Reservoir rock is the one of the important component in petroleum system i.e without it petroleum system is impossible. This presentation contain all necessary information regarding reservoir rock.

1. DEPARTMENT OF EARTH SCIENCES
SUBJECT: Petroleum geology
SUBMITTED TO: sir, Abdul slam
SUBMITTED BY: SALAHUDIN
KHURSHEED
ROLL NO: 5641
PROGRAM: BS GEOLOGY
SEMESTER: 06
DATE: 07-04-20

2. THE Reservoir rock, its prerequisites and
their mesuring techniques
submitted
by
Salahudin khursheed
5641
2

3. RESERVIOR Rock
• Definition: Reservoir rocks are rocks that
have the ability to store fluids inside their
pores, so that the fluids (water, oil, and gas)
can be accumulated. In petroleum geology,
reservoir is one of the elements of petroleum
system that can accumulate hydrocarbons (oil
or gas). Reservoir rock must have good
porosity and permeability to accumulate and
drain oil in economical quantities.
3

4. Explanation: Theoretically, any rock may act
as reservoir for oil and gas. In practice, the
sandstone and carbonate contain the major oil
reserves, although fields do occur in shale and
diverse igneous and metamorphic rocks. For a
rock to act as a reservoir it must posses two
essential properties: It must have pores to
contain the oil or gas, and the pores must be
connected to allow the movement of fluids; in
other words, rock ,must have permeability.
Other properties include: Payzone thickness,
Lithology and Rock compressibilty.
4

5. Types Of Reservoir rocks
As a rock to be named a reservoir has to be a porous
and permeable lithological structure. It encompasses
sedimentary rocks. These sedimentary rocks may be
made of sandstones (quartz sand or arksosic
sandstone), carbonates mud or dolomite. Dolomites
mostly form good reservoirs because the common
reason behind it is that there is Mg, 13% smaller than
Ca in a way that during dolomitization, there is a total
decrease in volume of the material by 13%, here by
13% porosity is gained.
5

6. 1-Sandstone reservoir rock: The term sand refers
to a specific grain with sizes between (62 µm - 2 mm).
The performance of the sandstone as a reservoir rock
is described by its combination of porosity and
permeability depending on the degree to which the
sand dominates its. The favorable texture is depicted
by packaging of similar sized grains, not a
combination of coarse and fine grained composition.
The best sandstone reservoirs are those that are
composed mainly of quartz grains of sand size of
nearly equal sizes or silica cement, with minimal
fragmented particles. Sandstone reservoirs are
generally 25 meters thick 6

7. 2-Carbonate reservoir rocks: The most
fascinating aspects of carbonate reservoir
rocks are their content. Carbonates are usually
made of fossils which “range from the very
small single cell to the larger shelled animals”.
Most carbonate rocks are deposited at or in
very close neighborhood to their site of
creation. The "best-sorted" carbonate rocks
are oolites in which encompass grains of the
same size and shapes even though Oolites are
poorly sorted.
7

8. 3-Atypical and Fractured Reservoir: Some 90%
of world oil and gas occur in sandstone or
carbonate reservoirs. The remaining 10% occur in
what may therefore be termed Atypical reservoir,
which range from various types of basement to
fractured shale. Theoretically any rock can be a
petroleum reservoir if it is both porous and
permeable. A typical reservoir may form by two
processes: Weathering and Fracturing
8

9. Prerequisite for reservior rock
• For a rock to act as a reservoir it must posses
two essential properties: It must have pores to
contain the oil or gas, and the pores must be
connected to allow the movement of fluids; in
other words, rock ,must have permeability. So
there are two important prerequisite :
Porosity
Permeability
9

10. Porosity
Definition: Porosity of reservoir is the property
that tells how porous a rock is. It is also defined
as a measure of the capacity of reservoir rocks to
contain or store fluids
Mathematically: It can be defined as the ratio
between the volume of the void to the total
volume of rock mass
Porosity(%)=Volume of voids/bulk volume rock*100
10

