Houston College Mod 1 Prerequisites For Hydrocarbon Accumulation PPT

  

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MODULE 1
1.0
PREREQUISITES FOR HYDROCARBON ACCUMULATION
The accumulation of hydrocarbons and formation of oil or gas deposit involve
certain prerequisites. These are the following:
1.
2.
3.
4.
5.
6.
Source Rock
Reservoir Rock
Trap
Seal
Timing
Migration
Not all petroleum discoveries, however, are commercial or economic – that is
they can all be developed and produced at a profit. Additional geological
requirements for a petroleum deposit to be economic are:
1.
Sufficient volume of accumulated hydrocarbon – in-place
reserves
2.
Producibility – recoverable reserves
a. adequate reservoir drive
b. concentration
c. oil quality (e.g., API gravity or viscosity)
3.
Preservation of the petroleum deposit, that is freedom from:
a. flushing
b. biodegradation
c. diffusion
d. overcooking
Non-geological factors affecting profitability of a petroleum discovery are:
• Cost of development and production
• Price of oil/gas
• Fiscal terms
1.1
Source Rock
1.1.1
Definitions:
Source Rock
— Sedimentary rock containing organic material, which under heat, time,
and pressure was transformed to liquid or gaseous hydrocarbons.
Source rock is usually shale or limestone.
Some explorationists use a stricter definition — that is requiring sufficient
hydrocarbon generation and migration from the rock unit to form
commercial accumulation(s) of oil and/or gas for it to be considered a
source rock.
Possible source rock
— any unit of rock, which by its general lithology and depositional
environment, may generate hydrocarbons.
Potential source rock
— contains adequate quantities of organic matter to generate oil or gas
but has not yet done because of insufficient thermal maturation.
Effective source rock
— is generating or has generated and expelled petroleum.
An effective source rock may further be classified into:
Active source rock – presently generating and expelling petroleum.
Quiescent potential source rock – previously active yet has stopped
generating and expelling petroleum because of thermal cooling due
to uplift or erosion but may become active again if reburied.
Spent source rock – has completed the process of oil or gas generation
and expulsion.
It is apparent from the above definitions that a source rock to be effective has to
attain a certain level of maturation so that hydrocarbons may be generated.
However, before a source rock could be effective, it has first to be a good
potential source rock – that is, it has to be sufficiently organically rich.
1.1.2 Organic Matter in Sediments
Remains of plants and animals deposited with the sediments comprise the
organic matter, which if in sufficient quantity makes the sediments possible
source rock.
The types of organisms that contribute organic matter to sediments changed
through time.
Time
Pre-Devonian
Late Devonian
Cretaceous
Organism
Bacteria, phytoplanktons and zooplanktons, algae
Gymnosperms (non-flowering plants)
Angiosperms (flowering plants)
This is quite important because the nature of hydrocarbon generated – whether
oil or gas – by a source rock depends on the type of the organic matter it
contains.
Figure 1-2. Change in organic material contribution through geologic time. (from
Emery, 1996)
1.1.3
Organic Richness
Controls on organic richness and source potential of a possible source rock are:
• terrestrial organic productivity
• terrestrial organic matter supply
• primary productivity
• water depth
• oceanic circulation
• organic matter preservation – anoxic conditions
• sedimentation rate
Figure 1-1. Factors affecting the organic richness of a possible source rock.
(from Emery, 1996)
Figure 1-3. Hydrocarbon source systems through geologic time. (from Emery,
1996)
Average composition of some biomolecules compared to petroleum
Biomolecule
C
H
S
N
Carbohydrates
44
6
Lignins
63
5
0.1
0.3
Proteins
53
7
1
17
Lipids
76
12
Petroleum
85
13
1
0.5
O
50
31.6
22
12
0.5
The biomolecules listed in the table are the principal structural components of
living organisms. Lignins are exclusive to plants and with cellulose, form an
important chemical constituent of wood.
