This document summarizes key concepts about porosity and permeability from a student presentation. It discusses how porosity is the volume of void space available to contain fluids, and permeability relates to how easily fluids can pass through materials. Several factors that control porosity are described, including packing density, grain size, sorting, and post-burial changes from processes like compaction, cementation, and fracturing. Common methods for determining porosity from well logs are also summarized, including bulk density, neutron, and acoustic logs. Equations for calculating porosity from each log type are provided.
This document provides a basic overview of the fundamental rock properties. It delivers a detailed analysis of the basic reservoir rock properties like porosity, permeability, Fluid saturation , wettability, etc.
Introduction
Petrophysic of the rocks
It is the study of the physical and chemical properties of the rocks related to the pores and fluid distribution
Porosity, is ratio between volume of void to the total voids of the rock.
Permeability, is ability of a porous material to allow fluids to pass through it.
Electric, most of the sedimentary rocks don’t have conductivity.
Radiation, clay rocks have 40K, radiate alpha ray.
Hardness, it depends on the cementing material and thickness of the sediments.
WELL LOGGING
The systematic recording of rock properties and it’s fluid contents in wells being drilled or produced to obtain various petrophysical parameters and characteristics of down hole sequences (G.E Archie 1950).
The measurement versus depth or time, or both, of one or more physical properties in a well.
These methods are particularly good when surface outcrops are not available, but a direct sample of the rock is needed to be sure of the lithology.
A wide range of physical parameters can be measured.
In some cases, the measurements are not direct, it require interpretation by analogy or by correlating values between two or more logs run in the same hole.
Provide information on lithology, boundaries of formations and stratigraphic correlation.
Determine Porosity, Permeability, water, oil and gas saturation.
Reservoir modeling and Structural studies… etc.
Types of Well Logging
Logs can be classified into several types under different category
Permeability and lithology Logs
Gamma Ray log
Self Potential [SP] log
Caliber log
Porosity Logs
Density log
Sonic log
Neutron log
Electrical Logs
Resistivity Log
For contact : omerupto3@gmail.com
WELL LOG : Types of Logs, The Bore Hole Image, Interpreting Geophysical Well Logs, applications, Production logs, Well Log Classification and Cataloging
Reservoir Porosity; Porosity Definition; Types Porosity; Origins of Porosity in Clastics and Carbonates; Primary (Original) Porosity; Secondary (Induced) Porosity; Pore Space Porosity Classification; Absolute (or Total) Porosity; Effective Porosity; Porosity Calculated; Porosity Values; Porosity in Sandstone; Sandstones Porosity Types; Factors That Affect Porosity in Sandstones ; Grain Packing in Sandstone; Progressive Destruction of Bedding Through Bioturbation; Dual Porosity in Sandstone; Dissolution Porosity in Sandstone; Porosity in Carbonate; Carbonates Porosity Types; Idealized Carbonate Porosity Types; Comparison of Total and Effective Porosities; Reservoir Average Porosity; MEASUREMENT OF POROSITY
This document provides a basic overview of the fundamental rock properties. It delivers a detailed analysis of the basic reservoir rock properties like porosity, permeability, Fluid saturation , wettability, etc.
Introduction
Petrophysic of the rocks
It is the study of the physical and chemical properties of the rocks related to the pores and fluid distribution
Porosity, is ratio between volume of void to the total voids of the rock.
Permeability, is ability of a porous material to allow fluids to pass through it.
Electric, most of the sedimentary rocks don’t have conductivity.
Radiation, clay rocks have 40K, radiate alpha ray.
Hardness, it depends on the cementing material and thickness of the sediments.
WELL LOGGING
The systematic recording of rock properties and it’s fluid contents in wells being drilled or produced to obtain various petrophysical parameters and characteristics of down hole sequences (G.E Archie 1950).
The measurement versus depth or time, or both, of one or more physical properties in a well.
These methods are particularly good when surface outcrops are not available, but a direct sample of the rock is needed to be sure of the lithology.
A wide range of physical parameters can be measured.
In some cases, the measurements are not direct, it require interpretation by analogy or by correlating values between two or more logs run in the same hole.
Provide information on lithology, boundaries of formations and stratigraphic correlation.
Determine Porosity, Permeability, water, oil and gas saturation.
Reservoir modeling and Structural studies… etc.
Types of Well Logging
Logs can be classified into several types under different category
Permeability and lithology Logs
Gamma Ray log
Self Potential [SP] log
Caliber log
Porosity Logs
Density log
Sonic log
Neutron log
Electrical Logs
Resistivity Log
For contact : omerupto3@gmail.com
WELL LOG : Types of Logs, The Bore Hole Image, Interpreting Geophysical Well Logs, applications, Production logs, Well Log Classification and Cataloging
Reservoir Porosity; Porosity Definition; Types Porosity; Origins of Porosity in Clastics and Carbonates; Primary (Original) Porosity; Secondary (Induced) Porosity; Pore Space Porosity Classification; Absolute (or Total) Porosity; Effective Porosity; Porosity Calculated; Porosity Values; Porosity in Sandstone; Sandstones Porosity Types; Factors That Affect Porosity in Sandstones ; Grain Packing in Sandstone; Progressive Destruction of Bedding Through Bioturbation; Dual Porosity in Sandstone; Dissolution Porosity in Sandstone; Porosity in Carbonate; Carbonates Porosity Types; Idealized Carbonate Porosity Types; Comparison of Total and Effective Porosities; Reservoir Average Porosity; MEASUREMENT OF POROSITY
The reservoir (rock porosity and permeability)salahudintanoli
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.
