This document discusses porosity of reservoir rocks. It defines porosity as the ratio of pore volume to bulk volume of a rock. Porosity can be classified as original or induced. Factors that affect porosity include particle size, sorting, packing, cementation and stress. Porosity is important for reservoir engineering calculations as it represents the pore space occupied by fluids. It is measured through core analysis, well logging, or well testing. Laboratory methods to determine porosity include measuring bulk volume through fluid displacement or gravimetric techniques and pore volume through fluid saturation.

1. Porosity
• Learning Outcomes
Reservoir Rocks & Fluid Properties

2. Porosity of Reservoir Rocks
• Definition of Porosity
• Classification of Porosity
• Factors affecting Porosity
• Applications of Porosity
• Determination of Porosity
Reservoir Rocks & Fluid Properties

3. Porosity
Definition: Measure of
pore space in porous
media.
Packing
Sorting
Grain Shape
High Low

4. Reservoir Rocks & Fluid Properties

5. • Rock reservoir have pore that are connected and contain fluids
(oil, gas, water) that can flow through the rock.
• Reservoir rock looks solid to the naked eye, but a microscopic
examination reveals the existence of tiny openings in the rock.
• These spaces or tiny openings (typically up to 300 μm) in
petroleum reservoir rocks are the one in which petroleum
reservoir fluids are presents
Reservoir Rocks & Fluid Properties
1
Porosity of Reservoir Rocks

6. Definition of Porosity
• Porosity(φ) : the ratio of the pore volume in a
rock to the bulk volume of that rock. Express in per
cent.
Mathematical form is:
φ = Vp/Vb
Reservoir Rocks & Fluid Properties

7. Porosity
• Porosity is a measure of the void space in rock,
hence, measures how much HC in rock
• Porosity φ = Vp/Vb = (Vb-Vm)/Vb; Vb = Vp + Vm
– theoretically, φ varies from 0% - 47.6%
– In practice, φ varies between 3% and 37%
• Porosity is a function of particle size distribution:
– Framework materials (sandstone) – high φ
– Interstitial materials (shaly-sand) – low φ
Reservoir Rocks & Fluid Properties

8. Classification of Porosity
Porosity can be classified into;
1. Original porosity
2. Induced porosity
• Original porosity (primary) is formed during the deposition of rock
materials, e.g. porosity between granular in sandstone,
porosity among crystal and oolitic in limestone
• Induced porosity (secondary) is developed by some geological
process on the deposited rock material.
E.g; Fractures, or vugs cavity usual occur in limestone
(chemical reaction b/w CaCO3 and MgCl2)
Reservoir Rocks & Fluid Properties

9. Porosity
Sand grain
Cement material
Effective / connected
porosity (25%)
Ineffective Porosity
(5%)
Total Porosity (30%)
Reservoir Rocks & Fluid Properties
Deadend or cul-de-
sac pore

10. Types of Porosity
• 3 kinds porosity includes:
– Effective porosity
– Ineffective/ Isolated porosity
– Total porosity
• Effective porosity is the measure of the void space that is filled
by recoverable oil and gas; or the amount of pore space that is
sufficiently interconnected to yield its oil & gas for recovery.
• φ = Vol. of interconnected pores + Vol. of deadend
Total or bulk vol. of reservoir rock
Reservoir Rocks & Fluid Properties

11. PORE-SPACE CLASSIFICATION
• Total porosity, t =
• Effective porosity, e =
Total Pore Volume
Bulk Volume
Interconnected Pore Space
Bulk Volume
• Effective porosity – of great importance;
contains the mobile fluid

12. COMPARISON OF TOTAL AND EFFECTIVE POROSITIES
• Very clean sandstones : e  t
• Poorly to moderately well -cemented
intergranular materials: t  e
• Highly cemented materials and most
carbonates: e < t

13. Types of Porosity
• Ineffective porosity is the ratio of the volume of isolated or
completely disconnected pores to the total or bulk volume
• φ = Vol. of completely disconnected pores
Total or bulk volume
• Total or absolute porosity is the ratio of the entire void spaces
in the reservoir rock to the bulk volume of the rock
• φ = Vol. of interconnected + Vol. of deadend or cul-de-sac
pores + Vol. of isolated pore
Total or bilk volume
Reservoir Rocks & Fluid Properties

