Basics of reservoir engineering 250409 112704

(1)

Basic Reservoir

Engineering

(2)

Basic Reservoir

Engineering

(3)

Rock Types

(4)

Types of Rocks

• Igneous Rocks (from Magma when cools and solidifies)

– basalt (ext.), andesite, granite, gabbo (int.) etc.

• Sedimentary Rocks (compressed and cemented)

– Clastic, Organic and Chemical

– sandstone, limestone, dolomite, shale, halite, etc.

• Metamorphic Rocks (any type change by heat / pressure)

– marble (metamorphosed limestone), schist, gneiss, etc.

• Majority of important hydrocarbon reservoirs rocks are sedimentary rocks

(5)

Sedimentary Rock Classification

Clastic Rock -

Formed From Debris (weathering and erosion) of Older Rock

Rock Type Particular Diameter

Conglomerate Sandstone Siltstone Shale

Pebbles Sand Silt Clay

- 2 to 64 mm - 0.06 to 2 mm - 0.003 to 0.06 mm - Less than 0.003 mm

Nonclastic - Mostly of Chemical or Biochemical Origin

Rock Type Composition

Limestone Calcite - CaCO3

Dolomite Dolomite - CaMg(CO3)2

Salt Halite - NaCI

Gypsum Gypsum - CaSO4.2H2O

Chert Silica - SiO2

Coal Chiefly Carbon

(6)

The Rock Cycle

Cooling& solidification (crystallization)

Melting

Magma

Metamorphic rocks

HeatandPressure (Metamorphism)

Heat and Pressure (Metamorphism)

Sedimentary rocks

Weathering, transport and deposition Compression& Cementation

Sediments

Igneous

rocks Weathering, transport and deposition

(7)

Hydrocarbon Traps

(8)

Conditions Required for Hydrocarbon Reservoir

• Mother rock

– rich in organic material

• Alteration

– molecular structure change by heat and

hydrocarbon migrate through porous media or fracture

• Trap

– trapped by a impermeable rock

• Reservoir Rock

– porous and permeable

(9)

Accumulation of Oil & Gas into a Reservoir

(10)

"Normal" Pressure Distribution from Surface through a Reservoir Structure

(11)

• Trap Types

–Structural

–Stratigraphical –Combined

Hydrocarbon Traps

(12)

Oil

Sandstone Shale

Gas

Dome Trap

(13)

Oil / Gas

Fault Trap

(14)

Salt Diapir

Oil/Water Contact

Oil/Gas Gas Contact

Closure

Shale Oil Trap

Fractured Basement

Oil

Fold Trap

Salt Oil

Dome

Structural Traps

(15)

Channel Pinch Out

Oil/Gas

(modified from Bjorlykke, 1989)

Oil/Gas

Uncomformity

Oil/Gas

Unconformity Pinch out

Stratigraphic Traps

(16)

Asphalt Trap

Water

Biodegraded Oil/Asphalt Partly

Biodegraded Oil

Hydrodynamic Trap

Shale

Water

Hydrostatic Head

Other Traps

Meteoric Water

Oil

(17)

Reservoir Fluid Overview

(18)

Hydrocarbon

• Combination of C and H

H

H C H

H H

H C C H H H

H H H

H C C C H H H H

C C C

H

C H

C

C H

H H

METHANE ETHANE

PROPANE

(19)

Structure of Several Members of the Arene, or Aromatic, Series

(20)

Other elements found in Reservoir Fluids

• Water (Salinity)

• H2S

• CO2

• N2

• Hg (Mercury)

(21)

API Gravity

or

SG

141.5

API + 131.5 SG =

API = 141.5 −131.5

Where

SG: Specific Gravity

API: API Gravity (60degF)

(22)

