basic knowledge petroleum industry reservoir engineer_vt

8/11/2019 Basic Knowledge Petroleum Industry Reservoir Engineer_VT

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Basic Knowledge Petroleum

Industry Reservoir Engineer

Vivi Tanuwidjaja SLB Reservoir Engineer

SPE SC UI 30 April 2011


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Personal Background

Name: Vivi Indrayanti Tanuwidjaja

Petroleum Engineering, Trisakti University

Join SLB since 2006 as a reservoir engineer Mainly support Formation Tester. Borehole

reservoir study

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Outline

Introduction

Petroleum Geology

Reservoir Rock properties Reservoir Fluid properties

Reservoir fluid types

Drive Mechanism

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Introduction

Definition of Reservoir Engineering

Application of scientific principles to the drainage

problems arising during the development and

production of oil and gas reservoirs

The art of developing and producing oil and gas

fluids in such a manner as to obtain a higheconomic recovery.

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Petroleum Geology

Reservoir Accumulation

There must be a source rock containing organic

matter and it must be buried deeply enough so

that temperature and time can cause the organicmatter to mature into petroleum

Not all the organic matter to mature can becomes

petroleum.

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Reservoir accumulation

There are five factors that comprise the critical risks to petroleum

accumulation; 1) a mature source rock, (2) a migration path connecting

source rock to reservoir rock, (3) a reservoir rock that is both porous and

permeable, (4) a trap, and (5) an impermeable seal.

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Traps

A trap is a geometric configuration of

structures and/or strata, in which permeable

rock types (the reservoir) are surrounded and

confined by impermeable rock types (the seal)

Most traps fall into three categories: structural

traps, stratigraphic traps or combination traps

(both structural and stratigraphic traps)

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Traps Cont Structural traps are the most

common exploration target. It coversover 75% of the worlds discovered

reserves

Stratigraphic traps are formed due

to lateral and vertical changes in rock

type. It covers around 13% of the

worlds reserves

Combination traps contain about 9%of the worlds petroleum reserves.

These traps are often found in areas

where faults and folds were actively

growing during deposition8


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Seals

Traps must be sealed byimpermeable barriers inorder to stop the continuedupward migration of

petroleum

Shale is the dominantcaprock or worldwidereserves. Evaporites are the

most efficient caprock andcommonly in carbonate-richbasins

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Crude Oil Classifications

Crude oil is a natural mixture of

hydrocarbons that is liquid in

underground reservoirs and

remains liquid at the surface after

passing through separating

facilities.

Most normal crude oils falls into:

Rich paraffins

Paraffins &naphthenes

Aromatic intermediate oil The chemistry of petroleum

determines the types and amounts

of refined hydrocarbon produced

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Reservoir Rock Properties

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Porosity

Definition Percentage of the formation volume available to

store fluid

Three Main Types of Porosity1. Inter Connected multiple pore throat passages

2. Connected single pore throat passages

3. Isolated no connection between pores

1 + 2 = Effective Porosity

General Rule: Porosity decreases with depth12


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Porosity

Intra-granular Porosity

(Limestones)

Inter-granular Porosity

(Sandstones)

Primaryformed during

deposition

Fenestral (Shrinkage)

Intercrystalline

(Between Crystals)

Solution

(Leaching of Solution)

Moldy or Vuggy

Fracture

Secondary

Formed after

deposition

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Idealized Packed Spheres

CUBIC PACKING

HEXAGONAL

PACKING

RHOMBOHEDRAL

PACKING

= 47.6%

= 39.5%

= 25.9%

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Porosity Types

Sandstones Primary Inter-granular

Dissolution or Vug

Micro-pores

Fractures

Carbonates Inter-particle/inter-particle

Inter-crystal

Moldic / Fenestral / Vug

Fracture

Porosity of rocks varies between ~1% to over 40%

Mediocre if: < 5 %Low if: 5% < < 10 %

Average if: 10% < < 20 %

Good if: 20% < < 30 %

Excellent if: > 30 % 15


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Permeability

Ability with which a fluid can flow through a

formation is a measure of how permeable the

rock is.