Porosity Permeability Relationship in carbonate rock pptAmar Gaikwad
A information about porosity and permeability in a carbonate rock. in which we studied the porosity measurement , carbonate rock ,permeability and correlation between them.
The reservoir (rock porosity and permeability)salahudintanoli
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.
Porosity Permeability Relationship in carbonate rock pptAmar Gaikwad
A information about porosity and permeability in a carbonate rock. in which we studied the porosity measurement , carbonate rock ,permeability and correlation between them.
Porosity is the quality of being porous, or full of tiny holes. Liquids go right through things that have porosity. It is shown as a fraction of the volume of voids over the total volume, which is between 0 and 1, or between 0% and 100% as a percentage. Primary and secondary porosity can be read directly from neutron, density, and sonic logs.
Very detailed descriptions may require subdivision into units containing (for example) a single mudstone lens or crossbed set, and will therefore be on the order of a few centimeters or tens of centimeters thick. For each unit, the kinds of observations listed in the succeeding paragraphs are made where appropriate.
Water scarcity is the lack of fresh water resources to meet the standard water demand. There are two type of water scarcity. One is physical. The other is economic water scarcity.
Automobile Management System Project Report.pdfKamal Acharya
The proposed project is developed to manage the automobile in the automobile dealer company. The main module in this project is login, automobile management, customer management, sales, complaints and reports. The first module is the login. The automobile showroom owner should login to the project for usage. The username and password are verified and if it is correct, next form opens. If the username and password are not correct, it shows the error message.
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When the automobile is sold to the customer, stock will be reduced automatically. When a new purchase is made, stock will be increased automatically. While selecting automobiles for sale, the proposed software will automatically check for total number of available stock of that particular item, if the total stock of that particular item is less than 5, software will notify the user to purchase the particular item.
Also when the user tries to sale items which are not in stock, the system will prompt the user that the stock is not enough. Customers of this system can search for a automobile; can purchase a automobile easily by selecting fast. On the other hand the stock of automobiles can be maintained perfectly by the automobile shop manager overcoming the drawbacks of existing system.
Hybrid optimization of pumped hydro system and solar- Engr. Abdul-Azeez.pdffxintegritypublishin
Advancements in technology unveil a myriad of electrical and electronic breakthroughs geared towards efficiently harnessing limited resources to meet human energy demands. The optimization of hybrid solar PV panels and pumped hydro energy supply systems plays a pivotal role in utilizing natural resources effectively. This initiative not only benefits humanity but also fosters environmental sustainability. The study investigated the design optimization of these hybrid systems, focusing on understanding solar radiation patterns, identifying geographical influences on solar radiation, formulating a mathematical model for system optimization, and determining the optimal configuration of PV panels and pumped hydro storage. Through a comparative analysis approach and eight weeks of data collection, the study addressed key research questions related to solar radiation patterns and optimal system design. The findings highlighted regions with heightened solar radiation levels, showcasing substantial potential for power generation and emphasizing the system's efficiency. Optimizing system design significantly boosted power generation, promoted renewable energy utilization, and enhanced energy storage capacity. The study underscored the benefits of optimizing hybrid solar PV panels and pumped hydro energy supply systems for sustainable energy usage. Optimizing the design of solar PV panels and pumped hydro energy supply systems as examined across diverse climatic conditions in a developing country, not only enhances power generation but also improves the integration of renewable energy sources and boosts energy storage capacities, particularly beneficial for less economically prosperous regions. Additionally, the study provides valuable insights for advancing energy research in economically viable areas. Recommendations included conducting site-specific assessments, utilizing advanced modeling tools, implementing regular maintenance protocols, and enhancing communication among system components.
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Sachpazis:Terzaghi Bearing Capacity Estimation in simple terms with Calculati...Dr.Costas Sachpazis
Terzaghi's soil bearing capacity theory, developed by Karl Terzaghi, is a fundamental principle in geotechnical engineering used to determine the bearing capacity of shallow foundations. This theory provides a method to calculate the ultimate bearing capacity of soil, which is the maximum load per unit area that the soil can support without undergoing shear failure. The Calculation HTML Code included.
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About
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
• Remote control: Parallel or serial interface.
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Technical Specifications
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
Key Features
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
• Remote control: Parallel or serial interface
• Compatible with MAFI CCR system
• Copatiable with IDM8000 CCR
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
Application
• Remote control: Parallel or serial interface.
• Compatible with MAFI CCR system.
• Compatible with IDM8000 CCR.
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
• Easy in configuration using DIP switches.