Classification of Hydrocarbon

Black Volatile Retrograde Wet Dry

Oil Oil Gas Gas Gas

Initial <1750 1750 to > 3200 > 15,000* 100,000*

Producing 3200

Gas/Liquid Ratio, scf/STB

Initial Stock- < 45 > 40 > 40 Up to 70 No

Tank Liquid Liquid

Gravity, API

Color of Stock- Dark Colored Lightly Water No

Tank Liquid Colored White Liquid

*For Engineering Purposes

(23)

Black Oil

Volatile Oil

Retrograde Gas

Wet Gas

Dry Gas Phase

Change in Reservoir

Bubblepoint Bubblepoint Dewpoint No Phase Change

No Phase Change Heptanes

Plus, Mole Percent

> 20% 20 to 12.5 < 12.5 < 4* < 0.8*

Oil

Formation Volume Factor at Bubblepoint

< 2.0 > 2.0 - - -

*For Engineering Purposes

Classification of Hydrocarbon

(24)

0

0 30

Heptanes plus in reservoir fluid, mole % Initialproducing gas/oilratio,scf/STB

Dewpoint gas Bubblepoint oil Volatile

oil Wet Retrograde

gas gas

50000 Dry gas

Black oil

Classification of Hydrocarbon

(25)

Hydrocarbon Behavior

(Single component / Constant temp.)

(26)

Hydrocarbon Behavior

(Single component / Constant temp.)

(27)

Vapor Pressure Curves for Two Pure Components and Phase Diagram for a 50:50 Mixture of the Same Components

(28)

Reservoir Fluid PVT Diagram

Criocondenbar

Criocondentherm Critical point

(29)

Phase Diagram of a Typical Black Oil

Black Oil

Critical Point

Pressure,psia

Separator

Pressure path in reservoir

Dewpoint line

% Liquid

Temperature, °F

(30)

Pressure

Temperature, °F

Separator

% Liquid

Dewpoint line Pressure path

in reservoir

2 Volatile oil

3

1 ^Critical_point

Phase Diagram of a Typical Volatile

Oil

(31)

3

Separator

% Liquid Pressure path

in reservoir 1

Retrograde gas 2

Critical point

Pressure

Temperature

Phase Diagram of a Typical

Retrograde Gas

(32)

Pressure

Temperature

% Liquid

1

Wet gas

Critical point

2

Separator

Phase Diagram of a Typical Wet

Gas

(33)

Pressure

Temperature

1

Dry gas

% Liquid

2

Separator

Phase Diagram of a Typical Dry

Gas

(34)

Three Gases

• Dry gas - gas at surface is same as gas in reservoir

• Wet gas - recombined surface gas and condensate represents gas in reservoir

• Retrograde gas - recombined surface gas and condensate

represents the gas in the reservoir but not the total reservoir fluid

(retrograde condensate stays in

reservoir)

(35)

Relationships between Surface and Downhole Volumes

— Dissolved Gas Systems

(36)

Typical PVT Data for Differential Vaporization of an Undersaturated Oil at Constant Temperature (305°F)

(37)

Oil Formation Volume Factor (Bo)

Pb

Oil at Surface

Gas at Surface

Oil in Place Oil Volume in Place

Oil Volume at Surface Bo =

(38)

Production Gas Oil Ratio (GOR)

Pb

Oil at Surface

Gas at Surface

Oil in Place Oil Volume at Surface GOR = GasVolume at Surface

(39)

Excercise

• There is 1,000,000 bbls of recoverable oil in reservoir. If you recover all of the oil to the

surface, how much stock tank volume of oil and gas (standard condition) you can obtain?

Assume: Bo = 1.2, GOR = 600, reservoir is saturated and no free gas is drained.

• If the oil price is $25/bbl and gas price is $3/mscf, how much revenue can you get? (you do not

have to consider production cost in this exercise).

