersaturated reservoirs, though of minor importance,

liquid expansion is the only natural source of available energy.

COMPACTION DRIVE

When a reservoir is put on production, there is an increase in the difference between

overburden pressure and pore pressure. The effect is reduction in pore volume of the

reservoir. Only in cases, where formation compressibilities are high, significant oil

recovery by compaction drive can happen.


" #

$ ESTIMATION OF RESERVES

INTRODUCTION:

Estimation of in place oil and gas reserves is the most important phase of the activity

which forms the basis of all future actions. The reserve estimates dictate actions to be

taken by the company ,leading institutions and private investors. Many petroleum

engineers spend major part of their professional lives , developing estimates of reserves

and production capabilities, along with new methods and techniques for improving these

estimates.

OBJECTIVE OF RESERVE ESTIMATES :

The objective of stock taking of reserves is mainly for national strategic planning. This

exercise is not only done for existing oil and gas fields for short term commitments ,but

also carried out for new discoveries or in new promising structures on prognosticated

basis for long term planning.

TIME OF ESTIMATION:

The process of estimating oil and gas reserves for a producing field continues

throughout the life of the field. There is always uncertainty in making such estimates.

The level of uncertainty is affected by the following factors:

1. Reservoir type,

2. Source of reservoir energy,

3. Quantity and quality of the geological, engineering, and geophysical

data,

4. Assumptions adopted when making the estimate,

5. Available technology, and

6. Experience and knowledge of the evaluator.

The magnitude of uncertainty, however, decreases with time until the economic limit is

reached and the ultimate recovery is realized. Since more & more information

accumulates during the life of a property ,the reserve estimates become correspondingly

6


accurate. The periods of time during which reserves are estimated to design specific

type of plan are :

1. Prior to drilling and development;

2. Just after drilling and completion;

3. At-least after one year production data is available;

4. When the production is declining;

5. At matured depletion.

METHODS OF ESTIMATION :

The oil and gas reserves estimation methods can be grouped into the following

categories:

1. Analogy,

2. Volumetric,

3. Decline analysis,

4. Material balance calculations for oil reservoirs,

5. Material balance calculations for gas reservoirs,

6. Reservoir simulation.

In the early stages of development, reserves estimates are restricted to the analogy and

volumetric calculations. The analogy method is applied by comparing factors for the

analogous and current fields or wells. A close-to-abandonment analogous field is taken

as an approximate to the current field. This method is most useful when running the

economics on the current field; which is supposed to be an exploratory field.

The volumetric method, on the other hand, entails determining the areal extent of the

reservoir, the rock pore volume, and the fluid content within the pore volume. This

provides an estimate of the amount of hydrocarbons-in-place. The ultimate recovery,

then, can be estimated by using an appropriate recovery factor. Each of the factors used

in the calculation above have inherent uncertainties that, when combined, cause

significant uncertainties in the reserves estimate.

As production and pressure data from a field become available, decline analysis and

material balance calculations, become the predominant methods of calculating reserves.

These methods greatly reduce the uncertainty in reserves estimates; however, during

early depletion, caution should be exercised in using them. Decline curve relationships

are empirical, and rely on uniform, lengthy production periods. It is more suited to oil

wells, which are usually produced against fixed bottom-hole pressures. In gas wells,


however, wellhead back-pressures usually fluctuate, causing varying production trends

and therefore, not as reliable.

The most common decline curve relationship is the constant percentage decline

(exponential). With more and more low productivity wells coming on stream, there is

currently a swing toward decline rates proportional to production rates (hyperbolic and

harmonic). Although some wells exhibit these trends, hyperbolic or harmonic decline

extrapolations should only be used for these specific cases. Over exuberance in the use

of hyperbolic or harmonic relationships can result in excessive reserves estimates.

Material balance calculation is an excellent tool for estimating gas reserves. If a reservoir

comprises a closed system and contains single-phase gas, the pressure in the reservoir

will decline proportionately to the amount of gas produced. Unfortunately, sometimes

bottom water drive in gas reservoirs contributes to the depletion mechanism, altering the

performance of the non-ideal gas law in the reservoir. Under these conditions, optimistic

reserves estimates can result.

When calculating reserves using any of the above methods, two calculation procedures

may be used: deterministic and/or probabilistic. The deterministic method is by far the

most common. The procedure is to select a single value for each parameter to input into

an appropriate equation, to obtain a single answer. The probabilistic method, on the

other hand, is more rigorous and less commonly used. This method utilizes a distribution

curve for each parameter and, through the use of Monte Carlo Simulation; a distribution

curve for the answer can be developed. Assuming good data, a lot of qualifying

information can be derived from the resulting statistical calculations, such as the

minimum and maximum values, the mean (average value), the median (middle value),

the mode (most likely value), the standard deviation and the percentiles.

The probabilistic methods have several inherent problems. They are affected by all input

parameters, including the most likely and maximum values for the parameters. In such

methods, one can not back calculate the input parameters associated with reserves.

Only the end result is known but not the exact value of any input parameter. On the

other hand, deterministic methods calculate reserve values that are more tangible and

explainable. In these methods, all input parameters are exactly known; however, they

may sometimes ignore the variability and uncertainty in the input data compared to the

probabilistic methods which allow the incorporation of more variance in the data.

A comparison of the deterministic and probabilistic methods, however, can provide

quality assurance for estimating hydrocarbon reserves; i.e. reserves are calculated both


deterministically and probabilistically and the two values are compared. If the two values

agree, then confidence on the calculated reserves is increased. If the two values are

away different, the assumptions need to be reexamined.

PROCEDURES FOR ESTIMATION AND CLASSIFICATION OF RESERVES

The process of reserves estimation falls into three broad categories: volumetric, material

balance and decline analysis. Selection of the most appropriate reserves estimation

procedures depends on the information that is available. Generally, the range of

uncertainty associated with an estimate decreases and confidence level increases as

more information becomes available and when the estimate is supported by more than

one estimation method. Regardless of the estimation method(s) employed, the resulting

reserves estimate should meet the certainty criteria in Definitions of Reserves.

Volumetric Methods

Volumetric methods involve the calculation of reservoir rock volume, the hydrocarbons in

place in that rock volume and the estimation of the portion of the hydrocarbons in place

that ultimately will be recovered. For various reservoir types at varied stages of

development and depletion, the key unknown in volumetric reserves determinations may

be rock volume, porosity, fluid saturation or recovery factor. Important considerations

affecting a volumetric reserves estimate are outlined below:

Rock volume – may simply be determined as the product of a single well drainage area

and wellbore net pay or by more complex geological mapping. Estimates must take into

account geological characteristics, reservoir fluid properties and the drainage area that

could be expected for the well or wells. Consideration must be given to any limitations

indicated by geological, geophysical data or interpretations as well as pressure depletion

or boundary conditions exhibited by test data.

# Elevation of Fluid Contacts - In the absence of data that clearly defines fluid contacts,

the structural interval for volumetric calculations of proved reserves should be restricted

by the lowest known structural elevation of occurrence of hydrocarbons (LKH) as defined

by well logs, core analyses or formation testing.

Porosity and fluid saturation and other reservoir parameters – determined from logs and

core and well test data.

Recovery factor - based on analysis of production behavior from the subject reservoir, by

analogy with other producing reservoirs and/or by engineering analysis. In estimating

recovery factors, the evaluator must consider factors that influence recoveries such as


rock and fluid properties, hydrocarbons-in-place, drilling density, future changes in

operating conditions, depletion mechanisms and economic factors.

The volumetric estimation of hydrocarbon reserves is done by using the following

formulae:

• For inplace oil reserves in tonnes

Bo

GrSpSohAQ

...... φ=

• For inplace free gas reserves in m3

++

=

ztt

PP

GrSpShAQ s

sg

1273273

...... φ

• For inplace solution gas reserves in m3

Bo

RGrSpSohAQ s....... φ

=

Where Q= Quantity of hydrocarbon

A= Area of the pool in square meters

h = Average thickness of the pool in meter

Ø = Porosity of the reservoir rock, fraction

So =Oil saturation, fraction

Sg =Gas saturation, fraction

Bo = Formation volume factor of oil

P = Reservoir pressure, Kg/cm2

Ps= Standard pressure, Kg/cm2

ts= Reservoir temperature, 0 c

Z = Compressibility factor of gas at pressure P

Rs= Solution gas oil ratio m3/tonne.

To evaluate the recoverable part of the hydrocarbon reserves, the recovery factor will

have to be introduced in the above formulae. The recovery factor depends on the

operative drive mechanism in the pool and the production technique adopted therein.

For the calculation of oil and gas reserves by volumetric method, it is essential to

determine the average values of different reservoir parameters needed for these

calculations. Some of the parameters determined in the early stage of exploration are

likely to change with time. However, more reliable data are obtained from delineation

wells.


Preparation of Maps and Calculation of rock volume

After completion of detailed layer wise correlation of the zone of interest, the following

well wise parameters need to be determined:

Top and bottom of the zone

Total (Gross) thickness

Effective thickness (Permeable part)

Hydrocarbon saturation part of the effective thickness (Pay thickness)

Level of fluid contacts

Effective porosity of the zone

Percentage of hydrocarbon saturation

Structure Contour Map

A structure contour map showing lines connecting points of equal elevation on the top of

a marker bed, depicts the geological structure. The estimated top and bottom elevations

at mean sea level of the zone of interest in each well is tabulated for the preparation of

structure map at the top and bottom of the zone. For inclined wells the necessary

correction of the vertical shortening is to be applied.

Structure map on Top of Pay sand


Fluid contacts

For assessing the limits and the thickness of hydrocarbon saturation part of the reservoir,

it is necessary to find out fluid contacts i.e. oil - water, gas - oil and gas - water

contacts.

The fluid contacts in a highly porous and permeable formation are generally distinct, but

it is not clear in fine grained low permeability formation.

Oil Water contact

The level below which the oil bearing formation is saturated with water is known as the

oil - water contact of that formation.

In reality, all the wells drilled in the oil bearing formation do not exhibit oil water contact.

Normally the procedure is to assume oil water contact to be horizontal plane. Thus, if the

sub sea level of the contact can be determined in several wells, it is possible to extend

the contact the reservoir to the sections where the contact is ill defined. This contact is

drawn on structure contour map to define the boundaries of the oil zone.

Tilted oil - water contact

There are cases where the oil water contact in a reservoir is not a horizontal plane. The

OWC may be tilted due to:

• If the water zone is in a dynamic state

• If the formation is highly heterogeneous in porosity and permeability

The most important factor is the horizontal permeability which could cause a tilted OWC.

This type of tilt in water table occurs due to formation of a considerably thick transition

zone in the region of fine grains and low permeability.

This concept, coupled with the study of formation pressures in different wells will help to

eliminate many of the faults generally, shown in the structure contour maps to adjust all

OWC data along horizontal planes.

Edge water system

Where OWC is encountered only in the down dip (flank) wells and not in the up dip

(crestal) wells. Presence of edge water in the formation necessitates in marking of outer

and inner oil water contacts.

Tracing the averaged OWC on the structure contour map drawn at the top of the

formation is defined as the outer oil water contact. Plotting the level of OWC on the

structure contour map drawn at the top of the formation is defined as the outer oil water

contact. Plotting the level of OWC on the structure contour map drawn at the bottom of


the formation and tracing the same line on the structure contour map drawn at the top of

the formation is defined as the inner oil water contact. This should be traced off with

appropriate symbol to prevent confusion.

Edge Water System

Bottom water system

Where OWC is encountered in the entire flank as well the crestal wells of the formation.

The generalize OWC is plotted on the structure contour map drawn at the top of the

formation and there is only one OWC in this system as all the oil bearing areas has the

presence of water below it. The structure contour map at the bottom of the formation is

not drawn in this case.

Bottom Water System

Gas-Oil and Gas-Water contact

In a formation where the oil or water is overlain by gas, gas - oil or gas - water contacts

are observed. Like oil-water contacts, the gas - oil and gas - water contacts can also be

edge or bottom type and are to be drawn on structure contour maps the same way as

discussed for the oil water contacts.


A common fluid contact

If several beds in a multilayered producing horizon have a common oil-water, gas-water

contact, the entire horizon can be counted as a single unit and its reserves can be

estimated accordingly.

The same oil water contact for several strata or horizons indicates a hydrodynamic

continuity which may either be due to pinch out of the shale layers or existence of

fractures within shales permitting fluid communication. The presence of a single oil -

water or gas - oil contact of course does not eliminate the necessity of careful study of all

the present features in individual beds.

Areal Extent of Oil-Pool

The concept of the nature of trap (structural, stratigraphic or combination type) will help

to a great extent to define the pool limit. From the study of all the reservoir types, this

has been concluded that hydrocarbon reservoirs are essentially bounded by four ways:

- pinch out or disappearance of the formation

- facies change or loss of permeability

- faulting

- fluid contact

One or any combination of these four phenomena may act as the limiting factor.

Iso-pach (Gross Thickness) Map

The total thickness (sand-shale) of the unit encountered in all the wells or adjacent to the

field is tabulated. The isopach map is drawn connecting the same gross thicknesses of

different wells indicates depositional pattern.

Iso- Effective Thickness Map

The term effective thickness generally means the total thickness of the permeable layers

of a formation. For the calculation of reserves and drawing up a production plan, the

effective thickness of the productive formation has to be assessed. In determining

effective thickness, the layers which do not exhibit the reservoir characteristics are

deducted from the total thickness of the formation. Though laborious, but accuracy of the

reserves estimation is dependant on this parameter to a considerable extent. Hence it is

desirable that effective thickness of each well is carefully determined from the study of

all available geological and well data.


After tabulating the well wise effective thickness data for the entire well in or adjacent to

the field, an iso-effective thickness map is drawn by connecting the same effective

thickness values. The isopach map should form as a guide map for drawing of this map.

This map helps in establishing the sand geometry of the zone interest.

Iso-pay map

Bottom water case: From the field structure contour map, the OWC and other pool

limits are traced on a blank field map. The OWC is labeled as ‘zero’ as it will be line of

zero oil sand thickness. The thickness contours taking a trend from the iso effective

thickness map shall nearly follow the structure contours ie, maximum at the crest and

declining towards the flanks.

Edge water case

The pool limits and OWC (inner and outer) from structure contour map are traced on a

blank field map and the outer OWC is labeled as ‘Zero’ as it is a line of zero oil sand

thickness.

As the total net sand (effective thickness) and net oil-sand (net pay or oil-saturated

column) for wells inside the inner oil-water contact are identical, the total net sand

(effective thickness) contours and the final net oil-sand isopachous (isopay) should be

identical in this area. Super impose the blank map over the total net sand map (effective

thickness map) previously prepared and trace off all contours that lie inside the inner oil-

water contact. This is the most important part of the final isopay map. The contours in

the oil-water wedge will more or less parallel structure contours and data from wells in

the wedge fill into them. It will be seen that where a contour crosses the inner oil-water

contact it makes an abrupt turn towards the next numerically high contour. While

preparing the oil sand isopach (isopay) map, the oil - gas wedge zone should be taken

into consideration in the same way as the water-oil wedge zone while calculating the

value of the isopay (oil sand/gas sand thickness) contours. Should the reservoir be so

shaped that in some parts of field, the entire thickness of the same is in the gas cap, the

total net sand contours may still be used to find out net pay or oil/gas saturated

thickness contours.


Iso-pay map

Calculation of Net Hydrocarbon Saturated Rock Volume

Preparation of the isopach, isoeffective thickness and the isopay maps of the reservoir is

followed by planimetering the areas between the isopay lines of the isopay map of the

reservoir, to obtain the volume.

The assessing of volume of the rock body by three methods can be used.

1. Trapezoidal rule: The volume of a trapezoid is

)(2 1++= nn AAh

Volume


Or a series of successive trapezoids

2)2....22(

2 1210nn

nn

AhAAAAA

hVolume ++++++= −

Where:

h = Isopay contour interval

Ao = area enclosed by the zero isopay line

A1, A2, A3, An = Areas enclosed by successive isopach lines

hn = average thickness above the top of maximum thickness isopach line.

2. Pyramidal rule: The volume of the frustum of a pyramid is given by :

( )11 .3 ++ ++= nnn AAnAAh

V

Where:

V = volume between n and n + 1 contours.

h = interval between the isopach lines

An = area enclosed by the lower isopach lines

A n + 1 = area enclosed by the next higher isopach line

This equation is used to determine the volume between successive isopay lines and the

total volume is the sum of these separate volumes.

For better accuracy, the pyramidal formula should be used. Because of its simpler form

the trapezoidal formula however, is commonly used, though it introduces an error of 2 %

when the ratio of successive areas is 0.5. Therefore, a commonly adopted rule in

unitization programs is, whenever the ratio of the areas of any successive isopay lines is

smaller than 0.5, the pyramidal formula should be applied.

Graphical Method

The rock volume can also be obtained by plotting a graph of areas enclosed by contours

of the structure maps on top and bottom of the formation. The areas plotted as a function

of depth. The area enclosed by the two resulting curves represents the gross volume of

hydrocarbon bearing rocks. The gross rock volume is determined by graphical and

numerical integration of the area between the two curves or by planimetering. This

method does not assume any fixed relationship between each contour as in the case of

the trapezoidal or pyramidal rules.


Sometimes it is considered desirable to know the rock volume distribution as a function

of depth. This can be done by dividing the area between two curves into smaller

segments and calculating the area for each little segment A0, A1, A2. etc. The cumulative

volume distribution with depth can be expressed in terms of rock volume above or below

a given depth depending on whether gas cap or water drive is the predominant source of

energy.

EVALUATION OF RESERVOIR PARAMETERS

Average porosity

In volumetric reserves calculation the average porosity of the producing horizon is an

important factor. To arrive at an average value of porosity it is necessary to evaluate first

the average porosity of the formation in an individual well. That is each value of porosity

is assumed to represent the interval from which the sample was taken. If all the intervals

sampled from well are of uniform thickness, the weighted average and arithmetic

average are identical. If the intervals differ in both thickness and value of the porosity,

then the two averages differ.

The thickness weighted average porosity is about one percent higher that the arithmetic

average. The summation of ( h) is the porosity or volume capacity of the section.

Determination of average value of hydrocarbon saturation in the reservoir

Hydrocarbon saturation can be obtained from laboratory and electrolog analysis. For use

in volumetric estimation of hydrocarbon reserves, the weighted average hydrocarbon

saturation is to be assessed. In evaluation of hydrocarbon saturation also – (1)

Arithmetic weighted average, (2) Area weighted average and (3) Volumetric weighted

average techniques are used. If sufficient data are available, the most efficient method

of averaging the value is volumetric. The objective can be achieved by superimposition

of Isopay and Isosaturation map and then calculating the saturation value for each block.

At the final stage, the value is obtained by dividing the product of the total pore and total

hydrocarbon volume by total pore volume.

This method can be effectively used only when there sufficient data points uniformly

spread over the field. If only a few data points are available, arithmetic or area weighted

average method will be more useful.


Reservoir pressure: Reservoir pressure is an important parameter in determining fluid

volume, unlike reservoir temperature, reservoir pressure is a variable in most reservoir

processes. A distinction is thus made between initial reservoir pressure and the pressure

attained after production from the reservoir.

• Initial pressure: The earliest pressure observations are usually made during drill-

stem tests. DST pressure record may include a closed in pressure prior to the fluid flow.

These observations are excellent source of data on initial reservoir pressure.

The most reliable initial pressure records are obtained from pressure buildup tests on

early wells which are produced until cleared of completion fluid and then closed in for

pressure recording.

Initial reservoir pressure can be verified and in some instances, determined from

correlation of pressure and production history of the reservoir. For a gas reservoir, a P/Z

plot is linear with cumulative gas production.

Reservoir Temperature

Reservoir temperature is required for planning many operations in the wells. These are

measured with maximum thermometers after temperature equilibrium is reached. This

condition is attained if sufficient time is given (24 or 48 hrs). With several readings

against different sands, a standard temperature curve can be prepared for the field.

The reservoir temperature is constant over the life of a reservoir. Average reservoir

temperature in low relief reservoirs can be determined at the volumetric mid point of the

reservoir. In reservoir of considerable relief the effect of temperature variations can be

taken into account by considering temperature gradient.

If measured temperature data are not available, regional geothermal gradient can be

utilized to find out the reservoir temperature from the following relation:

T= Surface temp. 0C +gt (h)

Where,

T = Formation temperature at depth h

h = Depth from surface, 100m.


gt = Geothermal gradient 0C/100 m.

Formation Volume Factor

This parameter is very important for both volumetric and material balance reserve

estimation.

For volumetric reserve estimates, FVF (flash) at initial reservoir pressure is utilized.

Gas Compressibility Factor (Z)

The accurate estimation of gas compressibility factor (Z) is very important for estimation

of free gas reserves. As the gas deviation factor varies usually between 0.7 to 1.2, it has

got a great bearing on the assessed gas.