11. Explanation: Porosity is is the first of the two
essential attributes of a reservoir. The pore spaces,
within a rock are generally filled with connate water,
but contain oil or gas in a field. Porosity is either
expressed as void ratio, which is the ratio of a voids
to solid rocks
Type Of Pores:
 Caternary
 Cul-de-sac
 Closed
11

12. 1-Caternary: pores are those that communicate
with other by more than one throat passage.
2-Cul-de-sac: also called as dead ends. Pores have
only one throat passage connecting with other
pores.
3-Closed: pores have no communication with
other pores. 12

13. Catenary and cul-de-sac pores constitute
effective porosity, in that hydrocarbons can
emerge from them. In catenary pores
hydrocarbons can be flashed out by a natural or
artificial water drive.
Cul-de-sac pores are unaffected by flashing, but
may yield some oil or gases by expansion as
reservoir pressure drops.
Closed pores are unable to yield hydrocarbons
(such oil or gas having invaded an open pores
subsequently closed by compaction or
cementation).
effective porosity is extremely important
being directly related to permeability. 13

14. TYPES OF POROSITY
(a) Primary Porosity: is described as the porosity of the
rock that formed at the time of its deposition. It
may be divide into three subtypes
1-Intragranular:pores are generally found within
the the skeletal grains of carbonate sands and are
thus often cul-de-sac pores.
Because of compaction and cementation they are
generally absent in carbonate reservoirs.
2-Intergranular: Interparticles pores are initially in
all sediments. They are often quickly lost in clays
and carbonate sands because of the combined
effects of compaction and cementation
14

15. 3-Fenestral: pores occur where there is primary
gap in rock framework larger than grain support
interstices.
15

16. (b) Secondary porosity: formed after deposition leads to
other couple of reservoirs types
1-Intercrystalline porosity: which refers to pores
occurring between their crystal faces of crystalline
rock, is far more important type of secondary
porosity.
2-Moldic porosity: it is fabric selective that is only the
grains or the matrix has been leached out.
3-Vuggy porosity: vugs, by contrast , are pores whose
boundaries crosscut grain, matrices and earlier
cement .Vugs tend to be larger than moldic pores
With increasing vuggy pores it changes into
Covernous porosity.
16

17. 4-Fracture porosity: it is the last major type of
porosity to consider it is extremely important not
so much because it increases the storage capacity
of reservoir but because of the degree to which it
may enhance permeability. Fracture are rare in
unconsolidated, loosely cemented sediments,
which response to stress by plastic flow. They may
occur in brittle rock not only in sandstone and
limestone but also in igneous metamorphic and
shale.
17

18. Measurement Of Porosity
Porosity may be measured in three ways: directly from
core, Indirectly from geophysical log or from Seismic data
(a) Directly From core: The main reason for cutting core is to
measure the petrophysical properties of the reservoir. The
porosity of a core sample may be measured in the
laboratory using several methods. For homogeneous
rocks, like many sandstones, samples of only 30mm cube
or so many be cut or chipped from the core. For
heterogeneous reservoirs, including many limestone's,
analysis of a whole core sample is generally necessary.
Several of the most common porosity measurements
procedures are briefly described in the following section
18

19. 1- Washburn-Bunting Method
One of the earliest
and simplest
method for
measuring porosity
is the gas expansion
technique described
by Washburn and
Bunting in 1922.
19

20. The basic apparatus is shown above in the figure. Air
within the pores of the sample is extracted when a
vacuum is created by lowering and raising the
mercury bulb. The amount of air extracted can be
measured in the burette then:
Porosity(%)=volume of gas extracted/bulk volume of
sample*100
Bulk volume can be extracted indepentendently by
another method, which generally involve applying
Archimedes principle of displacement to the sample
when totally submerged in mercury
20

21. 2-Boyles Law Method
Boyle's law: is an ideal gas law where at a
constant temperature, the volume of an ideal
gas is inversely proportional to its absolute
pressure. There are a couple of ways of
expressing the law as an equation. The most
basic one states: PV = k. where P is pressure, V
is volume, and k is a constant. It can be
applied to porosity measurements.
21

22. Porosimetry: is an analytical technique used to
determine various quantifiable aspects of a
material's porous nature, such as pore diameter,
total pore volume, surface area, and bulk and
absolute densities.
Boyels law porosimeter:
22

