Transcript Geological conditions of the forming of oil and gas in the organic

Geological conditions of the forming of oil and gas in
the organic concepts
Dr OCTAVIAN COLȚOI - Senior Geoscientist - Geological Institute of Romania (IGR), Romania
* email address: [email protected]; coltoi_o @yahoo.com
Short overview of the petroleum organic concepts
 Petroleum is present in sedimentary rocks as liquid - oil (i.e. liquid hydrocarbons, named crude oil),
gases (natural gaseous hydrocarbons) or as a mixture between these 2 mentioned chemical phases.
Also, petroleum contains and nonhydrocarbons gases (S, N and O).
 Crude oil is represented by the next liquid fractions: condensate gas, light oil, normal, and heavy
oil.
 Concerning the chemical composition, petroleum is basically expressed by the combination
between two main elements (C and H) in the variable percentages which lead to a appearing of
different known complex molecular structures (saturated and unsaturated molecules).
 Petroleum consists from a mixture of the three chemical series: normal paraffin compounds
(simplest hydrocarbons saturated “alkane”- methane to butane series), naphthenic compounds
(cycloalkanes), and olefins and aromatics compounds (hydrocarbons unsaturated, e.g. benzene) in
the various percentages.
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 Natural bitumen are natural substances characterized by predominance of compounds with C and
H in different proportion (hydrocarbons). Sometimes, other atoms (e.g. O, S and N) will can
participate in the chemical constitution of these substances.
 Bitumen results from bio degradation of the organic matter. The source of the organic matter is
supplied by the single-celled planktonic plants and animals (Diatoms, Blue-green algaes,
Foraminiferas, etc.). Their bodies are mostly constituted from lipids beside to small quantity of
amino acids (proteins) and carbohydrates.
 These single-celled organisms lived to various depositional environments; their development
starting to appearance of life on Earth and till in present.
 Oil is the liquid representative of the natural bitumen and is present in reservoir rocks. Solid
bitumen is represented by asphalt, ozokerite, tar or pitch (the oxidized oils), kerogen (present in
source rock).
 Also, the bitumen exists and in the coals but this has another origin (terrestrial plants, in fact) and
the chemical composition is a little different (especially in connection with the increased
proportion of oxygen.
 Crude oil content 80 – 90 % carbon by weight and hydrogen between 10-14 % while bitumen is
characterized by a percentage of carbon from 80 to 85 and hydrogen between 8-11 %.
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Sulphur is present in the medium and heavy fractions of crude oils (up to 5 % by weight) and is
associated with N (less than 0.1 % by weight) and O (less than 2 % by weight) beside to the rest of
hydrocarbons while in low and medium fractions (below 0.05 % by weight) this is associated only
with C and H.
The content of S from bitumen is given by:
-Water from marine environments is rich in sulphates. In this sedimentary domain exist an intense
bacterial activity of reduction of sulphates having as resulting the productions of sulfuric acid and
sulphur.
- In the early stage of sedimentary basins, sulphuric acid and sulphur combines with organic matter
from unconsolidated sediments and creating some the organic compounds who contain the
sulphur (Mercaptans, Thiophenes, and more).
- These compounds are very resistant from the chemical point of view and, the other part they will
become constitutive part of the bitumen from the future rocks.
- Another source is given by the contents of this chemical element from the humic acids from
recently marine sedimentary deposits.
- Concerning this idea, the precursor of petroleum, respectively kerogen, only two type of kerogen
are responsible for the higher content of the sulphur (kerogen type I and II).
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Also, the geological time is responsible for the quality of petroleum, respectively the chemical
fractionary (cracking) of the derived substance from kerogen (this it will be explained in the next
slides - transformation of the disseminated OM from sediments).
! Excess of sulphur from crude oil is removed by refining but this process is expensive and this
situation lead to increasing of price of crude oil.
The content of N from bitumen is given by:
- This chemical element is inherited from proteins of animal planktons who participated to the
forming of the organic matter (e.g. amount of the Nitrogen in a molecule of protein is maxim 17
%.). About 60 % from organic mass of the plankton is represented by the proteins.