Solution Gas-Oil Ratio and Specific Gravity of Reservoir Fluids

Solution gas-oil ratio is an important parameter for the estimation of solution gas

reserves. The gas in solution normally refers to the total amount of gas that is liberated

while bringing the oil from reservoir conditions to stock tank conditions and is reported in

cubic meters of stock tank oil. This parameter can therefore be determined from surface

measurements through separators and from PVT samples in the laboratory either by

flash or differential liberation process.

Flash GOR is used for estimation of solution gas reserves.

The specific gravity of the reservoir fluids, gas and oil is also important parameters for

reserve estimates. It is determined in the laboratory from PVT samples under standard

pressure and temperature conditions. Specific gravity of oil and gas is also determined

using surface oil and gas samples. These values should be compatible with specific

gravity values determined by PVT analysis.

PERFORMANCE TECHNIQUES :

These methods are mainly used during development stage and during producing life of

the reservoir. As new wells are drilled the volume and geometrical distribution of the

reservoir becomes more accurately defined as well as the reservoir porosity and

saturation values .On the other hand ,fluid withdrawals and injection into the reservoir

and the corresponding changes in fluid interfaces must be accounted for as the

inventory of reserves is continuously updated whether the amount of hydrocarbon

reserves is estimated by computer as in : Field Studies “ or manually ,the procedures are


the same in principle. Obviously , the trend in reservoir studies is towards numerical

simulation on which not only the static inventory of reserves is kept ,but which can

predict future behaviour of a field. Using the performance data ,the reserves can be

studied by the following three methods :

A. Material Balance approach

B. Numerical Simulation Technique;

C. Decline Curve Analysis

INITIAL –IN-PLACE ESTIMATION USING MATERIAL BALANCE EQUATIONS :

The material balance equation was first presented in 1936 by Schilthuis. When properly

applied, it can be used for;

• Estimating initial hydrocarbon in place

• Predicting future reservoir performance

• Predicting ultimate hydrocarbon recovery under various types of primary drive

mechanism.

Though the material balance equation is of zero order, by introducing the rate term we

one can add time dimension to it.

Material balance methods of reserves estimation involve the analysis of pressure

behavior as reservoir fluids are withdrawn, and generally result in more reliable reserves

estimates than volumetric estimates. Reserves may be based on material balance

calculations when sufficient production and pressure data is available. Confident

application of material balance methods requires knowledge of rock and fluid properties,

aquifer characteristics and accurate average reservoir pressures. In complex situations,

such as those involving water influx, multi-phase behavior, multilayered or low

permeability reservoirs, material balance estimates alone may provide erroneous results.

Therefore, if sufficient pressure production performance data are recorded and PVT data

describing the reservoir fluid behaviour are available ,the amount of oil or gas in place in

a reservoir , can be computed by Material Balance Method. The method is based on the

premise that the pore volume (Pv)of a reservoir remains constant or changes in a

predictable manner with the reservoir pressure drop ,as oil ,gas and/or water are

produced.


It is important that calculations at several pressure withdrawal points must yield

consistent results. The successful application of this method requires an accurate

history of the average pressure of the reservoir ,reliable oil, gas and water production

data ,and PVT data on reservoir fluids.

The most frequently used material balance equations are given below with reference to

the type of reservoir. The unknowns are also indicated .The unknown other than in place

reserves , have to be determined by independent means.

1. Oil Reservoir with Gas Cap and active water drive :

Np( Bt+Bg (Rp-Rsi)-(We-Wp)

N = ----------------------------------------

m/Bgi(Bg) + (Bt-Boi)

Unknowns - N, We, m

2. Oil Reservoirs With gas cap ,no active water drive ( We=0):

Np( Bt +Bg(Rp-Rsi) +Wp

N= --------------------------------

m/Bgi ( Bg-1) +(Bt-Boi)

Unknown - N, m

3. Initially under-saturated oil reservoir in the active water drive (m=0):

(i) Above Bubble Point

( Np(1+p Co) - (1-Sw)

N= -----------------------------------

P( Co+Cf - Sw( Co-Cw)

Unknown - N .

(ii) Below Bubble Point :

Np( Bt+Bg ( Rp-Rsi) _(We-Wp)

N = -------------------------------------

(Bt-Boi)


Unknown - N,We.

4. Initially Under-saturated reservoir ,no active water (We=0)

(i) Above Bubble point :

(Np(1+PCo)+ (1-Sw)

N= -----------------------------

P (Co +Cf –Sw ( CO-Cw)

Unknown –N.

(ii) Below bubble point

Np(Bt +Bg (Rp-Rsi)+Wp

N = ------------------------------

Bt-Boi

Unknown - N

5. Gas Reservoirs with active water drive

Gp.Bg _ (We-Wp)

GR = -----------------------

( Bg- Bgi)

Unknown- GR, We.

6. Gas Reservoirs with no active water drive :

GpBg +Wp

GR = ---------------

Bg-Bgi

Unknown - GR

Where :

Bg= Gas FVF,Vol/Vol

Bo = Oil FVF ,RB/STB ( Res.m3/std.m3)

Bt = Bo+ ( Rsi-Rs)Bg,RB/STB

Cf = Compressibility factor for reservoir rock,Vol/Vol/psi

Co = Compressibility factor for oil ,Vol/Vol/psi

Cw= Compressibility factor for water ,Vol/Vol/psi

GR = Reservoir gas in place ,SCF( Std.m3)

Gp= Cumulative gas produced ,SCF (Std.m3)


i = Initial conditions

m = Ratio of gas cap volume to oil zone volume

N = Reservoir oil in place ,STB ( Std.m3)

Np = Cumulative oil produced ,STB (Std.m3)

Rs = Solution GOR,SCF/STB (Std.m3/Std.m3)

Sw = Interstitial water saturation,fraction of pore volume

We = cumulative water influx ,bbl(m3) and

Wp = Cumulative water produced ,bbl.(m3)

RESERVOIR SIMULATION :

Estimation of reserves in any hydrocarbon reservoir is essentially a two-stage process.

In the first phase volumetric reserves are estimated by plani-metering the base maps-

structure contour, oil pay/gas pay thickness ,porosity, saturation .In the next phase the

volumetric in-place are modified ( if need be ) after watching the performance of the field

in terms of reservoir pressure, producing GOR’s and water cuts etc. The in-place are

revised upwards or reduced depending on whether the performance of the reservoir ( in

terms of pressure, GOR, water cut ) is better or worse with respect to a certain reserve

base estimated volumetrically.

The same philosophy is carried over in reservoir simulation. The volumetric phase of

reserve estimation is termed as Initialization. The inputs required for this phase are the

base maps-structure contours hydrocarbon pay thickness ,porosity, saturation . These

are discretized and read as input data to each simulation grid. Next the relevant PVT

data are read in the form of PVT tables . Transition zones are defined in terms of

capillary pressure curves. Volumetric reserve estimation then becomes simply an

arithmetic sum of the in-place hydrocarbons in each grid block. Sealing faults and fault-

blocks with different fluid contacts can also be defined in the simulation models. Layering

in the vertical direction can be made to conform with Geological Layers ,and further sub-

divided into still sub-layers depending on desired accuracy of modeling flows in the

vertical direction. It is possible to obtain a summary of layer-wise / block-wise reserves at

the end of the initialization process. These can be cross checked with volumetrically

estimated reserves ( obtained by plani-metering ). The two are generally found to be in

agreement.


The second stage of confirming volumetrically estimated reserves is termed as “history

matching”. Wells are defined in the reservoir and oil production rate assigned to them as

per their actual performance. The simulator then produces a response in terms of

calculated reservoir pressure, GOR, water cut which is compared with the actual

performance of these wells. This process is called history matching. Attempts are made

to match the history by adjusting the level of aquifer support, the transmissibilities,

shapes of relative permeabilities etc. If after all these changes a ‘satisfactory’ history

match is not obtained the validity of the volumetrically estimated reserves is in question

and suitable local and global modification to these reserves is made.

Computer reservoir modeling can be considered a sophisticated form of material

balance analysis. While modeling can be a reliable predictor of reservoir behavior, the

input rock properties, reservoir geometry and fluid properties are critical. Evaluators

must be aware of the limitations of predictive models when using these results for

reserves estimation.

The portion of reserves estimated as proved, probable or possible should reflect the

quantity and quality of the available data and the confidence in the associated estimate.

Production Decline Methods

Production decline analysis methods of reserves estimation involve the analysis of

production behavior as reservoir fluids are withdrawn. Confident application of decline

analysis methods requires a sufficient period of stable operating conditions after the

wells in a reservoir have established drainage areas. In estimating reserves, evaluators

take into consideration factors affecting production decline behavior, such as reservoir

rock and fluid properties, transient versus stabilized flow, changes in operating

conditions (both past and future) and depletion mechanism.

Reserves may be assigned based on decline analysis when sufficient production data is

available. The decline relationship used in projecting production should be supported by

all available data.

The portion of reserves estimated as proved, probable or possible should reflect the

confidence in the associated estimate.


METHOD :

In decline curve analysis a varying characteristics of the well performance that can be

measured easily is selected as a variable to produce a trend curve and the cumulative

production or time are selected as independent variables and plotted as abscissas. For

extrapolation the dependent variable ( such as rate, pressure or water cut ) need to be a

continuous function of the independent variable and change in some uniform definable

manner. By plotting the values of this continuously changing dependent variable as

ordinates against the values of the independent variable as abscissas, and graphically or

mathematically extra-polating the apparent trend until a known end point is reached, one

can estimate the remaining reserves or the remaining life for a reservoir. For oil reserves

these plots are usually the logarithm of the producing rate Vs time. The two essential

requirements to use this method are (i) undisturbed production from the well and (ii)

producing the well at capacity.

Reserves Related to Future Drilling and Planned Enhanced Recovery Projects

The foregoing reserves estimation methodologies are applicable to recoveries from

existing wells and enhanced recovery projects that have been demonstrated to be

economically and technically successful in the subject reservoir by actual performance

or a successful pilot. The following criteria should be considered when estimating

incremental reserves associated with development drilling or implementation of

enhanced recovery projects. In all instances, the probability of recovery of the

associated reserves must meet the certainty criteria contained in Definitions of Reserves.

Additional Reserves Related to Future Drilling

Additional reserves associated with future drilling in known accumulations may be

assigned where economics support and regulations do not prohibit the drilling of the

location.

Aside from the criteria stipulated in Definitions of Reserves, factors to be considered in

classifying reserves estimates associated with future drilling as proved, probable or

possible include:

Whether the proposed location directly offsets existing wells or acreage with proved or

probable reserves assigned, and

The expected degree of geological continuity within the reservoir unit containing the

reserves, and The likelihood that the location will be drilled.


In addition, where infill wells will be drilled and placed on production, the estimator must

quantify well interference effects, that portion of recovery which represents accelerated

production of developed reserves, and that portion which represents incremental

recovery beyond those reserves recognized for the existing reservoir development.

Reserves Related to Planned Enhanced Recovery Projects:

Reserves that can be economically recovered through the future application of an

established enhanced recovery method may be classified as follows:

Proved reserves may be assigned to planned enhanced recovery projects when the

following criteria are met:

Repeated commercial success of the enhanced recovery process has been

demonstrated in reservoirs in the area with analogous rock and fluid properties, the

project is highly likely to be carried out in the near future. This may be demonstrated by

factors such as the commitment of project funding, and Where required, either regulatory

approvals have been obtained, or no regulatory impediments are expected, as clearly

demonstrated by the approval of analogous projects.

Probable reserves may be assigned when a planned enhanced recovery project does

not meet the requirements for classification as proved, however, the following criteria are

met:

The project can be shown to be practically and technically reasonable, and Commercial

success of the enhanced recovery process has been demonstrated in reservoirs with

analogous rock and fluid properties, and it is reasonably certain that the project will be

implemented.

Possible reserves may be assigned when a planned enhanced recovery project does not

meet the requirements for classification as proved or probable, however, the following

criteria are met:

the project can be shown to be practically and technically reasonable, and commercial

success of the enhanced recovery process has been demonstrated in reservoirs with

analogous rock and fluid properties but there remains some doubt that the process will

be successful in the subject reservoir.

VERIFICATION OF RESERVES ESTIMATES

A practical method of verifying that reserves estimates meet the definitions and

guidelines is through periodic reserves reconciliation of both entity and aggregate


estimates. The tests described below should be applied to the same entities or groups of

entities over time, excluding revisions due to differing economic assumptions:

Revisions to proved reserves estimates should generally be positive as new information

becomes available.

Revisions to proved plus probable reserves estimates should generally be neutral as

new information becomes available.

Revisions to proved plus probable plus possible estimates should generally be negative

as new information becomes available.

These tests can be used to monitor whether procedures and practices employed are

achieving results consistent with certainty criteria contained in Definitions of Reserves. In

the event that the above tests are not satisfied on a consistent basis, appropriate

adjustments should be made to evaluation procedures and practices.

The Nature and Purpose of Estimating and Auditing Petroleum Reserves:

Estimates of Reserves Information are made by or for Entities as a part of their ongoing

business practices. Such Reserves Information typically may include, among other

things, estimates of (i) the reserves quantities, (ii) the future producing rates from such

reserves, (iii) the future net revenue from such reserves, and (iv) the present value of

such future net revenue. The exact type and extent of Reserves Information must

necessarily take into account the purpose for which such Reserves Information is being

prepared and, correspondingly, statutory and regulatory provisions, if any, that are

applicable to such intended use of the Reserves Information. Reserves Information may

be limited to Proved Reserves or may involve other categories of reserves as

appropriate to the estimate.

Estimating and Auditing Reserves Information in Accordance With Generally

Accepted Engineering and Evaluation Principles

The estimating and auditing of Reserves Information is predicated upon certain

historically developed principles of geo-science, petroleum engineering, and evaluation

methodologies, which are in turn based on principles of physical science, mathematics,

and economics. Although these generally accepted geological, engineering, and

evaluation principles are predicated on established scientific concepts, the application of

such principles involves extensive judgments by qualified individuals and is subject to

changes in (i) existing knowledge and technology; (ii) fiscal and economic conditions; (iii)


applicable contractual, statutory, and regulatory provisions; and (iv) the purposes for

which the Reserves information is to be used.

The Inherently Imprecise Nature of Reserves Information

The reliability of Reserves Information is considerably affected by several factors. Initially,

it should be noted that Reserves Information is imprecise due to the inherent

uncertainties in, and the limited nature of, the accumulation and interpretation of data

upon which the estimating and auditing of Reserves Information is predicated. Moreover,

the methods and data used in estimating Reserves Information are often necessarily

indirect or analogical in character rather than direct or deductive. Each person estimating

and auditing oil and gas Reserves Information is encouraged to exercise his or her own

judgment concerning the matters set forth in these Standards. Reserves Information are

required, in applying generally accepted petroleum engineering and evaluation principles,

to make numerous unbiased judgments based upon their educational background,

professional training, and professional experience. The extent and significance of the

judgments to be made are, in themselves, sufficient to render Reserves Information

inherently imprecise.

The Need for Standards Governing the Estimating and Auditing of Reserves

Information

The adoption of these Standards fulfills at least three useful objectives.

First, although some users of Reserves Information are cognizant of the general

principles that are applied to databases in the estimation of Reserves Information, the

judgments required in estimating and auditing Reserves Information, and the inherently

imprecise nature of Reserves Information, many users of Reserves Information continue

to fail to understand such matters. The adoption, publication, and distribution of these

Standards should enable users of Reserves Information to understand these matters

more fully and therefore place the appropriate level of confidence on Reserves

Information.

Second, the wider dissemination of Reserves Information through public financial

reporting, such as that required by various governmental authorities, makes it imperative


that the users of Reserves Information have a general understanding of the methods of,

and limitations on, estimating and auditing Reserves Information.

Third, as Reserves Information proliferates in terms of the types of information available

and the broader dissemination thereof, it becomes increasingly important that Reserves

Information be estimated and audited on a consistent basis by competent, well-trained

professional geoscientists and engineers. Compliance with these Standards is a method

of facilitating evaluation and comparisons of Reserves Information by the users thereof.

In order to accomplish the three above-discussed objectives, following points are

included in these Standards (i) definitions of selected terms pertaining to the estimation

and evaluation of Reserves Information, (ii) qualifications for persons estimating and

auditing Reserves Information, (iii) standards of independence and objectivity for such

persons, (iv) standards for estimating reserves and other Reserves Information, and (v)

standards for auditing reserves and other Reserves Information. Although these

Standards are predicated on generally accepted geo-science, petroleum engineering,

and economic evaluation principles, it may in the future become necessary, for the

reasons set forth in to clarify or amend certain of these Standards. Accordingly, the

Society, as a part of its governance process, will periodically review these standards and

determine whether to amend these Standards or publish clarifying statements.

Note that these Standards apply independently of the classification system and

associated guidelines adopted by the entity; the reference system should be clearly

identified.

DEFINITIONS OF RESERVES

The determination of oil and gas reserves involves the preparation of estimates that

have an inherent degree of associated uncertainty. Classifications of proved, probable

and possible reserves have been established to reflect the level of these uncertainties

and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional

judgement combined with geological and engineering knowledge to assess whether or

not specific reserves categorization criteria have been satisfied. Knowledge of concepts

including uncertainty and risk, probability and statistics, and deterministic and

probabilistic estimation methods is required to properly use and apply reserves


definitions. These concepts are presented and discussed in greater detail within the

guidelines that follow this section.

The following definitions apply to both estimates of individual reserves entities and the

aggregate of reserves for multiple entities.

RESERVES CATEGORIES

Reserves are estimated remaining quantities of oil and natural gas and related

substances anticipated to be recoverable from known accumulations, from a given date

forward, based on:

Analysis of drilling, geological, geophysical and engineering data,

The use of established technology, and

Specified economic conditions, which are generally accepted as being

reasonable and shall be disclosed.

Reserves are classified according to the degree of certainty associated with the

estimates.

Proved reserves are those reserves that can be estimated with a high degree of

certainty to be recoverable. It is likely that the actual remaining quantities recovered will

exceed the estimatedproved reserves.

Probable reserves are those additional reserves that are less certain to be recovered

than proved reserves. It is equally likely that the actual remaining quantities recovered

will be greater or less than the sum of the estimated proved plus probable reserves.

Possible reserves are those additional reserves that are less certain to be recovered

than probable reserves. It is unlikely that the actual remaining quantities recovered will

exceed the sum of the estimated proved plus probable plus possible reserves.

DEVELOPMENT AND PRODUCTION STATUS

Each of the reserves classifications (proved, probable and possible) may be divided into

developed and undeveloped categories.

Developed reserves are those reserves that are expected to be recovered from existing

wells and installed facilities or, if facilities have not been installed, that would involve a

low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on


production. The developed category may be subdivided into producing and non-

producing:

Developed producing reserves are those reserves that are expected to be recovered

from completion intervals open at the time of the estimate. These reserves may be

currently producing or, if shut-in, they must have previously been on production, and the

date of

resumption of production must be known with reasonable certainty.

Developed non producing reserves are those reserves that either have not been on

production, or have previously been on production, but are shut-in, and the date of

resumption of production is unknown.

Undeveloped reserves are those reserves expected to be recovered from known

accumulations where a significant expenditure (e.g. when compared to the cost of

drilling a well) is required to render them capable of production. They must fully meet the

requirements of the reserves classification (proved, probable, possible) to which they are

assigned.

Discovered

Resources

I

---------------------------------------------

I I

Recoverable Unrecoverable

Resources Resources

( Ult.Reserves ) ( As of Date )

I I

I I

------------------ -----------------------

I I I I

Cumulative Reserves Contingent Unrecoverable

Production ( Future Resources Resources

Production) ( Rec. and ( Unrec.

Unecon.) Unecon.)

Fig. : Discovered Resources


In multi-well pools it may be appropriate to allocate total pool reserves between the

developed and undeveloped categories or to subdivide the developed reserves for the

pool between developed producing and developed non-producing. This allocation should

be based on the estimator’s assessment as to the reserves that will be recovered from

specific wells, facilities and completion intervals in the pool and their respective

development and production status.

LEVELS OF CERTAINTY FOR REPORTED RESERVES

The qualitative certainty levels contained in the definitions are applicable to individual

Reserves Entities, which refers to the lowest level at which reserves calculations are

performed, and to Reported Reserves, which refers to the highest level sum of individual

entity estimates for which reserves estimates are presented. Reported Reserves should

target the following levels of certainty under a specific set of economic conditions:

At least a 90% probability that the quantities actually recovered will equal or exceed the

estimated proved reserves.


sum of the estimated proved plus probable reserves.


sum of the estimated proved plus probable plus possible reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the

various reserves categories is desirable to provide a more clear understanding of the

associated risks and uncertainties. However, the majority of reserves estimates will be

prepared using deterministic methods that do not provide a quantitative measure of

probability. In principle, there should be no difference between estimates prepared using

probabilistic or deterministic methods.