1. Suez University
Faculty of Petroleum & Mining Engineering
Porosity and Permeability
Student
Belal Farouk El-saied Ibrahim
Class / III
Section / Engineering Geology and Geophysics
Presented to
Prof. Dr. / Ali Abbas
2. Porosity and Permeability
Both are important properties that are related to fluids in sediment and
sedimentary rocks.
Fluids can include: water, hydrocarbons, spilled contaminants.
Most aquifers are in sediment or sedimentary rocks.
Virtually all hydrocarbons are contained in sedimentary rocks.
Porosity: the volume of void space (available to contain fluid or air) in a
sediment or sedimentary rock.
Permeability: related to how easily a fluid will pass through any
granular material.
3. I. Porosity (P)
The proportion of any material that is void space, expressed as a
percentage of the total volume of material.
VP
P = ×100
VT
Where VP is the total volume of pore space
and VT is the total volume of rock or
sediment.
In practice, porosity is commonly based on measurement of the total
grain volume of a granular material:
VT − VG
P=
× 100
VT
Where VG is the total volume of
grains within the total volume of
rock or sediment.
∴VP = VT − VG
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26. Porosity varies from 0% to 70% in natural sediments but exceeds 70%
for freshly deposited mud.
Several factors control porosity.
a) Packing Density
Packing density: the arrangement of the particles in the deposit.
The more densely packed the particles the lower the porosity.
e.g., perfect spheres of uniform size.
Porosity can vary
from 48% to 26%.
27. Shape has an important effect on packing.
Tabular rectangular particles can vary from 0% to just under 50%:
Natural particles such as shells can have very high porosity:
28. In general, the greater the angularity of the particles the more open the
framework (more open fabric) and the greater the possible porosity.
b) Grain Size
On its own, grain size has no influence on porosity!
Consider a cube of sediment of
perfect spheres with cubic
packing.
VT − VG
P=
× 100
VT
d = sphere diameter; n = number of grains along a side (5 in this example).
29. VT − VG
P=
× 100
VT
Length of a side of the cube = d × n = dn
Volume of the cube (VT):
VT = dn × dn × dn = d 3n3
Total number of grains: n × n × n = n3
Volume of a single grain: V =
π 3
d
6
Total volume of grains (VG):
π 3
3π
VG = n × d = n d 3
6
6
3
30. VT − VG
P=
×100
VT
Where: VT = d n
3 3
π 3
d n −n d
6 × 100
P=
d 3 n3
3 3
Therefore:
and
π 3
VG = n d
6
3
3
π
d n 1 − ÷
6 ×100
P=
d 3 n3
3 3
Rearranging:
Therefore:
π
P = 1 − ÷× 100 = 48%
6
d (grain size) does not affect the porosity so that porosity is independent
of grains size.
No matter how large or small the spherical grains in cubic packing have
a porosity is 48%.
31. There are some indirect relationships between size and porosity.
i) Large grains have higher settling velocities than small grains.
When grains settle through a fluid the large grains will impact the
substrate with larger momentum, possibly jostling the grains into tighter
packing (therefore with lower porosity).
ii) A shape effect.
Unconsolidated sands tend to
decrease in porosity with
increasing grain size.
Consolidated sands tend to
increase in porosity with
increasing grain size.
32. Generally, unconsolidated sands undergo little burial and less
compaction than consolidated sands.
Fine sand has slightly higher porosity.
Fine sand tends to be more angular than coarse sand.
Therefore fine sand will support a more open framework (higher
porosity) than better rounded, more spherical, coarse sand.
33. Consolidated sand (deep burial, well compacted) has undergone
exposure to the pressure of burial (experiences the weight of overlying
sediment).
Fine sand is angular, with sharp edges, and the edges will break under
the load pressure and become more compacted (more tightly packed
with lower porosity).
Coarse sand is better rounded and less prone to breakage under load;
therefore the porosity is higher than that of fine sand.
34. c) Sorting
In general, the better sorted the sediment the greater the porosity.
In well sorted sands fine grains are not available to fill the pore spaces.
This figure shows the relationship between sorting and porosity for
clay-free sands.
35. Overall porosity decreases with increasing sorting coefficient (poorer
sorting).
For clay-free sands the reduction in porosity with increasing sorting
coefficient is greater for coarse sand than for fine sand.
The difference is unlikely if clay was also available to fill the pores.
36. For clay-free sands the silt and fine sand particles are available to fill
the pore space between large grains and reduce porosity.
37. Because clay is absent less
relatively fine material is not
available to fill the pores of fine
sand.
Therefore the pores of fine sand
will be less well-filled (and have
porosity higher).
38. d) Post burial changes in porosity.
Includes processes that reduce and increase porosity.
Porosity that develops at the time of deposition is termed primary
porosity.
Porosity that develops after deposition is termed secondary porosity.
Overall, with increasing
burial depth the porosity of
sediment decreases.
50% reduction in porosity
with burial to 6 km depth due
to a variety of processes.
39. i) Compaction
Particles are forced into closer packing by the weight of overlying
deposits, reducing porosity.
May include breakage of grains.
Most effective if clay minerals are present (e.g., shale).