23. In this instrument pre volume is measured by sealing
the sample in the pressure vessel, decreasing the
pressure by known amount, and measuring the
increase in volume of the contained gas. Conversely,
the grain volume can be measured and , if the bulk
volume is known, porosity can be determined .
(b) Porosity measurements indirectly by well logs:
The prime target of well logs is the measurement of
various geophysical properties of the subsurface rock
formations. Of particular interest is porosity.
23

24. 1-CNL (compensated neutron) logs: also called
neutron logs, determine porosity by assuming that
the reservoir pore spaces are filled with either water
or oil and then measuring the amount of hydrogen
atoms (neutrons) in the pores. These logs
underestimate the porosity of rocks that contain gas.
….Logging tools provide measurements that allow
for the mathematical interpretation of porosity.
There are different types of well logging that used to
estimate the porosity of the formation around the
well, such as:
24

25. 2-FDC (formation density compensated) logs: also
called density logs, is a porosity log that measures
electron density of a formation and determine
porosity by evaluating the density of the rocks.
Because these logs overestimate the porosity of rocks
that contain gas they result in “crossover” of the log
curves when paired with Neutron logs.
3-NMR (nuclear magnetic resonance) logs: may be
the well logs of the future. These logs measure the
magnetic response of fluids present in the pore
spaces of the reservoir rocks. In so doing, these logs
measure porosity and permeability, as well as the
types of fluids present in the pore spaces. 25

26. PERMEABILITY
• Definition:
Permeability is a factor that quantifies how hard or
how easy it is for the fluid to flow. through the
reservoir to the oil producing well; the greater the
permeability, the easier the. fluid flows.
Permeability of a rock is a measure of the ability of
the rock to transmit fluids through it.
Unit: The standard unit for permeability is the
Darcy (d) or, more commonly, the millidarcy (md)
26

27. Theoretical Background:
The fundamental relationship given by Henry is the
basis for permeability determination. Darcy's law
originates from the interpretation of the results of
the flow of water through an experimental
apparatus. In this experiment, water was allowed to
flow downward through the sand pack contained in
an iron cylinder. Manometers located at the input
and output ends measured fluid pressures, which
were then related to flow rates to obtain the
following fundamental Darcy's law:
27

28. q = water flow rate
K = constant of
proportionality
A = cross-sectional
area
Δh = h1–h2 =
difference in height
between the levels
in
L = length (cm 28

29. Factors controlling permeability
(a)Pore geometry:
Permeability is a function of the geometry of the
pore structure of the porous media. Permeability is
controlled in sandstone by grain size, grain
orientation, packing arrangement, cementation, clay
content, bedding, and grain size distribution and
sorting. In carbonates, permeability is a function of
the degree of mineral alteration (such as
dolomitization), porosity development, and
fractures. Following figure shows the relationship
among permeability, sorting, and grain size.
29

30. (b)Bedding:
Directional and local variations of permeability
generally exist in reservoirs. Permeability
perpendicular to bedding planes (vertical
permeability) is typically lower than horizontal
permeability (parallel to the bedding planes 30

31. © Porosity:
Several attempts have been made in the past to
derive a general relationship between porosity and
permeability. Prominent among these relationships is
the work of Kozeny, which considered the porous
media as a bundle of capillary tubes of equal length.
Modifications to account for tortuosity of flow paths
in the porous media have been proposed, including
the Carman-Kozeny model (1938). Unfortunately, only
qualitative results have been obtained using these
permeability-porosity relationships because of the
complexity of the geometry of the porous media.
31

32. (d) Confining Pressure: Permeability decreases with
increasing confining pressure. Unconsolidated or
poorly lithified rock undergoes much greater
permeability reduction under confining pressure than
well-consolidated rock. a greater percentage of
permeability reduction is typically observed in lower
permeability rock than in higher permeability rock. To
determine permeability-stress relationships, which
are representative of in situ reservoir conditions,
permeability measurements should be made on
selected samples at a series of confining pressures.
Jones has recently presented a method that allows a
two-point determination of a permeability-stress
model that reduces the required measurements. 32