UNCERTAINTY IN RESERVES ESTIMATION

Reserves estimation has characteristics that are common to any measurement process

that uses uncertain data. An understanding of statistical concepts and the associated

terminology is essential to understanding the confidence associated with reserves

definitions and classifications.

Uncertainty in a reserves estimate arises from a combination of error and bias:


Error is inherent in the data that are used to estimate reserves. Note that the term “Error”

refers to limitations in the input data, not to a mistake in interpretation or application of

the data. The procedures and concepts dealing with error lie within the realm of statistics

and are well established.

Bias, which is a predisposition of the evaluator, has various sources that are not

necessarily conscious or intentional.

In the absence of bias, different qualified evaluators using the same information at the

same time will produce reserves estimates that will not be materially different,

particularly for the aggregate of a large number of estimates. The range within which

these estimates should reasonably fall depends on the quantity and quality of the basic

information, and the extent of analysis of the data.

DETERMINISTIC AND PROBABLISTIC METHODS

Reserves estimates may be prepared using either deterministic or probabilistic methods.

Deterministic Method

The deterministic approach, which is the one most commonly employed worldwide,

involves the selection of a single value for each parameter in the reserves calculation.

The discrete value for each parameter is selected based on the estimator’s

determination of the value that is most appropriate for the corresponding reserves

category.

Probabilistic Method

Probabilistic analysis involves describing the full range of possible values for each

unknown parameter. This approach typically consists of employing computer software to

perform repetitive calculations (e.g. “Monte Carlo Simulation”) to generate the full range

of possible outcomes and their associated probability of occurrence.

Comparison of Deterministic and Probabilistic Estimates

Deterministic and probabilistic methods are not distinct and separate. A deterministic

estimate is a single value within a range of outcomes that could be derived by a

probabilistic analysis. Ideally,there should be no difference between Reported Reserves

estimates prepared using deterministic and probabilistic methods.


Application of Guidelines to the Probabilistic Method

The following guidelines include criteria that provide specific limits to parameters for

proved reserves estimates. For example, volumetric estimates are restricted by the

lowest known hydrocarbon (LKH).Inclusion of such specific limits may conflict with

standard probabilistic procedures, which require that input parameters honour the range

of potential values.

Nonetheless, it is required that the guidelines be met regardless of analysis method.

Accordingly, when probabilistic methods are used, constraints on input parameters may

be required in certain instances. Alternatively, a deterministic check may be made in

such instances to ensure that aggregate estimates prepared using probabilistic methods

do not exceed those prepared using a deterministic approach including all appropriate

constraints.

AGGREGATION OF RESERVES ESTIMATES

Reported Reserves are typically comprised of the aggregate of estimates prepared for a

number of individual wells, reservoirs and/or properties/fields.

When deterministic methods are used, Reported Reserves will be the simple arithmetic

sum of all estimates within each reserves category. Evaluators and users of reserves

information must understand the effect of summation on the probabilities of estimates.

The probability associated with the arithmetic sum for a number of individual

independent estimates is different from that of the individual estimates. Arithmetic

summation of independent high probability estimates will result in a total with a higher

probability; arithmetic summation of low probability estimates will yield a total

with a lower probability.

As the definitions and guidelines require a conservative approach in the estimation of

proved reserves, the minimum probability target for proved Reported Reserves will be

satisfied with a deterministic approach as long as there are enough independent entity

estimates in the aggregate.Where a very small number of entities dominate in the

Reported Reserves, a specific effort to meet the probability criteria may be required in

preparing deterministic estimates of proved reserves. Since proved plus probable


reserves prepared by deterministic methods will approximate mean values, the

probability associated with the estimates will essentially be unaffected by aggregation.

When probabilistic techniques are used in reserves estimation, aggregation is typically

performed within the probabilistic model. It is critical that such models appropriately

include all dependencies between variables and components within the aggregation.

Where dependencies and specific criteria contained in the guidelines have been treated

appropriately, reserves for the various categories would be defined by the minimum

probability requirements, subject to the considerations provided in the following

paragraphs.

Reported Reserves for a company will typically not be the aggregate results from a

single probabilistic model since reserves estimates are used for a variety of purposes

including planning, reserves reconciliation, accounting, securities disclosure and asset

transactions. These uses will generally necessitate tabulations of reserves estimates at

lower aggregation levels than the total Reported Reserves. For these reasons, and due

to the lack of general acceptance of probabilistic aggregation up to the company level,

reserves should generally not be aggregated probabilistically beyond the field (or

property) level.

Statistical aggregation of a tabulation of values, which does not result in a

straightforward arithmetic addition, is not accepted for most reporting purposes.

Consequently, discrete estimates for each reserves category resulting from separate

probabilistic analyses, which may, as appropriate, include aggregation up to the field (or

property) level, should be summed arithmetically. As a result,Reported Reserves will

meet the probability requirements in Section 1.4 regardless of dependencies between

separate probabilistic analyses and may be summed with deterministic estimates within

each reserves category.

It is recognized that the foregoing approach imposes an additional measure of

conservatism when proved reserves are derived from a number of independent

probabilistic analyses since the sum of independent 90 percent probability estimates has

an associated probability of greater than 90 percent.


Nonetheless, this is considered to be an acceptable consequence given the need for a

discrete accounting of component proved estimates.

Conversely, this approach will cause the sum of proved plus probable plus possible

reserves derived from a number of probabilistic analyses to fail to meet the 10 percent

minimum probability requirement. Given the limited application for proved plus probable

plus possible Reported Reserves, this is also considered to be an acceptable

consequence.

GENERAL REQUIREMENTS FOR CLASSIFICATION OF RESERVES

The following general conditions must be satisfied in the estimation and classification of

reserves:

Drilling Requirements

Proved, probable or possible reserves may be assigned only to known accumulations

that have been penetrated by a well-bore. Potential hydrocarbon accumulations that

have not been penetrated by a well-bore may be classified as Prospective Resources.

Testing Requirements

Confirmation of commercial productivity of an accumulation by production or a formation

test is required for classification of reserves as proved. In the absence of production or

formation testing, probable and/or possible reserves may be assigned to an

accumulation on the basis of well logs and/or core analysis which indicate that the zone

is hydrocarbon bearing and is analogous to other reservoirs in the immediate area that

have demonstrated commercial productivity by actual production or formation testing.

Economic Requirements

Proved, probable or possible reserves may be assigned only to those volumes which are

economically recoverable. The fiscal conditions under which reserves estimates are

prepared should generally be those which are considered to be a reasonable outlook on

the future. If required by securities regulators or other agencies, constant or other prices

and costs also may be used. In any event, the fiscal assumptions used in the

preparation of reserves estimates must be disclosed.

Undeveloped recoverable volumes must have a sufficient return on investment to justify

the associated capital expenditure in order to be classified as reserves as opposed to

Contingent Resources.


Regulatory Considerations

In general, proved, probable or possible reserves may be assigned only in instances

where production or development of those reserves is not prohibited by governmental

regulation. This provision would, for instance, preclude the assignment of reserves in

designated environmentally sensitive areas. Reserves may be assigned in instances

where regulatory restraints may be removed subject to satisfaction of minor conditions.

In such cases, the classification of reserves as proved, probable or possible should be

made with consideration given to the risk associated with project approval.

ESTIMATION OF RECOVERY FACTORS

Knowledge of recoverable reserves is important because it serves as a guide to sound

development of reservoirs. Before applying secondary recovery techniques it is

important to estimate the primary recoverable oil and the expected gain by application of

the secondary recovery technique. Careful and detailed prediction of performance to be

expected permits judicious design of injection facilities and production handling facilities

as well as to maximize the economic gains.

The primary oil recovery can be estimated byb:

- Volumetric method

- Material balance equation

- Graphical and decline curve analysis

- Empirical methods.

The volumetric method of estimating recoverable reserves is based on applying a

recovery factor to volumetrically estimated in place volumes. The form of the recovery

factor depends upon the producing drive mechanism of the reservoir. In case of

solution gas drive reservoir the recoverable oil will be equal to the original oil-in=place

minus the oil remaining in the reservoir at abandonment.

1-Sw 1-Sw-Sg

Np = Ah (-------- - ----------- )

Soi Bo


( 1-Sw-Sg )

And Recovery factor = 1- ------------ x Boi

(1-Sw)

where Sw = Initial water saturation

Sg = gas saturation in the reservoir at abandonment pressure

Boi = Oil formation volume factor at initial reservoir pressure ( bubble point pressure )

Bo = Oil formation volume factor at abandonment pressure.

The above recovery applies to oil recovered below bubble point pressure. If reservoir

pressure greatly exceeds the bubble point pressure, additional oil recovery due to

compressibility of oil ,water and rock will have to be accounted.

In the above equation, the free gas saturation oil abandonment Sg is difficult to estimate.

C.R. Smith recommends a value of 0.25 as a first approximation for oil with solution

GOR of about 100V/V and oil gravity for 30 to 40 API. The Sg would decrease with

decrease in oil gravity or solution GOR.

Wahl et.al. have presented a series of charts from which the recovery factor for

reservoirs operating under depletion drive may be estimated. Data on bubble –point

pressure oil formation volume factor ,oil viscosity , solution GOR are required for using

these charts. The charts are based on material balance equation calculation technique

and use a correlatior for relative permeability data .

Krg/ Kro = ( 0.0435 -0.4556)

Where = 1-Sgc-Sw-So)/So-C

Sgc = critical gas saturation

C= Constant (= Residual oil saturation ?) usually 0.25

In case of reservoir under water drive where there is no appreciable decline in reservoir

pressure ,water influx is either parallel to the bedding planes as in thin steep dipping

beds with water drive ,or upward as in case of bottom –water drive. The recovery by

active water drive then is :


Ah(1-Sw-Sor)

Np = -------------------

Boi

( 1-Sw-Sor)

And recovery = --------------

(1-Sw)

where Sor is the residual oil saturation remaining after water displacement .Since the

reservoir pressure is maintained nearl atits original value ,no free gas saturation

develops and also the oil volume factor at abandonment remains Boi.

The volumetric method of recovery factor estimation can be used even in very early

stage of development of the field. However, it is dependent on the accuracy of

estimation of Sor.

The residual oil saturation is actually dependent on efficiency of displacement .Factors

influencing displacement efficiency are displacing –displaced fluid mobility ratio, the

reservoir dip, throughput rates ,and the heterogeneity of the reservoir rock. Residual oil

saturations reported from core analysis of cores taken with a water base drilling fluid is a

reasonable estimation of Sor. However, it is recommended that this saturation value be

corrected by multiplying with Bo to account for displacement by expansion of solution

gas since the pressure on the core is reduced to atmospheric pressure. In case of water

injection correction for un-swept area has to be accounted by introducing the sweep

efficiency term.

Craze and Buckley made reservoir analysis of some 103 fields of which 70 were

produced wholly or partially under water drive conditions. The residual oil saturations

range from 17.9 to 60.9 percent of pore space.Arps related the sor data to reservoir oil

viscosity and permeability as given below :

Reservoir Oil Viscosity,cp Sor,%

0.2 30.0

0.5 32.0

1.0 34.5

2.0 37.0

5.0 40.5

10.0 43.5

20.0 46.5


Further since the trapped oil is controlled by pore open sizes, a correction of the Sor

trend is incorporated as a deviation dependent on permeability.

Reservoir Permeability,md Deviation of Sor,%

50 +12.0

100 +9

200 +6

400 0

500 -0.2

1000 -1.0

2000 -4.5

5000 -8.5

Since the Craze-Buckley data was arrived at by comparing recoveries from the reservoir

as a whole the residual oil calculated by this method includes sweep efficiency ,effect of

well location ,by-passing of some of the oil ,and the abandonment of some fields before

flooding in all the zones is completed owing to excessive water –oil –ratios.

The material balance technique can be used only if sufficient pressure production data is

available .It is used in conjunction with GOR and saturation equations. Representative

relative permeability data is required, and aquifer parameters ,in case of water

drive ,have to be judiciously decided. Fluid properties may be available from analysis.

The method can be used only after sufficient production history has been generated.

Too many unknowns ,like size of gas cap ,nature of water influx representative reservoir

pressure ,relative permeability etc. effect the accuracy of the calculations.

The decline curves are used when extensive production history is available. The method

is based on establishing mathematical relation for the trend of a reservoir parameters,

like oil rate, and extrapolating it to a pre-decided limit.

The method is considered quite accurate and requires little other information. But it is

useful only towards the declining stage of the reservoir. The method assumes that the

operating conditions of the wells do not change an that the true decline in the reservoir’s

production capability is observed in the performance data.

J.J.Arps has suggested the utility of estimation of recoverable reserves early in the stage

of development. While detailed mathematical modeling of a specific field would be

fortuitous ,the early estimates provide a basis for capital investments planning .Craze-


Buckley, Guttrie-Greenberger and J.J. Arps have made significant contributions in

developing empirical correlations for estimation of oil recovery.

Guthrie and Greenberger have made a statistical study of the Craze and Buckley data

on water drive fields which resulted in the empirical relations.:

RF =0.11403 + 0.2719 log K +0.25569Sw+0.1355 log o -1.5380

-0.00035h

where RF = Recovery factor fraction

K = Permeability,md

o = Oil Viscosity ,cp

h = net pay thickness ,ft.

The equation is based on a statistical analysis of the performance of a number of water

drive fields, the effect of well spacing, production rate, heterogeneity of the formation

and pore-to-pore displacement efficiency have been included.

The committee headed by J.J. Arps after analyzing the performance of various fields

gave the following relations for both depletion and water drive reservoirs.

The depletion drive :

RE = 41.815 [ (1-Sw)/B ] ^0.1611( K/ ob)^ 0.0979 .

(Sw)^ 0.3722 . (Pb/Pa) ^ 0.1741.

Where RE = recovery efficiency below bubble point in percent

= porosity ,fraction

K = permeability,darcy

ob = viscosity of oil ,cp at Pb

Pb = bubble point pressure.

B = FVF at Pb

Pa = Abandonment pressure.

RECOVERY ABOVE Pb ( Depletion Drive )

RE = n/N = Bb-Boi /Boi

Where

n = Oil produced;

N= IOIP

Boi = FVF at Pi


Bo = FVF at Bc

Co = -1/V.dV/dP = -1/B.dB/dP;

Or log B = -CoP+ const.

When B= Boi ,P=Pi

B= Bb, P=Pb

Then Bb-Boi/ Boi = Co (Pi-Pb)

RE =n/N = Co (Pi-Pb)

For Water drive reservoirs :

RE = 54.898 [ (1-Sw)/Boi]^0.4222. ( K wi/oi)^ 0.077

(Sw)^-0.1902. (Pi/Pa)^-0.2157

The formula gives practical recovery factors.

MATERIAL BALANCE METHOD :

In the simplest form, the material balance can be written as :

Initial Volume= Volume remaining + Volume produced

Few terms are explained here for better understanding.

Oil Formation Volume Factor (Bo):It is defined as the number of reservoir barrels of

oil and dissolved gas that must be produced to obtain one stock tank barrel of stable oil

at the surface condition. Its unit is reservoir barrel/stock tank barrel of oil.

Solution Gas Oil Ratio (RS):It is defined as the number of standard cubic feet of gas

produced with each stock tank barrel of oil that was dissolved in the oil in the reservoir.

It’s unit is standard cubic feet/stack tank barrel.

Gas Formation Volume Factor (Bg): It is defined as volume in barrels that one

standard cubic foot of gas at the surface occupies as free gas in the reservoir. Its unit is

reservoir barrel/standard cubic feet.

The Material Balance Equation :

After the start of production, let the reservoir pressure drops from Pi to current pressure

of P(say). During this p∆ drop in pressure, if the reservoir is allowed to expand


underground, the total expansion plus any natural water influx must equal the volume

expelled from the reservoir as production, as the reservoir is not allowed to expand.

Hence,

Underground withdrawal(rb) = Expansion of the system (rb) + cumulative water

influx (rb)

1. Underground withdrawal If the cumulative volumes of produced fluid measured are

NP = Cumulative oil (stb)

WP = Cumulative water (stb)

Gp = Cumulative gas (scf)

And

Rp = cumulative gas (scf)/cumulative oil (stb) = P

P

NG

(scf/stb) . This is the cumulative

GOR sice the start of production.

Oil + dissolved gas = NPBo (rb)

Water = WPBW (rb)

Free gas = NP(RP-RS)Bg

The cumulative under ground withdrawal is therefore;

( )[ ] WPgSPOP BWBRRBN +−+ (rb)

2. Expansion of The System Oil System

Change in the volume of underground oil when the pressure drops by p∆

N(BO-Boi) (rb)

Amount of gas liberated is

N(RSi-RS) (rb)

The total change in volume of oil i.e. expansion will be

N[ (BO-Boi) + (RSi-RS)Bg] (rb)

Gas Cap expansion;

The initial HCPV of the gas is


gi

Oi

BB

mN (scf)

At reduced pressure p, it occupies reservoir volume of

gi

gOi B

BmNB (rb)

The Gas cap expansion can be given as

−1

gi

gOi B

BmNB (rb)

Connate Water Expansion

pVCdV WWw ∆= where VW is the total volume of water

WCWC

WCW SS

HCPVPVSV

−==

1

The total HCPV defined as

WC

WCWOiW S

PSCNBmV

−∆+

=∂1

)1( (rb)

Pore Compaction As fluids are produced and the pressure declines the entire reservoir pore volume is

reduced

WC

fOif S

pCNBmPPVCPV

−∆+

=∆=∂1

)1()()( (rb)

Water Influx If pressure drop results in influx of We (STB) of water or WeBW (rb) Adding this one gets

[ ] ( )[ ]+−+−=+−+ gSSiOiOWpgSPOP BRRBBNBWBRRBN )()(

WeWC

fWWOi

gi

gOi BW

S

pCSCNBm

B

BmNB +

−∆++

+

−

1

)()1(1

The above equation is called the material balance equation. To condense the material balance into more understandable form Havlena and Odeh

employed following methods


( ) WfwgO WeBEmEENF +++=

In which [ ] WpgSPOP BWBRRBNF +−+= )(

( ) gSSiOiOO BRRBBE )( −+−=

−= 1

gi

gOig B

BBE

( )Wc

fWCWOifw S

pCSCBmE

−∆+

+=1

)(1

Material Balance Above the Bubble Point pCNBBWBN effectiveOiWPOP ∆=+

where

wc

fWCWOOeffective S

CSCSCC

−++

=1

Material Balance for Depletion Below Bubble Point Once the pressure falls below the bubble point , solution gas is liberated from the oil.

Morris Muskat presented the performance prediction of a depletion below bubble point

pressure.

Let us consider an initially gas saturated reservoir from which NP stb of oil has been

produced. Then the oil remaining in the reservoir would be

Nremaining = N-Np= O

O

BVS

Where V is the pore volume (rb0. The change in this volume with pressure is

P

BBS

VP

SB

VP

N O

O

OO

O

R

∂∂

−∂

∂=

∂∂

2

1

The total volume of dissolved and free gas in the reservoir is;


Gr = ( )g

WcOO

SO

BV

SSB

RSV −−+ 1

Its change in volume with pressure is given by

∂∂−−

−∂

∂−

∂∂

−∂

∂+

∂∂

=∂

∂p

B

BSS

pS

BpB

BSR

pS

BR

pR

BS

Vp

G g

g

wcoO

g

O

O

OSO

O

SS

O

Or22

)1(1

Hence producing GOR expression can be given as;

pB

BS

pS

B

p

B

BSS

pS

BpB

BSR

pS

BR

pR

BS

ROoO

O

g

g

WCoO

g

O

O

OSO

O

SS

O

O

∂∂

−∂

∂∂

∂−−−

∂∂

−∂

∂−

∂∂

+∂

∂

=

20

22

1

)1(1

The producing GOR can be approximated with Darcy’s law for GOR

Sgro

OO

g

rg RkB

B

kR +=

µµ

The above two equation can be equated to give

g

O

ro

rg

g

g

WcOO

g

o

ro

rg

O

OS

O

gO

o

k

kp

B

BSS

pB

k

k

BS

pR

B

BS

pS

µµ

µµ

+

∂∂−−

−∂

∂+

∂∂

=∂∂

1

)1(

The above equation can be calculated for change in SO for depletion below bubble point.