Freshly deposited mud may have 70% porosity but burial under a
kilometre of sediment reduces porosity to 5 or 10%.
http://www.engr.usask.ca/~mjr347/prog/geoe118/geoe118.022.html
40. ii) Cementation
Precipitation of new minerals from pore waters causes cementation of
the grains and acts to fill the pore spaces, reducing porosity.
Most common cements are calcite and quartz.
Here’s a movie of cementation at Paul Heller’s web site
.
41. iii) Clay formation
Clays may form by the chemical alteration of pre-existing minerals after
burial.
Feldspars are particularly common clay-forming minerals.
Clay minerals are very fine-grained and may accumulate in the pore
spaces, reducing porosity.
Eocene Whitemud
Formation, Saskatchewan
42. iv) Solution
If pore waters are undersaturated with respect to the minerals making up
a sediment then some volume of mineral material is lost to solution.
Calcite, that makes up limestone, is relatively soluble and void spaces
that are produced by solution range from the size of individual grains to
caverns.
Quartz is relatively soluble when pore waters have a low Ph.
Solution of grains reduces VG, increasing porosity.
Solution is the most effective means of creating secondary porosity.
v) Pressure solution
The solubility of mineral grains increases under an applied stress (such
as burial load) and the process of solution under stress is termed
Pressure Solution.
The solution takes place at the grain contacts where the applied stress is
greatest.
43. Pressure solution results in a reduction in porosity in two different ways:
1. It shortens the pore spaces as the grains are dissolved.
2. Insoluble material within the grains accumulates in the pore spaces as
the grains are dissolve.
44. v) Fracturing
Fracturing of existing rocks creates a small increase in porosity.
Fracturing is particularly important in producing porosity in rocks with
low primary porosity.
45.
46. POROSITY DETERMINATION
FROM LOGS
Most slides in this section are modified primarily from NExT PERF Short Course Notes, 1999.
However, many of the NExT slides appears to have been obtained from other primary
sources that are not cited. Some slides have a notes section.
48. POROSITY DETERMINATION BY LOGGING
Increasing
radioactivity
Increasing Increasing
resistivity
porosity
Shale
Oil sand
Shale
Gamma
ray
Resisitivity Porosity
49. POROSITY LOG TYPES
3 Main Log Types
• Bulk density
• Sonic (acoustic)
• Compensated neutron
These logs do not measures porosity directly. To
accurately calculate porosity, the analyst must
know:
•Formation lithology
• Fluid in pores of sampled reservoir volume
50. DENSITY LOGS
• Uses radioactive source to generate
gamma rays
• Gamma ray collides with electrons in
formation, losing energy
• Detector measures intensity of backscattered gamma rays, which is related
to electron density of the formation
• Electron density is a measure of bulk
density
51. DENSITY LOGS
• Bulk density, ρb, is dependent upon:
– Lithology
– Porosity
– Density and saturation of fluids in pores
• Saturation is fraction of pore volume
occupied by a particular fluid (intensive)
53. Mud cake
(ρ mc + hmc)
Formation (ρ b)
Long spacing
detector
Short spacing
detector
Source
54. BULK DENSITY
ρb = ρma ( 1 − φ) + ρ f φ
Matrix
•Measures electron density of a formation
•Strong function of formation bulk density
•Matrix bulk density varies with lithology
–Sandstone 2.65 g/cc
–Limestone 2.71 g/cc
–Dolomite 2.87 g/cc
Fluids in
flushed zone
55. POROSITY FROM DENSITY LOG
Porosity equation
ρma − ρb
φ=
ρma − ρ f
Fluid density equation
ρ f = ρmf Sxo + ρh ( 1 − Sxo )
We usually assume the fluid density (ρf) is between 1.0 and 1.1. If gas is present, the
actual ρf will be < 1.0 and the calculated porosity will be too high.