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I. GEOLOGICAL CONDITIONS
In the organic origin of the forming of oil and gas fields, in the sedimentary basin (space, location) it’s
necessary to be accomplished 5 geological conditions in the same time. These are:
1. Existence of the source rocks (to be clearly understood that mean the mother rocks or rocks which
will generate and expelled the hydrocarbons); e.g., shales, carbonated rocks, etc.
2. Existence of the reservoirs or reservoirs rocks (to be clearly understood that mean the host rocks for
the expelled hydrocarbons from source rocks); e.g., sandstones, sands, fissured limestones, etc.
3. Existence of the seal rocks - cap rocks - (to be clearly understood that these rocks must function as a
cover for the previously mentioned rocks); e.g., shales rocks, salt, etc.
4. Existence of the pathways of the oil and gas migration from source rocks to reservoirs; i.e., fissures,
fractures, faults, etc.
5. Existence of the geological traps necessary to protection of the oil and gas into accumulations into
reservoirs. e.g., structural, stratigraphic trap, etc.
! Each of these rock types has a characteristic composition and texture that is a direct result of
depositional environment and post-depositional (diagenetic) processes (i.e., cementation, etc.)
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1. Reservoir rocks (or Reservoirs) – short description
Usually, these are coarse-grained, porous and permeable rocks which have space for accumulation of
hydrocarbons and, also, to create the condition for extracting of hydrocarbons when the exploitation will
start.
Reservoir are dominantly sedimentary rocks. About 99 % of the oil and gas fields are located in these
type of the rocks. The rest (1%) is represented by the fractured igneous and metamorphic rocks.
The sedimentary rocks are represented by the unconsolidated rocks (sands, rarely gravels,) and
consolidated rocks (sandstones, microconglomerates, conglomerates). Also, another sedimentary
reservoirs are represented by the carbonated rocks (fissured, fractured limestones, dolomites, chalks).
These category of rocks are characterized by the four fundamental components:
- Porosity (e.g. Intergranular or Intragranular porosity for sandstones) defined as space with no mineral
matter; commonly filled with water). This could be primary or secondary porosity; in connection is
permeability (low/higher). e.g. porosity of the sandstone is 10 – 30 % from the whole volume of rock.
- Grains. Dimensions and the type of contact between grains will influence the occupied space and the
circulation of fluids. The cementing of the grains could be to the matrix type (fine-grained like claysized sediment) or the cement type (chemically precipitated mineral material).
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2. Seal rocks (or Cap rocks) – short description
Seal rocks are considered a protecting cover for the reservoir rocks. The main condition of them is to
dispose to capacity to rapidly close their hydrocarbons pathways and does not permit to expelling
outside to the reservoirs.
This mechanism of closure (partially or totally) must be effective after the each tectonic event. Thus, the
main role of this type of rock is intended to delay the flowing process of fluids outside.
From another point of view, the seal rocks are considered impermeable rocks (evaporitic rocks: salt,
gypsum, anhydrite) or with some permeability – fine-grained rocks but should have high thickness (e.g.
shales, clays, marls).
Knowing the main characteristic of the gaseous, respectively the escape of gaseous at the low diffusion
rate, in generally, shales and marls are considered the seal rocks with the mentioned condition that these
strata must have a considerable thickness.
Part of them are chemical sedimentary rocks formed by chemical precipitation of minerals and are
crystalline, and often composed of only one mineral (salt, gypsum, anhydrite); another part is
represented by the rocks like shales, marls which are formed in another geological conditions
(accumulated grains, compaction and so on).
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An example of the oil and gas accumulation (oilfield) from Romania – Transylvanian Basin
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3. Source rocks – short description
Source rock is divided in two: one is the mineral part and the other part is bituminous organic matter.
Mineral matrix is consist of the shales, carbonaceous and, more rarely, from coal.
Organic matter may be derived from aquatic organisms and bacteria. Also, another type of organic
matter found in source rocks is derived from terrestrial plants but this will generate, in most cases, coals.