At any stage of depletion the oil saturation is related to recovery in following way

)1()(

wcOi

OPO S

NBBNN

S −−

=

Giving

o

oi

WC

OP

BB

SS

NN

−−=

11

Material Balance Method in a Gas Reservoir


The initial gas in place can be determined without even knowing A, h, φ or SW provided

enough pressure production history is available. This can be done due to following

relationship;

As per mole balance on the gas;

Moles of gas produced = Initial moles of gas - moles of gas remaining

As per real gas law following substitution can be done in the above relation;

[ ]

ZRT

WWVP

RTZVP

RTGP pe

i

i

SC

PSC)( −−

−=

Assuming no water production for a volumetric reservoir the above relation reduces to;

VZTP

VTZ

PT

GP

i

i

SC

PSC

−

=

Or

PSC

SC

i

i GVTTP

ZP

ZP

−=

The above equation is an equation of straight line in terms of (P/Z) vs GP Havlena-Odeh Interpretation Havlena – Odeh expressed the material balance in terms of gas production, fluid

expansion, and water influx as;

Underground withdrawal = Gas Expansion + Water expansion/pore compaction + water influx =>

With water influx

Without influx

Gas produced

P/Z

GIIP


( ) ( )We

WC

fWCWgigigwpgp BWp

S

CSCGBBBGBWBG +∆

−+

+−=+1

F = G (Eg + Ef,w) + We BW Where; F= Underground fluid withdrawal= GPBg + WP BW Eg= Gas expansion=Bg - Bgi

Ef,w = Water and rock expansion = ( )

wi

fWiWgi S

CSCB

−+

1

Defining Drive Mechanism Dake (1994) presented an excellent discussion of the strengths and weaknesses of the

material balance equation as straight line. The Havlena-Odeh equation can be

expressed as following equation;

wfo

We

wfO EEBW

NEE

F

,, ++=

+ for oil reservoir

wfg

We

wfg EEBW

GEE

F

,, ++=

+ for gas reservoir

The classical approach to find out the type of drive mechanism, is to plot the right hand

side expression of oil reservoir/gas reservoir as shown in the above equation against oil

production/gas production. Dake suggested that typically two type of trend is observed.

• In a particular case all the points of wfO EE

F

,+ or

wfg EEF

,+ may lie on a

horizontal straight line, as shown in the plot as trend line A. Line A on the plot implies

that the reservoir can be classified as a volumetric reservoir, i.e. We=0. This defines

purely depletion type of reservoir. The energy for production from the reservoir purely

derives from the expansion of the rock, connate water and the oil. Furthermore, the

ordinate value of the plateau determines the initial oil in place N, or initial gas in place

GIIP.

Alternately the values of the ordinate term as shown in the plot below may rise as

illustrated by the trend B and C. Both the curve suggest of aquifer energy. Plot C

represents an active aquifer, whereas plot B represents weak reservoir. However, it


should be remembered that the trend is highly rate dependent. Higher rate than the

water influx into the reservoir may lead to dipping of the trend suggesting otherwise low

strength reservoir, whereas lower withdrawal rate than aquifer influx may suggest active

water drive reservoir. Hence, it may give wrong impression. The conclusion should be

made based on other reservoir parameters viz. aquifer volume, KV/Kh ratio, water

production trend etc.

Abnormally Pressured Gas Reservoir High pressured gas reservoirs, usually do not show the typical straight line relationship

between P/Z and gas production value. It is generally observed that they typically exhibit

two slopes. The second slope is steeper than the first slope. The initial/first slope is due

to gas expansion and significant pressure maintenance brought about by formation

compaction, water expansion. Hence, GIIP calculated from the first slope would be

erroneously very high. At approximately normal pressure gradient, the formation

compaction is essentially complete and the reservoir assumes the characteristics of

normal gas expansion reservoir. This accounts for the second slope.

Roach (1981) proposed a graphical technique for analyzing abnormally pressured gas

reservoirs. He put forward following equation for determining GIIP

αααα =(1/G) * ββββ -ER

Where;

NP or GP

A

B

C wfEEF

,+


( )

( )PP

ZP

ZP

i

i

i

−

−

=1/

α

and

( )

)(

/

Pp

ZPZP

i

i

i

−

=β


# % &

Technology to increase oil recovery from a porous formation beyond that obtained by

conventional means. Conventional oil recovery technologies produce an average of

about one-third of the original oil in place in a formation. Conventional technologies are

primary or secondary. Primary technologies rely on native energy, in the form of fluid

and rock compressibility and natural aquifers, to produce oil from the formation to wells.

Secondary technologies supplement the native energy to drive oil to producing wells by

injecting water or low-pressure gas at injection wells. The target of enhanced recovery

technologies is that large portion of oil that is not recovered by primary and secondary

means.

Many of the challenges encountered by secondary technologies are identical to those

encountered by enhanced recovery technologies. Those challenges include reducing

residual oil saturation, improving sweep efficiency, fitting the technology to the reservoir

heterogeneities, and minimizing up-front and operating costs.

Residual oil remains trapped in a porous rock after the rock has been swept with water,

gas, or any other recovery fluid. The residual oil saturation is the percentage of the pore

space occupied by the residual oil. The residual oil saturation depends on the pore size

distribution and connectivity, the interfacial tension between a recovery agent and the oil,

the relative wettability of the rock surfaces with respect to the recovery agent and the oil,

the viscosity of the fluids, and the rate at which the fluids are moving through the rock.

The sweep efficiency specifies that portion of a reservoir that is contacted by a recovery

fluid. Sweep efficiency increases with volume of injected fluid. It also depends on the

pattern of injection and production wells in a formation, on the mobility of the oil and the

recovery fluid, and on heterogeneities in the formation.

A wide variety of processes have been considered for enhancing oil recovery: thermal

processes, high-pressure gas processes, and chemical processes. Specifically, low

residual oil saturation can be obtained by selecting a recovery fluid that provides a very

low interfacial tension between the oil and the fluid. With very low interfacial tension, the

'


capillary number is large. And high sweep efficiency can be obtained by selecting a

recovery agent with low mobility or by increasing the mobility of the oil.

Different Phases in Field Development

There are broadly three phases in the development of a field. The phases are defined

as;

• Primary recovery phase

• Secondary recovery phase

• Tertiary recovery phase

Primary Recovery Phase

Primary oil recovery phase describes the production of hydrocarbons under the natural

driving mechanism present in the reservoir. The sources of natural reservoir energy are

fluid and rock expansion, solution gas drive, gravity drainage, and the influx of water

from aquifers. Based on the principal source of reservoir energy, the reservoirs are

classified as (1) Water drive, (2) solution gas drive, (3) fluid expansion, (4) gas-cap drive,

and (5) gravity drainage. These natural sources of energy displace oil towards the

producer without supplementary help from injected fluids such as water or gas.

Secondary Recovery Phase

Lack of sufficient natural drive in most reservoirs has led to the practice of

supplementing the natural reservoir energy by introducing some form of artificial drive,

the most basic method being the injection of gas or water.

Primary

Secondary

Tertiary

QO

Time


Water flooding, called secondary recovery because the process yields a second batch of

oil after a field is depleted by primary production

The practice of Water flooding apparently began accidentally as early as 1890, when

operators realized that water entering the productive formation was stimulating

production. The practice of Water flooding expanded rapidly after 1921. The earlier slow

growth of Water flooding was due to several factors. The oil demand was less and

impact of Water flooding on oil production was immense. However, after 1921 demand

of oil picked up and interest for Water flooding grew many folds. Gas injection developed

about the same time as the Water flooding and was a competing process in some

reservoirs.

Water or gas is pumped into the reservoir to produce more pressure on the oil, when

natural pressure is too low to bring the oil to the well.” Typical recoveries are 25-45%

after primary recovery (average 32%) of the total oil in place.

The four basic possibilities in such recovery are:

• Mining

• Squeezing

• Pushing

• Sucking

Mining involves removing the oil bearing rock from its position several hundreds or

thousands of feet below the surface of the earth. It is brought to the surface for

processing as an ore. This method proved to be uneconomical because of the

concentration of ore is low and the depths of most deposits make mining difficult.

Squeezing has to do with the pressing out the oil from the rock by force.

Pushing is the most successful secondary recovery. This is done by displacing the oil

from the rock with some other substance.

Sucking is a type of variation of pushing. The air in the atmosphere is used as a pusher.

The primary techniques are supplemented by the injection of water or gas in the

secondary recovery technique. They do not displace all of the oil. That which is trapped

by capillaries force in the pores is called residual oil.


WATERFLOODING:

In a water flood, water is injected in a well or pattern of wells to displace oil towards

producer. Initially, oil alone is produced as the part of the reservoir at the irreducible

water saturation is swept. When the leading edge of the capillary transition zone reaches

the producer breakthrough occurs (the first appearance of water in the produced

fluids).After breakthrough, both oil and water are produced and the watercut increases

progressively. Eventually the trailing edge of the capillary zone reaches the producer

and only water is produced. Because water is readily available and inexpensive, the

oldest secondary recovery method is water flooding, pumping water through injection

wells in to the reservoir.

The water is forced from injection wells through the rock pores, sweeping the oil ahead

of it towards production wells. This is practical for light to medium crude. Over time, the

percentage of water in produced fluids-the water cut-steadily increases. Some wells

remain economical with water cut as high as 99%.But at some point, the cost of

removing and disposing of water exceeds the income from oil production and secondary

recovery is then halted. While deciding suitability of a candidate reservoir for Water

flooding following reservoir characteristics should be considered;

Flood Pattern

The areal geometry of the reservoir will influence the location of wells and that will

essentially decide the flooding pattern (injection-production well arrangements) to be


used if the reservoir is to be produced through water-injection practices. The commonly

used flood patterns are given in the following figures;


The characteristics of the different flood patterns are given in the following table.

Pattern P/I

Regular

P/I

Inverted

d/a EA, %

Direct Line Drive 1 - 1 56

Staggered Line

Drive

1 - 1 76

4-Spot 2 1/2 0.866 -

5-Spot 1 1 1/2 72

7-Spot 1/2 2 0.866 -

9-Spot 1/3 3 1/2 80

P = number of Production wells

I = number of injection wells

d= distance from an injector to the line containing two producing wells

a = distance between wells in line in regular pattern

EA = Areal sweep efficieny at water break through for W/O = 1

• Mobility Ratio

Mobility ratio, which is the ratio of the displacing phase and the displaced phase, is an

important parameter for the selection of water flooding process. Mobility ratio less than 1

suggests that the water moves slower than the oil. This leads to piston type of

displacement leading to better sweep efficiency than cases where mobility ratio is

greater than 1. Low oil viscosity is preferred for water flooding. The reason is; at

abandonment areal sweep efficiency would be very high.

Mobility ratio = mobility of water in the water contacted portion / mobility of oil in

the oil bank

O

ro

W

rw

K

K

M

µ

µ=

• Recovery Efficiency

A simplistic model for estimating overall recovery involves factoring the recovery

efficiency into individual process efficiencies.

ER = EA * EV * ED * EM


Where;

ER = Overall recovery efficiency

EA = areal sweep efficiency

EV = Vertical sweep efficiency

ED = Displacement efficiency

EM = mobilization efficiency

Areal Sweep Efficiency

It is defined as the fractional area of the field that is invaded by an injected fluid. The

major factors determining areal sweep are fluid mobility, pattern type, areal

heterogeneity, extent of field development, and total volume of fluid injected.

Vertical Sweep Efficiency

It is defined as the fraction of the vertical section that is contacted by injected fluids and

is primarily a function of the vertical heterogeneity and the degree of vertical segregation.

Displacement Efficiency

It is the fraction of the mobile oil in the swept zone that has been displaced and is a

function of the volume injected, the fluid viscosities and the relative permeability curves

of the rock. Displacement efficiency will continually increase with increasing water

saturation in the reservoir. Buckley and Leverett developed a well established theory

called frontal displacement theory to determine the relation ship between the increase in

the average water saturation in the swept area as a function of cumulative water injected.

The theory will be discussed in the subsequent section.

Mobilization Efficiency

It is defined as the fraction of the oil in place at the start of a recovery process that

ultimately could be recovered by that process and is given as

oi

oi

oforpoi

oi

M

BS

BSBS

E/−

=

Soi = oil saturation at start of project

Boi = Oil formation factor at start of project

Sorp = residual oil to process

Bof = Oil formation volume factor at the end of process


Buckley and Leverett Theory of Frontal Displacement The Buckley and Leverett model was developed by application of the law of

conservation of mass to the flow of two fluids (Oil + Water) in one direction. The classic

theory consists of two equations;

Fractional Flow Equation

Frontal Advance Equation

The following three assumptions are made while deriving the frontal displacement

expression.

1. Incompressible flow

2. Fractional flow of water is a function of only water saturation

3. No mass transfer between phases takes place.

For a linear system mass flux rate in x direction both for oil and water can be written as;

( ) ( )φρρ OOoxO St

ux ∂

∂=∂∂− for oil

( ) ( )φρρ WWWxW St

ux ∂

∂=∂∂− for water

The above equation can also be written in volumetric form as;

( ) ( )φρρ OOoO St

Aqx ∂

∂=∂∂− for oil

( ) ( )φρρ WWWW St

Aqx ∂

∂=∂∂− for water

In the Buckley-Leverett model, water and oil are considered incompressible and thus O

and W are constant. Hence the above equation becomes;

t

SA

xq OO

∂∂

=∂

∂− φ


t

SA

xq WW

∂∂

=∂

∂− φ

The sum of above two equations gives;

( )WOWO SS

tA

xqq

+∂∂=

∂+∂

− φ)(

Since SO+SW =1.0

0)(

=∂+∂

−x

qq WO

or qO +qW =qt = constant Saturation qO and qW vary with distance x. However, because of oil and water are

assumed to be incompressible, the total volumetric flow rate at any time t is constant for

every position of x in the linear system.

The fractional flow of a phase is defined as the volume fraction of the phase that is

flowing at x, t.

For oil and water phases;

WO

OO qq

qf

+=

WO

WW qq

qf

+=

=>

t

SqA

xf W

t

W

∂∂

=∂

∂−

φ

The water saturation in a porous rock is a function of distance and time

Hence,

),( txSS WW =

or


dtt

Sdx

xS

Sx

W

t

WW

∂∂

+

∂∂

=∂

To know the value at particular instant of water saturation SW we can put dSw = 0

=>

t

W

x

W

S

xS

tS

dtdx

W

∂∂

∂∂

−=

The term WSdt

dx

is the velocity at which the saturation, SW , moves through the porous

media.

FW happens to be a function of saturation hence;

t

W

tW

W

tW

W

xS

Sf

Sf

∂∂

∂∂

=

∂∂

=>

tW

Wt

S Sf

Aq

dtdx

W

∂∂

=

φ

The above equation is called Buckley-Leverett equation, which states that in a linear

displacement process, each water saturation moves through the porous rock at a

velocity that can be computed from the derivative of the fractional flow with respect to

water saturation. For two-phase flow, the total flow rate qt is essentially equal to the total

injection rate, iW

WW SW

WW

S Sf

Ai

dtdx

∂∂

=

φ615.5

Where;

IW= water injection rate, bbl/day A=cross sectional area, ft2


The total distance specified water saturation will travel during a total time t,

( )W

W

S

WWS dt

dfA

tix

=

φ615.5

Where;

t= time, day

(x)Sw = distance from the injection for any given saturation SW, ft

Tertiary Recovery/EOR Phase

Tertiary recovery involves injecting other gases (such as carbon dioxide), or heat (steam

or hot water) to stimulate oil and gas flow to produce remaining fluids that were not

extracted during primary or secondary recovery phases. Typical recoveries are 5-20% of

OIP after primary and secondary recovery (average13%).The third type of recovery is

tertiary or enhanced. This “can sometimes be achieved if the viscosity of the oil is

lowered so that it flows more easily, either by heating the oil (by injecting steam, for

example) or by injecting chemicals into the reservoir.” The tertiary recovery is also a

supplementation of natural reservoir energy; however it is defined as that additional

recovery over and above what could be recovered from primary and secondary recovery

methods. Various types of tertiary or EOR recovery processes are given as follows;

EOR Processes

Thermal EOR

Processes

Chemical

EOR

Miscible EOR

Processes

Immiscible

EOR

Microbial EOR

Processes

• In-situ

combustion

• Air injection

• Steam

flooding

• Alkali-

Surfactant-

Polymer

• Polymer

• Hydrocarbon

miscible

• CO2 miscible

• N2 miscible

• Flue gas

• Hydrocarbon

immiscible

• CO2

immiscible

• N2

immiscible

• Flue gas

• Consortium

of Bacteria

used for

insitu

generation of

suphonates,

CO2,etc. for

profile

modification


As evident from the above other than Water flooding process, all other natural reservoir

energy supplementation processes have been considered as EOR process. Broadly,

EOR are essentially designed to recover oil, commonly described as residual oil.

Within a broad context, the applicability of the assortment of IOR and EOR technologies

depends by and large on two factors: the API gravity of the oils and the depth of the

reservoirs. In reality, the proper technical selection parameters are the oil viscosity and

the reservoir pressure. These, however, are related empirically to oil gravity and

reservoir depth, respectively.

Enhanced Oil Recovery

The ever increasing demand of hydrocarbon has led to vigorous E&P efforts in finding

new oil reserves. Newer oil reservoirs discovered are in general found to be less efficient

than their predecessors, making future recovery efficiency abysmally low. Conventional

exploitation methods in these reservoirs in general do not perform well. In physical

sense lot of oil remain In-situ. This has led to R&D efforts for improving recovery of oil,

producible beyond primary and secondary methods.

In the last decade or so, many techniques have been investigated in the laboratory to

improve the technology and methods for development and production of oil reservoirs

beyond primary and secondary recovery processes. These techniques for improving the

recovery beyond primary and secondary process have got its appellation Enhanced Oil

Recovery.

An Enhanced Oil Recovery (EOR) process involves supplementation of natural reservoir

energy externally to produce incremental oil that cannot be produced techno-

economically by conventional means.

Application of an EOR process in a particular reservoir involves four important steps- (i)

identification of suitable EOR process, (ii) laboratory studies, (iii) pilot testing, and (iv)

commercialization. Selection of the appropriate EOR process is the single most crucial

factor for success of any EOR project.

There is not a single process that can be considered a “cure-all” for recovering additional

oil from all types of reservoirs. Each process has its specific application, as they not only

depend upon reservoir rock and fluid properties but also on past production history.


Crude oil recovery by EOR processes is rather difficult and high risk operation, and the

likelihood of its success is influenced by a great many factors. However, technical and

economic criteria still dictates the selection of a process. The problem faced by the

reservoir engineer is to identify all the EOR process applicable to a candidate reservoir

or to check the suitability of a particular process in the light of all information available

about the reservoir under study. Prior information on reservoirs similar to the candidate

reservoir may also influence the choice of an EOR method. This leads to crucial need for

experts in this area of EOR process selection.

To understand the type of EOR processes and the range of reservoir rock and fluid

parameters suited for the process, the processes are discussed one by one.

In this process, steam is continuously introduced into an injection well. When steam is

injected into the reservoir, heat is transferred to the oil bearing formation, reservoir fluids

and some of the adjacent cap and base rock. The heat reduces the oil viscosity. This

increases the mobility of oil. As the steam loses heat energy it condenses to yield a

1.1a Steam Flooding Process

1.1 Thermal EOR Process


mixture of steam and hot water. Because of pressure gradient towards producing well,

an oil bank is formed ahead of steam zone. This enables the immobile oil to get

produced from the reservoir. In general steam reduces the oil saturation in the steam

zone to very low value (about 10±%. Some oil is also transported by steam distillation.

Technical Screening Guidelines

Crude Oil

Gravity : <36o API

Viscosity : > 20cP

Composition: Not critical but some light ends for steam distillation will help.

Reservoir

Type of formation : Sand or sand stone with high porosity and

Permeability preferred

Net Thickness : >15 feet

Average permeability : >10mD

Depth : 300-5000 ft

Temperature : Not Critical

Limitations :

• Oil saturation must be high, and the pay zone should be more than 15ft thick to

minimize the heat losses to adjacent formations.

• Lighter, less viscous crude oils can be steam flooded, but normally they are not if

reservoir responds to an ordinary water flood.


• Steam flooding is primarily applicable to viscous oil in massive, high permeability

sandstones or unconsolidated sands.

• Steam flooded reservoirs should be as shallow as possible as long as pressure

for sufficient injection rates can be maintained. This is to avoid excessive heat

losses in the well bore.

• Steam flooding is not normally used in carbonate reservoir.

• Cost per incremental barrel of oil is high.

• Low percentage of water-sensitive clays is desired for good injectivity.

• Adverse mobility ratio and channeling of steam may make this process

unattractive.

This process involves starting a fire in the reservoir and injecting air to sustain the

burning of some of the crude oil, usually in combination with water. A combustion front is

formed at which the injected air burns a small portion of the reservoir oil. The process

combustion can be achieved through low temperature oxidation and high temperature

oxidation. Low temperature oxidation is suited for light oil. Hot flue gas and steam

resulting from combustion and water vaporization displace the oil ahead of the

combustion front. Vaporization of the light ends and thermal cracking also occur. Ahead

of the combustion front, the vaporized light ends condense, providing some assistance

to displacement by solvent dilution of the virgin crude.

1.1 b In-situ Combustion Process



Crude Oil

Gravity : <48o API

Viscosity : < 100cP

Composition: Some asphaltic components to aid coke deposition.