As a rule of thumb, horizontal permeability is 10 times

greater than vertical permeability. (non fractured systems)

Aerially, permeabilities can also vary considerably and

trends are usually identified as the direction of flow and

the best reservoir quality

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Permeability

There must be some continuity between pores to

have permeability.

Unit of Permeability is the Darcy.

It is defined as that permeability which will allow a fluid of onecentipoise viscosity to flow at a velocity of one centimeter per

second for a pressure drop of one atmosphere per centimeter.

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Permeability grain size

Porosity is independent

of grain size, however

permeability is different.

The finer the grain size,

the narrower the throatpassages between pore

spaces and it makes

harder for fluids to move

through a rock

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Permeability grain sorting

The better sorted the

sand, the higher are both

porosity and permeability.

This is because the pore

spaces are being pluggedup by the finer particles

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Absolute Effective Permeability

Absolute permeability occurs when only onefluid present in the rock. Absolutepermeability is calculated by darcys law using

laboratory-measured data Effective permeability occurs when more than

one fluid is present. It is a function of the fluidsaturation

The ratio of effective to absolute permeabilityis termed relative permeability

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Permeability Range

Range is very wide: 0.1mD to > 10 D

< 1 mD :Mediocre

1 to 10 mD :Very Low

10 to 50 mD:Low

50 to 200 mD:Average

200 to 500 mD:Good

> 500 mD :Excellent

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Saturation

Saturation of a phase is the fraction of

the pore volume occupied by the phase

So + Sg + Sw = 1

Connate water saturation (Swc) is

primarily reduces the amount of spaceavailable betweeen oil and gas

(irreducible water)

Soc (Critical oil saturation) is the most

exceeded value where the oil remains

in pores (will not flow)

Sgc (Critical gas saturation) is the most

exceeded saturation value where the

gas immobile

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Wettability

Is defined as the tendency of one fluid to spread or adhere to

a solid surface in the presence of other immiscible fluids

for a rock-water-oil system, it is the rocks preference for either water

or oil

when two immiscible fluids such as oil and water are togetherin contact, the angle measured in water is called the contact

angle .

This is a quantitative measure of Wettability

OilWater

If < 90 then Rock is water wet

If > 90 then Rock is oil wet

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Effect of Wettability

0.4

0

0.2

400 1006020 80

Water Saturation (% PV)

RelativePermeability,

Fraction

1.0

0.6

0.8

Water

Oil

Strongly Water-Wet Rock

0.4

0

0.2

400 1006020 80

Water Saturation (% PV)

RelativePermeability,

Fraction

1.0

0.6

0.8

WaterOil

Strongly Oil-Wet Rock

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Reservoir Fluid Properties

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Hydrocarbon Phase Behaviour

Thermodynamics is the branch of science thatstudies fluid Phase behavior.

A Phase is the status in which a fluid existsand is separated by a physical boundary.

Only three phases exists:

Vapour

Liquid

Solid

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Hydrocarbon Phase Behavior

PVT, WHAT DOES IT MEAN?

PVT ( Pressure-Volume-Temperature) is the term used todescribe the study of fluids. In Petroleum engineering, it is the

study of hydrocarbon fluids and formation waters.

Understanding the behaviour of reservoir fluids as pressureand temperature varies, is crucial in determining the futureperformance of the reservoir and its impact on wells and

surface facilities.

PVT data is usually derived from laboratory experimentscarried out on representative samples of reservoir fluids.

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Hydrocarbon Phase behaviour

Single component system

Critical Temperature =

Temperature above which 2

phases cannot co-exist in

equilibrium regardless of thepressure.

Critical Pressure = Point

above which 2 phases

cannot co-exist inequilibrium.