Under to influence of temperature and pressure, the organic matter is converted in a substance named
kerogen (solid bitumen). In geological time, the same parameters (T, P and other factors) convert a big
proportion of the kerogen in petroleum.
Thus, the organic part is represent by the extractable organic matter (E.O.M), and is consist from
kerogen and small quantity of hydrocarbons (0.01 %).
The quantity of the organic matter from source rocks, respectively from kerogen, is quantify by the
Total Organic Content of Carbon (T.O.C)
As geochemical point of view, kerogen is insoluble in the usual organic solvents and is composed of a
variety of organic fragments (algae, pollen, macerals like vitrinite and so on).
The quality of the generated hydrocarbons is not depending only by the type of the matrix of source
rocks (the mineralogical composition). The main role is in connection with the type of kerogen.
The amount and quality of the generated hydrocarbons is done by the transformation ratio of the
kerogen into petroleum.
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Transformation of the organic matter in hydrocarbons, via kerogen
The organic material from sedimentary rocks (source of most oil) is derived from plants and planktonic
animals (phyto- and zooplankton) which live in aquatic environments (marine, brackish, or fresh water).
First stage in a petroleum formation is diagenesis.
Diagenesis – geological process of compaction of the unconsolidated/precipitation of fine-grained
sediments under direct influence of temperature and pressure.
This process is efficient if the burial depth of the sedimentary rocks increase, quickly. In the same time
(i.e. geological time), the microorganisms are incorporated into sediments. Rapid burial of the remains
of these organisms within fine-grained sediments effectively preserved them.
During this early stage of the evolution of sedimentary basin, under the influence of the chemical
reactions, microbial and poorly compaction actions, the water is expelled out from system while the
carbohydrates, proteins, and lipids from dead organisms remain into sediments and forms new
structures, called kerogen (a waxy material) and bitumen (a black tar).
Their parallel evolution during the next stages will generate all types of hydrocarbons and residual
products.
Resumed, nature and abundance of organic matter will contribute in a different behaviour of the mineral
phase, soon after deposition. As I mentioned previously, minerals composition and structure of
sedimentary rocks will influences composition and distribution of fluid phases with the depth.
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As I mentioned previously, diagenetic stage is dominated by biological activity and many chemical
rearrangements. At the end of this stage the organic matter is converted in kerogen. This conversion is
based to the next chemical reactions:
- Anaerobic fermentation reactions. The
process of decomposition of organic
matter (byopolimers) is carried out by
bacterias.
These
anaerobic
microorganisms are buried within
sediments and are capable to living in
absence of free oxygen from the surface
to max – 1000 m underground. Organic
matter is converted, partly, in biogenic
methane gas (first generation gases),
carbon dioxide, water and biopolymers.
- Geo-catalytic reactions. During to this
later stage (so-called proto-petroleum
stage) occur reactions and chemical
combinations between geo-catalysts and
biopolymers who determined the forming
of kerogen (geopolymer) and small
quantities of liquid hydrocarbons.
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The diagenesis (immature stage) extends from surface to maxim – 2 km depth and corresponding to the
temperature of maxim 600C at the 2 km depth (if the geothermal gradient is normal, respectively 330C
per km.
The next process in forming of the petroleum is the Catagenesis stage; this is considered a mature zone
for the forming of the whole hydrocarbons chains. As a conventional rule, is defined as a extended zone
of the burial depth of sediments from cca 2 km to max 4.5 km. If it used the same normal geothermal
gradient, this depth interval is characterized by a variance of temperature from 600C to max. 1500C.
Catagenesis requires a specific window of conditions for expelling of the formed hydrocarbons from
source rocks. Thus, if this is hot it will produce the hydrocarbons (60 to max. 1500C) and second, if it is
cold the plankton will remain trapped as kerogen.