(40)

GOR  Rs

Surface

Reservoir

Bg

GOR

Rs

Vo Vg3

GWR

Vg2 Vg1

GOR = V

_g

1 + V

_g

2 + V

_g

3 V

_o

Bw Bo

(41)









 B k

ro

rg

g 

o  ^o 

GOR = Rs_{+ }

B ^  ^k



Gas-Oil Ratio

(for Pr < Pb and no Free Gas Cap)

where:

GOR R_s

B_oand B_g

_o and _g k_rg/k_ro

– Production gas oil ratio – Gas in solution in oil

– Oil and gas volume factors – Oil and gas viscosities

– Gas/oil-relative permeability-ratio

(42)

Basic Parameters Used

in Reservoir Engineering

(43)

Viscosity (  )

• A measure of resistance to flow

• Symbols –_o, _g, _w

• Units – cp

• Source – Lab measurements, correlations

• Range and typical values

–0.25 – 10,000 cp, Black oil –0.5 – 1.0 cp, Water

–0.012 – 0.035 cp, Gas

(44)

Variation of Viscosity with Pr

Visc

Pressure

Pb

(45)

Fluid Compressibility (C

_o

, C

_g

, C

_w

)

c

_o

 − 1 V

_o

= −  ln ( V

_o

)

V

_o

p p

• Fractional change in volume due to a unit change in pressure

• Symbol – c_o, c_g, c_w

• Units – psi^-1, microsips (1 microsip = 1x10^-6 psi^-1)

• Source – Lab measurements, correlations

(46)

Porosity (  )

•Total Porosity

•Effective Porosity

(47)

Cubic Packing of Spheres

Porosity = 48%

(48)

Rhombic Packing of Spheres

Porosity = 27 %

(49)

Packing of Two Sizes of Spheres

Porosity = 14%

(50)

Intergranular Porosity

rombohedrally packed spheres:  = 26%

grain sorting, silt, clay and cementation effect porosity

(51)

Permeability (K)

A p k = qL

• Permeability is the measure of capacity of rock to transmit fluid.

: k

: Darcy or milliDarcy (D or mD) : Well tests (eff.), core analysis

• Symbol

• Units

• Source (abs.)

• Range : 0.001 mD - 10,000 mD

 L

q = kA  p

or

(52)

Definition of a Darcy

(53)

Effect of Grain Size on Permeability

(54)

Same Effective Porosity – Different

Permeabilities

(55)

Relative Permeability (K

_rw

, K

_ro

)

(56)

Pore Compressibility (C

_f

)

c f  1  =  ln (  )

 p p

–4x10^-6psi^-1, well-consolidated sandstone –30x10^-6psi^-1, unconsolidated sandstone –4 to 50 x 10^-6psi^-1consolidated limestones

(57)

Net Pay Thickness

h_net = h₁ + h₂ + h₃

Shale Sand

h₃ h₂ h₁

(58)

Saturations (S

_w

, S

_o

, S

_g

)

H₂O

(59)

Archie’s Equation

where:

S_w: water saturation a: constant

: porosity

m: cementation factor

R_w: formation water resistivity R_t: true resistivity (measured by deep resistivity

measurement)

t w

S² R

(lim estone ) S² R

( sandstone ) Sⁿ R



²



^2.15

a R_w



^m

= 1 R_w

= 0.62 R_w

=

(60)

Types of Openhole Logs to Determine Saturation

• Resistivity log – Induction tools – Laterolog tools

• Porosity log

– Neutron tools – Density tools – Sonic tools

– Magnetic resonance tools

(61)

Exercise

• Calculate oil saturation in the following case

Rock type: sandstone

R_w: 0.0912 (at bottom hole temperature)

: 0.2

R_t: 20 ohm meter

(62)

Solution

20 0.2

^2.15

w

0.62 0.0912 0.2

^2.15

20

0.62 0.0912 S

_w²

S

_w

= 0.3

 S

_o

= 0.7 S =

=

(63)

Wellbore Radius (r

_w

)

r_w

Bit Size or

Caliper Reading

(64)