Critical Point = Point above

which no phase transition is

clear

Critica

l Point

TC

PC

Liquid

Gas

Temperature

Pressure Temperature Plot

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Multi component system At all pressures and temperatures within the phase diagram,

two phases exist. All points outside the phase envelope showonly one phase.

Critical Point = all intensive properties of the gas and liquidphases are equal (density, viscosity, surface tension,composition)

Cricondentherm = maximum temperature at which twophases can exist at equilibrium right most extremity of

the phase envelope Cricondenbar = maximum pressure at which two phases

can exist at equilibrium - uppermost extremity of thephase envelope

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Multi component system cont Bubble Point

As one decreases the pressure (increasing To notusually an option) within the reservoir, it is the

point (pressure) at which the first bubble of gasstarts to break out of solution for a giventemperature.

Dew Point

As one decreases (gas) or increases (liquid) thepressure within the reservoir, it is the point(pressure) at which the first droplet of liquid isformed . (used for gas systems)


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P-T phase diagram of a Reservoir Fluid

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Bo = formation volume factor (rm3/stm3)

Volume occupied by one stock-tank unit volume

of oil and its associated gas in the reservoir at the

given pressure P and temperature T.

Boi = initial formation volume factor (rm3/stm3)

Volume occupied by one stock-tank unit volumeof oil and its associated gas at virgin reservoir

conditions (Pi, Ti, Cum Prod = 0)

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Bg = formation volume factor (rm3/stm3)

Volume occupied by one stock-tank unit volume of gasin the reservoir at the given pressure P andtemperature T.

Bgi = initial formation volume factor (rm3/stm3)

Volume occupied by one stock-tank unit volume ofgas at virgin reservoir conditions (Pi, Ti, Cum Prod = 0)

Rs = Solution Gas Oil Ratio (GOR).

Volume of gas measured at standard conditions,which will dissolve in a unit volume of stock tank oil atthe given pressure and temperature conditions.

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Reservoir Fluid Types

Two Types = Hydrocarbon & Water

Hydrocarbon Classification

Dry gas

Wet gas

Retrograde Condensate

Volatile Oil

Black oil

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Black Volatile Retrograde Wet Dry

Oil Oil Condensate Gas Gas

GOR < 300 300-600 > 600 > 2500 no

liquid

API gravity < 45 >40 > 40 up to 70 no

liquid

liquid color dark Light

color

light water no

color white liquid

C7+ mol% > 20 12.5-20 4-12.5 0.7-4


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Drive Mechanisms

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Oil Reservoir Drive Mechanisms

Each reservoir is composed of a unique combination of geometric form,geological rock properties, fluid characteristics, and primary drive

mechanism

Each of primary drive mechanism has certain typical performance

characteristics in terms of

Ultimate recovery factor Pressure decline rate

Gas-Oil ratio

Water production

There are 5 basic drive mechanisms for primary recovery:

Gravity-drainage drive

Solution-gas drive

Gas-cap drive

Water drive

Combination drive 37


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What drives recovery???Primary Drive

Mechanisms

Gas Drive

Solution Gas Drive

Water Drive

No external pressure support

Low Cost

First 5 35% RecoverySecondary DriveMechanisms

Gas Injection

Water Injection

External pressure support medium cost

Next 10 25%

Recovery

e.g.

steam

polymer

surfactant

miscible gas

External pressure support High cost

Next 15

35%Recovery

Tertiary Drive Mechanisms

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Gravity-Drainage Drive

Main characteristics: Differential gravity is the main drive energy

Segregation of the gas occurs and because oilcompressibility is low, pressure drops rapidly until it

reaches the bubble point Liberated gas has a tendency to move up structure to

form a secondary gas cap.

Unless assisted by artificial lift, pressure decline causesthe oil production to drop rapidly.

Slow steady production contributes to minimizing theGOR as it allows the liberated gas to migrate up thestructure.