As it observed, the temperature is increasing and, evidently, the pressure (deeper burial). In this stage,
the main process is conducted by the thermal degradation of the kerogen. Thus, the cracking of kerogen
(process of breaking a long-chain of hydrocarbons into the simples molecules) is conducted by:
- Reactions of the heterolytic cleavage; it forms the iso-paraffinic (heavy oil);
- Reactions of the homolytic cleavage; it forms oil, light oil and thermogenic methane gas (to the
second generation) – Oil window;.
- At the end of this stage it forms “wet gases” (condensated gases). A part of kerogen is nontransformed, residual, poorly or devoid of hydrocarbons.
Must be mentioned that cracking process is catalysed by the existing minerals from sediments.
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The last stage in
forming of
hydrocarbons is
Metagenesis.
This supermature
zone is
characterized by
forming of the
hydrocarbons gases
(to third
generations) and
residue carbon. The
remains from nontranformed kerogen
will become inert
compound (KIV).
*
In comparison, in the terrestrial burial, the organic sediment is dominated by cellulose and lignin
and mineral fractions is much smaller and, of course, the transformation of the OM is restricted. In
these conditions OM forms peat which under the temperature and pressure specific of the catagenesis
stage will form coals. If the temperature and pressure are supplied at the higher conditions this it will
lead to higher ranks of coals.
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II. ASSESSMENT OF THE SOURCE ROCKS
The assessment key of the sedimentary basin concerning the richness in the hydrocarbons is to evaluate
the potential hydrocarbon of the source rocks. This aspect is included into the geological history and is
crucial to understand the petroleum system in a sedimentary basin.
Petroleum system in a modern theory consists of a geological basic, respectively the combining to
source and reservoir rocks necessary to have an accumulation.
Oil and gas fields (oil and gas pools) mean one, two or more petroleum system present in a sedimentary
basin.
Concerning the assessment of the richness in hydrocarbons, there are many way to understood this
concept.
The amount and type of organic matter and its maturity from source rocks are estimated and determined
in the laboratory. Hereby, the maturity evaluation and estimation of petroleum potential are done by the
next techniques and methods made to bitumen.
a. Optical organic matter (microscopy method) study based to the reflectometry and UV
fluorescence. This method show the organic facies and organic particles based to the description (e.g.
Vitrinite reflectance, Thermal Alteration index and so on).
b. Organic matter quantity and quality evaluation (geochemical method) using the different types
of laboratory apparatus (i.e. Rock Eval, Lecco, etc) – pyrolysis methods.
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Microscopy methods
1. Vitrinite Reflectance (VRo). This optical method is based to analysing of maceral named vitrinite, a
component of the coals and kerogen from sediments. To chemical point of view, this is composed of
polymers, cellulose and lignin derived from the cell-wall material (humic peat) or woody tissue of the
terrestrial plants. This method is not used for kerogen from source rocks oldest than Devonian because
starting with this stratigraphic interval appeared the upper terrestrial plant.
This method is used to establish the maximum temperature history of sedimentary rocks and was
initially used to establish the rank of coal. Recently, this methods was applied, with successfully, and
on the hydrocarbons source rocks. In this idea, VRo can be used as an indicator of maturity and is
typically abundant in KIII. Also, Rvo is used in the burial modelling to identify the unconformities who
exist in the sedimentary deposits.
VRo is defined as a measured percentage of reflected light from a kerogen sample which is immersed
in oil (% Ro = % reflectance in oil) and show the next values:
- VRo < 0.65% is characteristic for Diagenesis stage.
- 0.65 < VRo < 2% is characteristic for Catagenesis stage – 0.65 < Vro < 1.3% - oil window.
– 1.3 < Vro < 2% - wet gases.
- Vro > 2 % is characteristic for Metagenesis stage.
In absence of this maceral in the marine sediments can be used the alternative maturity parameters
(liptinite, graptolite, chitinozoans, scolecodonts, reflectance, etc).
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2. Thermal Alteration Index. This method is based to the main capacity of the pollen and spores to
changing their natural colouring during to sedimentation processes. Thus, the old sedimentary rocks
(being to Metagenesis stage) incorporate polymorphous who is characterized by the blackish colouring
while the recent sediments (Diagenesis stage) contain spores, pollen with the yellowish colouring.