14. Applications of Porosity
• What is the significance Porosity in engineering reservoir?
• From the reservoir engineering point of view, porosity is probably one of
the most important reservoir rock properties and its quantitative value is
used in all reservoir engineering calculations ‘cos it represents the pore
spaces that’s occupied by mobile fluids.
• For common reservoir rock types, under average operating conditions, porosity
values ranges;
Porosity % 25~20 20~15 15~10 10~5 5~0
Reservoir Rocks & Fluid Properties
Grade Very
good
good moderate poor no
value
Evaluating formation

15. Applications of Porosity
Porosity data are used in these basic reservoir evaluations:
1. Volumetric calculation of fluids in the reservoir
2.Calculation of fluid saturations
3.Geological characterization of the reservoir
 Calculating hydrocarbon in a reservoir
 HCPV = Area x Thickness x φ x (1 – Sw)
 where: A = surface area of the reservoir
 h = thickness of the formation
 φ = porosity
 Swi= the percent of the pore volume
 occupied by the water
Reservoir Rocks & Fluid Properties

16. Various packing of spheres: cubic & rhombohedral
Reservoir Rocks & Fluid Properties
cubic packing of
spheres resulting in a
least-compact
arrangement with a
porosity of 47.64%
Rhombohedral
packing of spheres
resulting in a most-compact
arrangement
with a porosity of
26%
Spherical size variation influences
type & volume of solid porosity
Porosity
36%
Porosity
20%
Effect of cement material

17. FACTORS THAT AFFECT POROSITY
PRIMARY
• Particle sphericity and angularity
• Packing
• Sorting (variable grain sizes)
SECONDARY (DIAGENETIC)
• Cementing materials
• Overburden stress (compaction)
• Vugs, dissolution, and fractures

18. Porosity Measurements
• From definition of porosity, porosity of rock sample can be
determined by measuring any two of these quantities:
 bulk volume
 pore volume
 grain volume
• Sources of Porosity data:
 Core analysis – direct measurement
 Well logging analysis
 Well testing indirect measurement
Reservoir Rocks & Fluid Properties

19. Porosity
• Porosity from loggings:
 Sonic log
t t  1   t   Dt = sonic travel time recorded by log
m f Dtm = sonic travel time for the matrix
mineral grains (w/o porosity), (55, 47 and 43 microsec/ft
for quartz, limestone and dolomite, respectively)
Dtf = sonic travel time for fluid in the
pore space
 = porosity, fraction
Reservoir Rocks & Fluid Properties
 Density log
       b m f 1 b = bulk density recorded by log
m = density of the matrix mineral grains (w/o porosity),
(2.65, 2.71 and 2.87 gm/cc
for quartz, limestone and dolomite, respectively)
f = density of the fluid in the pore space

20. Determination of Porosity
• Several methods: involves only the determination of two out of 3
(Vp, Vm, & Vb)
• Bulk volume by the following methods
– Coated sample immersed in water, or
– Water-saturated sample immersed in water, or
– Dry sample immersed in Hg method (no more Hg in the labs)
• Grain volume: by Melcher- Nutting method in which the sample is
crushed and its volume measured with a pychnometer
Reservoir Rocks & Fluid Properties

21. Laboratory Measurement of Porosity
• Under laboratory the following are measured;
• Vp, pore volume directly measured indirectly
• Vb, bulk volume directly measured indirectly
• Porosity measurement
– Vb, bulk volume directly measured
Reservoir Rocks & Fluid Properties
• Direct measure, Vb
Common shaped sample (cylinder, or cubic) measured the dimensions and
consider bulk volume
A
L

22. Porosity
• Measurement of Vb,
Irregular & regular sample shapes
A
L
 Two means explained here;
- volumes faulted (volumetrically)
- methodologies gravity (gravimetrically)
 To use above method must prevent fluid
Reservoir Rocks & Fluid Properties
penetration into the pore sample by:
- coating with wax
- saturating the core with same fluid
- using mercury

23. Porosity
• Measurement of Vb ,
Mercury volume displacement by the
rock sample when completely immersed
in the liquid
Reservoir Rocks & Fluid Properties
Hg
Mercury volume addition after core sample
is included in mercury is bulk volume.