ρmf
is the mud filtrate density, g/cc
ρh
is the hydrocarbon density, g/cc
Sxo
is the saturation of the flush/zone, decimal
56. DENSITY LOGS
Working equation (hydrocarbon zone)
ρb = φ S xo ρmf + φ ( 1 − S xo ) ρhc
+ Vsh ρ sh + ( 1 − φ − Vsh ) ρma
ρb
=
Recorded parameter (bulk volume)
φ Sxo ρmf
=
Mud filtrate component
φ (1 - Sxo) ρhc =
Hydrocarbon component
Vsh ρsh
Shale component
=
1 - φ - Vsh =
Matrix component
57. DENSITY LOGS
• If minimal shale, Vsh ≈ 0
• If ρhc ≈ ρmf ≈ ρf, then
∀ ρb = φ ρf - (1 - φ) ρma
ρma − ρb
φ = φd =
ρma − ρ f
φd = Porosity from density log, fraction
ρma = Density of formation matrix, g/cm3
ρb = Bulk density from log measurement, g/cm3
ρf = Density of fluid in rock pores, g/cm3
ρhc = Density of hydrocarbons in rock pores, g/cm3
ρmf = Density of mud filtrate, g/cm3
ρsh = Density of shale, g/cm3
Vsh = Volume of shale, fraction
59. NEUTRON LOG
• Logging tool emits high energy
neutrons into formation
• Neutrons collide with nuclei of
formation’s atoms
• Neutrons lose energy (velocity) with
each collision
60. NEUTRON LOG
• The most energy is lost when colliding
with a hydrogen atom nucleus
• Neutrons are slowed sufficiently to be
captured by nuclei
• Capturing nuclei become excited and
emit gamma rays
61. NEUTRON LOG
• Depending on type of logging tool either gamma
rays or non-captured neutrons are recorded
• Log records porosity based on neutrons
captured by formation
• If hydrogen is in pore space, porosity is related
to the ratio of neutrons emitted to those counted
as captured
• Neutron log reports porosity, calibrated
assuming calcite matrix and fresh water in
pores, if these assumptions are invalid we must
correct the neutron porosity value
62. NEUTRON LOG
Theoretical equation
φN = φ S xo φNmf + φ ( 1 −S xo ) φNhc
+ Vsh φ sh + ( 1 − φ − Vsh ) φNma
φN
= Recorded parameter
φNma = Porosity of matrix fraction
φ Sxo φNmf
= Mud filtrate portion
φNhc = Porosity of formation saturated with
φ (1 - Sxo) φNhc = Hydrocarbon portion
Vsh φNsh
= Shale portion
(1 - φ - Vsh) φNhc = Matrix portion where φ = True
porosity of rock
φN = Porosity from neutron log measurement, fraction
hydrocarbon fluid, fraction
φNmf = Porosity saturated with mud filtrate, fraction
Vsh = Volume of shale, fraction
Sxo = Mud filtrate saturation in zone invaded
by mud filtrate, fraction
64. ACOUSTIC (SONIC) LOG
Upper
transmitter
R1
R2
R3
R4
Lower
transmitter
• Tool usually consists of
one sound transmitter
(above) and two receivers
(below)
• Sound is generated,
travels through formation
• Elapsed time between
sound wave at receiver 1
vs receiver 2 is dependent
upon density of medium
through which the sound
traveled
66. COMMON LITHOLOGY MATRIX
TRAVEL TIMES USED
Lithology
Sandstone
Limestone
Dolomite
Anydridte
Salt
Typical Matrix Travel
Time, ∆, µ
tma sec/ft
55.5
47.5
43.5
50.0
66.7
67. ACOUSTIC (SONIC) LOG
Working equation
∆t L = φ S xo ∆t mf + φ ( 1 − S xo ) ∆t hc
+ Vsh ∆t sh + ( 1 − φ − Vsh ) ∆t ma
∆tL
= Recorded parameter, travel time read from log
φ Sxo ∆tmf = Mud filtrate portion
φ (1 - Sxo) ∆thc = Hydrocarbon portion
Vsh ∆tsh
= Shale portion
(1 - φ - Vsh) ∆tma = Matrix portion
68. ACOUSTIC (SONIC) LOG
• If Vsh = 0 and if hydrocarbon is liquid
(i.e. ∆tmf ≈ ∆tf), then
∀ ∆tL = φ ∆tf + (1 - φ) ∆tma
or
∆t L − ∆t ma
φs = φ =
∆t f − ∆t ma
φs = Porosity calculated from sonic log reading, fraction
∆tL = Travel time reading from log, microseconds/ft
∆tma = Travel time in matrix, microseconds/ft
∆tf = Travel time in fluid, microseconds/ ft
70. SONIC LOG
The response can be written as follows:
t log = t ma ( 1 − φ) + t f φ
φ=
t log − t ma
t f − t ma
tlog = log reading, µsec/ft
tma = the matrix travel time, µsec/ft
tf = the fluid travel time, µsec/ft
φ = porosity
72. EXAMPLE
Calculating Rock Porosity
Using an Acoustic Log
Calculate the porosity for the following intervals. The measured travel times from the
log are summarized in the following table.
At depth of 10,820’, accoustic log reads travel time of 65 µs/ft.
Calculate porosity. Does this value agree with density and neutron
logs?
Assume a matrix travel time, ∆tm = 51.6 µsec/ft. In addition, assume the formation is
saturated with water having a ∆tf = 189.0 µsec/ft.
75. RESPONSES OF POROSITY LOGS
The three porosity logs:
– Respond differently to different matrix
compositions
– Respond differently to presence of gas or
light oils
Combinations of logs can:
– Imply composition of matrix
– Indicate the type of hydrocarbon in pores
76. GAS EFFECT
• Density - φ is too high
• Neutron - φ is too low
• Sonic - φ is not significantly
affected by gas
77. ESTIMATING POROSITY FROM
WELL LOGS
Openhole logging tools are the most common method
of determining porosity:
• Less expensive than coring and may be less
risk of sticking the tool in the hole
• Coring may not be practical in unconsolidated
formations or in formations with high secondary
porosity such as vugs or natural fractures.
If porosity measurements are very important, both
coring and logging programs may be conducted so
the log-based porosity calculations can be used to
calibrated to the core-based porosity measurements .