Note that petroleum has higher C and H, about the same sulfur, and less
nitrogen and oxygen. It is apparent from the table that lipids are the
biomolecules closest in chemical composition to petroleum – needing only to lose
a little oxygen to become hydrocarbon. Lipids include fats and waxes,
particularly the waxy coatings of pollen grains, spores, and leaves.
It is apparent here that the hydrocarbon generated upon maturation of the source
rock, whether oil or gas, depends on chemical composition – particularly
hydrogen and carbon — of the precursor organic matter.
1.1.4 Conversion of Organic Matter to Petroleum
The generation of petroleum from primary organic matter occurs in 3 stages.
Diagenesis
• burial of no more than 3-400 m
• low T and P
• mainly compaction and expulsion of water
• alteration due primarily to microbial action
• biogenic gas generation due to anaerobic decay
• change is basically progressive lost of acid groups
• end of diagenesis is when the organic matter becomes insoluble (in acid,
base, or organic solvents)
This is attained when there are no more acid groups left, the organic matter has
turned to kerogen. There is no fundamental chemical difference between a coal
and terrestrial kerogen. It is simply that coals occur in massive deposits (ratio of
organic matter to mineral matter is sufficiently high) while kerogen is dispersed in
a mineral matrix. Kerogen or brown coal are the end products of diagenesis of
organic matter.
Kerogen is defined as the organic material in sedimentary rocks that is insoluble
in organic solvents.
Some of the original free lipids, including hydrocarbons, also remain. These
compounds are relatively resistant to microbial degradation and they include the
biochemical fossils referred to as biomarker.
Catagenesis
• burial to depths of several kilometers
• marked decrease in sediment porosity and permeability
• considerable increase in temperature and pressure
• temperature range is 50-180°C
• vitrinite reflectance increases from 0.5 to 2.0%
• principal zone of oil formation
• end of catagenesis is marked by the inability of the kerogen to produce
hydrocarbons further
Metagenesis
• occurs at great depths
• vitrinite reflectance increases to >2%
• kerogen residue is converted to graphite
• expelled bitumen is further broken down to methane and a carbon residue
• coals are converted to anthracite
Figure 1-4. Transformation of organic matter to hydrocarbons. (from Murray,
etal., 1992)
1.2
Reservoir Rock
In petroleum geology, a reservoir rock is any rock that has sufficient porosity and
permeability to permit the storage and accumulation of crude oil or natural gas
under adequate trap conditions, and to yield the hydrocarbons at satisfactory flow
rate upon production. Sandstones, limestones, and dolomites are the most
common reservoir rocks, but accumulation in fractured igneous and metamorphic
rocks is not unknown.
1.2.1 Porosity
Porosity is defined as the ratio of the pore volume to the bulk volume of a
material. It is usually expressed as a percentage.
φ=
Pore Volume
Bulk Volume − Grain Volume
× 100 =
× 100
Bulk Volume
Bulk Volume
Total Porosity – the ratio of the volume of all the pores to the bulk volume of a
material, regardless of whether or not all of the pores are interconnected.
Effective Porosity — the ratio of the interconnected pore volume to the bulk
volume of a material.
Types of Porosity
Primary
Intergranular
Intraparticle
Secondary
Intercrystalline
Solution (moldic and vuggy)
Fracture porosity
Porosity in reservoir rocks serves as storage space for the hydrocarbons, but for
oil or gas to be able to move into the pores and flow out when produced requires
something else…
1.2.2 Permeability
Permeability is the property of a porous medium to transmit fluids when a
pressure gradient is imposed. An empirical correlation function, Darcy’s Law,
relates permeability to pressure gradient, fluid flow velocity and viscosity.
Darcy’s Law
v=
k dP
µ dL
v = apparent flow velocity, cm/s
µ = viscosity of the flowing fluid, centipoises
dP/dL = pressure gradient in the direction of flow, atmosphere/cm
k = permeability of the porous medium, darcies
Stated in terms of volume flow rate, Darcy’s Law is
Q=
k ( P1 − P2 ) A
µL
Q = rate of flow, cm3/s
k = permeability of the porous medium, darcies
(P1 – P2) = pressure drop across the sample, atmosphere
A = cross-sectional area, cm2
µ = viscosity of the flowing fluid, centipoise
L = length of sample, cm
The basic and standard unit of permeability is darcy. It is equivalent to the
passage of one cubic centimeter of fluid of one centipoise viscosity flowing in one
second under a pressure differential of one atmosphere through a porous
medium having a cross-sectional area of one square centimeter.