Total Compressibility (C

_t

)

+ S g c g c t = c f + S o c o + S w c w

Typically, C_w : 3E^-6

C_o : 3E^-5(Black oil) C_g : 1/pressure

C_f : 4E^-6

(65)

Exercise

• Calculate total compressibility in the following case

• c_f : 3.6E-06

• c_o : 1.158E-05

• c_w : 2.277E-06

• c_g : 6.023E-05

S_o : 0.83 S_w : 0.17 S_g : 0

(66)

Exercise Solution

C

_t

= 1.36 x 10

^-5

psi

^-1

(67)

Exercise

• Calculate total compressibility in the following case

• c_f : 3.6E-06

• c_o : 1.158E-05

• c_w : 2.277E-06

• c_g : 6.023E-05

S_o : 0.73 S_w : 0.17 S_g : 0 .1

Compare solution with previous Example

(68)

Calculation of

Hydrocarbon Volumes

(69)

Oil Initially In Place (OIIP or POES)

OIIP = Ah  ( 1 − S w )

Where;

A: Area

h: Thickness

: Porosity

S

_w

: Water Saturation

(70)

Stock Tank Oil Initially In Place

Where:

A: area

: porosity

h: formation thickness S_w: water saturation B_o: formation volume factor

STOIIP = Ah  ( Bo 1 − Sw )

(71)

What are Reserves?

• Oil and gas trapped beneath the earth’s

surface that can be recovered under existing economic conditions and with current

technology.

(72)

Recovery Factor

• Affected by:

– Reservoir Rock – Fluid Properties

– Reservoir Continuity, Heterogeneity – Economic Conditions



_{t ,p}

N

_p

 RF = 

N

where:

N: stock tank oil originally in place Np: cumulative stock tank oil prod

(73)

Reserves Uncertainty

True Ultimate Recovery

Wells Completed

Cumulative Production

Time

Abandonment At Economic Limit Increasing

Recovery

Range of

Recovery Estimates

II

I III

(74)

Exercise

• What is the STOIIP in the following case (in bbls)?

A: 300m x 500m h: 200m : 20%

S_w: 25%

1m³ = 6.289bbls

B_o: 1.35

• If ultimate RF of this reservoir is 30% and oil

price is $20/bbl, how much is the total revenue?

Assume there is no market for the gas in this case.

(75)

Probabilistic Estimation

ProbabilityDensity ProbabilityDensity

Min Max Min Max

Frequency of CumulativeProbability 1.0

0 Min Max

Monte Carlo Approach

No preference Strong preference

(76)

Recoverable Reserve

Probabilistic Representation

Probabilitythatthereserve isatleast aslargeasindicated

Min 1.0

0

Recoverable

Proven reserve (10% level)

Proven + Probable (50% level)

Proven + Probable + Possible (90%

level) Max

RR=STOIIP x RF

(77)

Reservoir Drive Mechanism

(78)

• Solution-gas drive

• Gas-cap drive

• Water drive

• Combination drive

• Gravity-drainage drive

Oil Reservoir Drive Mechanisms

(79)

• Liberation, expansion of solution gas

• Influx of aquifer water

• Expansion of reservoir rock and compression of pore volume

• Expansion of original reservoir fluids - Free gas

- Interstitial water - Oil, if present

• Gravitational forces

Reservoir Energy Sources

(80)

Solution Gas Drive in Oil Reservoirs

(81)

• No original gas cap or aquifer

• Main source(s) of reservoir energy

• liberation and expansion of dissolved gas

• Possible secondary gas cap

• liberated free gas can migrate up-structure

• Typical production characteristics

• Rapid GOR increase after P_b

Solution Gas Drive in Oil Reservoirs

(82)

Formation of Secondary Gas Cap

(83)

Reservoir pressure behavior

Bubblepoint pressure Initial reservoir

pressure

10 0

15

5

Oil recovery, % of OOIP

Reservoirpressure, psig

Typical Production Characteristics

(84)