79. GEOLOGICAL AND PETROPHYSICAL
DATA USED TO DEFINE FLOW UNITS
Core Lithofacies
Core Pore
Plugs Types
Petrophysical
Data
Gamma Ray Flow
Log
Units
φ vs k Capillary
Pressure
5
4
3
2
1
80. Schematic Reservoir Layering Profile
in a Carbonate Reservoir
Baffles/barriers
SA -97A
Flow unit
SA -251
3150
3200
SA -356 SA -71 SA -344
3150
3100
SA -371
3100
SA -348
3250
SA -346
SA -37
3150
3100
3200
3250
3200
3200
3150
3300
3150
3200
3150
3250
3300
3250
3250
3200
3250
3250
3200
3300
3350
3300
3250
3300
3250
3350
3350
From Bastian and others
81. Why is porosity important?
Especially because it allows us to make estimations of the amount of
fluid that can be contained in a rock (water, oil, spilled contaminants,
etc.).
Example from oil and gas exploration:
82. Why is porosity important?
Especially because it allows us to make estimations of the amount of
fluid that can be contained in a rock (water, oil, spilled contaminants,
etc.).
Example from oil and gas exploration:
83. Why is porosity important?
Especially because it allows us to make estimations of the amount of
fluid that can be contained in a rock (water, oil, spilled contaminants,
etc.).
Example from oil and gas exploration:
84. Why is porosity important?
Especially because it allows us to make estimations of the amount of
fluid that can be contained in a rock (water, oil, spilled contaminants,
etc.).
Example from oil and gas exploration:
85. Why is porosity important?
Especially because it allows us to make estimations of the amount of
fluid that can be contained in a rock (water, oil, spilled contaminants,
etc.).
Example from oil and gas exploration:
How much oil is contained in the discovered unit?
In this case, assume that the pore
spaces of the sediment in the oilbearing unit are full of oil.
Therefore, the total volume of oil is
the total volume of pore space (VP)
in the oil-bearing unit.
86. VP
P = ×100
VT
Total volume of oil = VP, therefore solve for VP.
VT = 800m × 200m ×1m = 160, 000m3
P × VT
VP =
100
P = 10%
Therefore:
10 ×160, 000
VP =
100
= 16, 000m
3
of oil
87. II. Permeability (Hydraulic Conductivity; k)
Stated qualitatively: permeability is a measure of how easily a fluid will
flow through any granular material.
More precisely, permeability (k) is
an empirically-derived parameter
in D’Arcy’s Law, a Law that
predicts the discharge of fluid
through a granular material.
88.
89.
90.
91.
92.
93.
94.
95.
96.
97.
98.
99.
100. Those are all properties that are independent of the granular material.
There are also controls on permeability that are exerted by the granular
material and are accounted for in the term (k) for permeability:
k is proportional to all sediment properties that influence the flow of
fluid through any granular material (note that the dimensions of k are
cm2).
Two major factors:
1. The diameter of the pathways through which the fluid moves.
2. The tortuosity of the pathways (how complex they are).
101. 1. The diameter of the pathways.
Along the walls of the pathway the velocity is zero (a no slip boundary)
and increases away from the boundaries, reaching a maximum towards
the middle to the pathway.
Narrow pathway: the region where the velocity is low is a relatively
large proportion of the total cross-sectional area and average velocity is
low.
Large pathway: the region where
the velocity is low is proportionally
small and the average velocity is
greater.
It’s easier to push fluid through a large
Pathway than a small one.
102. 2. The tortuosity of the pathways.
Tortuosity is a measure of how
much a pathway deviates from a
straight line.
103.
104. 2. The tortuosity of the pathways.
Tortuosity is a measure of how
much a pathway deviates from a
straight line.
The path that fluid takes through a
granular material is governed by
how individual pore spaces are
connected.
The greater the tortuosity the
lower the permeability because
viscous resistance is cumulative
along the length of the pathway.
105. Pathway diameter and tortuosity are controlled by the properties of the
sediment and determine the sediment’s permeability.
The units of permeability are Darcies (d):
1 darcy is the permeability that allows a fluid with 1 centipoise
viscosity to flow at a rate of 1 cm/s under a pressure gradient of 1
atm/cm.
1
d )
Permeability is often very small and expressed in millidarcies (
1000
106. a) Sediment controls on permeability
i) Packing density
Tightly packed sediment has smaller
pathways than loosely packed
sediment (all other factors being
equal).
Smaller pathways reduce porosity and the size of the pathways so the
more tightly packed the sediment the lower the permeability.
107. ii) Porosity
In general, permeability increases with primary porosity.
The larger and more abundant the pore spaces the greater the
permeability.
Pore spaces must be well connected
to enhance permeability.
108. Shale, chalk and vuggy rocks (rocks with large solution holes) may have
very high porosity but the pores are not well linked.
The discontinuous pathways result in low permeability.
Fractures can greatly enhance permeability but do not increase porosity
significantly.
A 0.25 mm fracture will pass fluid
at the rate that would be passed
by13.5 metres of rock with 100 md
permeability.