1 darcy = 9.869 x 10-9 cm2
Darcy’s Law assumes:
1.
Laminar flow
2.
No reaction between the fluid and the rock
3.
One phase (fluid) is present at 100% saturation
Absolute Permeability (ka) – permeability of a rock to a fluid when the rock is
100% saturated with that fluid.
Effective Permeability (ke)– permeability of a rock to a particular fluid when that
fluid has a pore saturation of less than 100%
Relative Permeability (kr) – the ratio of the effective permeability of a fluid at a
given value of saturation to the effective permeability of that fluid at 100%
saturation (absolute permeability), expressed as a fraction from 0 to 1.
Figure 1-5. Graph of relative permeability and saturation. (from Corelab, 1973)
Permeability is a vectorial property, that is, it varies depending on the direction of
measurement (horizontal and vertical permeability)
1.3
Trap
Any barrier to upward movement of oil or gas, allowing either or both to
accumulate. A trap includes a reservoir rock and an overlying or updip
impermeable cap.
A trap is basically a geometry of reservoir rock.
•
•
•
•
•
•
•
Crest or culmination – the highest point of the trap
Spill point – the lowest point
Vertical closure – vertical distance between the crest and the spill point
Areal closure – area under the vertical closure
Pay – thickness of productive reservoir
Gross pay – total vertical interval of productive zone
Net pay – thickness of actual productive intervals, excludes intervening
non-productive layers.
Figure 1-6. Trap nomenclature using a simple anticline as an example.
Figure 1-7. Difference of gross pay and net pay.
Classification of Traps
Structural trap – formed due to folding, faulting, and other deformation
Stratigraphic trap – result of lithologic changes rather than structural deformation
porosity/permeability trap – formed by lateral variation in
porosity/permeability of the reservoir rock, e.g., as a result of
cementation, presence of clay minerals, or decrease in grain size
Combination trap – a trap that has both structural and stratigraphic elements
Hydrodynamic trap – due to flow of water
1.4
Seal
Effectiveness of a trap is not determined by its 4-way closure only. A seal is also
required.
Seal is an impervious or impermeable bed capping the reservoir rocks in a trap.
Vertical seal
Lateral seal
Whenever two immiscible phases are present in a fine bore tube, there is a
pressure drop across the curved liquid interface called capillary pressure.
Capillary pressure in a tube can be calculated if the fluid interfacial tension (T),
rock-fluid contact angle (θ), and the tube radius are known (r).
Force Up = 2πrTcosθ
Capillary pressure can also be expressed as a hydrostatic head. It is equal to
the product of the height of the liquid rise (h), the density difference of the two
liquids (Dw-Dh), and the gravitational constant (g).
Force Down = πr2h(Dw-Dh)g
Capillary pressure, Pc =
Force Up
Force Down
=
2
Ï€r
Ï€r 2
Capillary pressure may be used to quantify the quality or effectiveness of a seal.
The force down equation of capillary pressure may be used to estimate the
height of the hydrocarbon column a trap may contain. This can be used in
assessing trap fill.
The mere presence of the four prerequisites discussed above, namely source
rock, reservoir rock, trap and seal in a basin is not enough for a petroleum
deposit to form. They also have to be in a proper spatial and temporal relation,
thus, the additional requisites timing and migration.
1.5 Migration
— movement of generated hydrocarbons from the source rock to the reservoir
rock in a trap through conduits such as permeable beds, fractures, and faults.
Primary Migration or Expulsion – movement of generated hydrocarbons out of
the source rock into a more permeable conduit.
Secondary Migration – movement of petroleum through the conduit into a
reservoir in a trap.
Accumulation is the end of migration — that is the hydrocarbons have reached a
trap and are stored in the reservoir.
