PP 324

Professor: Luis Alberto Colán García

Senior Reservoir Engineering Pluspetrol Norte S.A.

(Operating Company fields Jungle

Block 1AB & Block 8)

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Parameter Symbol Dimensions cgs SI Darcy Field

Length L L cm metre cm ft

Mass m M gm kg gm lb

Time t T sec Sec sec hr

Velocity u L/T cm/sec metre/sec cm/sec ft/sec

stb/d

(liquid)

Rate q L3 /T cc/sec metre3 /sec cc/Sec

Mscf/d

(gas)

Pressure p (ML/T2 )/L2 dyne/cm2 Newton/metre2

(Pascal)

atm psia

Density M/L3 gm/cc kg/metre3 gm/cc lb/cu.ft

Viscosity M/LT gm/cm.sec

(Poise)

kg/metre.sec cp cp

Permeability k L2 cm2 metre2 Darcy mD

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1 ft = 0.3048 m 1 acre = 4047 m2 = 43560 ft2

1 bbl = 0.159 m3 1 acre-ft = 1233 m3

1 dyne = 10-5 N 1 atm = 101.3 kPa

1 psi = 6.9 kPa 1 cal = 4.817 J

1 Btu = 1055 J 1 HP = 746 W

1 cp = 0.001 Pa s 1 md = 10-15 m2

1 lb = 0.454 kg 1 bar = 100 kPa

•1 acre-ft = 43560 ft3 •1 acre-ft = 7758 barrels •1 barrel = 5.61458 ft3 Temperature Farenheit Pressure Psia Thickness ft. Gravity oil API • 1 atm = 14.7 Psia

LECTURE 1

How is petroleum formed?

Petroleum is result of the deposition of plant or animal matter in areas

which are slowly subsiding.These areas are usually in the sea or along its

margins in coastal lagoons or marshes, occasionally in lakes or inland

swamps. Sediments are deposited along with that at least part of the

organic matter is preserved by burial before being destroyed by decay. As

time goes on and the areas continue to sink slowly, the organic material is

buried deeper an hence is exposed to higher temperatures and

pressures.Eventually chemical changes result in the generation of

petroleum,a complex,highly variable mixture lf hydrocarbons.

Objectives are to be able to:

Discuss basic elements of Petroleum Systems

Describe plate tectonics and sedimentary basins

Recognize names of major sedimentary rock types

Describe importance of sedimentary environments to petroleum industry

Describe the origin of petroleum

Identify hydrocarbon trap types

Define and describe the important geologic controls on reservoir properties, porosity and permeability

Petroleum Systems approach

Geologic Principles and geologic time

Hydrocarbon Generation, Migration, and Accumulation

Rock and minerals, rock cycle, reservoir properties

Hydrocarbon origin, migration and accumulation

Sedimentary environments and facies; stratigraphic traps

Plate tectonics, basin development, structural geology

Structural traps

Petroleum System - A Definition

•A Petroleum System is a dynamic hydrocarbon

system that functions in a restricted geologic

space and time scale.

•A Petroleum System requires timely

convergence of geologic events essential to

the formation of petroleum deposits.

These Include:

Mature source rock Hydrocarbon expulsion Hydrocarbon migration Hydrocarbon accumulation Hydrocarbon retention

(modified from Demaison and Huizinga, 1994)

Cross Section Of A Petroleum System

Overburden Rock

Seal Rock

Reservoir Rock

Source Rock

Underburden Rock

Basement Rock

Top Oil Window

Top Gas Window

Geographic Extent of Petroleum System

Petroleum Reservoir (O)

Fold-and-Thrust Belt

(arrows indicate relative fault motion)

Essential

Elements

of

Petroleum

System

(Foreland Basin Example)

(modified from Magoon and Dow, 1994)

O O

Sed

imen

tary

Basin

Fil

l

O

Stratigraphic

Extent of

Petroleum

System

Pod of Active

Source Rock

Extent of Prospect/Field

Extent of Play

Uniformitarianism

Original Horizontality

Superposition

Cross-Cutting Relationships

Angular Unconformity

A

B

C

D

E

F

G

H I J

K

Igneous

Dike

Disconformity ◦ An unconformity in which the beds above and

below are parallel

Angular Unconformity ◦ An unconformity in which the older bed intersect

the younger beds at an angle

Nonconformity ◦ An unconformity in which younger sedimentary

rocks overlie older metamorphic or intrusive igneous rocks

Establishes the age equivalence of rock layers in different areas

Methods: ◦ Similar lithology

◦ Similar stratigraphic section

◦ Index fossils

◦ Fossil assemblages

◦ Radioactive age dating

Geologic Cycle The cooling and movements of earth inner

molten rocks caused warping and movements of the crust resulting in the formation of mountains and valleys.

Erosion /weathering (wind, water and temp) is the process of earth breakdown into rock grains.

Rock grains are transported by water and deposited in the sedimentary basins (valleys or the sea) in horizontal beds.

Sedimentary beds are uplifted by structural movements and the cycle is repeated.

Geologic Time

Oldest beds are deposited in the bottom

Due to erosion and /or non-deposition , no single sequence is a complete record of geologic time (table 1)

Paleontology (study of fossils) is used to define geologic períods.

Natural radioactivity of minerals (Uranium & Thorium) determines absoluter rock age.

Geologic Time Chart

0

50

100

150

200

250

300

350

400

450

500

550

600

0

10

20

30

40

50

60

Cry

pto

zo

ic

(Pre

cam

bri

an

)

Phanerozoic

Quaternary

Tertiary

Cretaceous

Jurassic

Triassic

Permian

Pennsylvanian

Mississippian

Devonian

Silurian

Ordovician

Cambrian

Millio

ns

of

ye

ars

ag

o

Millio

ns

of

ye

ars

ag

o

Bil

lio

ns

of

ye

ars

ag

o 0

1

2

3

4

4.6

Paleocene

Eocene

Oligocene

Miocene

Pliocene

Pleistocene Recent

Qu

ate

rnary

peri

od

Tert

iary

peri

od

Eon Era Period Epoch

Pale

ozoic

M

esozoic

Ce

no

zo

ic E

ra

LECTURE 2

SEDIMENTARY

Ro

ck-f

orm

ing

pro

cess

So

urc

e o

f

mate

rial

IGNEOUS METAMORPHIC

Molten materials in

deep crust and

upper mantle

Crystallization

(Solidification of melt)

Weathering and

erosion of rocks

exposed at surface

Sedimentation, burial

and lithification

Rocks under high

temperatures

and pressures in

deep crust

Recrystallization due to

heat, pressure, or

chemically active fluids

The Rock Cycle

Magma

Metamorphic Rock

Sedimentary Rock

Igneous Rock

Sediment

Heat and Pressure

Weathering, Transportation and Deposition

a

n

i

Sedimentary rocks

• Are formed by sediments that have settled into layers. The layers are squeezed together until they harden into rock.

• Formed by the cementation of sediment grains/particles on or near surface at ordinary temperature .

• Sandstone

• Limestone (CaCO3)

• Dolomite (CaMg(CO3)2

Igneous Rocks • An igneous rock is a rock that had molted

(derritió) but it later cooled and hardened

(endureció).

• Formed by solidification of molten

minerals/materials:

• Beneath surface (magma):Granite

• At surface (lava): Basalt

Metamorphic Rocks

• Is an igneous or sedimentary rock that has been changed (alterada) by heat and pressure.

• Formed within earth’s crust by transformation of other rocks at high pressure and temperature (marble,slate)

Siltstone, mud

and shale

~75%

• Relative abundance Sandstone

and conglomerate

~11%

Limestone and

dolomite

~13%

Quartz Crystals

Naturally Occurring Solid

Generally Formed by Inorganic Processes

Ordered Internal Arrangement of Atoms (Crystal Structure)

Chemical Composition and Physical Properties Fixed or Vary Within A Definite Range

Minerals - Definition

Mineral Composition Shale (%) Sandstone (%)

Clay Minerals

Quartz

Feldspar

Rock Fragments

Carbonate

Organic Matter, Hematite, and Other Minerals

60

30

4

<5

3

<3

5

65

10-15

15

<1

<1

(modified from Blatt, 1982)

Quartz

Feldspar

Calcite

Mechanically and Chemically Stable

Can Survive Transport and Burial

Nearly as Hard as Quartz, but

Cleavage Lessens Mechanical Stability

May be Chemically Unstable in Some

Climates and During Burial

Mechanically Unstable During Transport

Chemically Unstable in Humid Climates

Because of Low Hardness, Cleavage, and

Reactivity With Weak Acid

Some Common Minerals

Silicates

Oxides Sulfides Carbonates Sulfates Halides

Non-Ferromagnesian (Common in Sedimentary Rocks)

Anhydrite Gypsum

Halite Sylvite

Aragonite Calcite Dolomite Fe-Dolomite Ankerite

Pyrite Galena Sphalerite

Ferromagnesian (not common in sedimentary rocks)

Hematite Magnetite

Quartz Muscovite (mica) Feldspars Potassium feldspar (K-spar) Orthoclase Microcline, etc . Plagioclase Albite (Na-rich - common) through Anorthite (Ca-rich - not common)

Olivine Pyroxene Augite Amphibole Hornblende Biotite (mica)