109. iii) Grain Size
Unlike porosity, permeability increases with grain size.
The larger the grain size the larger the pore area.
For spherical grains in cubic packing:
Pore area = 0.74d2
110. A ten-fold increase in grain size yields a hundred-fold increase in
permeability.
iv) Sorting
The better sorted a sediment is the
greater its permeability.
In very well sorted sands the pore
spaces are open.
In poorly sorted sands fine grains
occupy the pore spaces between
coarser grains.
111. v) Post-burial processes
Like porosity, permeability is changed following burial of a sediment.
In this example permeability
is reduced by two orders of
magnitude with 3 km of
burial.
Cementation
Clay formation
Compaction
Pressure solution
All act to reduce permeability
112. b) Directional permeability
Permeability is not necessarily isotropic (equal in all directions)
Fractures are commonly aligned in the same direction, greatly
enhancing permeability in the direction that is parallel to the
fractures.
113. Variation in grain size and geological structure can create directional
permeability.
E.g., Graded bedding: grain
size becomes finer upwards in
a bed.
Fluid that is introduced at the surface will follow a path that is towards the
direction of dip of the beds.
114. Fabric (preferred orientation of the grains in a sediment) can cause
directional permeability.
E.g., A sandstone unit of prolate particles.
The direction along the long axes of grains will have larger pathways
and therefore greater permeability than the direction that is parallel to
the long axes.
Editor's Notes
{"49":".\n","77":"Determining formation porosity using open-hole porosity logging tools is the most common method of determining porosity for several reasons:\nCoring is often more expensive than logging and may be riskier in terms of sticking the tool in the hole.\nCoring may not be practical in soft unconsolidated formations or in formations with a high degree of secondary porosity such as vugs or natural fractures.\nWhen porosity measurements are considered very important, both coring and logging programs are generally conducted. When both measurements are available, the log-based porosity calculations are usually calibrated to the core-based porosity measurements.\n","55":"We usually assume the fluid density (f) is between 1.0 and 1.1. If gas is present, the actual f will be < 1.0 and the calculated porosity will be too high. \nmfis the mud filtrate density, g/cc\nhis the hydrocarbon density, g/cc\nSxo is the saturation of the flush/zone, decimal\nThe bulk density log is a pad device. This means that the log must be in constant contact with the borehole wall. This is accomplished through the use of a caliper arm on the back side of the density device. When the pad loses contact with the formation either through rugosity or washouts, the bulk density reading is affected. The reading from the density log is always too low in the presence of rugosity or washout. This results in a calculated porosity that is much too high, because the density log is reading in essence the porosity of the washout or the gap between the porosity, pad, and the borehole wall. Although density logs are compensated for the presence of mudcake, this compensation is often inadequate to account for all of the effects of borehole breakouts, washouts, and rugosity. \n","72":"Calculate the porosity for the following intervals. The measured travel times from the log are summarized in the following table.\nAssume a matrix travel time, tm = 51.6 sec/ft. In addition, assume the formation is saturated with water having a tf = 189.0 sec/ft.\n","67":"tL=Recorded parameter, travel time read from log\n Sxo tmf=Mud filtrate portion\n (1 - Sxo) thc=Hydrocarbon portion\nVsh tsh=Shale portion\n(1 - - Vsh) tma=Matrix portion\n","56":"b=Recorded parameter (bulk volume)\n Sxo mf=Mud filtrate component\n (1 - Sxo) hc=Hydrocarbon component\nVsh sh=Shale component\n1 - - Vsh=Matrix component\n","62":"N=Recorded parameter\n Sxo Nmf =Mud filtrate portion\n (1 - Sxo) Nhc=Hydrocarbon portion\nVsh Nsh=Shale portion\n(1 - - Vsh) Nhc=Matrix portion\nwhere\n =True porosity of rock\nN =Porosity from neutron log measurement, fraction\nNma =Porosity of matrix fraction\nNhc=Porosity of formation saturated withhydrocarbon fluid, fraction\nNmf=Porosity saturated with mud filtrate,fraction\nVsh=Volume of shale, fraction\nSxo=Mud filtrate saturation in zone invadedby mud filtrate, fraction\n","79":"Petrophysical analyses of core samples are used to identify reservoir flow units and non-flow units. The results are used to calibrate well logs, after which well logs can be used to map flow units throughout a field.\n","68":"s=Porosity calculated from sonic log reading, fraction\ntL=Travel time reading from log, microseconds/ft\ntma =Travel time in matrix, microseconds/ft\ntf =Travel time in fluid, microseconds/ ft\n","57":"d=Porosity from density log, fraction\nma=Density of formation matrix, g/cm3\nb=Bulk density from log measurement, g/cm3\nf=Density of fluid in rock pores, g/cm3\nhc=Density of hydrocarbons in rock pores, g/cm3\nmf=Density of mud filtrate, g/cm3\nsh=Density of shale, g/cm3\nVsh=Volume of shale, fraction\nSxo=Mud filtrate saturation in zone invaded by mudfiltrate, fraction\n","63":"Uses a radioactive source to bombard the formation with neutrons\nFor a given formation, amount of hydrogen in the formation (I.e. hydrogen index) impacts the number of neutrons that reach the receiver\nA large hydrogen index implies a large liquid-filled porosity (oil or water). The hydrogen index is calibrated to limestone porosity. If the lithology is sandstone or dolomite, the following chart can be used to correct the porosity.