33. Permeability Measurements
• The permeability of a reservoir can be measured
by following ways;
1- By mean of drill stem or production test:
In this test, a well is drilled
through the reservoir. Casing is set and perforated,
tubing is run within the casing, the interval to be
tested is sealed off with packers, and the interval is
allowed to flow. The rate of flow and drop in
pressure at the commencement and conclusion of
test can be measured, and reservoir fluid can be
recovered at the surface. Thus all the parameters…33

34. ……….. are known to enable permeability to be
calculated from darc’s law . This type of test is , of
course in many ways is obvious and significant.
2-Wireline Log:
The second
way o measuring permeability is
from wireline logs. It has long
been possible to identify
permeable zone in a qualitative
way from SP and caliper logs,
but only recently has it been
possible to quantify permeability
fro logs with any degree of
reliability.
34

35. …Permeabilities measured in cores can be correlated
to wireline measurements taken in the cored
borehole. At various times and places, almost every
wireline log has been used to correlate to
permeability. The porosity-permeability crossplot is,
perhaps, the most used; however, it is subject to
considerable error. In select basins, the GR log
response can be used to correlate to permeability
while, in other basins, the neutron log or acoustic log
seems to provide the correlation with least statistical
scatter.
35

36. 3- Permeameter:
an instrument for measuring permeability of a
substance to a given thing: in physics, for measuring
magnetic permeability; in geology, for measuring
permeability to various gases and liquids.
Probe permeameter (properm): The purpose of the
PROPERM is to perform rapid, non-destructive,
localized permeability measurements on rock samples
using the steady state method. A measurement is
taken by positioning the probe tip at a desired
location on the sample and then pressing against its
surface 36

37. Working mechanism of probe permeameter
37

38. 4-Sidewall samples:
This technique is valid for slightly to unconsolidated
sandstone rock types. Carbonate rock types are
generally too heterogeneous for small samples to
provide any meaningful reservoir-wide value for
permeability. Sidewall samples of sandstone rock
types are inherently contaminated with drilling mud
particles and are of little use for direct measurement
of permeability. However, we can inspect the rock
sample with a binocular microscope to estimate
median grain size, sorting, and degree of
consolidation, and to characterize pore fills. With
these data, we can develop correlations to
permeability on the basis of whole core……. 38

39. ……..measurements. An alternative is to disaggregate
the sample and determine a grain size analysis with
laser light scattering, which can then be correlated to
permeability on the basis of whole core analysis.
5-NMR logs:
Interpretation of NMR logging responses provides a
volumetric distribution of pore sizes. If the pores are
assumed to be spherical in shape, a value for
permeability can be computed. These size-dependent
data have been coupled with NMR pore volumes and
NMR fluid saturations to produce an NMR permeability
log. The chapter on NMR logging in this section of the
Handbook shows examples of these techniques. 39

40. Determining permeability
• Point-by-point permeability values are needed
over the reservoir interval at the wellbores for
several purposes. First, the distribution and
variation of the permeabilities are needed by the
engineers to develop completion strategies.
Second, this same information is needed as input
to the geocellular model and dynamic-flow
calculations (e.g., numerical reservoir-simulation
models). For both of these, the first consideration
is the location of shale and other low-
permeability layers that can act as barriers or
baffles to vertical flow……
40

41. …..A second consideration is the nature of the
permeability variation (i.e., whether the high-
permeability rock intervals occur in specific layers
and the low-permeability intervals occur in other
layers, or that there is so much heterogeneity that
the high- and low-permeability intervals are
intimately interbedded with each other).
When good-quality core data are not available,
estimates of permeability can be made from empirical
equations. Permeability is controlled by such factors
as pore size and pore-throat geometry, as well as
porosity. ……
41

42. To take some account of these factors, the widely
used Timur equation relates permeability to
irreducible Sw and porosity, and therefore can be
applied only in hydrocarbon-bearing zones. This form
of his equation applies to a medium-gravity oil zone
where k = absolute permeability in millidarcies, ϕe =
effective (not total) porosity as a bulk volume fraction,
and Sw = effective water saturation above the
transition zone as a fraction of PV….. 42