Otherwise, TAI shown the next:
- For Diagenesis stage – light yellow to dark yellow;
- For Catagenesis stage – orange;
- For Metagenesis stage – brown to black.
Thus, this method is used for determining of the maturity level of the whole sedimentary section not for
only source rocks from this geological section.
Also, optical analyses can include and others. There are:
3. Conodonts Alteration Index (CAI);
4. Ostracod Alteration Index (OAI);
5. Foraminifera Alteration Index (FAI).
These mentioned analysis are based to the transformation of the structures of the microorganisms
during the sedimentation and, especially during compaction in the Catagenesis and Metagenesis stages.
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6. Organic Metamorphism and the Generation of Petroleum
Level of Organic Metamorphism (LOM) is a the thermal metamorphism process which affect the
organic matter during burial depth. This methodology is suitable for the thermal range in the generation
and, also, in the destruction of petroleum. LOM is based on coal rank and is easy used for calibrating to
other useful scales of organic metamorphism.
LOM show the next values:
- 0 – 5 – Diagenesis stage;
- 5 – 12 – Catagenesis stage;
-> 12 – Metagenesis stage.
A relation of temperature to time for petroleum generation is based on LOM values of sedimentary
rocks. Thus, this relation is nearly equivalent to a doubling of the reaction rate for each additional
10°C, and the apparent activation energies increase from about 18 to 33 kcal/mole as LOM increases
from 9 to 16.
These methodologies are combined and interconnected to get a strong image, qualitative image on what
happen in the sedimentary basin and to establish, in present, the level of the productivity of the source
rocks who already generated the hydrocarbons. These correlations and modellings are useful to
knowing the quantity of generated hydrocarbons, geological time when were generated and how were
expelled (and what quantity was retained in the kerogen).
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Another way to establish the thermal maturity of the OM from the geological formations (i.e.,
sedimentary rocks) is to used the empirical relationship between VRo and petroleum formation. This
is possible using of simple geological modelling in the sedimentary basin based to the time and
temperature who acting on rocks (Time-Temperature index).
Thus, TTI of maturity is a theoretical measure of maturation and oil generation. One needs to be able
to model the geological burial history of the area (Depth v Time) and be able to estimate the
geothermal history. Allowance has to be made for uplift and erosion as well.
This TTI was implemented by Lopatin.
This method is based to reconstruction of
the depositional and tectonic history of
the geologic section of interest. This is
accomplished by plotting depth of burial
versus geological age and to specify its
temperature history. The model has a
basic equation for the computation. The
used parameters is time expressed by the
length of time in millions of years spent
by the sediment in the temperature
interval and values of the highest and
lowest temperature interval encountered.
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Pyrolysis methods (geochemical method)
This method determine the contents of the main chemical elements from kerogen, respectively C, H
and O (Pseudo-Van Krevelen diagram). This is based to heating, gradually, a part from source rock or a
kerogen from the source rocks.
The heating mean a rate from 50C/min to 250C/min till is reaching the 6500C. During the heating are
released the common elements (C, H, and O) who forms the chemical structures of the microorganism
and kerogen.
Also, this simulation process of the source rock maturity showing the temperatures of the main phases.
The correspondence showing the next values: kerogen type I and II are determined by temperatures
between 425 and 4400C while kerogen type III correspond to the temperature of 4700C.
Based to the next parameters, was established the correlation and limits for the each type of
kerogen. Kerogen types are defined on H/C and O/C values (or HI and OI from Rock-Eval). Thus:
- Kerogen Type I is characterized by the value of H/C ratio between 1.7 - 2.0; O/C ratio between 0.1 0.15 and transformation ratio into petroleum is about 90 %.
- Kerogen Type II is characterized by the value of H/C ratio between 1.0 - 1.5; O/C ratio between 0.15
- 0.25 and transformation ratio into petroleum is about 60-70 %.