Red = Sedimentary Rock- Forming Minerals

Framework ◦ Sand (and Silt) Size Detrital Grains

Matrix ◦ Clay Size Detrital Material

Cement ◦ Material precipitated post-depositionally, during

burial. Cements fill pores and replace framework grains

Pores ◦ Voids between above components

Norphlet Sandstone, Offshore Alabama, USA

Grains are About =< 0.25 mm in Diameter/Length

PRF KF

P

KF = Potassium Feldspar

PRF = Plutonic Rock Fragment

P = Pore

Potassium Feldspar is Stained Yellow With a Chemical Dye

Pores are Impregnated With Blue-Dyed Epoxy

CEMENT

Scanning Electron Micrograph

Norphlet Formation, Offshore Alabama, USA

Pores Provide the

Volume to Contain

Hydrocarbon Fluids

Pore Throats Restrict

Fluid Flow

Pore

Throat

Secondary Electron Micrograph

Jurassic Norphlet Sandstone Hatters Pond Field, Alabama, USA (Photograph by R.L. Kugler)

Illite

Significant Permeability Reduction

Negligible Porosity Reduction

Migration of Fines Problem

High Irreducible Water Saturation

Clay Minerals in Sandstone Reservoirs

Fibrous Authigenic Illite

Secondary Electron Micrograph

Jurassic Norphlet Sandstone Offshore Alabama, USA (Photograph by R.L. Kugler)

Occurs as Thin Coats on Detrital Grain Surfaces

Occurs in Several Deeply Buried Sandstones With High Reservoir Quality

Iron-Rich Varieties React With Acid

~ 10 m

Clay Minerals in Sandstone Reservoirs

Authigenic Chlorite

Secondary Electron Micrograph

Carter Sandstone North Blowhorn Creek Oil Unit Black Warrior Basin, Alabama, USA

Significant Permeability Reduction

High Irreducible Water Saturation

Migration of Fines Problem

(Photograph by R.L. Kugler)

Clay Minerals in Sandstone Reservoirs

Authigenic Kaolinite

100

10

1

0.1

0.01 0.01

0.1

1

10

100

1000

2 6 10 14 2 6 10 14 18

Pe

rme

ab

ilit

y (

md

)

Porosity (%)

Authigenic Illite Authigenic Chlorite

(modified from Kugler and McHugh, 1990)

Dispersed Clay

Clay Lamination

Structural Clay (Rock Fragments,

Rip-Up Clasts, Clay-Replaced Grains)

f e

f e

f e

Clay Minerals

Detrital Quartz Grains

Precipitation

Subsidence

CH 4 ,CO 2 ,H 2 S

Petroleum

Fluids

Meteoric

Water

Meteoric Water

COMPACTIONAL

WATER

Evapotranspiration Evaporation

Infiltration

Water Table

Zone of abnormal pressure

Isotherms

(modified from from Galloway and Hobday, 1983)

Thin Section Micrograph - Plane Polarized Light

Avile Sandstone, Neuquen Basin, Argentina

Dissolution of

Framework Grains

(Feldspar, for

Example) and

Cement may

Enhance the

Interconnected

Pore System

This is Called

Secondary Porosity

Pore

Quartz Detrital

Grain

Partially

Dissolved

Feldspar

(Photomicrograph by R.L. Kugler)

LECTURE 3

Organic Matter in Sedimentary Rocks

Reflected-Light Micrograph of Coal

Vitrinite

Kerogen Disseminated Organic Matter in Sedimentary Rocks That is Insoluble in Oxidizing Acids, Bases, and Organic Solvents.

Vitrinite A nonfluorescent type of organic material in petroleum source rocks derived primarily from woody material.

The reflectivity of vitrinite is one of the best indicators of coal rank and thermal maturity of petroleum source rock.

Hydrocarbon Generation Potential

TOC in Shale (wt. %)

TOC in Carbonates (wt. %)

Poor

Fair

Good

Very Good

Excellent

0.0-0.5

0.5-1.0

1.0-2.0

2.0-5.0

>5.0

0.0-0.2

0.2-0.5

0.5-1.0

1.0-2.0

>2.0

Schematic Representation of the

Mechanism

of Petroleum Generation and Destruction

(modified from Tissot and Welte, 1984)

Organic Debris

Kerogen

Carbon

Initial Bitumen

Oil and Gas

Methane

Oil Reservoir

Migration Thermal Degradation

Cracking

Diagenesis

Catagenesis

Metagenesis

Pro

gre

ssiv

e B

uri

al an

d H

eati

ng

Incipient Oil Generation

Max. Oil Generated

Oil Floor

Wet Gas Floor

Dry Gas Floor

Max. Dry Gas Generated

(modified from Foster and Beaumont, 1991, after Dow and O’Conner, 1982)

Vit

rin

ite R

efl

ecta

nce (

Ro)

%

We

igh

t %

Carb

on

in

Kero

gen

Sp

ore

Co

lora

tio

n In

de

x (

SC

I)

Pyro

lysis

T

(C)

max

0.2

0.3

0.4

0.5

4.0

3.0

2.0

1.3

1

2

3

4

5 6

7 8 9

10

430

450

465

65

70

75

80

85

90

95

0.6 0.7 0.8 0.9 1.0 1.2

OIL

Wet Gas

Dry Gas

Reservoir rock

Seal

Migration route

Oil/water contact (OWC)

Hydrocarbon accumulation

in the reservoir rock

Top of maturity

Source rock

Fault (impermeable)

Cross Section Of A Petroleum System

Overburden Rock

Seal Rock

Reservoir Rock

Source Rock

Underburden Rock

Basement Rock

Top Oil Window

Top Gas Window

Geographic Extent of Petroleum System

Petroleum Reservoir (O)

Fold-and-Thrust Belt

(arrows indicate relative fault motion)

Essential

Elements

of

Petroleum

System

(Foreland Basin Example)

(modified from Magoon and Dow, 1994)

O O

Sed

imen

tary

Basin

Fil

l

O

Stratigraphic

Extent of

Petroleum

System

Pod of Active

Source Rock

Extent of Prospect/Field

Extent of Play

what is “trap” ?

The term “trap” was first applied to a hydrocarbon accumulation

by Orton: “…stocks of oil and gas might be reapped in the

summits of folds or arches found along their wat to higher

ground .”A detailed historical account of the subsequent

evolution of the concept and etymology of the term trap is found

in Dott and Reynolds(1969).

Structural traps

Stratigraphic traps

Combination traps

Structural Hydrocarbon Traps

(modified from Bjorlykke, 1989)

Oil/Wat

er

Contact

Gas Oil/Gas

Contact

Oil

Closure

Fold Trap

Oil Shale Trap

Fracture Basement

Oil Salt

Diapir Salt

Dom

e

Oil

Sandstone Shale

Hydrocarbon Traps - Dome

Gas

Fault Trap

Oil / Gas

Normal Faults

Oil/Gas

Oil/Gas

Oil/Gas

Stratigraphic Hydrocarbon Traps

Uncomformity

Channel Pinch Out

(modified from Bjorlykke, 1989)

Unconformity Pinch out

Asphalt Trap

Water

Meteoric

Water

Biodegraded

Oil/Asphalt

Partly

Biodegraded Oil

Hydrodynamic Trap

Shale

Oil

Water

Hydrostatic

Head

(modified from Bjorlykke, 1989)

Other Traps

where can we find petroleum ?

Hydrocarbons—crude oil and natural gas—are found in

certain layers of rock that are usually buride deep beneath

the surface of the earth.

Salt

Dome

Faul

t

Unconfor

mity

Pincho

ut

Anticli

ne

LECTURE 4

• Source Rock - A rock with abundant hydrocarbon-prone organic matter

• Reservoir Rock - A rock in which oil and gas accumulates:

• Porosity - space between rock grains in which oil accumulates

• Permeability - passage-ways between pores through which oil and gas moves

• Seal Rock - A rock through which oil and gas cannot move effectively (such as mudstone and claystone)

•Trap - The structural and stratigraphic configuration that focuses oil and gas into an accumulation

•Migration Route - Avenues in rock through which oil and gas moves from source rock to trap

Petroleum System Elements

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1. Source Rock

2. Reservoir Rock

3. Timing / Burial History

4. Maturation

5. Migration

6. Cap Rock

7. Trap HIGH PRESSURE

10 km

1000

0

2000

3000

4000

5000

6000

7000

8000

9000

10000

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59

-

Reservoir Components

Reservoir Rock

Cap Rock Reservoir Trap Fluids

LECTURE 5

For rock to contain petroleum and later allow

petroleum to flow,it must have certain physical

characteristics. Obvilusly, there must be some spaces

in the rock in which the petroleum can be stored.

If rock has openings, voids, and spaces in which

liquid and gas may be stored, it is said to be porous .

For a given volume of rock, the ratio of the open

space to the total volume of the rock is called porosity,

the porosity may be expressed a decimal fraction but

is most often expressed as a percentage. For

example,if 100 cubic feet of rock contains many tiny

pores and spaces which together have a volume of 10

cubic feet, the porosity of the rock is 10%.

Structure contour maps of structure or zone tops

Data is obtained from open hole logs or seismic interpretations.

Net pay map using specific cut-off values to gross pay thickness

Hydro-carbon pore volume map (HCPV)

Cross-section

Structural: Open hole logs are illstrated, as such, “hanging the wells” is based on a selected datum depth

Stratigraphic: Open hole logs are illustrated, as such, “hanging the wells” is based on a selected strato or zone.