Reservoir

Type of formation : Sand or sand stone with high porosity and

permeability preferred

Net Thickness : >15 feet

Average flow capacity : > 20 mD-ft

Depth : > 500 ft

Temperature : 150oF preferred

Limitations

• The process will not sustain if sufficient coke is not deposited.

• Excessive deposition of coke will lead to low advancement of combustion front

and eventually killing of the process in the presence of sufficient quantity of air.

• Oil saturation and porosity must be high to minimize heat loss to rock.

• Produced flue gases can pose environmental problem.

• Operation problems such as severe corrosion caused by low pH hot water,

increased sand production, pipe failures as a result of high temperature and

adverse mobility ratio makes this process complicated and difficult.

• Heterogeneous formation can result in poor sweep efficiency.

The process also called as micellar or micro emulsion flooding, consists of injecting a

slug that contains surfactant, co-surfactants, oil, water and other chemicals. The function

of the surfactant is to reduce oil/water interfacial tension, but it may also cause

interphase mass transfer of reservoir oil and water. Both the interphase mass transfer

and reduction of IFT increase recovery of oil. Surfactant slug is often followed by

polymer thickened water to improve sweep efficiency.

1.2 Chemical EOR Process 1.2a Alkali Surfactant Polymer Process


In surfactant flooding, surfactant molecules generally are injected along with water to

reduce the oil/ water interfacial tension (IFT), which reduces capillary forces that may

trap oil in rock pores . Normally in chemical flooding processes, inclusion of a viscosifier

(usually a water-soluble polymer) is required to provide an efficient sweep of the

expensive chemicals through the reservoir


Crude Oil

Gravity : > 20o API

Viscosity : < 100 cP

Composition: Light intermediates are desirable

Reservoir

Type of formation : Sand stone preferred

Net Thickness : > 10ft

Average permeability : > 10mD

Depth : 950 to 9000 ft( temperature!)

Temperature : <200o F

Limitations

• Adsorption of chemicals can be detrimental to the process.

• High temperature leads to degradation of chemicals.

• Best results are obtained when alkaline material reacts with crude oil. The oil

should have acid number more than 0.2 mg KOH/g of oil.


• High amounts of anhydrite, gypsum or clays are undesirable.

• Formation water chloride of < 20,000 ppm and divalent ions (Ca++ and Mg++)

<500 ppm are desirable.

• High heterogeneity may lead to the failure of the process.

• Vertical fractures may lead to gravity segregation.

The objective of polymer flooding is to provide better displacement and volumetric

sweep efficiencies during a water flood. They do not lower the residual oil saturation.

They improve recovery by increasing the viscosity of water, decreasing the mobility of

water, contacting a large volume of the reservoir and reducing the injected fluid mobility

to improve aerial and vertical sweep efficiencies. Because, polymer flooding inhibits

fingering, the oil displacement is more efficient in the early stages as compared to a

conventional water-flood.


Crude Oil

Gravity : > 15o API

Viscosity : <200 cP

Composition : Not critical

Reservoir

Type of formation : Sand stone preferred

Net Thickness : > 10ft

1.2b Polymer Process


Average permeability : > 10mD

Depth : < 9000 ft( temperature!)

Temperature : < 229o F

Limitations and Facts

• There are two types polymer synthetically produced polymers (Acrylamide

type) and bio-polymers (Xanthum gum).

• Factors which degrade polymers are salinity, temperature, time, shear rate

and presence of divalent ions.

• Bio-polymers suffer from bacterial degradation and cause well bore plugging.

• Polymers may be ineffective in a mature water flood because of low mobile

oil saturation.

• High adsorption on reservoir rock may kill the process.

• Optimum temperature is a key selection criterion for polymers. Clay increase

polymer adsorption.

• If oil viscosities are high, a higher polymer concentration is needed to achieve

the desired mobility control.

• Some heterogeneity is acceptable but for conventional polymer flooding,

reservoirs with extensive fractures should be avoided.

1.3. EOR by Gas Injection Processes:

Gas Injection is the second largest enhanced oil recovery process, next only to thermal

processes used in heavy oil fields. The residual oil saturations in gas swept zones have

been found to be quite low, however, the volumetric sweep of the flood has always been

a cause of concern. The mobility ratio, which controls the volumetric sweep, between the

injected gas and displaced oil bank in gas processes, is typically highly unfavorable due

to the relatively low viscosity of the injected phase. This difference makes mobility and

consequently flood profile control the biggest concerns for the successful application of

this process.

Hydrocarbon miscible flooding consists of injecting light hydrocarbons through the

reservoir to form a miscible flood. The process recovers crude oil by generating

1.3.a Hydrocarbon Miscible Flooding


miscibility (in the condensing and vaporizing gas drive), increasing oil volume by swelling

and decreasing the viscosity of oil. Three different methods of attaining miscibility are

used. One method uses about 5% PV slug of liquefied petroleum gas such as propane,

followed by natural gas or gas and water. A second method called enriched(condensing)

gas drive , consists of injecting 10 to 20% PV slug of natural gas that is enriched with

ethane through hexane(C2 to C6) , followed by lean gas and possible water. The

enriching components are transferred from gas to the oil. The third method, called High

pressure (Vaporizing) gas drive, consists of injecting lean gas at high pressure to

vaporize C2 to C6 components from the crude oil being displaced.

Mechanisms:

Hydrocarbon miscible flooding recovers crude oil by:

• Generating miscibility (in condensing and vaporizing gas drive).

• Increasing the oil volume (swelling).

• Decreasing the viscosity of the oil.

Different tyoes of HC gas displacement are depicted below.

LPG Injection


Rich Gas Injection

Lean Gas Injection

Technical Screening Guides:

Crude Oil

Gravity >35o API

Viscosity <10 cp

Composition High percentage of light hydrocarbons (C2-C7)

Reservoir

Oil Saturation >30% PV

Type of Formation Sandstone or carbonate with a minimum of

fractures and high permeability streaks.

Net Thickness Relatively thin unless formation is steeply dipping.

Average Permeability Not critical if uniform

Depth >2,000 ft (LPG) to >5,000 ft ( High Pressure Gas)

Temperature Not critical

Limitations:

• The minimum depth is set by the pressure needed to maintain the generated

miscibility. The required pressure ranges from about 1,200 psi for LPG

process to 3,000-5,000 psi the High Pressure Gas drive, depending on the oil.


• A steeply dipping formation is very desirable to permit some gravity

stabilization of the displacement that normally has an unfavorable mobility

ratio.

Problems:

• Viscous fingering results in poor vertical and horizontal sweep efficiency.

• Large quantities of expensive products are required.

• Solvent may be trapped and not recovered.

This process is carried out by injecting large quantities CO2 (15% or more of the

hydrocarbon pore volume) into the reservoir. Miscible displacement by carbon dioxide is

similar to vaporizing gas drive. The only difference is a wider range of components; C2 to

C30 are extracted. As a result, CO2 flood process is applicable to a wider range of

reservoirs at lower miscibility pressure than those for the vaporizing gas drive. CO2 is

generally soluble in crude oils at reservoir pressures and temperatures. It swells the net

volume of oil and reduces its viscosity even before miscibility is achieved by vaporizing

gas drive mechanism. As miscibility is approached as a result of multiple contacts both

the oil phase and the CO2 phase can flow together because of lower interfacial tension.

CO2 can be recycled by extracting it from the crude at the surface.

1.3.b CO2 Flooding (Miscible & Immiscible)


Mechanisms:

CO2 flooding recovers crude oil by:

• Generation of miscibility.

• Swelling of crude oil.

• Lowering the viscosity of the oil.

• Lowering the interfacial tension between oil and the CO2 – oil phase in the near-

miscible regions.


Crude Oil

Gravity >26o API

Viscosity <15 cp (preferably < 10 cp)

Composition High percentage of intermediate hydrocarbons (C5-

C20), especially C5-C12

Reservoir


Type of Formation Sandstone or carbonate with a minimum of fractures

and high permeability streaks.


Average Permeability Not critical if sufficient injection rates can be

maintained.

Depth Deep enough to allow high enough pressure (> about

2,000 ft), pressure required for optimum production

(sometime called minimum miscibility pressure,

MMP).

Temperature Not critical but pressure required increases with

temperature.

Limitations:

• Very low viscosity of CO2 results in poor mobility control.

• Availability of CO2

Problems:

• Early breakthrough of CO2 causes several problems.

• Corrosion in producing wells.

• The necessity of separating CO2 from saleable hydrocarbons.


• Re-pressuring of CO2 for recycling.

• A high requirement of CO2 per incremental barrel produced.

Nitrogen gas flooding oil recovery method uses the inexpensive non hydrocarbon gas

nitrogen to displace oil in system which might be miscible or immiscible depending upon

the pressure and oil composition. Because of their low cost, large volumes of these

gases may be injected. The process recover oil by vaporizing the lighter component of

the crude oil and generating miscibility if the pressure is high enough, providing a gas

drive where a significant portion of the reservoir volume is filled with low cost gases.

Higher miscibility pressure required compared to all other gases.

Mechanisms:

Nitrogen and flue gas flooding recover oil by:

• Vaporizing the lighter components of the crude oil and generating miscibility if

the pressure is high enough.

• Providing a gas drive where a significant portion of the reservoir volume is

filled with low-cost gases.


Crude Oil

Gravity >24o API (>35 for nitrogen)

Viscosity <10 cp

Composition High percentage of light hydrocarbons (C1-C7)

Reservoir


Type of Formation Sandstone or carbonate with few fractures and

high permeability streaks.


Average Permeability Not critical

Depth >4,500 ft

Temperature Not critical

Limitations:

• Developed miscibility can be achieved with light oils and at high pressures;

therefore, deep reservoirs are needed.

1.3.c Nitrogen Gas Flooding (Miscible and Immiscible)


• A steeply dipping formation is very desirable to permit some gravity

stabilization of the displacement that normally has an unfavorable mobility

ratio.

Problems:

• Viscous fingering results in poor vertical and horizontal sweep efficiency.

• Corrosion can cause problems in the flue gas method.

• The non-hydrocarbon gases must be separated from the saleable produced gas

1.3.d Water Alternate Gas injection (WAG):-

WAG means that water and gas are alternately injected into one and the same well. A

WAG project exploits the good microscopic displacement arising from gas injection at

the same time as the water improves the mobility ratio. The best effect is obtained when

gravitation is insignificant, i.e. in reservoirs that are thin or have low permeability. It is

also expected that the pressure increase caused by water injection prior to the WAG

process, can give virtual miscibility between oil and gas, thereby improving oil

recovery. Water flooding, gas injection and water-alternating-gas injection (WAG) are

well-established methods for improving oil recovery. In reservoirs that have been water

flooded, it is still possible to recover a significant part of the remaining oil by injecting gas

alternately with water. Gas can occupy part of the pore space that otherwise would be

occupied by oil, thereby mobilizing the remaining oil. Water, injected subsequently, will

displace some of the remaining oil and gas, further reducing the residual oil saturation.

Repetition of the WAG injection process can further improve the recovery of oil.

Simultaneous water and gas injection (SWAG):

SWAG is similar to WAG except that water and gas injection takes place simultaneously.

SWAG experiments are performed with different SWAG (gas-water) ratios. The water


and gas are observed to flow simultaneously in the pores with water creeping on the

pore walls and gas moving in the pore centers. It is observed that residual oil ganglia are

sandwiched between gas-oil and water-oil menisci from opposite directions and the oil

was squeezed out as a result of very conductive oil layers. It is also noted that recovery

due to SWAG was Independent of the SWAG ratio.

1.4. Microbial Enhanced Oil Recovery Process

In present energy scenario overall world have need of cheaper energy source. For

fulfilling the demand of energy it is necessary to utilize optimum petroleum energy

source present in subsurface reservoir. For this we can do enhanced oil recovery using

microbes. Microbial EOR process is an in-situ process which is more advantageous than

injection approach. Product formed to aid in oil release are biological organism, they will

gone through biodegradation.

Microbial Enhanced Oil Recovery (MEOR) relies on microbes to ferment hydrocarbons

and produce a by–product that is useful in the recovery of oil. MEOR functions by

channeling oil through preferred pathways in the reservoir rock by closing/ plugging off

small channels and forcing the oil to migrate through the larger pore spaces. Nutrients

such as sugars, phosphates, or nitrates frequently must be injected to stimulate the

growth of the microbes and aid their performance. The microbes generate surfactants

and carbon dioxide that help to displace the oil.

Microbial growth can be either within the oil reservoir (in situ) or on the surface where

the by-products from microbes grown in vats are selectively removed from the nutrient

media and then injected into the reservoir. For in situ MEOR processes, the


microorganisms must not only survive in the reservoir environment, but must also

produce the chemicals necessary for oil mobilization.

WELL SELECTION CRITERIA FOR MEOR

THE TECHNIQUE INVOLVES:

• INJECTION OF TBHA MICROBIAL CONSORTIUM ALONG WITH NUTRIENTS IN THE

RESERVOIR

• INCUBATION OF THE CONSORTIUM.

• GROWTH AND PRODUCTION OF USEFUL METABOLITES (ACIDS,

BIOSURFACTANTS.

• INCREASE MOBILITY OF CRUDE OIL TOWARDS WELLBORE.

• CURRENTLY APPLIED IN HUFF AND PUFF MODE.

PARAMETER RANGE

Formation Sandstone

Depth <8000 ft.(2400m)

Temperature <900C

Pressure <300kg/cm2

Reservoir rock properties >50md

API gravity of crude oil <20cp

Water cut 30-90%

PH 4-9

Residual oil saturation >23%

Salinity <10%


• TARGET STRIPPER WELL/LOW PRODUCER.

Mechanisms of MEOR and potential microbes

S. NO METABOLITES ACTION

1 Acids Improving porosity and permeability

2 Gases(CO2, CH4) Increasing pore pressure, oil swelling,

Viscosity reduction

3 Solvents Dissolution of oil

4 Surfactant Reducing IFT between oil and water

5 Polymer Mobility control

Conclusions:

Secondary and enhanced oil recovery is applied to a large number of reservoir types,

except for very active water drive oil reservoirs, and dry & wet gas reservoirs. The

present trend is towards earlier application (better net present worth) although this

does not represent the optimum recovery anticipated. Yet a sufficient production

record (one to three years) is often necessary to gain minimum knowledge of the

reservoir.

As a rule, a number of injection patterns are investigated by simulation as a function

of :


The type of energy injected: water or gas, enhanced processes or steam or

combustion for heavy oil.

The volume of fluid injected.

The well pattern.

And a comparison is made among these various arrangements, with a study on primary

recovery as a reference.


% $ (

DEVELOPMENT PLAN FOR OIL & GAS RESERVOIRS

Need for Planned Development and Operation

In order to continue to make available at reasonable cost to the consumers an ample

supply of petroleum to meet future needs, it is essential that development and operation

of newly discovered reserves is conducted with maximum efficiency and economy. A

tremendous incentive also exists to increase the ultimate recovery of oil from reserves

already discovered and developed ,as well as from those yet to be discovered ,rather

than to dissipate those reserves through inefficient production practices. In developed

fields, where finding costs have already been spent ,application of more efficient

production practices may result in additional oil at reduced unit cost. Thus management

concepts as applied to reservoir development and production ,are a business necessity.

Fortunately, advances in technology have provided and are continuing to make available

an expanding knowledge regarding the physical mechanism of oil and gas recovery.

From this knowledge improved practices emanate and become integrated into field

operation. Utilization of more efficient methods in modern development and production

requires early planning and accumulation of sufficient information on the reservoir to

permit an intelligent decision as to the recovery procedure to be employed. To this end,

the development of the newly discovered oil or gas reservoir demands that a planned

programme for the location and spacing of development wells be initiated at the outset.

This programme has as its goal the efficient utilization of wells to achieve maximum

recovery at reduced cost. Improved completion practices and wider well spacing result in

more effective use of wells, in lower development costs and in avoidance of

unnecessary drilling. The planned development program on wider spacing means

conservation in a very real sense-the minimizing of waste of material ,manpower ,and

capital.

FIELD DEVELOPMENT APPROACHES

Exploratory efforts result into identification of prospective structures or oil and gas

accumulation. Presence or absence of oil and gas accumulation is proved by drilling and

8


the extent of accumulation by delineation campaign. The discoveries thus made vary in

proportion from major to minor fields. Planning the field development would follow. Any

exploitation strategy should be such that it is most economical in order to make the

investment most meaningful and fruitful. Statistically speaking major field discoveries are

made in the early stages of exploration in a new area and also achieved with less effort.

With the advancement of time, the rate of discovery of major fields assume a diminishing

trend. This situation is same not only in India but also the rest o the world. In Indian

context ,in Cambay basin ,after the discovery of Ankleshwar, Cambay, Kalol, Nawagam,

Sanand, Kadi ,Balol-Santhal which have been discovered over a span of 10-15 years.

After that there has not been any substantial addition to the major fields except Gandhar

in 1983.Though there are several discoveries ,but the fields are of limited nature.

Similarly , in Upper Assam Basin Lakwa, Geleki, Rudrasagar, Lakhmani,

Naharkatia ,Borholla-changpang are the major fields in the past. After that smaller fields

have been discovered .The offshore venture is no exception. The first discovery was

super giant Mumbai High field, followed by Heera, Bassein and Panna. Besides these

there are small fields like R-7,R-8, R-9, R-12, R-13 ,D-18 etc.

EXPLOITATION APPROACH :

As the amount of exploration efforts put in the discovery of fields is quite substantial and

hence requires an all out effort to evolve means to exploit all the fields economically. The

concept needs to be discussed under two heads i.e. On-land fields and Offshore

discoveries. Though the basic concepts of exploitation are similar but approaches are

different. There is no difficulty to exploit major fields which have got substantial in-place

and recoverable reserves. By adopting normal production practices they can be

exploited economically and the investments are appreciated. Such fields are termed as

“Easy-To-Discover –and-Produce” .Major fields designated above fall under this

category and it is always the case to give priority to such fields for development. The

minor fields are commonly called as “ Marginal Fields” including isolated pools. A

marginal field /isolated pool can be termed as marginal because of variety of reasons

like limited size, remote location, or poor reservoir properties . The development of these

resources must depend on real increases in oil and gas values or technical solutions

involving lower costs and accelerated revenues through early production startup and


high reservoir depletion rates. These are those fields whose economic returns are of

questionable nature.

THE DEVELOPMENT PLAN: PROCESS AND CONTENT

The Development Plan is the support document for development and production

authorisations and should provide a brief description of the technical information on

which the development is based. The document should provide a summary of the

operator’s understanding of the field although any background information should be

available should the Department require more detail.

Licensees are jointly and severally responsible for the Development Plan, which must

represent a single view of all the Licensees. An operator is usually appointed to be

responsible for the production of the Development Plan and to ensure that all necessary

consents and authorisations are obtained. It is usual for the Department to conduct

discussions with the operator as the representative of all the Licensees.

The following are suggested section headings together with the topics that should be

addressed.

FIELD DESCRIPTION

The description should be in summary form and only a brief statement, table or map of

the results provided with references to more detailed company-held data where

appropriate. Licensees are encouraged to submit only those maps, sections and tables

necessary to define the field adequately but should include at minimum a table of in-

place hydrocarbon volumes, a representative cross-section and top structure maps for

each reservoir. Maps should be in subsea depth at appropriate scales and include co-

ordinates in the United Kingdom National Grid.

Seismic Interpretation and Structural Configuration

A brief summary of the extent and quality of the seismic survey and the structural

configuration of the field should be presented using appropriate figures and maps.

Geological Interpretation and Reservoir Description


The stratigraphy of the reservoirs, facies variations, the geological correlation within the

reservoir and any other relevant geological factors that may affect the reservoir

parameters (both vertically and horizontally) and thereby influence reservoir continuity

within the field should be described in summary form. Figures and maps should be

provided where appropriate. The geological data provided should reflect the basis of

reservoir subdivision, and correlations within the reservoir, and should include the

relevant reservoir maps on which the development is based.

Petrophysics and Reservoir Fluids

A brief summary of the key field petrophysical parameters should be presented

incorporating log, core and well test data. A summary of the field PVT description should

be included.

Hydrocarbons-In-Place

The volumetric and any material balance estimates of hydrocarbons-in-place for each

reservoir unit should be stated together with a description of the cause and degree of

uncertainty in these estimates. The basis of these estimates should be available and

referenced.

Well Performance

The assumptions used in the Field Development Plan for the productivity and injectivity

of development wells should be briefly stated. Where Drill Stem or Extended Well Tests

have been performed the implications of these on production performance should be

given. The potential for scaling, waxing, corrosion, sand production or other production

problems should be noted and suitable provision made in the Field Management Plan.

Reservoir Units and Modelling Approach

Where the reservoir has been subdivided for reservoir analysis into flow units and

compartments the basis for division should be stated. A description of the extent and

strength of any aquifer(s) should be given. The means of representing the field, either by

an analytical method, some form(s) of numerical simulation, or by a combination of these

should be briefly described..