24. Porosity
• Measurement Vb ,
• Gravity method
Reservoir Rocks & Fluid Properties
Hg
scale Scale
A B
A Wtk = dry core weight
Wthg = mercury weight
B Wtb = mercury weight and core that
forced inside mercury
Mercury weight faulted = (Wtb - (Wtk + Wthg))
Mercury
volume faulted = Mercury weight faulted
mercury density
Core bulk
volume
=
Mercury volume
faulted

25. Porosity
 Porosity measurement
• Vp, pore volume determination
 Fluid saturation inside rock Wtk = dry sample weight
Wtt = saturated sample weight fluid
Wtf = fluid weight in pore
Reservoir Rocks & Fluid Properties
= Wtt - Wtk
H Vp = (Wtt - Wtk)/f 2O

26. Porosity
• Determination of Vp details using Boyle’s Law
Reservoir Rocks & Fluid Properties
Helium tank
Cylinder
sample
steel
line
sample
P3 V3 T1
P1 V1 = P3 V3
V3 = V1 + Vl + Vs -Vc - Vg
P1 V1 T1

27. Porosity
• Determination of Vp details using Boyle’s Law
P1 V1 = P2 V2 V2 = V1 + Vl + Vs – Vc
V1 + Vl + Vs - Vc = V2 = (P1 V1 )/ P2
P1 V1 = P3 V3 V3 = V1 + Vl + Vs - Vc - Vg
Vg = V1 + Vl + Vs - Vc - V3
Vg = (P1 V1 )/ P2 - (P1 V1 )/ P3
Vp = Vb - Vg
Reservoir Rocks & Fluid Properties
 = Vp / Vb = (Vb - Vg)/ Vb
V1 = Volume of cylinder helium
reference in P1 & T1
Vl = Connector tube volume cylinder
helium reference to cylinder
sample
Vs = Volume of empty cylinder sample
Vc = Volume of cakra steel
Vg = Volume of core sample

28. Uses of Porosity
• Basic use is to calculate volumetrically the quantity of
hydrocarbon (HC) in the rock
– N = 7758 X As X H X φ X Soi
– N= HC volume in the reservoir, res.bbl
– As = surface area, acres
– H= thickness of formation, ft
– φ = porosity, fraction
– Soi = initial oil saturation (1.0 – Swi), fraction
• If N is divided by Bo, we will get the volume on surface. Since
oil shrinks as it comes to the surface due to gas coming out,
(Nsurface < Nreservoir)
Reservoir Rocks & Fluid Properties

29.  Example 1.1 – Porosity Calculation
 Determination of Vb – Coating Method
• A = mass dry sample in air = 20.0 gm
• B = mass dry sample coated with paraffin = 20.9 gm Sgparaffin = 0.9
• C = mass of coated sample immersed in H2O at 40oF = 10 gm
(Sgwater= 1.0)
• Mass of paraffin = B – A = 20.9 – 20.0 = 0.9 gm
• Volume of paraffin = 0.9/0.9 = 1 cc
• Mass of water displaced = B – C = 20.9 – 10.0 = 10.9 gm
• Vol. of water displaced = mass of water/ρ of water = 10.9/1.0 =
10.9 cc
• Bulk volume = volume of water displaced – volume paraffin
• = 10.9 – 1.0 = 9.9 cc
• Bulk volume of rock = 9.9 cc

30.  Example 1.2 – Porosity Calculation
• From Example 1.1
• Mass of dry sample in air = 20 gm
• Bulk volume of sample = 9.9 cc
• Grain volume of sample = (mass of dry sample in air)/ (sand-grain
density)
• = 20/2.67 = 7.5 cc
• Total porosity = Øt = [(bulk vol. – grain vol.)/bulk volume] x 100
• = [(9.9 – 7.5)/9.9] x 100 = 24.2 per cent

31. Example 3
• A clean and dry core sample weighting 425g was 100% saturated
with a 1.07 specific gravity brine. The new weight is 453g. The core
sample is 12 cm long and 4 cm in diameter. Calculate the porosity of
the rock sample.
 SOLUTION:
The bulk volume of the core sample is:
Vb = π(r)2 (12) = 150.80 cm3
The pore volume is:
Vp = 1/џ (Vwet - Vdry) = 453 – 425 = 26.17 cm3
1.07
Reservoir Rocks & Fluid Properties

32. Cont…
• Then;
• Porosity of the core is:
φ = Vp/Vb = 26.17 = 0.173 or 17.3%
150.80
Reservoir Rocks & Fluid Properties

33. Transform of lab porosity to formation porosity
• φ =φ e−CPΔP
• ΔP ：effective overburden pressure change
• P C ：rock compressibility
• φ：lab porosity
Reservoir Rocks & Fluid Properties