Geologic Subsurface Maps

POROSITY The porosity of a rock is a measure of the storage capacity (pore

volume)that is capable of holding fluids. Quantitatively, the

porosity is the ratio of the pore volume to the total volume (bulk

volume). This important rock property is determined

mathematically by the following generalized

relationship:

where f=porosity

As the sediments were deposited and the rocks were being formed during past geological times, some void spaces that developed became isolated from the other void spaces by excessive cementation. Thus, many of the void spaces are interconnected while some of the pore spaces arecompletely isolated. This leads to two distinct types of porosity, namely:

• Absolute porosity

• Effective porosity

POROSITY

Absolute porosity

The absolute porosity is defined as the ratio of the total pore space in

the rock to that of the bulk volume. A rock may have considerable

absolute porosity and yet have no conductivity to fluid for lack of pore

interconnection. The absolute porosity is generally expressed

mathematically by the following relationships:

or

where fa =absolute porosity.

Effective porosity

The effective porosity is the percentage of interconnected

pore space with respect to the bulk volume, or

where f=effective porosity.

One important application of the effective porosity is its use in determining the original hydrocarbon volume in place. Consider a reservoir with an areal extent of A acres and an average thickness of h feet. The total bulk volume of the reservoir can be determined from the following expressions:

Bulk volume =43,560 Ah, ft3

or

Bulk volume =7,758 Ah, bbl

where A =areal extent, acres

h =average thickness

When porosity was developed?

Primary porosity.- Rock porosity developed during the initial rock deposition.

Secondary porosity.- Rock porosity due to a chemical reaction between the reservoir fluids and the rock, wich could occur for instance if some of the rock minerals are dissolved by the formation water (leaching) This phenomena is called “Diagenesis”

Factors affecting porosity values

• Sorting

• Arragement

• Cementation

How is porosity determined?

• Open hole logs

• Core samples

• Core plugs vs. Full core diameter (plug selection, fractures, vuggs)

• Overburden pressure correction (for permeability rocks)

• Core cleaning (humidity oven)

Porosity

i. Define: Porosity = Total pore volume in the rock sample Total rock sample volume (solid+pore)

ii. Mathematically:

iii. Range of porosity: 0.1 to 0.3

iv. Use reservoir core to measure porosity

v. Limitations

a. Rock sample must be large enough to obtain many sand grains and many pores to be representative

b. Features sample has a different type of pore space from sandstone

Porosity Determination from Logs Porosity Determination from Logs

Most log interpretation techniques in use today use a bulk volume rock approach

Quantitative rock data must be input into equations to derive values of phi and Sw. For example:

Db = Φ x Df + (1 - Φ) Dm

Porosity is then derived:

Φ = (Dma - Db)/(Dma - Df)

Values of matrix density are normally assumed:

Dma = 2.65 for clean sand

= 2.68 for limy sands or sandy limes

= 2.71 for limestone

= 2.87 for dolomite

Fluid density is that of the mud filtrate:

Df = 1.0 (fresh)

= 1.0 = 0.73N (salt)

Where: N = NaCl concentration, ppm x 10-6

Accurate knowledge of grain density is essential

Porosity at Net Overburden (NOB)

Increase in NOB can reduce porosity. Generally

the reduction is <10% of total porosity.

Less severe in consolidated rocks, more severe

in unconsolidated rocks

Grain Density

Measure the bulk volume of the sample. Weigh

the sample. GD = Dry weight/Grain volume

Most rocks are mixtures of minerals. The grain

density of any rock is variable and is dependent

on the mineralogy:

1.25gm/cc -- volcanic ash, some coals

2.65gm/cc -- clean, quartz sandstone

2.68gm/cc -- shaly sandstone with some carbonate

2.71gm/cc -- clean limestone

2.87 - >3.0gm/cc – dolomite

2.32gm/cc -- gypsum

2.96gm/cc -- anhydrite

3.89gm/cc -- siderite

Accurate values of grain density are important

because grain density is used to correct wireline

logs for potential sources of error

Example

One of the most important determinations for an oil accumulation is the volume of oil in place. Suppose that in geological evidence is known that the area extent of an oil reservoir is 2 million sqft and that the thickness of the bay zone is 30 ft. If the sand porosity and water saturation are 0.2 and 0.3, respectively, how much oil is present?

Solution:

Volume of bay = 2,000,000 ft3 x 30 ft = 6x107ft3

Total pore volume = 0.2 x 6x107 = 12x106 ft3

Then Sw+So=1; So = 1 - 0.3 = 0.7

Total oil volume = 0.7 x 12x106 = 8.4x106 ft3

LECTURE 6

PERMEABILITY

Permeability is a property of the porous medium that measures the

capacity and ability of the formation to transmit fluids. The rock

permeability, k, is a very important rock property because it

controls the directional movement and the flow rate of the reservoir

fluids in the formation. This rock characterization was first defined

mathematically by Henry Darcy in 1856. In fact, the equation that

defines permeability in terms of measurable quantities is called

Darcy’s Law.

Darcy developed a fluid flow equation that has since become one of

the standard mathematical tools of the petroleum engineer. If a

horizontal linear flow of an incompressible fluid is established

through a core sample of length L and a cross-section of area A,

then the governing fluidflow equation is defined as

where n=apparent fluid flowing velocity, cm/sec

k =proportionality constant, or permeability, Darcys

=viscosity of the flowing fluid, cp

dp/dL =pressure drop per unit length, atm/cm

The apparent velocity determined by dividing the flow rate by the cross-sectional area across which fluid is flowing. Substituting the relationship, q/A, in place of nin Equation 3-21 and solving for q results in

where q =flow rate through the porous medium, cm3/sec

A =cross-sectional area across which flow occurs, cm2

One Darcy is a relatively high permeability as the permeabilities of

most reservoir rocks are less than one Darcy. In order to avoid the use of fractions in describing permeabilities, the term millidarcy is used. As the term indicates, one millidarcy, i.e., 1 md, is equal to one-thousandth of one Darcy or,

1 Darcy =1000 md

The negative sign in Equation is necessary as the pressure increases in one direction while the length increases in the opposite direction.

Integrate the above equation

Linear flow model

where L =length of core, cm

A =cross-sectional area, cm2

The following conditions must exist during the

measurement of permeability:

• Laminar (viscous) flow

• No reaction between fluid and rock

• Only single phase present at 100% pore space

saturation

This measured permeability at 100% saturation of a

single phase is called the absolute permeability of the

rock.

For a radial flow, Darcy’s equation in a differential form can be

written as:

Intergrating Darcy’s equation gives:

The term dL has been replaced by dr as the length term has now become a radius term.

Rock Permeability

i. Measurement of the fluid ability to flow through the connected pores of the reservoir.

ii. A function of a degree of interconnection between pores in the rock

iii. The concept was introduced by Darcy in a classical experimental work from both petroleum engineering and ground water hydrology. Is expressed in milidarcies or Darcies.

iv. The flow rate can be measured against pressure (head) for different porous media

v. The flow rate of fluid thru specific porous medium is linearly proportional top head difference betwen the inlet and outlet and characteristic property of the medium, thus u = kDP

Where k = permeability and is a characteristic property of the porous medium

vi. The rock permeability is measured from core samples (plugs or whoke core) in the laboratory or it could also be calculated from well testing

a. Suppose a cylindrical sample (core) of a porous rock is fully saturated with liquid of viscosity .

b. Experimentally for a particular rock sample the expression

Darcy Equation

where k is constant

c. Q will increase a k increases, the higher the value of k the more readily will liquid flow through the core

l

A Q

P1 P2

)( 21 PPA

lQk

=

d. If in flow rate contain two fluid (oil and water), free gas is not present then,

d. If Q (cm3/s), (cp), l (cm) A (cm2), and P1 and P2 (atm), the value of k in Darcy is

1 Darcy = 10-8 cm2

)( 21 PPA

lQk oo

o

=

)( 21 PPA

lQk ww

w

=

LECTURE 7

SATURATION

Saturation is defined as that fraction, or percent, of the pore volume

occupied by a particular fluid (oil, gas, or water). This property is

expressed mathematically by the following relationship:

Applying the above mathematical concept of saturation to each reservoir

fluid gives

where

So =oil saturation

Sg =gas saturation

Sw =water saturation

Sg +So +Sw =1.0

Fluid Saturations from Cores

Through knowledge of porosity,

permeability and residual fluid saturations

(oil, water and gas), it is possible to predict

with a high degree of accuracy the probable

type of fluid

which will be produced from a given interval.

Review of the core fluorescence can also

be an indicator of oil gravity and should be

factored when type of production is

predicted.

Critical oil saturation, Soc

For the oil phase to flow, the saturation of the oil must exceed a

certain value which is termed critical oil saturation. At this particular

saturation, the oil remains in the pores and, for all practical

purposes, will not flow.