\n","80":"From studies of sedimentary facies, petrology, and petrophysics, we can correlate and map reservoir flow and non-flow (barrier/baffle) units to develop models for simulation. The example above shows carbonate flow (YELLOW) and non-flow (GREEN) reservoir units, Pozo Rica oil field, Mexico, based on core and well-log data. From an integrated reservoir study by H-RT.\n","47":"This figure depicts the basic setup of the logging process. A wireline truck with a spool of logging cable is setup so that the sonde (measuring equipment) can be lowered into the wellbore. The logging tools measure different properties, such as spontaneous potential and formation resistivity, as the sonde is brought to the surface. The information is processed by a computer in the logging vehicle, and is interpreted by an engineer or geologist. \n","64":"Sonic tools are usually borehole compensated (BHC), which substantially reduces spurious effects at hole size changes as well as errors due to sonde tilt.\nAs shown in the figure, the BHC system uses two transmitters, one above and one below a pair of sonic receivers. When one of the transmitters is pulsed, the sound wave enters the formation, travels along the wellbore and triggers both of the receivers; the time elapsed between the sound reaching each receiver is recorded. The speed of sound in the sonic sonde and mud is less than that in the formations. Accordingly, the first arrivals of sound energy the receivers corresponds to the sound-travel paths in the formation near the borehole wall. \nThe BHC tranmitters are pulsed alternately, and the delta t readings are averaged. In this way, the tool is compensated for tilt. \nIf the travel time for the matrix is known, then porosity can be calculated.\n","53":"To minimize the influence of the mud column, the source and detector, mounted on a skid, are shielded. The openings of the shields are applied against the wall of the borehole by means of an eccentering arm. The force exerted is substantial, and the skid has a plow shaped leading edge. Therefore, it is able to cut through soft mud cakes usually encountered at medium and shallow depths. Some mud cake may remain, however, and is “seen” by the tool as part of the formation. This must be accounted for.\nA correction is needed when the contact between the skid and the formations is not perfect (due to mud cake or roughness of the borehole wall). In unfavorable cases, this correction can be fairly large. If only one detector is used, the correction is not easy to determine, as it depends on the thickness, the weight, and even the composition of the mud cake or mud interposed between the skid and formation.\nUsing two detectors, a correction can be made for unfavorable conditions.\n","70":"Sonic log - measures the slowness of a compressional wave to travel in the formation. \nwhere t is travel time (slowness)\ntlog is log reading, sec/ft\ntma is the matrix travel time, sec/ft\ntf is the fluid travel time, sec/ft\n is porosity\nMatrix travel time (tma) is a function of lithology\ntma=53 sec/ft sandstone\n tma =46 sec/ft limestone\n tma =41 sec/ft dolomite\nThe sonic log measures the compressional arrival. There are several more sophisticated sonic logs that couple a different type of log and a more sophisticated processing algorithm to determine both the shear wave arrival and the compressional wave arrival. Using both the shear and compressional times, the log analyst can determine rock properties such as Poisson’s ratio, Young’s modulus, and bulk modulus. These values are very important when designing hydraulic fracture treatments or when trying to determine when a well may start to produce sand. \n","48":"An engineer or geologist can interpret the log readings to reach certain conclusions about the formation. For example, a decrease in radioactivity from the gamma ray log could indicate the presence of a sandstone formation. An increase in resistivity may indicate the presence of hydrocarbons. And, an increase in a porosity log might indicate that the formation has porosity and is permeable.\n","76":"Remember that the density log, the neutron log, and the sonic logs do not measure porosity. Rather, porosity is calculated from measurements such as electron density, hydrogen index and sonic travel time. The calculated density porosity is too high only because in the calculation we typically don’t account for the fluid density change. In other words, we assume the fluid density is 1 (or completely liquid filled) even though with gas that value is lower, which causes the calculated porosity to be too high. The neutron porosity is too low because the hydrogen index or the hydrogen density of gas is lower; therefore, the liquid-filled porosity is what the neutron log sees. So when gas is present, that value is lower than the actual porosity. And finally, the sonic log is not significantly affected by gas because it reads very near the wellbore and small gas saturations do not impact the overall travel time significantly. \n","65":"This figure illustrates sonic log response to an acoustic wave transmitted through a compacted formation. The time, To, at which the acoustic wave was initiated at the transmitter, is shown for reference. The first arrival at the receiver is the compressional wave. The Rayleigh wave, traveling at a slower rate, arrives later and is superimposed on the compressional wave. Following the Rayleigh waves are the slower mud waves, transmitted through the mud column and the tool.\nThe flexibility of borehole-compensated (BHC) equipment permits the recording of acoustic logs other than delta t. These include the Amplitude Log for fracture detection, Cement Bond Log, and Variable Density Log. \n"}