Improved Recovery Techniques

A summary of the alternative recovery techniques considered and the reasons for the

final choice is required.

Reservoir Development and Production Technology


The chosen recovery process should be described and the optimisation method

summarised, including reference to the potential for artificial lift and stimulation. Any

limitations on recovery imposed by production technology or by the choice of production

facility or location should be indicated. Remaining uncertainties in the physical

description of the field that may have material impact on the recovery process should be

described and a programme to resolve these should appear in the Field Management

Plan (Section 3.7).

DEVELOPMENT AND MANAGEMENT PLAN

The purpose of this section is to briefly set out the form of the development, describe the

facilities and infrastructure, and establish the basis for field management during

production. Where a particular topic is not relevant to a development it should be omitted.

Preferred Development Plan, Reserves and Production Profiles

This section should describe the proposed reservoir development indicate the drilling

programme, well locations, expected reservoir sweep and any provision for a better than

expected geological outcome. An estimate of the range of reserves for each reservoir

should be given (excluding fuel and flare) with a brief explanation of how the uncertainty

was determined and explicit statements of probability where appropriate. The assumed

economic cut-off should be stated. Expected production profiles, for total liquids, oil, gas,

gas usage and flare, associated gas liquids and produced water for the life of the field

are required. Where fluids are to be injected, annual and cumulative injection profiles

should be provided. Quantities can be provided in either metric units or in standard oil

field units (but with conversions to metric equivalents provided). Information to allow

calculation of sales quantities should be provided. The anticipated date for Cessation-of-

Production, together with the underlying assumptions, should be provided.

Drilling and Production Facilities

The drilling section should briefly describe the drilling package and well work-over

capability, and should include a description of the proposed well completion.

Process Facilities

A brief description of the operating envelope and limitations of the process plant should

be provided. The use and disposal of separator gas should be described.

The section should also include:

• A summary of the main and standby capacities of major utility and service

systems, together with the limitations and restrictions on operation.


• A summary of the method of metering hydrocarbons produced and utilized.

• A brief description of systems for collecting and treating oil, water and other

discharges.

• A brief description of any fluid treatment and injection facilities.

• A brief description of the main control systems and their interconnections with

other facilities.

Costs

Cost information is not required at present.

Field Management Plan

A brief review is required that sets out clearly the principles and objectives that the

Licensees will hold to when making field management decisions and conducting field

operations and, in particular, how economic recovery of oil and gas will be maximised

over field life. The rationale behind the data gathering and analysis proposed in order to

resolve the existing uncertainties set out in Section 2 and understand dynamic

performance of the field during both the development drilling and production phases

should be outlined.

The potential for workover, re-completion, re-perforation and further drilling should be

described. Where options remain for improvement to the development or for further

phases of appraisal or development, the criteria and timetable for implementing these

should be given.

ECONOMIC EVALUATION

For choosing one of the variants for development of the field, investment analysis for

each of the variants is made. The economic parameters analyzed are:

• Net preset value

• Payback period

• Internal Rate of Return

Net present value is the cumulative present day value (PDV) of profits of the entire

project. It takes into consideration the capital investment and operating expenses

incurred and the receipts during the life of the project, all values discounted in terms of

present day value.

Payback period is the time when the project would breakeven in terms of present day

value of investment and receipts. After the payback period, the project turns profitable.


Internal rate of return indicates the rate of return the investment made annually in terms

of present day value of investments and receipts. This parameter compares the

investment return in terms of other available alternative investment avenues.

While discussing the investment analysis, sensitivity analysis is also made in respect of

certain critical parameters like cost of products, production variations. The sensitivity

analysis measures the viability.

Considering both technical and economic aspects, the techno - economically

optimal variant is chosen for development of field.

FIELD DEVELOPMENT A COOPERATIVE EFFORT :

The stakes involved in a continuous ample supply of oil and gas make it imperative that

engineers, geologists, operators ,and regulatory agencies cooperate in promoting and

maintaining a sound, vigorous policy of oil and gas field development.

In the development of newly discovered oil or gas reservoir ,the exercise of good

practice demands the multi-disciplinary cooperative effort of the involved operators and

the regulatory agency in the initial planning of a controlled drilling programme to provide

a suitable number of wells and a proper well spacing pattern for efficient recovery.

The prevention of waste in the production of oil and gas from the reservoir likewise is a

cooperative process. Each individual operator has an obligation to develop and operate

his property so as to prevent waste and respect the rights of his neighbours. The

operator further has an incentive for prevention of waste in the reduced costs and

greater ultimate income resulting from increased recovery.

ONSHORE FIELDS DEVELOPMENT :

The advantage with the onshore fields is that the exploratory / delineation wells drilled on

the structure can be utilized for exploitation if they are suitably located. The factors

governing such fields are :

In place reserves .

Type of accumulation oil or gas.


Recoverable reserves oil and gas.

Area of accumulation.

Number of exploitation wells needed to drain the accumulation.

Transportation considerations to the consumer point.

Accelerated production of oil and gas.

Type of crude i.e. sweet or sour.

Reduced life of the field for early payout of the investment.

Gas utilization avenues.

Logistics associated with land acquisition and its viability for drilling.

Number and mode of exploitation objects.

Economics at national and international price of crude oil.

The exploitation of these fields ,if they can not sustain permanent structure like pipelines,

GGS, then normally semi-permanent installations are resorted to by constructing well

head installations at the proximity and the crude oil is transported by tankers. The well

head installation have provision for full monitoring of produced fields. There will be cost

escalation if the crude oil is sour. The well completion and other supporting equipment

are to be sour proof. It is desirable to group marginal fields if they fak=ll in proximity to

each other ,so that the investment on the mini GGS and other equipment can be shared

by these fields. Many a times ,it works out very economical. All these installations should

have such equipment which can be retrieved and reused at other locations. It may not

always be economical to go in for secondary recovery for such fields because of

prohibitive costs. As such they normally be exploited as efficiently as possible under

primary recovery mechanisms. Further , most of these fields ,economics can be

considerably improved by adopting “ Produce while in delineation “ by adopting mobile

production systems. Early returns on the investment would improve considerably in

terms of present day value and would reduce payout period. Already in ONGC,

development of some of the marginal onshore fields has been initiated. The exploitation

has been commenced from fields like Kaikalur, Narimanam and Kovilkalappal by means

of a mini well head installation and transportation of crude oil by tankers. These fields

are situated in SRBC. Plans are on hand to put Ravva shallow water offshore field on

EPS and by adopting aggressive exploitation strategy. The plan is to put the field on

stream by 1991 by installing tetrapod and transportation of crude oil by shuttle tankers.


In western region ,production of similar type was adopted in fields like Wasna, S. Malpur,

Dabka, Dahej,Padra, Limbodra and Langhnaj etc.

By resorting to these innovative technology ,it has become possible to exploit marginal

fields . EPS is drawing attention because of dual advantage of earning early revenues

from newly discovered fields as also for an early delineation of the fields. It is easier to

develop a gas field ,but the problems are multi-ferrous. Gas requires a pipe-line and a

consumer .Normally, if the gas reserves are low ,maintaining a longer plateau

compatible with the consumers requirement will not be possible. Under these conditions

it is desirable and appropriate to time the producers in phased manner from the same

field or from other fields in proximity such that reasonable length of plateau is

maintained. Alternately, if it is not possible, the associated gas produced from nearby

fields/wells may be supplemented to meet the gas commitment. Baramura field which

came under this category has been put on stream. Similar efforts have brought some

marginal fields on stream in SRBC by providing common gas production capsule for

Razole and Narsapur fields.

In order to design the development strategy for onshore fields the consideration is given

for :

Geo-technical aspects of the field;

Economic Aspects ;

The regulatory Aspects

GEO TECHNICAL ASPECTS :

The parameters which need to be considered for this include :

Depth of the reservoir;

The pressure /temperature of the reservoir;

Rock and fluid properties;

Reservoir Volumes;

Reservoir Drive mechanism;

Single layer/ multilayered pay zones;

Besides this availability of technologies / facilities also need to be taken into account

Conventional Wells ;


High tech wells ( Horizontal wells, multi-laterals,MWD, under-balanced drilling etc.)

Well intervention equipments;

Artificial lift system;

Source of water for pressure maintenance ;

Surface handling facilities and crude oil/gas transportation .

The rock and fluid properties which affect the designed strategy for field development

include :

Reservoir rock permeability – Good versus tight layers;

Composition of fluids : light oil /heavy oil; sweet/ sour –API gravity.

PVT / phase behaviour ( saturated / under –saturated reservoirs, bubble point

pressure, solution gas );

Bubble point pressure-requirement of pressure maintenance.

THE ECONOMIC ASPECTS :

Economics related parameters which influence the decision making process of field

development includes:

Price of crude oil /gas;

Capex ( Well cost, Surface Equipment )

Opex ( Crude processing, handling, transportation &maintenance

of wells & equipments)

Revenue;

Taxes ;

NPV;

IRR;

Similarly the regulatory aspects which ought to be considered into :

Guidelines set forth by Govt. / regulatory bodies need too be adhered to;

Central ground Water board ,pollution control Board, DGMS,DGH’s directives are to

be followed.

Effluent disposal norms;


Conservation of forest and environment ( Flors and fauna )

The following aspects related to life cycle of the field also deserve consideration during

deciding strategy for field development :

Initial stage – New field- Initial development scheme;

Mid Stage – Development / review of development scheme;

Mature stage –Achieved plateau and declining stage fields-EOR /IOR methods etc.

THE STRATEGY OF FIELD DEVELOPMENT FOR ONSHORE FIELDS :

The strategy of field development generally includes any /all of the following inputs as

inputs for achieving maximum possible recovery :

Infill drilling;

Pressure maintenance- Water /Gas injection

EOR;

Stimulation ( Hydro fracturing / acid/ steam etc.)

Single / Multiple completions;

Artificial Lift ( Gas lift/ SRP/ ESP )

OFFSHORE FIELDS EXPLOITATION :

Offshore venture ,it goes without saying, that the investment stakes are high. Every

effort needs to be made to make the exploitation economically viable. The disadvantage

with the offshore exploratory /delineation drilling is that the wells drilled under these

categories are expandable type and can not be used as producers unless they are

planned initially by completing them with a template. Normally, separate wells are drilled

to exploit the reserves. This is mainly due to uncertainty which is the enemy of offshore

field development. The conventional type of development of major offshore field is by

installing permanent platforms ,permanent process facilities and crude transportation

through under water pipelines. All these installations are non-retrievable and involve

heavy financial investments that can only be sustained by major oil and gas fields.

Economics will deteriorate, if conventional methods are adopted for marginal fields. In

addition to the parameters applicable for on-and marginal fields, the following aspects

would govern he exploitation:

Water depth


Subsurface soil conditions

Environmental conditions

Number of wells requirement

Producing life of the pool

Production options availability

Dept of the prospect

Well completion, single, multiple ,sub-sea.

Uncertainty is the great enemy of marginal field development. The principal areas where

uncertainties occur are in capital cost of development and the productivity . It has been

the experience that, severe capital cost over-runs the original estimates. Such levels of

over expenditure can not be tolerated in a marginal field development. Likewise, the

degree of confidence in marginal field than in the larger and more profitable

accumulations. This creates problems since commitment to costly delineation drilling

and data collection is hard to make when the developed field may give limited returns.

Under these conditions, the assessors left with minimal options in conceptualizing the

reservoir. An early understanding of reservoir rock and fluid characteristics is of utmost

importance as the decision for installing platform location will be decided. The platform

location should be located at a place from where most part of the productive area is

tapped, and is able to yield best productivities . This is only possible when major effort is

made on data acquisition from limited wells.

Several innovative production systems have been developed in the world for exploitation

of the marginal fields. There is no unique system which can satisfy all the marginal fields.

The technical solutions are frequently termed as ‘novel’ since they must incorporate

features not presently found in the majority of offshore developments. A marginal field

development is ,however , characterized by the requirement of the field and

development planning through technical and economic evaluation of a wide range of

development options prior to the initiation of detailed engineering.

The issues in future field development concepts are defined here as basic , essential

points in question when making the primary decision of whether to develop a prospect or

not. When a prospect is declared commercial ,this is the culmination of a complex


decision making process which can involve political factors and preference engineering

as well as basic technical and economic evaluation. The extent to which commerciability

is linked to the utilization of a specific development concept depends on the size and its

location, as well as current and forecasted prices, costs, product marketability and

values. One are which fall between 100m and above requires detailed attention to

improving the overall economic performance of future development. This will include low

cost development concepts ,whether conventional or novel, improved recovery of

reserves in place and minimization and control of cost escalation and project delays

which will adversely affect economics. This can only be achieved during pre-project and

conceptual design phase through increased effort and attention to investigating

alternative development options and to fully defining the preferred development

concepts , including design for construction , fabrication ,hook up and commissioning

prior to commitment to detailed engineering.

DEVELOPMENT DECISIONS :

The following points are usually taken into account for deciding whether a prospect is to

be developed or not to develop:

1) Whether the concepts available or proposed technically are feasible and to what

extent novel or unproven technology involved.

2) Are such concepts acceptable with respect to safety and regularity

requirements?( Current and those anticipated in the future).

3) Given the proposed concept ,is the prospect commercial and what are the

relative merits /disadvantages and associated risks of the alternatives ?

4) The economic evaluation would be needed at regulatory national price and

international price of crude oil.

5) The exploitation feasibility would be better understood by judicious evaluation of

such factors.

6) The political and national considerations involving factors like import

environment , political relations with neighbouring countries . Technology of

producing oil from Marginal fields.


Off late, oil industry is experiencing a glut in the International market. The main reason

for this is the availability of excessive produced oil. The effect of this is already felt in the

International market and the oil prices have been registering a downward trend. This

situation is going to have an impact on the oil industry and the same is felt in the

International market. Already the prices of drilling and other equipment has registered a

decline and there is availability of equipment on easy terms unlike earlier times. By

availing this opportunity it would be possible to make exploitation of marginal fields a

conceivable venture.

In the long run ,”as-easy-to-find-and-produce” reservoirs diminish ,one has to look the

marginal fields for their exploitation. The “Early Production System” has come into

prominence as most of the operators like to have their finds exploited at the earliest. The

early production concept aims at shortening the field development time and

hastening ,the investment recovery which is important in rendering profitable exploitation

of marginal fields.

In most cases ,marginal fields require storage capacity and loading system because of

long distance from coast or large offshore facilities does not justify use of submarine

pipeline transportation.

REQUIREMENT OF EARLY PRODUCTION SYSTEM:

• Drilling the production wells and fabricating the platform at the same time.

• Using a topside facility fully equipped onshore, thus minimizing the time lag from

installation to production start-up.

• Providing required storage facility.

CRITERIA FOR SELECTION OF PRODUCTION SYSTEM:

The criteria adopted for selection of any particular method for early production system

depends upon the following considerations :

Water depth

Environmental conditions

Sea bottom soil characteristics

Distance from shore

Anticipated qualities of oil and gas production

CONCEPTS OF EARLY PRODUCTION SYSTEM:


For an early production system the following facilities re to be created on the platform :

Production wells along with safety features.

Collection of well fluid upto production facilities.

Oil/gas separation facilities.

Oil storage facilities.

Oil transportation facilities.

WELL COMPLETIONS :

The choice available for completion of wells is either conventionally or by sub-sea type

depending upon the location and connected to the production facilities by means of sub-

sea flow-lines.

TEMPLATE VS SATELLITE FOR DEVELOPMENT :

A number of factors have to be considered while making a choice between satellite wells

and template development.

TEMPLATE:

The construction of a template requires early investment and presents a complicated

engineering problem. All equipments installed on the sea bed has to be suitable for a

long maintenance free life, the control system must be reliable and allow the necessary

operational flexibilities and a template necessitates very accurate construction to

accommodate the later connection of wells and flow lines. There is no flexibility in

changing the well location.

The multi-well template option reduces both congestion on the seabed and in the flow

line installation programme. There would be advantages like commingling / flow line

bundling and sharing service and control lines reduce number of lines. In this

regards ,there are likely to be cost and operational advantages for template drilled wells.

As already stated there is complexity in control system and in mechanical components.

Both advantages and disadvantages of multi-well template system tend to increase as

more wells are concentrated in one template.

SATELLITE :

The wells may be drilled directly above the largest area in the reservoir ,there is flexibility

in changing the location .The well is independent of others ,although seabed congestion


is generated by individual flow line /control conduits at each well. The installation of

single satellite wells is simpler ,with a minimum amount of equipment to be placed on

seabed. A disadvantage of satellite well is the high cost of flow and control lines

associated with each well and the mooring problems around the central platform created

by the lines on the seabed ,converging on the platform.

WELL SPACING

The subject of well spacing is one of vital importance to the petroleum industry. The well

itself plays a significant role in the development of oil and gas reservoirs and in control of

the recovery process. Maximum utilization of wells, then, becomes an integral part of

sound operating practices. Efficient exploitation of oil and gas reserves demands that

careful choice of well location and well spacing be made.

The role of the well in reservoir development and control brings into focus the subject of

proper well spacing. From the wealth of information accumulated to date in the field and

in the laboratory on the basic principles of reservoir behaviour, certain concepts have

emerged regarding the spacing of wells and their influence in the recovery picture.

WELL SPACING UNDER UNREGULATED PRODUCTION:

Prior to advent of efficient oil recovery practices ,unregulated production tendency

prevailed, and the attention of operators was focused on the well as a source of oil. With

the discovery of a new pool ,development was intense ,and close spacing became the

common practice. Dense drilling was also accompanied by production of each well at

capacity ,with little attention being given to efficient reservoir operation. Underground

waste became inevitable in this competitive race to capture oil. The drilling of an

excessive number of unnecessary wells compounded the waste in labour, materials and

development costs.

WELL SPACING UNDER CONTROLLED PRODUCTION:

Operators gradually became aware that uncontrolled production resulted in economic

waste and in loss of otherwise recoverable oil. It has been established that the amount

of oil which may be recovered from an oil reservoir is a widely varying quantity and

depends not upon close well spacing but upon (1) the particular conditions imposed by


nature on the underground structural trap.,(2) the properties of the contained fluids, and

(3) the controls exercised by the operator in its development an operation. It is now

recognized that the oil reservoir can be controlled to yield increased ultimate recovery

and that the wells serve principally as a means through which this control may be

exercised. Hence, operators have relegated the individual well to the background as a

source of oil and have shifted their emphasis o the reservoir.

However, wells do have three important functions in the development and operation of

an oil or gas reservoir:

1. That of providing conduits to the surface for the production of oil ,gas, and water.

2. That of providing access to the reservoir to obtain information concerning the

characteristics of the reservoir and its contained fluids

3. That of serving as a means by which a natural recovery mechanism or an induced

programme of gas or water injection may be observed an controlled during the field’s

productive life to obtain effective flushing of oil from the rock.

It is apparent ,then that wells must be properly located to meet the geometric and

stratigraphic configurations of the reservoir and to permit effective use of the reservoir

producing mechanism. With meeting these conditions ,the ultimate oil recovery is

essentially independent of well spacing.

GOOD PRACTICE :

The oil industry generally has come to recognize that there is such a thing as good

practice in the development and production of oil and gas reservoirs. Through

cooperative effort ,much has been done to promote good practice based upon sound

fundamental principles. This effort, within the framework of conservation laws adopted to

control the drilling of wells, the rte of oil and gas production ,and other factors that affect

the efficient recovery of oil ,has evolved into the workable system of present –day

conservation.

Application of good practice requires that each field be given individual technical study.

Certain general principles governing the efficient exploitation of oil fields have been


recognized ,but these principles can serve only as a guide in the solution of the specific

problem. Only by obtaining adequate information on the producing zone ,its contents

and the pressure and production behaviour of both the reservoir and its wells can an

intelligent geological and engineering analysis be made. There is no substitute for

factual data. A sound analysis based on facts is essential to proper control and efficient

operation.

DEVELOPMENT OF THE NEW RESERVOIR :

The discovery of a new oil reservoir presents to the geologist ,engineer, and operator a

challenging problem in planning a sound well spacing programme early in the

development stage to achieve maximum efficiency in recovery with a minimum number

of wells. Planning such a programme requires the early accumulation of factual data

necessary to determine the proper well spacing for each field. The importance of

obtaining field rules during the early development period that provide for proper spacing

cannot be overemphasized. The establishment of field rules that might encourage or

lead to the drilling of unnecessary wells should be avoided. Unnecessary wells burden

the industry with excessive capital investment ,promote waste by creating a pressure for

allow-ables beyond the range of efficient producing rates ,and endanger the correlative

rights of operators who have confined their drilling to wells necessary for efficient

operation.