Fluid Saturation

i. Water saturation, Sw = Volume filled by water/ Total pore volume

Oil saturation, So = Volume filled by oil/ Total pore volume

ii. If oil and water is the only fluid present, Sw + So = 1

iii. In most oil fields Sw tends to increase as porosity decrease

iv. Typical value of Sw – 0.1 to 0.5

v. Free gas also present in oil pools,

Free gas saturation, Sg = Volume filled by free gas/total pore volume

vi. 3 factors should always be remembered conceiving fluid saturation

a. It vary from place to place in reservoir rock; Sw higher in less

porous sections due to gravity segregation of the gas, oil and water

Residual oil saturation, Sor

During the displacing process of the crude oil system

from the porous media by water or gas injection (or

encroachment) there will be some remaining oil left that

is quantitatively characterized by a saturation value that

is larger than the critical oil saturation. This saturation

value is called the residual oil saturation, Sor. The term

residual saturation is usually associated with the

nonwetting phase when it is being displaced by a

wetting phase.

Movable oil saturation, Som

Movable oil saturation Som is another saturation of

interest and is defined as the fraction of pore

volume occupied by movable oil as expressed by

the following equation:

Som =1 Swc Soc

where

Swc =connate water saturation

Soc =critical oil saturation

Critical gas saturation, Sgc

As the reservoir pressure declines below the bubble-point pressure,

gas evolves from the oil phase and consequently the saturation

of the gas increases as the reservoir pressure declines. The gas

phase remains immobile until its saturation exceeds a certain

saturation, called critical gas saturation, above which gas begins

to move.

Critical water saturation, Swc

The critical water saturation, connate water saturation, and

irreducible water saturation are extensively used interchangeably

to define the maximum water saturation at which the water

phase will remain immobile.

LECTURE 8

Capillary pressure If a glass capillary tube is placed in a large open vessel containing

water, the combination of surface tension and wettability of tube to

water will cause water to rise in the tube above the water level

in the container outside the tube as shown in Figure 3.

The water will rise in the tube until the total force acting to pull the

liquid upward is balanced by the weight of the column of liquid

being supported in the tube.

Figure 3

CAPILLARY PRESSURE

The capillary forces in a petroleum reservoir are the result of the combined effect of the surface and interfacial tensions of the rock and fluids, the pore size and geometry, and the wetting characteristics of the system.

Any curved surface between two immiscible fluids has the tendency to

contract into the smallest possible area per unit volume. This is true

whether the fluids are oil and water, water and gas (even air), or oil and gas. When two immiscible fluids are in contact, a discontinuity in pressure exists between the two fluids, which depends upon the curvature of the interface separating the fluids. We call this pressure difference the capillary pressure and it is referred to by pc.

Capillary pressure =(pressure of the nonwetting phase) (pressure of

the wetting phase)

pc =pnw pw

Figure4

Transition Zone

The figure indicates that the saturations are gradually

changing from 100% water in the water zone to irreducible

water saturation some vertical distance above the water

zone. This vertical area is referred to as the transition zone,

which must exist in any reservoir where there is a bottom

water table. The transition zone is then defined as the

vertical thickness over which the water saturation ranges

from 100% saturation to irreducible water saturation Swc.

Water Oil Contact

The WOC is defined as the “uppermost depth in the

reservoir where a 100% water saturation exists.”

Gas Oil Contact

The GOC is defined as the “minimum depth at which a

100% liquid, i.e., oil +water, saturation exists in the

reservoir.”

Figure 5

It should be noted that there is a difference between

the free water level (FWL) and the depth at which 100%

water saturation exists. From a reservoir engineering

standpoint, the free water level is defined by zero

capillary pressure. Obviously, if the largest pore is so

large that there is no capillary rise in this size pore, then

the free water level and 100% water saturation level,

i.e., WOC, will be the same.

Capillary Pressure

Capillary pressure in reservoirs can be defined

as the difference between the force acting

downwards (hydrostatic head, related to density

contrasts) and the force acting upwards

(buoyancy, related to pore throat size, interfacial

tension and contact angle)

Capillary pressure is measured in the laboratory

generally using plug samples or rotary sidewall

cores. Occasionally cuttings samples are used

In the most common type of test, a non-wetting

phase fluid (e.g. mercury) is injected into the

rock at slowly increasing values of pressure. The

amount of fluid injected at each increment of

pressure is recorded and is presented as a

capillary curve

Capillary Pressure (1)

Capillary pressure exists in a hydrocarbon

reservoir fundamentally because of

differences in the density of various fluids

that affect the pressure gradients:

Pressure gradient of water = 0.44 psi/ft

(density = 1gm/cc)

Pressure gradient of oil = 0.33 psi/ft

(density = 0.8gm/cc)*

Pressure gradient of gas = 0.09 psi/ft

(density = 0.2gm/cc)**

* 30°API

** 5000psi

As hydrocarbons accumulate in a trap, the

difference in density between the fluids

results in a vertical segregation of the

fluids: gas on oil, oil on water For

example, at 10,000ft, oil pressure = 3300

psi and water pressure = 4400 psi

Capillary Pressure and

Water Saturation (2)

Reservoir Sw decreases with increasing height above the free water level (the level at

which the reservoir produces only water) .

Zones that are at irreducible water saturation (Swirr) produce only hydrocarbons. Swirr

occurs where sufficient closure and hydrocarbon column exist the transition zone occurs

between the free water level and the Swirr level. Formations in this zone produce water

and hydrocarbons. The magnitude of the Swirr and the thickness of the transition zone

are a function of the pore size distribution Small pore throats = low permeability = high

Swirr

Initial Reservoir Fluid Distribution

The amount of Sw at any height in the reservoir is a function of:

Pore throat size, wettability, interfacial tension, saturation history and differences

in fluid densities.

These variables control capillary pressure, therefore there is a relationship

between Sw, h, Pc and pore throat size.

Laboratory measurements of capillary pressure are used to relate Sw to height

above the free water level as long as appropriate values of laboratory and

reservoir interfacial tension and contact angle are used Laboratory tests can be

made with different fluids oil, brine, mercury

Capillary Pressure:

Static Measurement

Static Method – Mercury injection

Widely used, rapid, economic and simple. Mercury is the non-wetting phase and is injected into

a cleaned and evacuated core plug at successively increasing pressures from 0 to 60,000psi.

The core plug cannot be used for further testing because of residual Hg saturation Hg capillary

pressure data must be scaled to reservoir conditions using the following formula:

. Conversion factor = Mercury Pc = Sm Cos è m

Water-Air Pc Sw Cos è w

Where:

Sm = surface tension of mercury

Sw = surface tension of water

è m = contact angle of mercury against a solid (140 degrees)

è w = contact angle of water against a solid (0 degrees)

Capillary Pressure:

Dynamic Measurement

Dynamic Method -- Centrifuge

Generally uses oil-brine fluid system but

actual reservoir fluids can also be used

Rapid, more complicated and more expensive

than mercury Pc measurements

Requires preserved or restored-state core

plugs Large (2 inch) plugs are required. These

can be used for further analysis Brine

saturated samples are centrifuged at ever

increasing speeds under oil to obtain a

relationship between capillary pressure and

saturation

Capillary Pressure: Rock Controls

Pore geometry is a fundamental control on

capillary pressure, in particular the size of the pore

throats: the capillary pressure characteristics

change with changes in Rock

Type (pore geometry) In heterogeneous reservoirs,

it is essential to collect capillary pressure data for

each Rock Type that is present in the reservoir All

other factors being equal, the lower the

permeability the smaller the pore throats the higher

the Pce and the higher the Swirr.

Capillary pressure data is used to determine the

height above free water (column height) for each

Rock Type and to improve the prediction of the type

of fluid produced (hydrocarbon/water)

Use of Pc in Reservoir Simulation and Reservoir

Characterization

For purposes of simulation and characterization, it is

necessary to know the Free Water Level (FWL)

When FWL is known it is possible to predict Sw at any

height in the reservoir even in areas that lack well

Penetrations.

This is particularly important in the following cases:

Areas with long transition zones and no obvious FWL

Areas with misidentified or unknown FWL

Areas with unknown or incorrect Rw

Areas where a, m and/or n are incorrect or unknown

Areas with multiple Rock Types (where a, m,n and Sw

vary as a function of Rock Type)

In these situations, it is possible to solve for Sw using

either the Pc curves or the Leverett J Function.

LECTURE 9

WETTABILITY

Wettability is defined as the tendency of one fluid to spread

on or adhere to a solid surface in the presence of other

immiscible fluids. The concept of wettability is illustrated in

Figure1. Small drops of three liquids-mercury, oil, and

water—are placed on a clean glass plate.

The three droplets are then observed from one side as

illustrated in Figure 3-1. It is noted that the mercury retains a

spherical shape, the oil droplet develops an approximately

hemispherical shape, but the water tends to spread over the

glass surface.

The tendency of a liquid to spread over the surface of a

solid is an indication of the wetting characteristics of

the liquid for the solid. This spreading tendency can be

expressed more conveniently by measuring the angle

of contact at the liquid-solid surface. This angle, which

is always measured through the liquid to the solid, is

called the contact angle q.

The contact angle q has achieved significance as a

measure of wettability.

As shown in Figure 1, as the contact angle decreases, the wetting characteristics of the

liquid increase. Complete wettability would be evidenced by a zero contact angle, and

complete nonwetting would be evidenced by a contact angle of 80°. There have been

various definitions of intermediate wettability but, in much of the published literature,

contact angles of 60° to 90° will tend to repel the liquid.

The wettability of reservoir rocks to the fluids is important in that the distribution of the

fluids in the porous media is a function of wettability.

Because of the attractive forces, the wetting phase tends to occupy the smaller pores of

the rock and the nonwetting phase occupies the more open channels.