Gas/oilratio,SCF/STB

Gas/oil ratio

Reservoir pressure

Oil production rate

Time, years Production data

Oilproduction rate,STB/D ⁸⁰⁰

600

400

200

0

400

300

200

100

0 400

300

200

100

0

Pressure,psia

Solution Gas Drive in Oil Reservoirs

(85)

Cross Section

Oil producing well

Oil zone

Oil Gas cap zone

Gas Cap Drive

(86)

• Free gas phase exists as an original gas cap

• Pure gas-cap drive reservoir has no aquifer

• Expansion of gas cap and liberation and expansion of solution gas in the oil zone

• Gas cap expands pushing GOC down and maintaining higher pressure

• Good sweep

• dramatic GOR increase when gas breakthrough

Gas Cap Drive

(87)

Pressure,psia

Time, years

Production data

Gas/oilratio,scf/STB

2 1 0

800 600 400 200 0

Reservoir pressure

Gas/oil ratio

Oil

1300 1200 1100 1000 900

Oilproductionrate, MSTB/D

Gas Cap Drive

(88)

Water Drive in Oil Reservoirs

• Oil zone in communication with acquifer

• influx of acquifer water - edge-water drive, bottom-water drive

• Pressure decline relatively slow

• GOR kept relatively low and stable

• Water production increases steadily

• Oil production declines when water breakthrough

• Reasonable sweep - depends on mobility ratio

(89)

Water Water

Cross Section

Oil Zone

Water Drive in Oil Reservoirs

Edge-Water Drive

(90)

Cross Section

Oil Zone

Water

Bottom-Water Drive

(91)

Production data

Time, years 100

80 60 40 20 0 2300 2200 2100

2000 1900

2

1 40 0 30 20 10

Gas/oilratio,MSCF/STB 0 Watercut,%

Gas/oil ratio

Oil Water

Oilproductionrate, MSTB/D

Water Drive in Oil Reservoirs

(92)

2 1

0 60 40 20 0 2000

1900 1800 1700

20 15 10 5 0

Water

Gas/oil ratio

Oil

Time, years

Production data - lower oil production rate

WaterCut,%

Gas/oilratio,MSCF/STB

Oil production, MSTB/D

Effect of Production Rate on Pressure

(93)

Cross Section

Oil zone Water Gas cap

Combination Drive in Oil Reservoirs

(94)

• Main energy - gravitational force

• Good drainage efficiency and recovery factor

Oil

Point A

Point B

Point C Gas

Gas

Oil

Gravity Drainage in Oil Reservoirs

(95)

40 60 80 100 100

80

60

40

20

0

Gas-cap drive Water drive

Solution -gas drive

0 20

Reservoirpressure, Percentoforiginal

Cumulative oil produced, percent of original oil in place

Reservoir pressure trends

Pressure Trend

(96)

5

4

3

2

1

0

0 20 40 60 80 100

Cumulative oil produced, percent of original oil in place

Gas/oil ratio trends

Gas/oilratio,MSCF/STB

Water drive

Gas-cap drive Solution-

gas drive

GOR Trend

(97)

• Volumetric reservoir (gas expansion drive)

• Water drive

Gas Reservoir Drive Mechanisms

(98)

Volumetric Gas Reservoirs

• Gas reservoir with no acquifer

• expansion of gas

• Pressure decline slowly and continuously

• No water production

• Flowing life can be increased by reducing surface back-pressure through installing compression

(99)

Water Drive in Gas Reservoirs

• Gas reservoir with acquifer

• expansion of gas and water influx

• Pressure decline slower than volumetric gas reservoir

• Water production may start early and increases with time

• Flowing life can be increased by installing continuous or intermittent water removal equipment

(100)

• Solution-gas drive

• Gas-cap drive

• Water drive

• Combination drive

• Gravity-drainage drive

Oil Reservoir Drive Mechanisms

(summary)

(101)

• Volumetric reservoir (gas expansion drive)

• Water drive

Gas Reservoir Drive Mechanisms

(summary)

(102)

Exercise

• What is the drive mechanism of your reservoir?