1.6 Timing
— relationship between the time of trap formation and time of hydrocarbon
generation and migration.
Good timing is for the reservoir, trap and seal to be already in place before the
source rock generates hydrocarbons and migration starts.
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Petroleum Accumulation
Introduction
For petroleum to accumulate; there must be:
1. Source Rocks: These contain organic material from plants or algae. They are buried
and cooked below the earth’s surface for millions of years.
2. Migration: Once the oil is formed, it is forced by gravity to move out of the source
rock and upwards towards the surface. This is a very slow process travelling only a
few kilometers over millions of years.
3. Reservoir rock: The oil or gas will flow until it collects in a reservoir rock, which has
pores (holes) that act like a sponge. Trap (a barrier to fluid flow so that
accumulation can occur against it).
4. Trap: To trap the oil and gas the reservoir rock needs to have an impermeable rock,
called a ‘cap-rock’ above it and around it. This cap rock will not allow oil or gas to
travel through it. If there is no cap-rock the oil and gas will reach the surface as oil
or gas seep.
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Most knowledge has been obtained from experience and observation, but certain generalizations can be made:
• Petroleum originates from organic matter
• To become commercial, the hydrocarbons must be concentrated
• Petroleum reservoirs primarily occur in sedimentary rocks
1- Origin of oil and gas and Source rocks
The story of oil and gas begins hundreds of millions of years ago when the Earth was covered in swamplands filled with
huge trees and the seas were teaming with microscopic plants and animals. The oil and gas deposits started forming
about 290 to 350 million years ago during the Carboniferous Period, which get its name from the basic element in oil and
gas; carbon.
A popular belief is that oil comes from dead dinosaurs. It doesn’t. The giant reptiles lived mostly from 65 to 250 million
years ago, and most scientists believe oil actually comes from the tiniest plants and animals that preceded them.
As they died and sank to the ocean floor, the decomposing organisms, along with mud and silt, created hundreds of feet
of sediment, Sand, clay and minerals settled over this organic-rich mud and solidified into rocks. The weight of the rocks
above pressed the mud into a fraction of its original thickness. Heat from within the Earth cooked the mud’s organic
remains into a soup of hydrocarbons, the main element of petroleum and natural gas.
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Diatoms are an important group of phytoplankton. They contain a silica skeleton and may
reach 1 mm in diameter (right). Other phytoplankton organisms have a carbonate
skeleton.
Zooplankton includes planktonic foraminifera, radiolaria, and planktonic crustacea.
One theory for the origin of oil that Oil and gas originate from organic matter in
sedimentary rocks, dead vegetation in the absence of oxygen ceases to decompose. It
accumulates in the soil as humus and as deposits of peat in bogs and swamps.
Peat buried beneath a cover of clays and sands becomes compacted as the temperature,
weight and pressure of the cover increase, and water and gases are driven off. The
residue, ever richer in carbon, becomes coal.
In the sea, a similar process takes place. Of the marine life that is eternally falling slowly to the bottom of the sea,
vast quantities of it are eaten, some is oxidized, but a portion of the microscopic animal and plant life escapes
destruction and is entombed in the mud on the seafloor. The organic debris collects at the bottom and is buried
within a growing buildup of sands, clays and more debris until the thickness of sediment attains thousands of feet.
Bacteria takes oxygen from the trapped organic residues, breaking them down molecule-by-molecule into
substances rich in carbon and hydrogen, and the extreme weight and pressure of the mass compacts the clay into
hard shale.
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The generation of hydrocarbons from the source material depends primarily on the temperature to which the organic
material is subjected.
Hydrocarbon generation appears to be negligible at temperatures less than 150°F (65°C) in the subsurface and reaches
a maximum within the range of 225° to 350°F (107° and 176°C), the “hydrocarbon window”. Increasing temperatures
convert the heavy hydrocarbons into lighter ones and ultimately to gas. However, at temperatures above 500°F
(260°C), the organic material is carbonized and destroyed as a source material. Consequently, if source beds become
too deeply buried no hydrocarbons will be produced.