LECTURE 10

UNIT PUMPING

UNIT PUMPING

UNIT PUMPING

SYSTEM PRODUCTION

INJECTION GAS

PRODUCED FLUID

PRESSURE (PSI)

DE

PT

H (

FT

TV

D)

1000

2000

3000

4000

5000

6000

7000

0

1000 2000 0

OPERATING GAS LIFT VALVE

CASING PRESSURE WHEN

WELL IS BEING GAS LIFTED

FBHP

SIB

HP

CONSTANT FLOW GAS LIFT WELL

DISSOLVED GAS DRIVEDISSOLVED GAS DRIVE

GAS CAP DRIVEGAS CAP DRIVE

WATER DRIVE

Sistema cerrado (un pozo)

Field Production 1.Primary Recovery (Natural Methods)

i. 1st method of producing oil from a well

ii. Solution gas drive

a. pressure inside reservoir relieved when well punctures and gas trapped in oil forms bubbles

b. Bubbles grow, exert pressure push oil to well and up to surface (20-30%)

iii. Gas cap drive

a. If contain gas cap, drill well directly into oil layer – gas cap expand

b. Expanding gas pushes oil into well (40%)

iv. Water drive scenario

a. Water layer press against oil layer

b. Water pushes oil towards surface and replace it within the pores of the reservoir rock

c. Highest recovery: up to 75%

2.Secondary Recovery

i. Used to enhance or replace primary techniques

ii. Water flooding

a. Additional injection well is drilled into the reservoir

b. Pressure water injected

c. Water displaces the oil in reservoir

iii. Mechanical Lift

a. Reciprocating or plunger pumping called “horsehead”

b. Pump barrel lowered into well on 6 inch string steel rod (sucker rods)

c. Up and down movement force oil up to tubing

3. Tertiary Recovery

i. When 2nd recovery no longer effective

ii. Thermal Process

a. Steam Flooding – steam injected, heats oil to flow readily

b. in-situ combustion (fire flooding) – air injected, a portion if oil ignited , combustion front moves away from air injection well toward production well

iii. CO2 injection

a. CO2 injected, mix with oil – reduces forces that hold oil to pores, allows easily displace by injected water

iv. Chemical recovery

i. Inject polymer into water phase of reservoir trap, large molecule add bulk to water, water thicken, wash oil from pores

ii. Sometimes surfactant added to reduce force water to solid

4. Improvement of formation characteristic

i. To aid 3rd recovery because production drop

ii. Acidizing

a. Injecting acid into a soluble formation (exp: carbonate) to dissolve rocks

b. Enlarge the existing voids and increase permeability

iii. Hydraulic Fracturing

a. Inject a fluid into formation under significant pressure to enlarge existing fracture and create new fracture

b. This fracture extend outward from well bore into formation therefore increase permeability

Petroleum Production System

1. Petroleum hydrocarbon production involve 2 districts

i. Reservoir – a porous medium with a unique storage and flow characteristic

ii. Artificial structures includes well, bottom hole, surface gathering, separation and storage facilities

2. Production Engineering - attempts to maximize production in a cost effective way

3. Appropriate production technology and method related directly with other major area of petroleum engineering such as formulation evaluation, drilling and reservoir engineering

4. Petroleum Hydrocarbon

i. Mixture of many compounds – petroleum and natural gas

ii. Mixture depending on its composition and conditions of P and T occur as liquid or gas or mixture of 2 phase

4. Oil Gravity

i. Commonly expressed in degree API

ii. The terms heavy, medium and light crude cover approximately the ranges 10 to 20o, 20 to 30o and over 30o API, respectively

5. Instantaneous Water/Oil Ratio (WOR)

i. Homogeneous formation produce only oil and water (no free gas) then

ii. The pressure drop in oil may differ slightly from that in the water owing to effect of capillary forces, so dividing the equations above, results in

5.1315.141

60

=

F

o

oSGAPI

dl

dPkq

o

oo =

dl

dPkq

w

ww

=

wo

ow

o

w

k

k

q

q

=

iii. At the surface

iv. Or from above equation

(surface)

Where Bo is oil formation volume factor:

v. Bo is defined as ratio of the volume of oil (plus the gas in solution) at reservoir T and P to the volume of oil at standard conditions (so-called stock-tank oil)

o

wo

oo

w

q

qB

Bq

q=

wo

owo

k

kBWOR

=

6. Instantaneous Gas/Oil Ratio (GOR)

i. Homogeneous formation producing only oil and gas (no water production, although water may be present in the formation)

ii. Where the pressure drop across the distance dl is the same for both fluid, if capillary forces are neglected. Dividing

iii. Stock-tank oil rate will be qo/Bo, and surface free gas rate qg/Bg. In addition to free gas produced from the formation, each barrel of stock-tank oil will release a volume Rs of gas, then the total surface gas/oil ratio is

dl

dPkq

o

oo =

dl

dPkq

g

g

g =

go

og

o

g

k

k

q

q

=

iv. At the surface

v. Therefore

(surface)

7. Productivity Index

i. Bottom hole flowing pressure - producing pressure (Pwf) at the bottom of the well

ii. The difference bettwen this and the well static pressure (Ps) is

og

os

oo

gg

sqB

qgBR

Bq

BqR +=+

gog

ogo

skB

kBRGOR

+=

wfs PPDrawdown =

iii. Ratio of producing rate of the well to its draw down is called Producing Index.

iv. If the rate q (bbl/day) of stock-tank liquid and draw down (psi), the productivity index (J) is defined as

(bbl/day/psi)

iii. Productivity index is based on the gross liquid rate (oil rate + water rate)

iv. Specific productivity index, Js is the number of barrel (gross) of stock-tank liquid produced/day/psi/ft net thickness

wfs PP

qJ

=

)( wfs

sPPh

q

h

JJ

==

LECTURE 11

LECTURE 12

Petroleum reservoirs are broadly classified as oil or gas reservoirs.

These broad classifications are further subdivided depending on:

The composition of the reservoir hydrocarbon mixture

Initial reservoir pressure and temperature

Pressure and temperature of the surface production

The conditions under which these phases exist are a matter of

considerablepractical importance. The experimental or the

mathematical determinations of these conditions are conveniently

expressed in different types of diagrams commonly called phase

diagrams. One such diagram is called the pressure-

temperature diagram.

Figure 1-1 shows a typical pressure-temperature diagram of a

multicomponent system with a specific overall composition.

Although a different hydrocarbon system would have a

different phase diagram, the general configuration is similar.

These multicomponent pressure-temperature diagrams are

essentially

used to:

• Classify reservoirs

• Classify the naturally occurring hydrocarbon systems

• Describe the phase behavior of the reservoir fluid

LECTURE 13

Petroleum reservoirs are broadly classified as oil or

gas reservoirs.

The composition of the reservoir hydrocarbon

mixture

Initial reservoir pressure and temperature

pressure-temperature diagram

Figure 1-1 shows a typical pressure-temperature diagram of a

multicomponent system with a specific overall composition.

Although a different hydrocarbon system would have a different

phase diagram, the general configuration is similar.

These multicomponent pressure-temperature diagrams are essentially

used to:

• Classify reservoirs

• Classify the naturally occurring hydrocarbon systems

• Describe the phase behavior of the reservoir fluid

Critical point—The critical point for a multicomponent mixture is

referred to as the state of pressure and temperature at which all

intensive properties of the gas and liquid phases are equal (point C).

At the critical point, the corresponding pressure and temperature are

called the critical pressure pc and critical temperature Tc of the

mixture.

Bubble-point curve—The bubble-point curve (line BC) is

defined as the line separating the liquid-phase region from the

two-phase region.

Dew-point curve—The dew-point curve (line AC) is defined as

the line separating the vapor-phase region from the two-phase

region.

Oil reservoirs—If the reservoir temperature T is less

than the critical temperature Tc of the reservoir fluid,

the reservoir is classified as an oil reservoir.

Gas reservoirs—If the reservoir temperature is greater

than the critical temperature of the hydrocarbon fluid,

the reservoir is considered a gas reservoir.

Low-shrinkage oil

• Oil formation volume factor

less than 1.2 bbl/STB

• Gas-oil ratio less than 200

scf/STB

• Oil gravity less than 35° API

• Black or deeply colored

In general, if the reservoir temperature is above the

critical temperature of the hydrocarbon system, the

reservoir is classified as a natural gas reservoir. On

the basis of their phase diagrams and the prevailing

reservoir conditions, natural gases can be classified

into 3 categories:

Retrograde gas-condensate

Wet gas

Dry gas

If the reservoir temperature T lies

between the critical temperature Tc

and cricondentherm Tct of the

reservoir fluid, the reservoir is

classified as a retrograde gas-

condensate reservoir.

• the gas-oil ratio for a condensate

system increases with time due to the

liquid dropout and the loss of heavy

components in the liquid.

• Condensate gravity above 50° API

• Stock-tank liquid is usually water-white

or slightly colored.

Retrograde gas-condensate reservoir

Temperature of wet-gas reservoir

is above the cricondentherm of

the hydrocarbon mixture. Because

the reservoir temperature exceeds

the cricondentherm of the

hydrocarbon system, the reservoir

fluid will always remain in the

vapor phase region as the

reservoir is depleted isothermally,

along the vertical line A-B.