Early planning of a sound programme inherently places a mutual responsibility upon the

operator and the regulatory body-upon the operator to obtain sufficient data to make a

reasonable accurate appraisal and upon the regulatory body to promulgate ,in the light

of those facts ,the field rules to promote maximum reservoir efficiency. Maximum effort

should be directed toward the early accumulation of as much pertinent data as possible

in order that adequate technical information regarding proper spacing may be available.

It is prudent ,then to employ wide initial spacing in the development of a new reservoir to

permit early determination of the areal extent and geological characteristics of the pool,

the amount of oil and gas reserves ,the properties of the reservoir rock and its contained

fluids, and the nature of the producing mechanism . Early knowledge of these factors will

permit the strategic location of infill wells ,if needed, and the determination of whether


the natural recovery mechanism should be augmented by the injection of gas or water

for efficient recovery. It will also permit an early determination of the need for field-wide

unitization and will aid in the ultimate accomplishment of unitization.

Initial development on the widest feasible spacing is not only sound from an engineering

and geological viewpoint but best serves the public interest from the standpoint of sound

conservation. This view is shared by a majority of those in industry who have studied the

matter.

Therefore, as conclusion it can be said that:

For proper reservoir control in new fields, it is important to determine as promptly as

possible the structure, the reservoir characteristics ,the extent of the reservoir , the

magnitude of the reserves ,the primary reservoir energy source ,and the type of reservoir

control which will permit the greatest recovery. These data can best be determined by

drilling new fields on the widest possible spacing pattern .Wide-spacing development

programmes afford information that may be used to locate the most advantageous

structural position or the drilling of future infill wells and eliminate the expense of drilling

many unnecessary wells. Each reservoir presents a separate problem in the

determination of the well-spacing pattern.

RATE OF PRODUCTION :

Efficient recovery of oil from the reservoir demands a basic working knowledge of fluid

mechanisms and of the specific processes by which oil is recovered . The task then lies

in applying this knowledge to each reservoir. This application requires that the individual

characteristics of the reservoir be recognized ,that the process best suited to the

particular reservoir be chosen, and that the reservoir be so operated as to yield

maximum possible ultimate oil recovery.

Therefore, the following approach be adopted as soon as possible after the discovery of

each new reservoir. First, the type of drive naturally available and its relative

effectiveness to recover oil should be determined early. Early identification of the type of

drive requires that sufficient data on the reservoir and fluid properties and on the

pressure behaviour be accumulated to make a reasonably accurate appraisal.


With such information a choice can be made early as to the recovery technique to be

employed –whether to take full advantage of the natural drive present ,whether to

supplement the natural drive ,or whether to modify it completely by gas or water injection

or by employing one of the more recently developed techniques such as enriched gas

drive ,in-situ combustion ,etc. The earlier a choice is made between whether to operate

with an expanding gas cap or with a water drive ,the lower will be the total development

and operating costs and the greater will be the ultimate net return. In the development

aspect , the arrangement , location, and manner of completion of the wells must be

different for efficient control of a gas-cap drive than for efficient control of a water drive.

Under either drive it is usually desirable to conduct the operation at a high level of

reservoir pressure to avoid dominance of the depletion by dissolved gas drive. This

means starting the operation as early in the life of the pool as possible ,before serious

decline in reservoir pressure has taken place.

REQUIREMENT FOR PROPER CONTROL OF RESERVOIR PERFORMANCE

Efficient recovery of oil depends upon the degree to which the advancing gas or water

invades the entire reservoir and upon the uniformity with which the gas or water

displaces or flushes oil from all portions of the reservoir rock behind the advancing front.

The basic requirement for proper control of an oil reservoir may be summarized as :

I. An efficient dominant mechanism for the recovery of oil must be chosen. The recovery

mechanism may be solely the natural drive , if reservoir conditions are favourable ,it

may be augmented or supplemented by injection of gas or water ,or it may be modified

to create a completely new drive by injection of gas or water.

II. The dominant mechanism must consist in the progressive advance of gas or water

throughout the entire reservoir ,with the invading fluid displacing oil ahead of it to the

producing wells.

III. The boundary between the invaded and un-invaded portions of the reservoir must be

sharply defined and at all times reasonably uniform.

IV. Throughout the invaded portion of the reservoir ,oil should be flushed uniformly

regardless of variations in the texture of the producing formation. There must be no

trapping or bypassing of highly oil-saturated zones behind the advancing gas or water

front.


V. Excessive dissipation of gas or water must be avoided.

VI. Well should be so located and so completed as to permit adequate control of the

movement of the advancing gas or water for effective displacement of the oil.

VII. The reservoir pressure must be maintained throughout the recovery process at a

sufficiently high level to prevent excessive release of gas from solution.

CONTROL OF RATE OF PRODUCTION

Efficient recovery of oil from a reservoir is not obtained by chance ; it is accomplished

only by careful and deliberate action on the part of the operator. Experience has proved

that one of the most essential factors in meeting the requirement for efficient oil recovery

is control of the rate of production. Technical studies and observance of field behaviour

have shown that excessive rates of oil production lead to rapid decline in reservoir

pressure, to premature release of dissolved gas ,to irregular movement of the gas or

water displacement fronts ,to dissipation of gas and water ,to trapping and bypassing of

oil and , in extreme cases ,to a dominance of the entire recovery by inefficient dissolved

–gas drive. Each of these effects, resulting from excessive withdrawal rates, reduces the

ultimate recovery of oil. It is generally recognized that the most effective method of

controlling the displacement mechanism for increased ultimate oil recovery is to restrict

the oil –production rate.

Control of the rate of oil production alone will not necessarily suffice to ensure production

by a displacement drive. It is necessary also to control the progressive movement of the

displacing gas or water and to prevent their premature dissipation. Excessive production

of gas and water not only impairs the effective displacement of oil but leads to an actual

loss in ultimate recovery. Conservation measures taken to prevent waste of gas and

ineffective use of available water drive are essential adjuncts to proper control of

reservoir performance.

MAXIMUM EFFICIENT RATE

Definition : The ultimate oil recovery from most pools is directly dependent on the rate of

production. This dependence is such that for a chosen dominant mechanism for each

reservoir there is a maximum rate of production that will permit reasonable fulfillment of

the basic requirements for efficient recovery. Increase in the rate of production beyond

the maximum commensurate with efficient recovery will usually lead to rapidly increasing


loss of ultimate recovery. Reduction in rate below this maximum will not materially

increase the ultimate oil recovery. From these considerations there has developed the

concept of the Maximum Efficient Rate of production, commonly referred to as MER.

The maximum efficient rate for an oil reservoir is defined as the highest rate that can be

sustained for an appreciable length of time without damage to the reservoir ,and which if

exceeded would lead to avoidable underground waste through loss of ultimate oil

recovery.

GENERAL CRITERIA FOR DETERMINATION OF MER :

The concept of MER has a sound basis as an engineering principle in reservoir

technology. The MER is not an invariable characteristic of a reservoir but is dependent

on the recovery mechanism employed as well as on the physical nature of the

reservoir ,its surroundings ,and its contained fluids. For the same reservoir it will be

different for one recovery process than for another, and for the same mechanism the

MER may vary with the degree of depletion. It is possible through technical study of the

reservoir and its behaviour to determine the MER ,provided adequate geologic and

operating information on the reservoir is available.

In establishing the maximum efficient rate for a reservoir ,two independent physical

conditions must be satisfied:

A. The rate must not exceed the capabilities of the reservoir.

B. The individual well rate must not be excessive.

A third condition ,this one economic ,must also be satisfied : the individual well rte must

not be so low as to prohibit profitable operation.

In the early stages of development of a new field ,the MER is usually limited by the

efficient rate for the individual wells. After development is essentially complete ,there is

usually a sufficient or even an excessive number of wells to produce in the aggregate

the reservoir MER without simultaneously exceeding the capabilities of the individual

wells to produce efficiently. Hence, in the later stages of development, the controlling

limitation on the MER becomes the reservoir’s efficient capacity. In any case, the

smaller of the two capacities ,either of the reservoir or of the individual wells ,fixes the

MER for the field.


MAXIMUM EFFICIENT RATE FOR DIFFERENT TYPES OF RESERVOIR :

Dissolved –gas-drive Reservoirs – When a reservoir is operated under a dissolved-gas

drive ,the only displacing agent utilized is the gas released from solution ,with no other

source of gas and no water being effectively employed. This type of drive is inefficient

because the dissolved gas is released everywhere throughout the reservoir, is not

segregated ( in reservoirs having flat structures or where the force of gravity is not

utilized to permit effective segregation of gas upstructure),and cannot be prevented from

escaping through the producing wells during production operations. Both the rate of oil

flow and the ultimate oil yield depend primarily on the degree of exhaustion of the gas.

The determination of MER must take into consideration the following three classifications

of dissolved gas drive reservoirs :

Class1 . Those reservoirs in which there is potentially available free gas or water that

might , under different operating conditions ,be employed to change the dominant

recovery mechanism to a more efficient type of drive.

Class2. Those reservoirs in which no free gas or water is potentially available but whose

physical properties and fluid characteristics are favourable for segregation of gas within

the reservoir.

Class3. Those reservoirs having no displacing fluid potentially available other than

dissolved gas and whose characteristics are unfavourable as to permit no reasonable

modification of recovery efficiency through control of rate of production .

Pools in class 1 are those which initially contained sufficient free gas to provide a gas-

cap drive ,or into which sufficient influx of water could take place if operating conditions

were properly modified. These pools operate by dissolved-gas drive most frequently as a

result of improper reservoir control. This may entail (1) dissipation of free gas through

production of gas-cap wells or upstructure wells having high gas-oil ratios;(2) dissipation

of water through excessive production of water by edge wells; (3) excessive rates of oil

production ,such that oil is depleted by dissolved-gas drive substantially faster than oil

can be replaced by migration ahead of an expanding gas cap or advancing water. The

MER of class 1 reservoir is the rate that will permit a more efficient mechanism to


replace the dissolved –gas –drive mechanism ;it is the MER of the substituting

mechanism.

Class 2 pools operate under dissolved –gas drive because the sole displacing agent

naturally available is dissolved gas. However, pools in this category have physical

structures , reservoir-rock properties ,and oil viscosities that are favourable for the

employment of gas or water in an efficient manner as a displacing fluid. In these

reservoirs the less efficient dissolved-gas drive may be completely modified by the

injection of gas or water. Under this type of operation the MER would then be the MER

of a gas-cap drive or water drive mechanism employed. A third alternative would be to

use only the dissolved gas naturally available within the reservoir but to operate the

reservoir in such a manner that the force of gravity is utilized to permit effective

segregation of the liberated gas in the upper portion of the reservoir .In this type of

operation the rate of production is reduced to a sufficiently low value so that movement

of oil down-structure is brought about by gravity ,rather than pressure gradient ,and the

gas released from solution moves up-dip where it can be retained as a secondary gas

cap to displace additional oil.

Dissolved –gas-drive pools in class 3 have reservoir and fluid characteristics so

unfavourable that reduction in rate of oil production would have no appreciable effect on

ultimate oil recovery. Reservoirs placed in this category may have thin formations of little

structural relief, low formation permeability, high oil viscosity, or extreme lenticularity or

irregularity of the producing formation. For pools having no free gas cap ,no potential

water drive ,and physical conditions that prevent segregation of fluids by gravity, it has

not been demonstrated that reduction in rate of production can bring about any

improvement in the recovery efficiency. It is doubtful, according to current understanding,

that a pool of this sort has an MER.

Gas-cap-drive Reservoirs .An efficient gas-cap drive requires continuous maintenance ,

throughout the recovery process, of a distinct segregation between an enlarging gas-

invaded zone containing reduced oil saturation and a shrinking oil zone containing high

oil saturation. The recovery efficiency of this mechanism is very sensitive to the rate of

oil production for two reasons: (1) gas is not an effective oil displacement agent, and (2)


without any restraining factors, encroachment of free gas through the oil zone would

take place through only the most permeable channels, leaving the oil un-displaced in the

remainder of the formation. At high rates of production the pressure gradients caused by

flow of oil dominate the fluid movements in the reservoir, and the reservoir fluid

characteristics. Excessive rates lead to rapid encroachment of free gas throughout the

oil zone with relatively low displacement efficiency. Segregation of free gas under these

conditions is impossible, the entire free gas content is dissipated, the reservoir pressure

is rapidly lowered, and the recovery process reverts to the less efficient dissolved-gas

drive.

An efficient rate of production under gas-cap drive must be a rate such that gravity will

dominate the oil flow to maintain continuously an advancing gas front behind which the

oil saturation will be reduced to a satisfactory low value in regions of low as well as high

permeability. The recovery must be conducted at such a rate that oil migrates into the

lower portions of the reservoir by gravity drainage instead of being compelled to migrate

by expanding gas forcing its way into the oil zone in response to a pressure differential

between high pressure in the gas cap and low pressure in the oil zone. The pressure in

the oil zone actually should remain higher than the pressure in the gas-cap, with free gas

merely expanding to fill space vacated by the oil migrating downward. The chief function

of the gas is to maintain the pressure level at which gravity drainage proceeds. The

higher the pressure, the lower is the oil viscosity and the more rapid the drainage.

At sufficiently low rates of production ,a gas-cap drive of this sort is capable of yielding

very high recovery efficiency. Determination of the MER requires quantitative calculation

of the relationship between rate of production and the amount of residual oil saturation in

all parts of the reservoir at various successive stages of depletion. The MER is directly

dependent on the formation permeability ,the permeability distribution ,the relative

permeability –saturation relationships to gas and oil ,the angle of formation dip, the

fluidity of oil, and the size of the gas cap available to maintain pressure and act as the

displacing medium. Since low oil viscosity is desirable ,there is an advantage to

conducting the drainage at the highest possible level of reservoir pressure. Return of all

produced gas to the crest of the structure often assists maintenance of pressure. To

achieve a uniform advance of the gas-oil contact ,it is necessary that wells be properly

located and completed on the structure ,that upstructure wells be progressively shut in


as they go to gas ,and that oil be selectively produced from wells completed in the lower

portions of the reservoir. It is desirable that individual well rates be restricted to minimize

coning and fingering of gas.

Water-drive Reservoirs. Determination of the MER for a normal water-drive reservoir

requires that certain criteria for efficient operation under this type of drive be taken into

account. The first of this criteria is the reservoir pressure. The reservoir pressure one of

the most direct and useful indications of production efficiency ,serves in a water drive

field to indicate quantitatively the degree to which water influx is able to keep pace with

withdrawals. A proper level of reservoir pressure must be maintained throughout the

production history. This pressure level is usually taken to be one that will not permit

dissolved gas to be released in sufficient quantity to build up within the oil zone a free

gas saturation large enough to allow a flow of the liberated gas.

To determine the MER for a water-drive field ,it is thus first necessary to estimate the

rate of oil production ,together with the attendant production of gas and water, that will

maintain the pressure at the required pressure throughout the life of the field. The MER

determination requires basically a quantitative relationship between the reservoir

pressure and the rate of water influx.

The MER for a water –drive reservoir must also be such a rate that provides reasonably

uniform advance of the water –oil interface and uniform flushing of the oil behind that

interface in the regions invaded by water. Control of the uniformity of the advancing

water front ,as in the case of the advancing gas front ,is dependent upon the balance

between the component of gravity in the direction of flow and the pressure gradients

induced by flow.

Thus, the MER of production for a water-drive field involves ,the following aspects:

1. Control of the rate of oil withdrawal to such a degree that the oil may be

volumetrically replaced by water at a desirable level of reservoir pressure.

2. Control of oil withdrawal such that the force of gravity may keep reasonably uniform

the advancing water-oil interface.

3. Control of the rate of water advance such that dvantage may be taken of capillary

effects that allow water to penetrate and expel oil from the tight sands as well as the


more permeable sands ,thereby flushing oil uniformly from all portions of the

formation as the water-oil interface advances.

4. Control of the production of water and gas to prevent their premature dissipation and

ineffective use.

PRESSURE MAINTENANCE

Significance of Pressure in Reservoir Management :

Source of energy in the reservoir

An ideal monitoring tool.

Controls drilling procedure.

Affects surface facilities designing.

Recovery factor.

Deciding EOR technique.

NEED FOR PRESSURE MAINTENANCE :

Why Pressure Maintenance ?

Energy depletion with time and production.

Lesser oil recovery.

Gas Bypassing

Problem in drilling infill wells

Difficulty in further development of the field.

Requirement of artificial lift.

ADVANTAGES OF PRESSURE MAINTENANCE :

Better displacement and areal sweep efficiencies.

Utilization of dissolved gas

Low viscosity of oil.

More self flowing wells.

Higher API gravity of oil.

Delayed artificial lift requirement.

Facilitates future infill drilling programme.

Disposal of produced water.

OPTIMUM RESERVOIR PRESSURE FOR PRESSURE MAINTENANCE :

• Bubble point pressure.


• Critical gas saturation.

• Formation volume factor.

• Oil swelling

To maintain pressure just below bubble point pressure.

Pressure Options :

In homogeneous reservoirs ,maximum oil recovery can be expected if

flooding is initiated when the bubble point pressure has been reached.

This is because high free gas saturation in residual oil and favourable oil

viscosity.

However, heterogeneous causes the optimal pressure for the highest

recovery to be lower than bubble point pressure.

In case of low bubble point pressure, by the time it is reached the production

rates may have declined substantially making a water flood unattractive.

Under such situations water flood may be initiated much before the bubble point

pressure is reached.

WHY WATER INJECTION ?

Mainly the following two aspects are involved in water flooding :

• To maintain the reservoir /to restrict the decline in reservoir pressure .

• To push the oil towards the producing wells.

Why water is preferred for Pressure Maintenance :

o Cheap and easy availability.

o No damage to the formation.

o Low compressibility.

o High density.

o Favourable mobility ration.

o Easy to inject.

PRODUCTION POTENTIAL OF A WELL

For developing a field, it is necessary to know the production potential of a well i.e., the

optimal rate at which a well can be produced. The production potential of a well is

governed by Darcy’s law, which states that


−=

w

eoo

wfeo

rr

B

pphkQo

ln

)(00708.0

µ

Rearranging the equation,

=

−

w

eoo

o

wfe

rr

B

hkpp

Qo

ln

00708.0)(

µ

=

w

eoo

o

rr

B

hkJ

ln

00708.0

µ

Where, J = Productivity index, STB/day/psi

ko = effective permeability to the oil, mD

h = thickness, ft

The productivity index is a constant characteristic of the well and is critical parameter

which determines the number of wells needed to exploit the reservoir for a given

withdrawal rate.

Efficient reservoir production also demands efficient operation of the wells tapping the

reservoir. The maximum efficient rate for a reservoir cannot exceed the combined

efficient rates of the individual wells. Thus the determination of the efficient capacity of a

reservoir to produce makes it imperative that an investigation of the capabilities and

limitations of each well to produce its proportionate share be conducted. One of the most

useful tools in determining the productive capacity of a well is the flow test. From the

flow test productivity index and specific productivity index of the well are determined.

These data give directly the total pressure drop and the pressure drop per unit of

formation section to a well during flow at a given production rate The productivity test

permits quantitative evaluation of the maximum rate at which a well may be produced to

avoid excessive localized pressure drops around the well, to maintain high oil

saturation ,and to prevent or minimize fingering or coning of gas and water into the well.

APPLICATION OF NEW TECHNIQUES IN FIELD DEVELOPMENT :


The technological advancement is going on all around to overcome difficult situations

and environments there by achieving improvement in recovery with accelerated

production from reservoirs. The techniques that have come up recently are :

o Infill drilling

o Cluster drilling

o Horizontal drilling.

INFILL DRILLING TECHNOLOGY :

Infill drilling concept is applicable to old fields which have been on production for

long .As a result of differential depletion of the reservoir caused due to reservoir

heterogeneity or any other reason ,oil islands are left unswept in the reservoir. The infill

drilling in the unswept part of the reservoir would enable to improve and accelerate

recovery process.

The objectives of infill drilling are :

Increase in ultimate recovery from judiciously selected reservoirs.

Improvement in per well recovery attractive under current economic considerations.

Delineate and minimize pay discontinuity in heterogeneous reservoirs.

Determine size, shape and orientation of fractures.

Determine oil productivity and potential of close grid locations.

Evaluate remaining oil saturation to operative drive mechanism.

Concepts ,analysis and confirmation of simulated data.

Development of shale gas reservoirs.

Exploitation of heavy and extra heavy crude reservoirs.

Monitoring EOR pilots.

Accelerated oil production for quick return when warranted.

To sweep unswept zone ,tapping of untapped traps.

Recovery of “Wedge edge” oil.

Improve areal sweep by minimizing poor geometry effects caused by original well

arrangement and/or initial injection-production well selection.

To eliminate possible adverse effects on prior injection imbalance.

CLUSTER DRILLING :


This is a technique of drilling number of wells from one surface location. Operations are

carried out by shifting a part of the rig equipment especially derrick ,its substructure and

prime movers from one well mouth to the other leaving mud system , pumps, generators

etc. at the same place and the wells are drilled directionally. Normally one well will be

vertical and others are directional.