• What are the characteristics of pressure, GOR, water production evolution?

(103)

Average Recovery Factors

Oil Reservoirs

Drive Mechanism

Average Oil Recovery Factors,

% of OOIP

Range Average

Solution-gas drive 5 - 30 15

Gas-cap drive 15 - 50 30

Water drive 30 - 60 40

Gravity-drainage drive

16 - 85 50

(104)

Average Recovery Factors

Gas Reservoirs

Drive Mechanism

Average Gas Recovery Factors,

% of OGIP

Range Average

Volumetric reservoir

(Gas expansion drive)

70 - 90 80

Water drive 35 - 65 50

(105)

• 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

Properties Favorable for Oil

Recovery

(106)

• Water drive oil reservoirs

• Large aquifer

• Low oil viscosity

• Gravity drainage oil reservoirs

• High reservoir dip angle

• Favorable permeability distribution

Properties Favorable for Oil Recovery

• High relative oil permeability

• Little reservoir heterogeneity and stratification

• Large fluid density difference

• Large segregation area

• Low withdrawal

(107)

• Volumetric gas reservoir (gas expansion drive)

• Low abandonment pressure

• Water-drive gas reservoir

• Large aquifer

• Small degree of reservoir heterogeneity and stratification

Properties Favorable for Gas

Recovery

(108)

• Solution-gas drive - API study

• E_R: in %

( )

^



  

^0.1741

^0.0979

 ^ob 

0.1611 wi

 p_a 

 p S_wi ^0.3722  ^b 

B_ob 

 

(

¹ ⁻ ^S

)

^ ^ ^k

E_R = 41.8 



Estimation of Oil Recovery Factors

(109)

• Water drive - API study







−0.2159 i

 ^a 

−0.1903 wi

^0.0770

 ^oi 

 ^w 

0.0422 wi

 

p

 p 

(

^S

)

k

 

(

¹ ⁻ ^S

)

^ ^

E_R = 54.9  

 B_oi 

(110)

• Water drive : Guthrie-Greenberger study

E_R = 0.272 log k + 0.256 S_wi − 0.136 log _o

− 1.538  − 0.0003 h + 0.114

(111)

Exercise

• Estimate recovery factor of your field

• Comments/observations?

(112)

Summary

• Average recovery factors

• Favorable reservoir properties

• Estimating oil recovery factors

(113)

Other Important Concepts

(114)

Productivity Index (PI or IP)

q

p − p

_wf

PI =

(115)





 r

k  h

 PI =

e

q

p − p

_wf

 − 3 + S

 r

_w

 4

141.2    B

0

 ln

(116)

Changes (decrease) with time:

•Decrease in the permeability to oil due to presence of free gas near the wellbore

•Increase of oil viscosity with Pr < Pb

•Reduction in perm. Due to formation compressibility.

(117)

Flow Efficiency

wf ideal

f

PI

E = PI

_actual

= p − p p −

_wf

p −  p

_s

8

8 + Skin Pr odRatio =

Rule of Thumb

(118)

Skin Concept:

500 1500

Introduced in 1953 by Van Everdingen and Hurst for differences in observed and calculated bottomhole pressure

2000

1 10 100 1000 10000

Distance from center of wellbore, ft

Pressure,psi

1000 p

s

(119)

Skin Concept:



^w

 P

_e

− P

_wf

Kh n  

=141.2 q  B

₀

 l  r r

_e



Steady State with flow at Re

(as per “Darcy”)

(120)

Skin Concept:

Steady State with flow at Re (“Real Life”)