Wet-gas reservoir

Wet-gas reservoirs are characterized by the following

properties:

• Gas oil ratios between 60,000 to 100,000 scf/STB

• Stock-tank oil gravity above 60° API

• Liquid is water-white in color

• Separator conditions, i.e., separator pressure and

temperature, lie within the two-phase region

Wet-gas reservoir

The hydrocarbon mixture

exists as a gas both in the

reservoir and in the

surface facilities.

Usually a system having a

gas-oil ratio greater than

100,000 scf/STB is

considered to be a dry gas.

Dry-gas reservoir

Temperature of Test = Reservoir Temperature

V t1

V t2

V t3

= V

b

V t5 V

t4

oil oil oil oil

oil

gas gas

Hg Hg Hg Hg

Hg

P 1 >> P

b P

2 > P

b P

3 = P

b P

4 < P

b P

5 < P

4

1 2 3 4 5

Properties determined ◦ Pb ◦ Co

gas

oil

oil oil oil

oil

gas

Hg

Hg

Hg Hg

Hg

P 1 = P b P 2 < P b P 2 < P b P 2 < P b P 3 < P 2 < P b

1 2 3 4 5

gas oil

Gas off

Temperature of Test = Reservoir Temperature

Properties Determined ◦ Oil formation volume factor at the Bubble Point

pressure Bodb and below the bubble point pressure Bod

◦ Solution gas-oil ratio at the Bubble Point pressure Rsdb and below the bubble point pressure Rsd

◦ Isothermal compressibility (derived property)

LECTURE 14

The Water-Drive Mechanism Many reservoirs are bounded on a portion or all of their peripheries

by water bearing rocks called aquifers. The aquifers may be so

large compared to the reservoir they adjoin as to appear infinite for

all practical purposes, and they may range down to those so small

as to be negligible in their effects on the reservoir performance.

Reservoir have

a water drive

Characteristics Trend

Reservoir pressure Declines very slowly (remains

very high)

Gas oil ratio Little change during the life of

the reservoir (remains low)

Water production Early excess water production

Well behavior Flow until water production gets

excessive.

Oil recovery 35 to 75 %

Rock and Liquid Expansion

When an oil reservoir initially exists at a pressure higher than

its bubble-point pressure, the reservoir is called an

undersaturated oil reservoir.

At pressures above the bubble-point pressure, crude oil,

connate water, and rock are the only materials present. As the

reservoir pressure declines, the rock and fluids expand due to

their individual compressibilities.

The reservoir rock compressibility is the result of two factors:

• Expansion of the individual rock grains

• Formation compaction

Both of the above two factors are the results of a

decrease of fluid pressure within the pore spaces,

and both tend to reduce the pore volume through

the reduction of the porosity.

This driving mechanism is considered the least

efficient driving force and usually results in the

recovery of only a small percentage of the total

oil in place.

LECTURE 15

The Depletion Drive Mechanism This driving form may also be referred to by the following various

terms:

• Solution gas drive

• Dissolved gas drive

• Internal gas drive

In this type of reservoir, the principal source of energy is a result of gas

liberation from the crude oil and the subsequent expansion of the

solution gas as the reservoir pressure is reduced. As pressure falls

below the bubble-point pressure, gas bubbles are liberated within

the microscopic pore spaces. These bubbles expand and force the

crude oil out of the pore space as shown conceptually in Figure 1

Figure 1 Solution gas drive reservoir

Gas Cap Drive

Gas-cap-drive reservoirs can be identified by the presence of

a gas cap with little or no water drive as shown in Figure 2.

Due to the ability of the gas cap to expand, these reservoirs

are

characterized by a slow decline in the reservoir pressure.

The natural energy available to produce the crude oil

comes from the following two sources:

• Expansion of the gas-cap gas

• Expansion of the solution gas as it is liberated

Figure 2 Gas-cap drive reservoir

The Gravity-Drainage-Drive Mechanism

The mechanism of gravity drainage occurs in petroleum

reservoirs as a result of differences in densities of the

reservoir fluids. The effects of gravitational forces can be

simply illustrated by placing a quantity of crude oil and a

quantity of water in a jar and agitating the contents. After

agitation, the jar is placed at rest, and the more denser

fluid (normally water) will settle to the bottom of the jar,

while the less dense fluid (normally oil) will rest on top of

the denser fluid. The fluids have separated as a result of

the gravitational forces acting on them.

Characteristics Trend

Reservoir pressure Variable rates of pressure

decline, depending principally

upon the amount of gas

conservation.

Gas oil ratio Low gas-oil ratio

Water production Little or no water production.

Well behavior

Oil recovery Near to 80 %

The principle of natural water drive is that an aquifer provides the energy for

hydrocarbon production. Both water expansion, as a result of pressure

reduction, and inflow are involved.

Natural water drive is associated with high recovery rates; oil from

35-75% OIIP; gas from 60-80% GIIP.

It is not uncommon for flow from the

surface to supply the energy for

natural water drive.

When a pressure drop occurs, both

the oil and water liquid phases

expand resulting in production.

Additionally, water inflow radially and

vertically displaces the oil towards

the producers.

Cross-section view

Plane view

Water

Hydrocarbon

The Upper Devonian Leduc pools are driven by inflow from the Cooking Lake

Aquifer.

Oil producing well

Water Water

Cross Section

Oil Zone

Both bottom water drive, where the water leg underlies the entire reservoir, and

edge water drive, where only part of the areal extent is contacted by water, are

recognized.

Oil producing well

Cross Section

Oil Zone

Water

Edge Water Drive Bottom Water Drive

NATURAL WATER

DRIVE HISTORY watercut

GOR (R)

pressure

time

Rsi

OIL PRODUCTON

• Pressure remains high; small drop.

• R (producing gas oil ratio) remains low.

• Water influx starts early and increases to appreciable levels.

• Residual oil may be trapped behind the advancing water.

• Wells flow freely until water production (watercut) becomes excessive.

The Combination-Drive Mechanism

The driving mechanism most commonly encountered is one in

which both water and free gas are available in some degree to

displace the oil toward the producing wells. The most common

type of drive encountered,

therefore, is a combination-drive mechanism as illustrated in Figure

4. Two combinations of driving forces can be present in

combinationdrive reservoirs. These are (1) depletion drive and a

weak water drive and; (2) depletion drive with a small gas cap

and a weak water drive.

Then, of course, gravity segregation can play an important role in

any of the aforementioned drives.

Figure 4 Combination drive reservoir

RESERVOIR PERFORMANCE DATA (1)

Pressure trends in reservoirs under various drive mechanisms are distinctive.

100

0 10 20 30 40 50

% OIIP Produced

P

%

WATER DRIVE

GAS CAP DRIVE SOLUTION

GAS DRIVE

80

60

40

20

0

RESERVOIR PERFORMANCE DATA (2)

Producing GOR is also strongly diagnostic of drive mechanism.

0 10 20 30 40 50

%OIIP Produced

GOR

%

SOLUTION

GAS DRIVE

GAS CAP DRIVE

WATER DRIVE

100

80

60

40

20

0

Average Oil RecoveryFactors,

% of OOIPDrive Mechanism

Range Average

Solution-gas drive 5 - 30 15

Gas-cap drive 15 - 50 30

Water drive 30 - 60 40

Gravity-drainagedrive

16 - 85 50

Recovery factor is defined as the fraction (or percentage) of the volume of

hydrocarbon produced (recovered) from the amount of volume initially in place.

Average Gas RecoveryFactors,

% of OGIPDrive Mechanism

Range Average

Volumetric reservoir(Gas expansion drive)

70 - 90 80

Water drive 35 - 65 50

Solution-gas drive - API study

Water drive - API study

Water drive - Guthrie-Greenberger study

( (

=

1741.0

3722.0

0979.01611.0

18.41

a

bwi

obob

wiR

p

pS

k

B

SE

f

( (

=

2159.0

1903.0

0770.00422.0

19.54

a

iwi

oi

w

oi

wiR

p

pS

k

B

SE

f

114.00003.0538.1log136.0256.0log272.0 1010 ++= hSkE owiR f

These correlations work best for sandstone reservoirs.

Nomenclature

ER = Oil recovery efficiency (recovery factor), [% (for API

study); fraction (for G-G study)]

f = Reservoir porosity, fraction

Swi = Interstitial water saturation, fraction

Bob = Formation volume factor of oil at bubblepoint, RB/STB

k = Reservoir permeability, [darcy (for API study);

md (For G-G study)]

ob = Oil viscosity at bubblepoint pressure, cp

pb = Bubblepoint pressure of oil, psig

pa = Abandonment reservoir pressure, psig

Solution-gas drive oil reservoirs Low oil density Low oil viscosity High oil bubblepoint pressure

Gas-cap drive oil reservoirs Favorable oil properties Relatively large ratio of gas cap to

oil zone High reservoir dip angle Thick oil column

Water drive oil reservoirs

– Large aquifer

– Low oil viscosity

– High relative oil permeability

– Little reservoir heterogeneity

and stratification

Gravity drainage oil reservoirs

– High reservoir dip angle

– Favorable permeability distribution

– Large fluid density difference

– Large segregation area

– Low withdrawal

Volumetric gas reservoir (gas expansion drive)

◦ Low abandonment pressure

Water-drive gas reservoir

– Small aquifer

– Small degree of reservoir heterogeneity and stratification

LECTURE 16

When an oil and gas reservoir is trapped with wells, oil and gas, and frequently some water, are produced, thereby reducing the reservoir pressure and causing the remaining oil and gas to expand to fill the space vavated by the fluids removed. When the oil-and gas-bearing strata are hydraulically connected with water-bearing strata, or aquifers, water encroaches into the reservoir as the pressure drops owing to production .This water encroachment decreases the extent to which the remaining oil and gas expand and accordingly retards the decline in reservoir pressure.

