Oil shale and shale gas (abdallah)

Unconventional
Oil Shale & Shale Gas
By
Abdallah Khames Ibrahim
Geology Department, Faculty of Science, Alexandria University
Supervised by
Prof.Dr.Magdi Elghamri
Professor of petroleum Geology
2015

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Acknowledgement
After thanking ALLAH, thanks for every one helped me to finish my
graduation project
Especially:
Professors who supported and supervised me at the expense of their precious time;
Dr. Magdi Elghamri (professor of petroleum Geology) and Prof. Dr. Mohamed
Abdel-Aziz Younes (professor of petroleum Geology), also professor who helped me
in my project; Prof. Dr. Tharwat Ahmed Abdel Fattah (professor of Geophysics)
and a very special thanks for all doctors in the department of geology who helped me
to be a real geologist.
Abdallah khames
abdallah _khames@outlook.com

Unconventional oil shale and shale gas 2015
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Contents
Chapter page no.
Chapter I: introduction of Oil shale …………………………….......... 5
1.1 Definition of oil shale ……………………….………………………… 11
1.2 Origin of oil shale ……………………………………………………... 12
1.3 Origin of Organic Matter ………………………………………….….. 12
1.4 Thermal Maturity of Organic Matter ……….……………………........ 14
1.5 Classification of oil shale ....………………………………………..…. 14
1.6 Composition and properties ………………………………………........ 21
1.6.1 Mineral Components ………………………………………... 21
Chapter II: Exploration of oil shale ……………………..…………….. 24
2.1 Geological investigation ……………………………………………..... 25
2.2 GEOPHYSICAL investigation …........................................................... 25
2.2.1 Seismic characteristics of oil shale………………………...… 27
2.2.2 Log characteristics of oil shale……………………………..... 29
2.2.3 Single-well evaluation of oil shale………………………...… 31
2.2.4 Analysis of log-seismic multi-attributes………………...…… 35
2.2.5 Seismic quantitative evaluation of oil shale…………………. 37
2.2.5.1 The log-constrained seismic inversion………………........ 37
2.2.5.2 Prediction of the inversion volume of TOC ……………... 38
2.2.5.3 Prediction of the inversion volume of oil yield …………. 40
2.3 Geochemical investigation ………………………………..…………... 45
2.3.1 Rock Eval pyrolysis ……………………………………….... 46

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2.3.1 Fischer Assay…………………………………………....…… 47
2.3.3 Hydrous Pyrolysis Oil Yields ……………………………….. 48
Chapter III: Extraction of oil shale ……………………………………. 49
3.1 Ex-Situ Processing ……………………………………...…………….… 49
3.2 Ex situ technologies…………………………………………………….. 52
3.2.1 Internal combustion…………………………………………… 53
3.2.2 Hot recycled solids……………………………………………. 54
3.2.3 Conduction through a wall…………………………………..... 56
3.3 In-situ processing……………………………………………………….. 56
3.4 In-Situ Technologies……………………………………………………. 57
3.4.1 Shell In Situ Conversion Process (ICP)……………….. 57
3.4.2 American shale oil process………………………..…… 58
Chapter IV: Evaluation of Oil-Shale Resources, production….... 59
4.1 global oil shale resources…………………………………….......……. 59
4.2 global oil shale production ………………………………….……….... 60
4.3 oil shale in Egypt …………………………………….………………... 62
Chapter V: Introduction of shale gas...................................................... 71
5.1 Different between shale gas and natural gas ……………………...…… 72
5.2 Types of shale gas ……………………………..………..…….………... 73
5.3 Basic Characteristics of Shale Gas ……………………………………... 74
5.4 Characteristics of Shale reservoir ………………………………………. 76

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Chapter VI: Shale gas exploration……………………………………… 77
6.1 Geological investigation…………………………………………….... 77
6.2 RESERVOIR EVALUATION TECHNIQUE ………………………. 78
6.2.1 Seismic characteristics of oil shale…………..……………… 79
6.2.2 Log characteristics of oil shale…………………………..….. 80
6.2.3 Experimental analysis tech technique...................................... 81
Chapter VII: Shale gas extraction ……………………………………… 82
7.1 shale gas extraction …........................................................................... 82
Chapter VIII:Evaluation of Shale-Gas Resources, production... 84
8.1 global shale gas resources……………………………………....……. 84
8.3 shale gas in Egypt …………………………………….…………..….. 84
References ……………………………………………………………………….…... 86

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Chapter I
Introduction
Oil shale is commonly defined as a fine-grained sedimentary rock
containing organic matter that yields substantial amounts of oil and
combustible gas upon destructive distillation. Most of the organic
matter is insoluble in ordinary organic solvents; therefore, it must be
decomposed by heating to release such materials. Underlying most
definitions of oil shale is its potential for the economic recovery of
energy, including shale oil and combustible gas, as well as a number
of byproducts. A deposit of oil shale having economic potential is
generally one that is at or near enough to the surface to be developed
by open-pit or conventional underground mining or by in-situ
methods.
Oil shales range widely in organic content and oil yield.A
commercial grade of oil shale, as determined by their yield of shale
oil, ranges from about 100 to 200 liters per metric ton (l/t) of rock.

