02 review of reservoir rock and fluid properties

1TALENTS FOR DEVELOPMENT @MSc. Bui Tu An

Well Test Analysis

The review of reservoir rock and fluid properties

(Oilfield Units)

Instructors:

Bui Tu An (PVU)

Huynh Thanh Tung (Schlumberger)

Nguyen Tuan Duong (VSP)


Reservoir rock properties

Porosity

Saturation

Permeability

Pore volume Compressibility

Net Pay Thickness


Porosity

Porosity is a measure of the capacity of the reservoir rock to

store fluids.

ebulk volum

volumepore


Porosity

• Symbol -

• Units

– Equations - fraction

– Reports - % (or fraction)

• Source

– Logs, cores

• Range or Typical Value

– 30%, unconsolidated well-sorted sandstone

– 20%, clean, well-sorted consolidated sandstone

– 8%, low permeability reservoir rock

– 0.5%, natural fracture porosity


Porosity


Saturation

Saturation is the fraction of pore volume occupied by a

particular fluid.

volumepore

mewater volu

volumepore

volumegas

volumepore

volumeoil

w

g

o

S

S

S


Saturation

• Units – fraction or %

• Source – logs


– 15 to 25% – connate water saturation in well-sorted,

coarse sandstones

– 40 to 60% – connate water saturation in poorly

sorted, fine-grained, shaly, low-permeability

reservoir rock


Saturation


Permeability

Permeability is the measure of capacity

of rock to transmit fluid.

pA

Lqk


Permeability

• Units: Darcy or millidarcy (D or mD)

• Source: Well tests, core analysis

• Range: 0.001 md - 10,000 md



Pore volume compressibility (formation compressibility

or rock compressibility) is the fractional change in

porosity due to unit change in pressure

ppp

V

Vc

p

p

f

ln11



• Units – psi-1, microsips (1 psip = 10-6 psi-1)

• Source – Lab measurement, correlation, guess


Net Pay Thickness

The net pay thickness is the total thickness of all

productive layers in communication with the well.

h = h1 + h2 + h3

Shale

Sand

h3

h2

h1


Net Pay Thickness

• Symbol – h Units – ft Source – logs

• Range: 5 ft or even less - 1,000 ft or more


Fluid Properties

Formation Volume Factor

Fluid Compressibility

Viscosity



The formation volume factor is the volume of fluid at

reservoir conditions necessary to produce a unit

volume of fluid at surface conditions (stock tank).

Symbol – Bo, Bg, Bw

Units – res bbl/STB, res bbl/ Mscf

Source – Lab measurements, correlations

st

res

V

VB



• Range and typical values

– Gas

• 0.5 res bbl/Mscf, at 9000 psi

• 5 res bbl/Mscf, at 680 psi

• 30 res bbl/Mscf, at 115 psi



Compressibility is the fractional change in volume due

to a unit change in pressure.

p

V

p

V

Vc oo

o

o

ln1

p

V

p

V

Vc ww

w

w

ln1

p

V

p

V

Vc

gg

g

g

ln1



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

• Source – Lab measurements, correlations

Ideal gas

– 60x10-6 psi-1, at 9000 psi

– 1.5x10-3 psi-1, at 680 psi

– 9x10-3 psi-1, at 115 psi


Viscosity

Viscosity is a measure of resistance to flow --

specifically, is defined as the rate of shear strain to the

applied shear stress within a fluid.

Symbols: o, g, w

dy v

v + dv

dy

dvA

F


Other Properties

Two other variables used in well test

interpretation are neither rock nor fluid

properties:

The total compressibility

The wellbore radius


Total Compressibility

The total compressibility defined reflects change of

both pore volume and fluid volume with change in

pressure.

ggwwooft cScScScc

• Units

– psi-1, microsips

• Source

– Calculated


Wellbore Radius

Wellbore radius is the size of wellbore.

rw


Wellbore Radius

• Symbol

– rw

• Units

– feet

• Source

– Bit diameter/2

– Caliper log


– 2 to 8 in.


Exercise 1

List 4 objectives of well testing?

List as many as possible without referring to

the notes.


Exercise 2

Define variables used in well testing

Define, give the units for, and name a common source for each of

the following variables used in well testing. Complete as much of

this exercise as possible before referring to the notes.

1. Porosity

2. Saturation

3. Permeability

4. Pore-Volum Compressibility

5. Net sand thickness

6. Formation volume factor

7. Fluide Compressibility

8. Viscosity

9. Total Compressibility

10. Wellbore radius


Exercise 3

Calculate total compressibility for undersaturated oil reservoir(above the bubblepoint)

Sw = 17%, oil gravity = 27API,

Rso = 530 scf/STB, gas gravity = 0.85, Tf = 185F,

p = 3500 psi, cf = 3.610-6 psi-1

Tsep= 75°F, psep = 115 psia

From fluid properties correlations,

pb = 2803 psi

co = 1.158 x 10-5 psi-1

cw = 2.277 x 10-5 psi-1


Exercise 4

Calculate total compressibility for saturated oil reservoir (below

the original bubblepoint)

Sw = 17%, Sg = 5%, oil gravity = 27API,

Rso = 530 scf/STB, gas gravity = 0.85, Tf = 185F,

p = 2000 psi, cf = 3.610-6 psi-1

Tsep = 75°F, psep = 115 psia


pb = 2803 psi

co = 1.429 x 10-4 psi-1

cg = 5.251 x 10-4 psi-1

cw = 4.995 x 10-6 psi-1


Exercise 5

Calculate total compressibility for the following Low-

pressure, high-permeability gas reservoir

Sw = 20%, gas gravity = 0.74, Tf = 125F, p = 125 psi,

cf = 3.610-6 psi-1, cw = 4 x 10-6 psi


cg = 8.144 x 10-3 psi-1

cw = 4x10-6 psi-1


Exercise 6

Calculate total compressibility for the following high

pressure, low permeability gas reservoir

Sw = 35%, gas gravity = 0.67, Tf = 270F,

p = 5,000 psi, cf = 2010-6 psi-1


cg = 1.447 x 10-4 psi-1

cw = 3.512 x10-6 psi-1

02 review of reservoir rock and fluid properties

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