In as much as the temperature in oil and gas reservoir remains substantially constant during the course of production, the degree to which the remaining oil and gas expand depends only on the pressure .By taking bottom-hole samples of the reservoir fluids under pressure and measuring their relative volumes in the laboratory at reservoir temperature and under various pressures ,it is possible to predict how these fluids behave in the reservoir as reservoir pressure declines.

The general material balance equation is simply a volumetric balance, Which states that since the volume of a reservoir (as defined by its initial limits)is a constant , the algebraic sum of the volume changes of the oil , free gas , water , and rock volumes in the reservoir volumes decreases , the sum of these two decreases must be balanced by changes of equal magnitude in the water and rock volumes .

If the assumption is made that complete equilibrium is attained at all times in the reservoir between the oil and its solution gas , it is possible to write a generalized material balance expression relating the quantities of oil , gas and water produced , the average reservoir pressure , the quantity of water that may have encroached from the aquifer , and finally the initial oil and gas content of the reservoir.

LECTURE 17

Reserves are natural resources that have already been discovered and can be exploited for profit today

Resources are deposits that we know of (or believe to exist), but are not exploitable today

Example: oil reserves ~1.2 trillion barrels, oil resources ~2 trillion barrels

Types: Oil, Gas, Natural Gas, Condensated gas, GNL and other fluids(CO2,N2,H2S)

Based :

Interpretation of Data Engineering and / or Geology available to date. Economic conditions such as prices, costs and market.

NATURAL ENERGY (PRIMARY RECOVERY)

ENHANCED RECOVERY METHODS

Analogies Volumetric Methods Material balance Decline Curve Analysis Reservoir Simulation Probalistic (Monte Carlo)

•Contour map of the productive

zone (net productive sand).

•Two methods are used for determining the gross volume:

•Trapezoidal V = h*( 0.5*A0 + A1+A2+A3+0.5*A4)

•Pyramidal V = h (A0 + 4*A1+2*A2+4*A3+A4)

3

For calculating insitu oil:

N = 7758*V*f*(1-Swi) / Boi STB

For the remaining oil:

Nf = 7758*V*f*(1-Swg) / Bo

Nf = 7758*V*f*(1-Sw -Sg) / Bo

The recovery factor F.R. :

F.R. = Np/N = 1 - Nf/N

V = Gross volume in Acres*ft

f = Porosity in fraction

Swi = Initial water saturation Fraction

Boi = Formation volume factor initial oil

Bo = formation volume factor of the final oil

Gas for calculating insitu: G = 43560*V*f*(1-Swi) / Bgi SCF

Para el gas remanente:

Ga = 43560*V*f*(Sgr) / Bga

The recovery factor F.R. :

F.R. = Gp/G =(Bga-Bgi)/Bgi

Méthod

o = 141.5 / (131.5 + API)

Mo= 6084/(API-5.9)

mw = R g 28.97 + 350 o

379

nw = R + 350 o

379 Mo

Mw = 0.07636 Rg + 350 o

0.002636 R + 350 o

Mo

w = Mw/28.97=Rg + 4584 o

R + 132800o

Mo

We found the Tr and Pr and

then the value of Z then

determine:

Gw = 379 PV/ ZRT

V = 43560 AH f(1-Swi)

R = 10.73 Psia-ft3 / lb-mol °R

Gas fraction:

fg = R /(R + 132800o/Mo

Amount of gas:

G = Gw* fg

Amount of liquids

N = Gw fg/R

Method 2.

avg gas prod. = gt ;

gt = qps ps + qst st

qps + qst Knowing STB cond. / MMSCF

and developed by using a

graph Standing can determine

a ratio (R)= u/ gt and by

empirical correlation can be

developed by finding Bo

Standing for condensate

reservoir.

There is a graph of Bo

function:

R SCF/STB, gt , st ,

Temperature reserv.

P reservoir,

relations at high gas / oil.

Amount of liquids

N = 7758Ah f (1-Swi)/ Bo

Amount of gas:

G = Rsi* N

Exponential Decline Conversions (where b = 0)

Hyperbolic Decline Conversions (where 0 < b < 1)

Harmonic Decline Conversions (where b = 1)

Lineal (where b = 1)

( ( b

i

i

tbD

qtq

11+

=

( tD

i

ie

qtq =

( ( tD

qtq

i

i

+=

1

( )*1(* tDqtq ii =

Exponential Decline Conversions (where b = 0)

Hyperbolic Decline Conversions (where 0 < b < 1)

Harmonic Decline Conversions (where b = 1)

Lineal (where b = 1)

)/()(* 11

ii

bb

iip bDDqqbqN =

iip DqqN /)( =

iiip DqqqN /)/ln(=

2/)( 21 qqNp =

Applications Mechanism PLOT

Hyperbolic • Solution Gas log (Np) vs log (q)

Exponential • Solution Gas Np vs q

• Water drive

wc = 0Np vs q

2

Lineal

• Water drive

wc <> 0Np vs cut (oil/water)

Exponential • Water drive with

fluid production cte. Np vs q

Harmonic • Water drive edge Np vs q

Lineal

• Gas cap

with slow GOR,

Solution gas = 0

Np vs 1/p

Hyperbolic

• Gas cap drive

with slow GOR

with solution gas slow

log (Np) vs log (q) b = 2,0

• Gas cap drive

after GOC break through

well producres.

Np vs GOR

Np vs Depth GOC

Para el cálculo tenemos: masa inicial- masa final final = masa removida

ni - nf = n producido del reservorio

PiVi/ziRT - PfVf/zfRT = PscGp/RTsc

Vf = Vi - We + WpBw

GBgi -(G -Gp) Bgf = We + WpBw

Reservorio volumétrico, no hay intrusión de

agua entonces Vi=Vf

Pf/zf = Pi/zi - Psc TGp/Tsc = b - m Gp

P/z

Gp MMM SCF

Gi

Pi/zi

Reservorios No saturado, producción

cerca al punto de Burbuja no hay intrusión

de agua, Compresibilidad de la formación

y agua=0

Vi = Vf ; Vi = N Boi ;

Vf = Nf Bof = (N - Np) Bof

Luego: N Boi = (N - Np) Bof

N = Np Bof / (Bof - Boi )

F.R. = (Bof - Boi )/ Bof

PETROLEO PETROLEO

AGUA AGUA

Pi Pb

Reservorios No saturado, producción

cerca al punto de Burbuja no hay intrusión agua , si

efectos compresibilidades

Cf +w = Cf +CwSwi/ (1-Swi)

N = Np Bof / (Bof - Boi (1- Cw+f DP))

F.R. = Bof - Boi (1- Cw+f DP)/ Bof

Reservorios No saturado, producción

debajo al punto de Burbuja no hay

intrusión de agua

Vi = Vf = Vo + Vg;

N Boi = (N - Np) Bof + Gf Bgf

Gf = Nrsi - (N-Np)Rs - NpRp siendo Rp = Gp/Np

N = Np [Bof + Bg (Rp- Rs)]/ [Bof - Boi + Bg(Rsi-Rs)]

F.R.= [Bof - Boi + Bg(Rsi-Rs)]/ [ Bof + Bg (Rp- Rs)]

Si hay intrusión de agua:

Vi = Vf = Vo + Vg+ Vw

Vw = We-BwWp

N ={ Np [Bof + Bg (Rp- Rs)]- (We-BwWp)}

[Bof - Boi + Bg(Rsi-Rs)]

PETROLEO PETROLEO

AGUA AGUA

Pi Pf

GAS

Pb

Reservorios No saturado, producción

debajo al punto de Burbuja no hay

intrusión de agua, considerando la

expansión del volumen poroso

N = Np [Bof + Bg (Rp- Rs)]

[Bof - Boi + Bg(Rsi-Rs) + Cf+w Boi DP]

F.R.= [Bof - Boi + Bg(Rsi-Rs) + Cf+w Boi DP ]

[ Bof + Bg (Rp- Rs)]

PETROLEO PETROLEO

AGUA AGUA

Pi Pf

GAS

Pb

Reservorios saturado, producción

debajo al punto de Burbuja , intrusión

de agua, considerando la

expansión del volumen poroso

m= Vgli/Voi

Vi = Vf = Vo + Vgd + Vgl + Vw;

Vgl = m N Boi [Bg - Bgi] / Bgi

N = Np [Bof + Bg (Rp- Rs) - (We-BwWp) ]

[Bof - Boi + Bg(Rsi-Rs) + m Boi [Bg - Bgi] / Bgi]

PETROLEO PETROLEO

AGUA AGUA

Pi Pf

GAS

Pb

Intrusión de agua.

GAS

LECTURE 17

The area of concern in this lecture includes:

• Types of fluids in the reservoir

• Flow regimes

• Reservoir geometry

• Number of flowing fluids in the reservoir

TYPES OF FLUIDS

In general, reservoir fluids are classified into three

groups:

• Incompressible fluids

• Slightly compressible fluids

• Compressible fluids

Incompressible fluids

An incompressible fluid is defined as the fluid whose

volume (or density) does not change with pressure.