43. …..Estimates that are based only on porosity are likely
to have large prediction errors, especially in carbonate
reservoirs. Equations of the following form, or a
logarithmic-linear form, are useful particularly in
sandstones:
In field evaluation, the starting point for calculations
of permeability is the routine-core-analysis data.
These data, and the associated SCAL measurements
of permeability and porosity as a function of
overburden stress, are input to calculations to
develop permeability values at reservoir conditions
and the permeability vs. porosity correlation…… 43

44. The permeability vs. porosity correlation is often
taken as semilogarithmic but usually with a steeper
slope at low-porosity values. Figs. 1 and 2
demonstrate the characteristics of these
relationships. Fig. 1 presents a typical permeability vs.
porosity relationship from routine-core-analysis data
(the scatter in these data increases at the lower-
porosity levels). Fig. 2 shows the permeability ratio
(stressed permeability divided by unstressed
permeability) vs. unstressed permeability. This ratio is
much smaller for low-permeability values and
approaches a value of 1.0 for the high-permeability
values. 44

45. Fig. 1 – Core permeability vs. core porosity
crossplot; data from an Asian gas field.
45

46. Fig. 2 – Crossplots of core permeability at stressed vs. surface conditions
and core permeability ratio vs. core permeability at surface conditions;
data from an Asian gas field. “Stressed” refers to the rock being
subjected to simulated overburden pressure of approximately 4,500 psia.
The permeability correction is larger at low permeabilities.
46

47. ..In developing the permeability vs. porosity
relationships, the technical team needs to identify the
extent to which the reservoir interval needs to be
subdivided into zones or layers. The subdividing of the
core data over the reservoir interval should be into
logical subdivisions that are strongly influenced by the
geologists’ understanding of the depositional
environment. This will naturally account for major
differences in grain size, sorting, and key mineralogical
factors. Alternatively, a sufficiently thick reservoir
interval can be subdivided into layers of 50 to 100 ft
each. A superior petrophysical methodology will be
developed if a thick reservoir is appropriately
subdivided, compared with treating the full reservoir…47

48. interval with a single permeability vs. porosity
correlation. A single permeability vs. porosity
correlation for a reservoir interval with different
depositional environments can lead to
underprediction of permeability by an order of
magnitude in an interval of better-sorted rocks
compared with poorly sorted rocks (see Fig. 3).
Identifying the location and correct values of highest-
permeability rocks is very important for reservoir flow
modeling
48

49. Fig. 3 – Typical reservoir permeability vs. Sw
crossplot; data from an Asian gas field.
49

50. After the permeability values have been calculated
point-by-point over the reservoir interval from the
various wells’ logs, these permeability values need to
be compared with those derived at each well from the
pressure-transient analysis (PTA) of the pressure-
buildup (PBU) or falloff data. The PBU permeability
values are average values for the interval open to flow
into the wellbore. The type of average (arithmetic,
geometric, harmonic, or somewhere in between) to
use with the point-by-point permeability values
depends on the nature of the depositional
environment and whether the perforated intervals are
a small fraction of the full reservoir interval…….
50

51. ….. If there are significant differences between the two
sets of average permeability values, then the technical
team needs to determine the likely cause of the
differences—small-scale fractures, relative
permeability effects, or some other geological factors.
The point-by-point permeability values may need to be
adjusted on the basis of the technical teams’
conclusions.
51
Absolute permeability: when a single fluid phase
completely saturates the pore spaces and the
permeability is referred to as absolute or specific. It
is represented by K.

52. 52
Relative permeability: it is the ratio of effective
permeability for a particular fluid at a given
saturation to base permeability. Relative
permeability ranges from 0.0 to 1.0.
Thus for oil,
Kro=Ko/K
for gas,
Krg=Kg/K
for water,
Krw=Kw/K
Here,
K= absolute permeability
Kr= relative permeability

53. 53
Kg= effective permeability at 100% gas saturation
Kw= effective permeability at 100%water
saturation.
K0= effective permeability at 100% oil saturation.

54. REFERENCES
Elements of petroleum geology by;
(Richard C shelly)
 Reservoir engineering a handbook by;
(Tarek Ahmed)
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