Clusture drilling is a common drilling practice in offshore. This has also become a

proven technique for on-land fields. Four to five well cluster are presently being drilled in

Lakwa, Geleki, Borholla, fields in E.R. successfully. This technique is applicable in hilly

terrain. This is cost effective too as in cluster drilling on every subsequent well of cluster

only a part of the rig is shifted and complete derigging/ rigging up construction of new

approach roads, new foundations and laying of long pipelines etc. is avoided. Further a

field posing logistic problems due to environment conditions or difficult terrain, cluster

drilling has emerged as the most efficient and economic method of development drilling

technique, world-over.

MERITS AND DEMERITS OF CLUSTER DRILLING :

MERITS :

An overall reduction in well cost is obtained due to reduction in the cost of :

foundation work and land acquisition;

approach roads;

rig building operations

transportation of equipment and material;

pipelines ( oil and gas pipelines, and water lines )

mud chemicals etc.

Rig days are saved in shifting of masts and substructure.

Rig cycle speeds are improved due to saving in the rig building

days.

Field can be put on production quickly.

DEMERITS :

o Length of the well bore increases which results in additional

o expenditure on drilling operations and tubing cost.

o More pressure losses occur in flowing wells due to increased tubing


o length of a directional well.

o Slows down pace of oil production because nearby drilled wells of a

o cluster are kept in subdued condition till all the wells of a cluster are

drilled. This is because simultaneous production is not desirable from safety point

of view.

HORIZONTAL DRILLING CONCEPT :

TECHNOLOGY OVERVIEW

Horizontal wells are a controlled, directional completion technique for exploiting

unrecovered mobile hydrocarbons in existing fields. These reserves usually remain

because the reservoir’s heterogeneity has prevented efficient development using vertical

wells. The primary screening tool is recovery efficiency as measured by the percentage

recovered of original oilin-place (OOIP) or original gas-in-place (OGIP). Screening is

carried out by reservoir characterization, followed by reservoir simulation.

The advantages of horizontal wells include higher productivity and a larger drainage

area per well. In Texas and Louisiana, horizontal wells in the Austin Chalk have become

attractive because of the relatively rapid payout from good initial production rates. The

disadvantages include higher drilling costs and greater mechanical risks. The economic

success rate in the US is about 60%, with failure usually occurring as a result of high

drilling/completion costs, formation damage, reservoir heterogeneity, or insufficient

geological characterization.

Insights

Horizontal wells are typically grouped in three categories and referred to as short-,

medium-, and largeradius wells depending on build rate.

Short-radius wells have a radius of curvature between 20 to 60 ft, a bit size less than 6-

3/4 in., and a drainhole length up to 1,000 ft. Medium-radius wells have a radius of

curvature between 200 to 1,500 ft., a bit size less than 8-1/2 in., and a drainhole length

up to 1,500 ft. Large-radius wells have a radius of curvature greater than 1,500 ft, a bit

size greater than 8-1/2 in, and a drainhole length up to 15,000 ft.


Short-and medium-radius wells can be completed open hole or with slotted liners. Long-

radius wells are typically completed with slotted liners or casing.

There are four basic completion approaches: openhole, slotted liner, cased, or hybrid

completions.

I. Open-hole completion, which requires a stable hole, has several advantages: it

preserves options after the well has been produced and evaluated, it is the easiest and

least expensive on which to perform selective stimulations, and it provides the best

production logs. In general, completions other than open hole are to preserve the

integrity of the hole (guard against collapse and sand production) and to allow zones to

be shut off.

II. Slotted liners are desirable in many cases for sand control and hole support.

III. Cased completions are used by operators to allow more flexibility for shutting off

selected zones after production has begun.

IV. Hybrid completions take advantage of the many drilling technologies available today.

Since large sections of the formation are exposed to drilling mud (with potential

damage) during horizontal drilling, horizontal wells lend themselves to underbalanced

drilling (UBD) methods.

Among its advantages, UBD can minimize formation and environmental damage, reduce

sticking in the differential drillstring, and lessen circulation losses. Gravity-induced mud

invasion of fractures also tends to be reduced. Disadvantages of UBD include the cost of

extra equipment and rig time, pipe connections, and mechanical problems including

sticking, bit jetting and flushing, and mud-pulsed logging. In addition, hole collapse is

possible.

The best UBD technique currently available utilizes coiled-tubing drilling, since it

minimizes most of the problems listed above. As a result, some drilling costs may

ultimately be reduced. The disadvantages of coiled tubing drilling include decreased

directional control, limited casing and bit size, associated costs, and pressure

monitoring.

Multilateral horizontal wells access several target zones in the same well. Potential

problems include: achieving an effective kickoff from the previous leg, formation damage


from mud, and slower cleanup. Once a well begins producing, it is also difficult to

allocate production to specific pay zones.

Enhanced oil recovery applications of horizontal drilling include heavy oil reservoirs and

steam-assisted gravity drainage (SAGD). In contrast to vertical wells using thermal

processes, the benefits of SAGD are increased oil productivity for the number of

required wells, higher production volumes compared to injected steam volumes, and

more ultimate recovery of oil in place. However, SAGD may not be applicable to

reservoirs with low absolute vertical permeability.

LESSONS LEARNT:

Horizontal wells have been effectively applied to naturally fractured reservoirs. In

addition, horizontal drilling is used in reservoirs that are layered or have problems with

water or gas coning, gas storage reservoirs, waterflood and enhanced oil recovery

operations, and heavy oil reservoirs. They now are used in the Austin Chalk of Louisiana

and Texas, as well as North Dakota’s Red River Formation. Horizontal drilling is being

applied in the heavy oil steam floods in California, waterfloods and CO 2 floods in west

Texas, and a variety of carbonate and sandstone reservoirs across

The objectives of horizontal drilling :

Improved productivity in tight reservoirs ,thin beds, soft formation and thin oil column

reservoir which are entrapped between gas cap and bottom water.

Exploitation of fractured reservoirs.

Improvement in per well cost by reducing number of development wells.

To overcome the logistic problem such as key location , located below river bed/

thickly populated area/ hilly terrain area etc.

Improvement in enhanced oil recovery by improving injectivity in steam injection

projects.

Greater dispensing of withdrawals through overcoming the problem of pressure sinks

at a single point.

To overcome problems of deformation of oil/ water and oil/gas interface thereby

delaying water/gas breakthrough.

Exploitation of heavy oil –overcome the problem of adverse mobility.


Characterization of reservoirs –to know the dimension / direction and occurrence of

heterogeneity in some specific areas.

Effective exploitation of :

Naturally fractured reservoirs.

Oil reservoirs sandwiched between gas and water.

Thin reservoir.

Reservoir with good vertical permeability.

DRAIN HOLE DRILLING :

This is also a recent innovation in drilling technology ,which has already been

implemented successfully in many fields. The technique involves cutting a window in

already existing well and drilling horizontally through it. The process requires highly

specialized equipment and technology. The turning radius in this type of drilling is very

low. Typically only few tens of feet. However, the horizontal length of the drain hole ,that

can be achieved is generally in the range of 100-150 mts.

The drain hole enjoys all the benefits of horizontal wells with the exception of productivity

restrictions imposed by drain hole length. However, it has an added advantage of

utilizing already existing wells which might have been abandoned for various reasons.

Obviously these are cheaper than new horizontal wells.

RESERVOIR SIMULATION

Reservoir simulation, or modeling, is one of the most powerful techniques currently

available to the reservoir engineer. Modeling requires a computer, and compared to

most other reservoir calculations, large amounts of data. Basically, the model requires

that the field under study be described by a grid system,

usually referred to as cells or grid blocks. Each cell must be assigned reservoir

properties to describe the reservoir. The simulator will allow us to describe a fully

heterogeneous reservoir, to include varied well performance, and to study different

recovery mechanisms. Additionally, due to the amount of data

required, we often will reconsider data which had previously been accepted. To make

the model run, we perturb the system (usually by producing a well) and move forward in

time using selected time intervals (time steps). The main type of results that we gain

from a model study are saturation and pressure distributions at various times ; quite


frequently, these variations will indicate what the primary drive mechanism is at any

given point in time.

On the other hand, modeling requires a computer with a fair amount of memory and a

great deal of engineering time; you cannot do a model study in an afternoon! It takes

time to locate the data, modify it to fit your grid system, enter it and then to actually run

the model. Minimum time for a very simple study is a week; average time is probably

from 3 to 6 months; large and/or complex studies may encompass years. In short, it

takes much more effort on your part to interpret the results of a simulator and as a result,

small screening models may be used to evaluate key parameters while larger models

would simulate

an entire field in detail. As the field is developed and more data becomes available,

intermediate models are often developed for specific regions or recovery processes in

the field; these models may be called scalable models, but changing the grid presents

additional problems. To be able to decipher what the model is telling you, you must first

define the problem. Simply running a study to model a field is not good enough; you

must decide ahead of time what questions you are trying to answer. Some typical

questions might be:

• What type of pattern should be used for water injection?

• Should a well be drilled in a certain location?

• How would rate acceleration affect the ultimate recovery?

• What is the effect of well spacing?

• Is there flow across lease lines?

• Will the oil rim rise to saturate the gas cap?

• Should gas injection be considered? If so, for how long?

• Should water injection be considered? If so, at what rates?

• Once we have decided what questions need to be answered, we can construct

the model grid.

Types of Models

There are five types of models, depending on the grid selected, that may be used

(although the first two types are used minimally today):

• One-dimensional horizontal

• One-dimensional vertical


• Areal (two-dimensional)

• Cross-sectional (two-dimensional)

• Three-dimensional

Additionally, the coordinate system, number of components (or phases) and treatment of

the flow equations yield a large number of simulation

possibilities. The most common coordinate system in use is that of Cartesian

(rectangular) coordinates.

A one-dimensional (1-D) model may be used to define a bottom water drive, determine

aquifer activity, yield an accurate material balance or as a screening tool prior to a large

complex study. Gravity drainage may be simulated using a 1-D vertical model.

Sensitivity studies may be conducted and interpreted rapidly using 1-D models; these

studies might include the effects of vertical permeability, injection rate, relative

permeability, residual oil saturation, reservoir size, etc. This information would be

extremely useful in more complex studies. Individual well behavior cannot be modeled

using a 1-D model; however, field behavior may be approximated. Trying to match

production history of individual wells using a 1-D model is both fruitless and time

consuming. 1-D models are seldom used extensively today.

There are two types of two-dimensional (2-D) Cartesian models; the most common is

the areal model. Strictly speaking, an areal model should be used only if there will be

very little vertical movement of fluids as in a thin sand; however, the areal model is also

employed for thick sands when no great differences in permeability exist (i.e.,

permeability layering). Dip can be incorporated in an areal model, although water under

running or gas overriding may not be in its proper perspective if permeability layering

exists. The effects of varying well patterns, both in type and spacing may be studied with

an areal model.

The other type of 2-D cartesian model, the cross-sectional model, is often used to

simulate a slice of a field. It will show vertical and horizontal movement, but is not useful

for determining well patterns. Its greatest usage is in determining completion intervals

and stratification effects. Usually, when orienting a cross-sectional model (commonly

called an X-Z model), the cross-section is taken parallel to the fluid movement (up or

down dip). This type of model is used for thick, layered reservoirs, water under running,

gas segregation, or a series of reservoirs co-mingled in the well bore.


The three-dimensional (3-D) model can handle any and all of the previous types of

studies; however, the computer time and interpretive engineering time are greatly

increased over that required for 2-D models. A 3-D model must be used when fluid

migration is expected parallel to the strike of a thick steeply

dipping bed (i.e., fluids will flow up dip and across dip). If a typical section of a field

cannot be determined for use in a 2-D model, then a 3-D model is required; however,

finely modeling the area of concern and “lumping” the remainder of the field into a few

large cells may save considerable time and money as shown

in the windowed model (Fig. 3.29, p. 24, M-13). Once again, you must define your

problem before you start to model it.

The second type of coordinates employed in simulation is the radial (R-Z-) or

cylindrical system and may exist in one to three dimensions. Radial systems in two

dimensions (R-Z) are sometimes referred to as coning models based on their early

applications for studying the effects of coning phenomena. They are single well models

designed to study individual well effects; additional wells may be included, but they will

not exhibit the performance shown in actual production. Coning models are fully implicit

in order to handle the rapid saturation changes that occur near the well bore. Field

studies (whole or partial) may also be performed using a cylindrical system, but this

application has found limited use. Aquifers may be simulated in radial models by use of

a water injection well in the

outer block; this technique works well for strong aquifers but may present problems with

weaker water drives. Radial models may be used to study coning, shale breaks, well

tests, vertical permeability effects, heterogeneity, and to determine maximum producing

rates; however, when studying coning, after shut-in, the cone will fall in a simulator

without hysteresis; whereas in reality, the cone will not completely drop and imbibition

effects will greatly inhibit future production.

Black oil (or Beta) models consist of three phase flows: oil, gas, and water, although

additional gas or aqueous phases may be included to allow differing properties. These

models employ standard PVT properties of formation volume factors and solution gas

and are the most common type of simulator.

Compositional simulators are similar to black oil models as far as dimensions and

solution techniques are concerned; here, the similarity ceases, for while volume factors


and solution gas effects are employed in a black oil model, a compositional model

employs Equations of State (EOS) with fugacity constraints,

and uses equilibrium values, densities and several varying components (including non-

hydrocarbons). Considerable time is required in the phase package (i.e., matching lab

data with simulator requirements) before the actual model can be run. It is reasonable to

state that this type of model requires additional expertise to be useful.

Finally, treatment of the model equations yields either an IMPES (implicit pressure,

explicit saturation) formulation, a fully implicit formulation, or some combination

thereof. Very simply, an IMPES model is current in pressure and solves for saturations

after pressures are known while a fully implicit model solves for both pressures and

saturations simultaneously. Rapid saturation changes require fully implicit models. The

semi-implicit treatment is a combination which attempts to estimate what saturations will

exist at the end of the time step.

1.2. Data Requirements

Variables required for assignment to each cell (location dependent):

• Length

• Width

• Thickness

• Porosity

• Absolute permeabilities (directional)

• Elevation

• Pressure(s)

• Saturations

Variables required as a function of pressure:

• Solution gas–oil ratio

• Formation volume factors

• Viscosities

• Densities

• Compressibility

Variables required as a function of saturation:

• Relative permeability

• Capillary pressure

Well data:


• Production (or injection) rate

• Location in grid system

• Production limitations

Lengths are normally obtained by superimposing a grid system on a field map and

measuring the appropriate distances. These increments are usually denoted using the

variable x with the subscript “i” referring to the cell location by column (running from left

to right). The standard practice of overlaying a grid on a map is used for one-

dimensional (both horizontal and vertical), areal and three-dimensional models. For

dipping reservoirs, the aerial distances will be shorter than the actual distances between

the wells. Usually, this discrepancy is not apparent due to the available accuracy of

several of the reservoir descriptive parameters, particularly for dip angles of less than

10; however, the variation may be corrected using pore volume and transmissibility

modifiers or as an input option in some simulators. The actual length is r = x/cos.

Widths are measured in the same manner as lengths and the same discussion applies.

Note that the widths in a cross sectional model need not be constant. Widths are

denoted as y with a subscript “j” and are sequenced by rows from rear to front (top to

bottom in an areal model).

Thickness values are obtained from seismic data, net isopach maps (for areal and 3-D

simulations), well records, core analysis and logs (for cross-sectional models).

Thicknesses in an areal model may vary with each cell and are denoted as z. For

layered models the subscript “k” is employed to denote the layers; they are sequenced

from top to bottom. For areal considerations (including 3-D), thickness values may be

obtained by superimposing a grid on a net pay isopach. Obviously, thickness values may

also be obtained by subtracting the bottom of the formation from the top of formation

when these maps are available; at this point, gross pay is known and must then be

reduced to net pay. Note that unless a net-to-gross input option is employed, thickness

must be a net pay. When constructing a cross-sectional model using well records and

logs, the actual distance between cell centers (centroids) is employed; however, the

pore volumes calculated in this instance are in error when (vertical) net pay is used since

they are calculated based on (length width net pay porosity).


Reservoir Simulation & History Matching Workflow

Enabling our engineers to give real insight into past and future reservoir

performance


SIMULATION STUDIES

Reservoir simulation process has been divided into three stages :

1. Initiation

2. History Matching

3. Predictions.

Each stage needs to be satisfied with positive results before jumping over to next stage.

However intermediate stage of history matching is most tedious part of simulation

studies.

INITIATION :

1. Make a data checking run and proceed further with the following steps :

A. Check initial fluid volumes in place and compare with volumetric

B. Calculations.

C. Check all reservoir property maps and input data. Don’t rely on data checking

routines supplied with the model to uncover all errors.

1. Make an equilibrium run with flow rates on all wells set. To zero. This should

simulate the history plus prediction period. Large time steps ( one year or more )can

be used. Check that the model is equilibrated properly. A reservoir is usually in a

static state before the first wells come on stream. A zero rate simulation is made to

assure the initial and final states are he same..

HISTORY MATCH AND PREDICTION:

The reservoir engineering continues to play an important role in the later stages of the

field developments. In fact the available data on the performance of the field serves as

feed back to the model and it helps in making the simulation more in accordance with

the real system. The knowledge about the performance of the field helps one to narrow

down the uncertainty and limits on various parameters so as to update our information

about the reservoir. This leads to more meaningful conclusions about the reservoir

performance in future. At this stage models can help us to make the decisions like :


1. Desirability and locations of new wells.

2. Optimum production rates of the existing wells for maximizing recovery.

3. The extent of natural energy mechanisms for driving the fluid and necessity of

supplementing it by various ways and so on.

The model in these later stages is constrained by the known performance . The model

must reproduce the behaviour over the known period. This is achieved by varying the

reservoir parameters within the admissible range. This leads to the perfection of

information regarding the reservoir .This predictions based on the history matching are

more reliable for longer history match. History matching is the process of matching the

model results to the actual field performance for the past.

The steps involved in conducting a reservoir simulation study whether it is quantitative or

qualitative are depicted schematically below :

DATA PREPARATION --PREDITION RUNS --- ANALYSIS RESULTS

I I I

I I I

SENSITIVITY RUNS I

I I

I I

I I

I--------------HISTORY MATCH

The variables in a reservoir model may be classified as state variables input parameters

control variables and output ,performance or response variables. The input parameters

are the rock properties and empirical data such as relative permeability ,capillary

pressure and PVT data. The state variables are those that determine the state of the

system at any time in a numerical simulator these are the pressure saturation

distributions .The control variables are the injection or production rates or a sand face

pressure. The response variables are production rates or average reservoir pressures,

WOR,GOR , etc.


UNCERTAINTY OF THE RESERVOIR DATA:

The input parameters have some uncertainty in their values. Some reservoir data are

known with accuracy are referred to as determinates and will not be adjusted during a

history match. For example, it is usually valid to assume that the fluid properties below

the bubble point ( Bo, Bg, Rs, g, o) are determinates for a reservoir that is single

connected unit and if careful measurements were made. The bubble point pressure Pb,

is assumed to be a determinate only if reliable sampling procedures were used.

The reservoir formation properties ( e.g. ,K ,Kr, Pc ,Cr ) are measured where the well

penetrates the reservoir. Even then the measurements are subject to significant errors.

The values of the formation properties within the reservoir between wells are inferred

from geological and petrophysical correlations. Thus, the distribution of formation

properties usually has a large degree of uncertainty. The limits of uncertainty depend on

the accuracy of measurements and the geological and the petrophysical correlations.

Generally, however, these are regarded as indeterminate. The hydrocarbon pore volume

and the aquifer size (if any ) are often regarded as indeterminate.

The reservoir performance variables themselves may be subject to significant error. The

oil production rates are usually measured accurately but the water and gas may have

been estimated from occasional water cut and GOR measurements. The well rates

usually have large fluctuations with time .These short time fluctuations must be

smoothed as averaged rates specified over finite interval of time.

PREDICTIONS

After history matching it is assumed that the reservoir is well modeled. Predictions runs

can be done to study the behaviour of the reservoir in the future, for example under

natural depletion .Other projects can be added to the simulation study e.g. water or gas

injection .Comparisons of the runs must lead to the best scheme of field development.

Prediction runs under natural depletion lead to :

o know in which well and layer ,it will be necessary to perform a work over .

o know the final recovery with existing wells at different production rates.

o Know the final recovery by drilling wells in the unswept areas.

Before, starting simulation runs this procedure should be followed :


1) Material balance with field data to get an idea of the amount of fluid in place.

2) Review of all field data i.e. production, decline, water-oil and gas-oil ratios.

The review of production data often gives some ideas for future modifications of the

initial model, for instance it will be important or not to change permeabilities in an area,

to lower some blocks in a zone badly defined to modified some well relative permeability

curve, etc.

Fundamentalsof Basic Reservoir Engineering 2010

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