Incompressible fluids do not exist; this behavior,

however, may be assumed in some cases to simplify

the derivation and the final form of many flow

equations.

Slightly compressible fluids

These “slightly” compressible fluids exhibit small changes in

volumeor density, with changes in pressure.

It should be pointed out that crude oil and water systems fit into

this category.

Compressible Fluids

These are fluids that experience large changes in volume as a

function of pressure. All gases are considered compressible

fluids.

FLOW REGIMES

There are three flow regimes:

• Steady-state flow

• Unsteady-state flow

• Pseudosteady-state flow

Steady-State Flow

The flow regime is identified as a steady-state flow if

the pressure at every location in the reservoir

remains constant, i.e., does not change with time.

Mathematically, this condition is expressed as:

(4-1)

The above equation states that the rate of change of pressure p

with respect to time t at any location i is zero. In reservoirs, the

steady-state flow condition can only occur when the reservoir is

completely recharged and supported by strong aquifer or

pressure maintenance operations.

Unsteady-State Flow

The unsteady-state flow (frequently called transient flow) is

defined as the fluid flowing condition at which the rate of change

of pressure with respect to time at any position in the reservoir

is not zero or constant.

This definition suggests that the pressure derivative with respect

to time is essentially a function of both position i and time t, thus

(4-2)

Pseudosteady-State Flow

When the pressure at different locations in the reservoir is

declining

linearly as a function of time, i.e., at a constant declining rate, the

flowing condition is characterized as the pseudosteady-state

flow. Mathematically, this definition states that the rate of

change of pressure with respect to time at every position is

constant, or

(4-3)

It should be pointed out that the pseudosteady-state flow is

commonly referred to as semisteady-state flow and

quasisteady-state flow.

Figure shows a schematic comparison of the pressure declines as

a function of time of the three flow regimes.

RESERVOIR GEOMETRY

For many engineering purposes, however, the actual flow geometry

may be represented by one of the following flow geometries:

• Radial flow

• Linear flow

• Spherical and hemispherical flow

Because fluids move toward the well from all directions and

coverage at the wellbore, the term radial flow is given to

characterize the flow of fluid

into the wellbore. Figure 4-1 shows idealized flow lines and iso-

potential lines for a radial flow system.

Figure 4-1 Ideal radial flow into a wellbore

Linear Flow

Linear flow occurs when flow paths are parallel and the fluid flows

in a

single direction. In addition, the cross sectional area to flow must

be

constant. Figure 4-2 shows an idealized linear flow system.

Figure 4-2 Ideal linear flow

into vertical fracture

Spherical and Hemispherical Flow Depending upon the type of wellbore completion configuration,

it is possible to have a spherical or hemispherical flow near

the wellbore. A well with a limited perforated interval could

result in spherical flow in the vicinity of the perforations as

illustrated in Figure 4-3. A well that only partially penetrates

the pay zone, as shown in Figure 4-4, could result in

hemispherical flow. The condition could arise where coning

of bottom water is important.

Figure 4-3 Spherical flow due to limited entry

Figure 4-4 Hemispherical flow in a partially penetrating well

NUMBER OF FLOWING FLUIDS IN THE RESERVOIR

There are generally three cases of flowing systems:

• Single-phase flow (oil, water, or gas)

• Two-phase flow (oil-water, oil-gas, or gas-water)

• Three-phase flow (oil, water, and gas)

The description of fluid flow and subsequent analysis of pressure

data becomes more difficult as the number of mobile fluids increases.

LECTURE 18

Since 1980, horizontal wells began capturing an ever-increasing

share of hydrocarbon production. Horizontal wells offer the

following advantages over those of vertical wells:

• Large volume of the reservoir can be drained by each horizontal

well.

• Higher productions from thin pay zones.

• Horizontal wells minimize water and gas zoning problems.

• In high permeability reservoirs, where near-wellbore gas velocities

are high in vertical wells, horizontal wells can be used to reduce

near-wellbore velocities and turbulence.

• In secondary and enhanced oil recovery applications, long

horizontal injection wells provide higher injectivity rates.

• The length of the horizontal well can provide contact with multiple

fractures and greatly improve productivity.

The actual production mechanism and reservoir flow regimes around

the horizontal well are considered more complicated than those for

the vertical well, especially if the horizontal section of the well is of

a considerable length. Some combination of both linear and radial

flow actually exists, and the well may behave in a manner similar

to that of a well that has been extensively fractured.

Assuming that each end of the horizontal well is represented by a

vertical well that drains an area of a half circle with a radius of b,

Joshi (1991) proposed the following two methods for calculating

the drainage area of a horizontal well.

Method I

Joshi proposed that the drainage area is represented by two half

circles of radius b (equivalent to a radius of a vertical well rev) at

each end and a rectangle, of dimensions L(2b), in the center.

The drainage area of the

horizontal well is given then by:

Figure 5-1

(5-1)

where

A =drainage area, acres

L =length of the horizontal well, ft

b =half minor axis of an ellipse, ft

Method II

Joshi assumed that the horizontal well drainage area is an ellipse

and given by:

(5-2)

with

(5-3)

where a is the half major axis of an ellipse.

Joshi noted that the two methods give different values for the

drainage area A and suggested assigning the average value for

the drainage of the horizontal well. Most of the production rate

equations require the value of the drainage radius of the

horizontal well, which is given by:

(5-4)

Where

reh =drainage radius of the horizontal well, ft

A =drainage area of the horizontal well, acres

LECTURE 19

A thorough understanding of the flowing well is necessary prior to placing it on artificial lift . There are two surface conditions under which a flowing well is produced , that is , it may be produced with a choke at the surface or it may be produced with no choke at the surface. The majority of all flowing wells utilize surface chokes . Some of the reasons for this are safety ; to maintain production allowable ; to maintain an upper flow rate limit to prevent sand entry ; to produce the reservoir at the most efficient rate ; to prevent water or gas coning ; and others.

In particular , flowing wells utilize a choke in their early stages of production . As time progresses , the choke size may have to be increased and eventually removed completely in order to try to optimize production .

The second condition that we are concerned with is producing the flowing well with no restrictions at the surface except normal Christmas tree turn , bends, etc . Even these may be streamlined in order to obtain the maximum flowing rate possible .

In order to analyze the performance of a conventionally completed flowing well , in is necessary to recognize that there are three distinct phases , which have to be studied separately and then finally linked together before an overall picture of a flowing well’s behavior can be obtained . These phase are the inflow performance , the vertical lift performance , and the choke (or bean )performance.

The inflow performance , that is , the flow of oil , water , and gas from the formation into the bottom of the well , is typified , as far as gross liquid production is concerned , by the PI of well or , more generally , by the IPR .

The vertical lift performance involves a study of the pressure losses in vertical pipes carrying two-phase mixtures(gas and liquid).

LECTURE 20

Oil well pumping methods can be divided into two main groups:

Rod systems.Those in which the motion of the subsurface pumping equipment originates at the surface and is transmitted to the pump by means of a rod string.

Rod less systems.Those in which the pumping motion of the subsurface pump is produced by means other than sucker rods.

Of these teo groups,the first is represented by the beam pumping system and the second is represented by hydraulic and centrifugal pumping systems.

The beam pumping system consists essentially of five parts:

The subsurface sucker rod—friven pump. The sucker rod string which transmits the

surface pumping motion and power to the subsurface pump.Also included is the necessary string of tubing and/or casing within which the sucker rods operate and which conducts the pumped fluid from the pumpto the surface.

The surface pumping eauipment which changes the rotating motion of the prime mover into oscillatinf linear pumping motion .

The power transmiddion unit or speed reducer. The prime mover which furnishes the necessary

power to the system.

LECTURE 22

Skin Factor

It is not unusual for materials such as mud

filtrate, cement slurry, or clay particles to

enter the formation during drilling,

completion or workover operations and

reduce the permeability around the wellbore.

This effect is commonly referred to as a wellbore damage and

the region of altered permeability is called the skin zone. This

zone can extend from a few inches to several feet from the

wellbore. Many other wells are stimulated by acidizing or

fracturing which in effect increase the permeability near the

wellbore. Thus, the permeability near the wellbore is always

different from the permeability away from the well where the

formation has not been affected by drilling or stimulation. A

schematic illustration of the skin zone is shown in Figure 4-5.

Skin Factor

Those factors that cause damage to the formation can produce

additional localized pressure drop during flow. This additional

pressure drop is commonly referred to as Dpskin. On the other

hand, well stimulation techniques will normally enhance the

properties of the formation and increase the permeability around

the wellbore, so that a decrease in pressure drop is observed.

Figure 4-5

• Positive Skin Factor, s > 0

When a damaged zone near the wellbore exists, k-skin is less

than k and hence s is a positive number. The magnitude of the

skin factor increases as k-skin decreases and as the depth of

the damage r skin increases.

• Negative Skin Factor, s < 0

When the permeability around the well k-skin is higher than that of

the formation k, a negative skin factor exists. This negative

factor indicates an improved wellbore condition.

• Zero Skin Factor, s = 0

Zero skin factor occurs when no alternation in the permeability

around the wellbore is observed, i.e., k-skin =k.

LECTURE 23;24

LECTURE 25

FINAL TEST