- Kerogen Type III is characterized by the value of H/C ratio between 0.5 - 1.0; O/C ratio between
0.25 – 0.35 and transformation ratio into petroleum is about 10 % (only gases).
- Kerogen Type IV is characterized by the value of H/C ratio is < 0.5; O/C ratio > 0.35 and
transformation ratio into petroleum is zero and gases about 1 %.
As concerning the petroleum potential it is necessary to use the next parameters which are common for
all used pyrolysis (e.g. pyrogram Rock Eval). Also, these parameters obtained are the next:
- T.O.C Total Organic Carbon (Weight % of rock)
- S1 Productivity = Kg of Hydrocarbons (Free and Thermovaporizable Per Ton of Rock ------> OIL
- S2 Potential Productivity = Kg of Hydrocarbons (Cracking of Kerogen) Per Ton of Rock ---> Kerogen
- PI Production Index = Ratio Productivity / Productivity + Potential Productivity) ----------> S1/S1+S2
- TMAX Temperature = Temperature (°C) of the Maximum Formation of Hydrocarbons by Cracking
of Kerogen --------------------> S2
- HI Hydrogen Index = Mg of Hydrocarbons
(Coming from Cracking of Kerogen) in the Per
Gram of TOC ----------> S2/TOC
- OI Oxygen Index = Mg of Carbon Dioxide
(Coming from Cracking of Kerogen) Per Gram of
TOC ----------> CO2/TOC
M inC = Mineral Carbon (Weight % of Rock)
The sedimentary rocks that could be considered source
rocks must have the content of the TOC more than 1 %
and maxim of value between 20-21 %.
Example of the pseudo-Van Krevelen diagram from sample of the Romania borehole
Based to the values of PI (Production Index), the source rocks are classified into:
- IP < 2000 ppm of hydrocarbons (<2 kg of hydrocarbons per ton gross rock) - poor source rocks;
- IP = 2000 – 6000 ppm of hydrocarbons (2-6 kg of hydrocarbons per ton gross rock)- rich source rocks;
- IP > 6000 ppm of hydrocarbons (> 6 kg of hydrocarbons per ton gross rock) - very rich source rocks;
Different types of kerogen contain different amounts of hydrogen relative to carbon and oxygen.
Kerogen is divided into 4 type:
- Kerogen Type I (called bacterial-algal kerogen). The depositional environment is lacustrine.
- Kerogen Type II (called planktonic kerogen). The depositional environment is marine.
- Kerogen Type III (called humic kerogen). The depositional environment is terrestrial. Also, may be
Kerogen type III S (rich in Sulphur).
- Kerogen Type IV (called inertinite kerogen). The depositional environment is terrestrial.
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KI – Transformation ratio of kerogen in petroleum is about 90%.
KII – Transformation ratio of kerogen in petroleum is about 60-70%.
KIII – Transformation ratio of kerogen in petroleum is < 10% (only gases).
KIV – Transformation ratio of kerogen in petroleum is 0 and gases about 1%.
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An example - Moesian Platform (Romanian
sedimentary basin)
The organic matter contained in the samples (core and
cutting) of the wells shows:
- Widely distributed type of organoclasts;
- In absence of true vitrinite originating from higher
plants in Lower Palaeozoic series, the various
encountered organic remains consists of:
Tasmanites (in fluorescence mode), microporous or
homogeneous fragments, structured graptolites,
oxidized organoclasts mainly inherited of the
continent (phytoclasts).
The maturity of the Silurian interval is established
taking into account the fluorescence of the Tasmanites
and the reflectance of graptolite; the maturity increases
with depth between 0.60 and 1% eq. VRo. The organic
matter is overmature with maturity of around 1.251.30 % in one of this well and a maturity increase with
depth between 1.30 and 1.60 eq. VRo in the other one.
Those
values
are
mainly
deduced
from
vitrinite/graptolite correlation.
The Silurian studied samples consist of carbonated claystones with an organic matter from type II and
with relatively low TOC content: less than 1.2 % weight for the overmature wells and less than 1.6 %
weight for the rest of studied wells.
Thank you for your attention