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2- Migration from source to reservoir
After generation, the dispersed hydrocarbons in the fine-grained source
rocks must be concentrated by migration to a reservoir. Compaction of
the source beds by the weight of the overlying rocks provides the driving
force necessary to expel the hydrocarbons and to move them throughout
the more porous beds or fractures to regions of lower pressure (which
normally means a shallower depth.) Gravity separation of gas, oil and
water takes place in reservoir rocks which are usually water-saturated.
Consequently, petroleum is forever trying to rise until it is trapped or
escapes at the earth’s surface. Vertical migration via faults and fractures
has led to many of the large oil accumulations, such as that found at
shallow depths in the northern Iraq.
Type of Hydrocarbon migration
Primary Migration: Primary migration of petroleum from source to reservoir is caused by the movement of water, which
carries oil out of the compacting sediments. When the source mud is deposited it contains 70 to 80 percent water the
remainder is solids, such as clay materials, carbonate particles or fine-grained silica. As they build up to great thickness in
sedimentary basins, water is squeezed out by the weight of the overlying sediments. Under normal hydrostatic pressure
(approximately 0.446 psi/ft), the clays lose porosity and the pore diameters shrink.
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Fluids tend to move toward the lowest potential energy. Initially this is upward, but
as compaction progresses there is lateral as well as vertical movement. The lateral
movement results primarily from the tendency of the flat clay mineral particles to lie
horizontally as they are compressed.
This reduces the vertical permeability of the compacting sediments. In addition, the
long continuous sands on the edges of basins orient fluid movement laterally as
burial progresses, as illustrated in Figure 2-18. The migration of oil from source to
reservoir is as follows:
1- Water flows toward the lowest potential energy.
2- Clays often have abnormal pressure because they are slow to release water.
3- Avenues of migration during basin compaction are:
• Sandstones
• Unconformities
• Fracture-fault systems
• biohermal reefs
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Primary migration mechanisms
1. Migration by diffusion. Because of differing concentrations of the fluids in the source rock and the surrounding rock
there is a tendency to diffuse. A widely accepted theory.
2. Migration by molecular solution in water. While aromatics are most soluble in aqueous solutions, they are rare in
oil accumulations, therefore discrediting the general importance of this mechanism, although it may be locally
important.
3. Migration along micro fractures in the source rock. During compaction the fluid pressures in the source rock may
become so large that spontaneous “hydro-fracing” occurs. A useful if underestimated hypothesis.
4. Oil-phase migration. OM in the source rock provides a continuous oil-wet migration path along which the
hydrocarbons diffuse along pressure and concentration gradient. This is a reasonable but unproved hypothesis,
good for high TOCs.
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Secondary Migration: The process in which hydrocarbons move along a porous and permeable layer to its final
accumulation is called secondary migration
The position of the accumulating pool is affected by several – sometimes conflicting – factors. Buoyancy causes oil to
seek the highest permeable part of the reservoir; capillary forces direct the oil into the coarsest-grained portion first,
and into successively finer-grained portions later.
Any permeability barriers in the reservoir channel will drive the oil into a somewhat random distribution. Oil
accumulations in carbonate rock are often erratic because part of the original void spaces have been plugged by
minerals introduced from water solutions after rock is formed.
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The geological activities effects on petroleum accumulation:
– In large sand bodies, barriers formed by thin layers of dense
shale may hold the oil at various levels.
– When crustal movements of the earth occur, oil pools are shifted
away from the place in which they originally accumulated.
– Faults sometimes cut through reservoirs, destroying parts of the
pools or shift them to different depths.
– Uplift and erosion bring the pools near the surface where the
lighter hydrocarbons evaporate.
– Fracturing of the cap rock allows oil to migrate vertically to
shallower depth.
Wherever differential pressures exist and permeable openings provide a
path, petroleum will move.
Tertiary migration: the migration of petroleum accumulation which trapped in the reservoir to the surface.