Kh r

Kh

e

s

   S

 r

^w



P

_e

− P

_sf

−P =141.2 q  B

⁰

ln   − 141.2 q  B

⁰

(121)

Skin Concept:

s

= 141.2qB kh

p s

S = Skin Factor as per Van Everdingen and Hurst

S = Adimentional number. Not related to any physical phenomena

Extra pressure drop “at the wellbore”

Zero thickness ==> Skin

(122)

Skin Concept:

In 1956 Hawkins introduces the concept of “Thick Skin”

- Zone of altered permeability around the Wellbore (ra / Ka) -Extra Pressure drops occurs not in the “Skin”of the wellbore but in a “Thick Zone”.

(123)

Skin Concept:

500 1500

2000

1 10 100 1000 10000

Pressure,psi

1000 p_s

(124)

Skin Concept:

 



 





  

 

 ^w 

a a

a e

 ^w 

a a

a e

e

 ^w 

a

 ^w  e a a

a

 

r r K

K − K

 S =

 

r r K − K

K h 

K

  r

r K h

  r

r K h

 ln

 141.2

 ln

−141.2

 ln

P = 141.2

0

0 0

qB

qB qB

Could be related to a physical phenomena (Invasion)

(125)

Reservoir Pressure Profile

500 1000 2000

1 10 100 1000 10000

Pressure,psi

s = +5 s = -2

1500

s = 0

(126)

Skin Concept:

So

==> Skin is CHANGE IN PRESSURE DROP that exists near the wellbore in “real wells” compared to a “Darcy-model”

of the well

What can cause this change in pressure drop near the wellbore??:

•Geometrical factors:

•Inclined Well (S<0)

•Spherical flow (Partial completion / Penetration)

•Perforations (phase, density)

(127)

Skin Concept:

Mechanical Skin “Damage”:

•Zone of altered permeability around the wellbore

•Change in stress distribution

•Drilling completion damage

•Perforations ==> Crushed zone

•Others

•Gas liberated from solution near the wellbore

•Gravel Packs completions

•Fracture / Stimulations

(128)

Damage Caused by Drilling Fluid

Mud filtrate invasion

(129)

Damage Caused by Production

P < P_b P > P_b

(130)

Damage Caused by Injection

Incompatible Water

“Dirty” Water

(131)

Geometric Skin - Converging Flow

to Perforations

(132)

Completion Skin

s = s_p + s_d + s_dp



− 

 

R 

dp d 

R

  ^p 

dp 

p dp

k

 k k

 k r

r

 L nh 

s =  ln r_dp

L_p

k_R k_dp

k_d r_p

r_d r_w

After McLeod, JPT (Jan. 1983) p. 32.

(133)

Geometric Skin - Partial Penetration

h

h_p

(134)

Gravel Pack Skin

L_g

Cement

gp p gp

2nk r

²

s = k

_R

hL

_g

(135)

Geometric Skin - Deviated Wellbore

h



hsec

(136)

Geometric Skin - Well With Hydraulic Fracture

L_f

(137)

Skin Concept:

Pressure Build ups measures TOTAL Skin

Individual components of Skin can NOT be simply added

WE NEED TO KNOW WHAT PART OF THE SKIN CAN BE REMOVED.

(138)

Skin Concept:

Example:

Partial completion and damage (after Saidikowski 1979)











 





   

 

− 2 

− 1  ln

w v

p t p

p d

p t

k k _h

 r t

 h h s = h

 s + s h

h_t s =

St = Total Skin , Sd = Mechanical Skin, Sp=Partial Comp Skin ht = Total Net Thickness, hp = Perforated thickness

Kh = Horiz Perm, Kv = Vert. Perm.

(139)

Skin Concept:

Example:

Given:

ht= 50 ft , hp = 10ft, Kh=100md, Anisotropic ratio=10 Bs = 8.5 in

We perform a BU and we obtain a S = 11

Should we stimulate?

(140)

Skin Concept:

Example:

(141)