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Solution gas drive(Depletion drive)

Main characteristics:

oil compressibility is the main drive energy

because oil compressibility is low, pressure drops rapidly

until it reaches the bubble point once bubble point is reached, solution gas is liberated.

since liberated gas has high compressibility, the rate of

pressure decline per unit of production reduces.

Once critical gas saturation is exceeded, produced GORincreases unless the conditions are right for a Secondary

Gas cap to be formed

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Solution-Gas Drive in Oil Reservoirs

Oil

A. Original Conditions

B. 50% Depleted

Oil producing wells

Oil producing wells

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Solution gas drive(Depletion drive)

Performance: Encourages formation of secondary gas cap

By location of wells away from the crest

By maintaining low p at the producing wells

Typical recovery factor of 5 - 30 %, is dependent on: Initial reservoir pressure

Solution GOR

Reservoir dip

Works well with

Low density / low viscosity Oil High bubble point pressure

Abandonment : high GOR, low res. Pressure

Supplement with Gas or Water injection

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Gas cap drive


initial condition: primary gas cap is present

high gas compressibility provides drive energy

the larger the gas cap the greater the energy locate wells as far away from GOC as possible.

but Wells too near to OWC ------> Coning

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Gas-Cap Drive in Oil Reservoirs

Cross Section

Oil producing well

Oilzone

OilzoneGas cap

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Gas cap drive

Performance: Slower decline in reservoir pressure

Longer production plateau

GOR increases as gas cap expands

Typical RF = 20 - 40%

Reservoir dip,

Size of gas cap

Prolong reservoir life by

GOR control

Re-completing wells

Gas re-injection into gas cap Works well with

Relatively large ratio of gas cap to oil zone

High reservoir dip angle

Thick oil column

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Water Drive


Initial condition:

large underlying aquifer (at least 10 times oil volume)

aquifer should have good permeability andcommunicates with the oil sand.

Wells position high up structure

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Bottom-water Drive in Oil Reservoirs

Oil producing well

Cross Section

Oil Zone

Water

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Water Drive

Performance: Knowledge of size and permeability of aquifer not usually

available

hence prediction of aquifer behaviour uncertain

typically produce 5% of the STOIIP to measure aquifer

response GOR remains at about solution GOR

increase in water prominent: up to 90% at end of field life.

Typical RF = 30-75% is dependent on aquifer strength or thesweep efficiency of injected water.

Supplement with water injection Works well with

Low oil viscosity

High relative oil permeability

Little reservoir heterogeneity and stratification

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Summary

Gas/oilratio

Reservoirpressure

Oil production rate

Reservoir pressure

Gas/oil ratio

Oil

Gas/oil ratio

Reservoir pressure

Oil

Water

Solution Gas Drive

(Low rec.)

Gas Cap Gas Drive(up to 40% rec.)

Water Drive(up to 75% rec.)

Production Profiles

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Combination drive

Performance: Slower decline in reservoir pressure

Longer production plateau Gas expansion process slower keeping GOR under control Typical RF = 30 - 75%

Reservoir dip,

Size of gas cap, size and strength of aquifer Abandonment: high GOR or watering out Prolong reservoir life by

Close monitoring or GOR and Wcut Reducing drawdown through horizontal drain holes Gas and water re-injection

Works well with Large gas cap and aquifers with respect to the oil zone High reservoir dip angle Thick oil column

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Combination Drive in Oil Reservoirs

Water

Cross Section

Oil zone

Gas cap

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Average Recovery Factors

Average Oil RecoveryFactors,

% of OOIPDrive Mechanism

Range AverageSolution-gas drive 5 - 30 15

Gas-cap drive 15 - 50 30Water drive 30 - 60 40

Combination Drive 16 - 85 50

Oil Reservoirs

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Thanks for patient hearing

basic knowledge petroleum industry reservoir engineer_vt

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