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3- Reservoir rocks
The petroleum liquids and vapors were emitted from these source rocks, moved upward through the sediment pores,
and accumulated between the grains of the sediment, or “reservoir rock.” The reservoir rocks often contained water,
which then pushed the lighter oil and gas upward until they hit an impermeable rock layer, such as mudstone or salt
rock, which becomes a “seal” or “cap rock.” The oil and gas are thus trapped in “reservoir rocks,” usually sandstone or
limestone.
So petroleum reservoirs aren’t underground pools as is commonly believed. They are actually rocks soaked in oil and
gas, just as water is held in a sponge. (The word petroleum comes from the Latin for “rock oil.”) And they’re not alone in
that sponge-like home. Other substances such as water, salt, carbon dioxide and hydrogen sulfide can get trapped in the
rocks too. Oil and gas, however, contain mostly two elements: hydrogen and carbon. How those elements are arranged
determines the form of the hydrocarbon. For example, natural gas contains the simplest hydrocarbon, methane, while
crude oils can be made up of more complex liquid and solid hydrocarbons.
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Reservoir Rocks Characteristic
1- Permeability
Definition
The Permeability of a rock is the ability of the hydrocarbons to move from one pore to
another so the pores of the rock must be connected together.
Unless hydrocarbons can move and flow from pore to pore, the hydrocarbons remain
locked in place and cannot flow into a well. In addition to porosity and permeability
reservoir rocks must also exist in a very special way. To understand how, it is necessary
to cross the time barrier and take an imaginary trip back into the very ancient past.
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Texture Affecting Permeability (and Porosity as well)
Increased roundness and sphericity lead to higher permeabilities, In what depositional settings do we find the
different grains shown here?
Typical occurrences of clay minerals in sandstones
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The clay type can also have a great influence on permeability.
Shown are kaolinite (a), chlorite (b), and fibrous illite (c).
How do their distributions and shapes affect permeability’s?
The different clay textures on the previous slide lead to dramatically different porosity/permeability relationships.
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Compaction
Compaction is particularly strong in rocks with lower grain fractions (the amount that
grains constitute of the total solid volume, shown here in fractions of unity, with the
rest being fine-grained matrix minerals).
Clays and other matrix minerals move under pressure into the pore spaces.
The softer grains in greywackes crumble and dislocate to clog the pores.
Cementation additionally leads to porosity reduction.
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Porosity
Definition
The porosity of a rock is the percentage of the total volume of the rock that is occupied
by interstices (or Porosity is the volume of the non-solid portion of the rock filled with
fluids, divided by the total volume of the rock).
Nearly all rocks and sediments contain openings called pores or voids, which come in all
shapes and sizes. Some of them are too small to be seen with the unaided eye, and the
smallest range in size down to the dimensions of molecules. In exceptional cases, they
may be many feet across. Materials containing a relatively large proportion of void
space are described as porous or said to possess “high porosity”. That fraction of the
pores through which water can flow is called “effective porosity”. Total porosity may
range from near zero to over 50%, depending on the material, while effective porosities
are typically somewhat smaller. The picture shows examples of different types of
porosity
Because of the higher solubility and different geomechanical properties of carbonates
compared to sandstones, a much greater variety of pore types is found in them;
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Type of Porosities
Primary porosity is the porosity developed by the original sedimentation process by
which the rock was created.
Secondary porosity is created by processes other than primary cementation and
compaction of the sediments.
An example of secondary porosity can be found in the solution of limestone or dolomite
by ground waters, a process which creates vugs or caverns. Fracturing also creates
secondary porosity. Dolomitization results in the shrinking of solid rock volume as the
material transforms from calcite to dolomite, giving a corresponding increase in
porosity.
Example of different type of porosity as shown in picture:
Intergranular (lime and dolomite grainstone)
Intercrystalline (Sucrosic dolomites)
Moldic* (moldic oolitic limestone and dolomite grainstone)
Matrix or Chalky (Mudstone, Chalks)
Moldic or vuggy in addition to matrix (vuggy Packstone and Wackstone)
Fracture or fissure porosity
* moldic porosity (mouldic porosity) A form of secondary porosity, developed by the preferential dissolution of shell
fragments or other particles, to leave empty spaces previously occupied by the particles.

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