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The U.S. Geological Survey has used a lower limit of about 40 l/t for
classification of Federal oil-shale lands. Others have suggested a
limit as low as 25 l/t.
Deposits of oil shale are in many parts of the world. These
deposits, which range from Cambrian to Tertiary age, may occur as
minor accumulations of little or no economic value or giant deposits
that occupy thousands of square kilometers and reach thicknesses of
700 m or more.
Oil shales were deposited in a variety of depositional
environments, including fresh-water to highly saline lakes,
epicontinental marine basins and subtidal shelves, and in limnic and
coastal swamps, commonly in association with deposits of coal.
In terms of mineral and elemental content, oil shale differs from
coal in several distinct ways. Oil shales typically contain much larger

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amounts of inert mineral matter (60–90 percent) than coals, which
have been defined as containing less than 40 percent mineral matter.
The organic matter of oil shale, which is the source of liquid and
gaseous hydrocarbons, typically has a higher hydrogen and lower
oxygen content than that of lignite and bituminous coal.
In general, the precursors of the organic matter in oil shale and
coal also differ. Much of the organic matter in oil shale is of algal
origin, but may also include remains of vascular land plants that more
commonly compose much of the organic matter in coal.
The origin of some of the organic matter in oil shale is obscure
because of the lack of recognizable biologic structures that would
help identify the precursor organisms. Such materials may be of
bacterial origin or the product of bacterial degradation of algae or
other organic matter.

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The mineral component of some oil shales is composed of
carbonates including calcite, dolomite, and siderite, with lesser
amounts of aluminosilicates. For other oil shales, the reverse is
true—silicates including quartz, feldspar, and clay minerals are
dominant and carbonates are a minor component. Many oil-shale
deposits contain small, but ubiquitous, amounts of sulfides including
pyrite and marcasite, indicating that the sediments probably
accumulated in dysaerobic to anoxic waters that prevented the
destruction of the organic matter by burrowing organisms and
oxidation.
Although shale oil in today’s world market is not competitive
with petroleum, natural gas, or coal, it is used in several countries
that possess easily exploitable deposits of oil shale but lack other
fossil fuel resources. Some oil-shale deposits contain minerals and
metals that add byproduct value such as alum [KAl(SO4)2•12H2O],

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nahcolite (NaHCO3),dawsonite [NaAl(OH)2CO3], sulfur,
ammonium sulfate, vanadium, zinc, copper, and uranium.
The gross heating value of oil shales on a dry-weight basis ranges
from about 500 to 4,000 kilocalories per kilogram (kcal/kg) of rock.
The high-grade kukersite oil shale of Estonia, which fuels several
electric power plants, has a heating value of about 2,000 to 2,200
kcal/kg. By comparison, the heating value of lignitic coal ranges
from 3,500 to 4,600 kcal/kg on a dry, mineral-free basis (American
Society for Testing Materials, 1966).
Tectonic events and volcanism have altered some deposits.
Structural deformation may impair the mining of an oil-shale deposit,
whereas igneous intrusions may have thermally degraded the organic
matter. Thermal alteration of this type may be restricted to a small
part of the deposit, or it may be widespread making most of the
deposit unfit for recovery of shale oil.

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The grade of oil shale can be determined by measuring the yield
of oil of a shale sample in a laboratory retort. This is perhaps the
most common type of analysis that is currently used to evaluate an
oil-shale resource. The method commonly used in the United States
is called the “modified Fischer assay,” first developed in Germany,
then adapted by the U.S. Bureau of Mines for analyzing oil shale of
the Green River Formation in the western United States (Stanfield
and Frost, 1949).

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1.1 Definition of oil shale
OIL SHALE: Rock That Turns into Oil
Oil Shale is an organic-rich, fine-grained sedimentary rock that
contains a solid organic compound known as kerogen. Oil shale
generally contains enough oil that it will burn, earning it the
nickname, “the rock that burns”. Kerogen is one of the first stages of
organic matter processing into petroleum, and all oil and gas are
ultimately derived from kerogen. Oil shale contains the remains of
algae and plankto deposited millions of years ago that have not been
buried deep enough to become hot enough to break down into the
hydrocarbons targeted in conventional oil projects.

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1.2 Origin of oil shale
Oil shale represents a large and mostly untapped hydrocarbon
resource. Like tar sand (oil sand in Canada) and coal, oil shale is
considered unconventional because oil cannot be produced directly
from the resource by sinking a well and pumping. Oil has to be
produced thermally from the shale. The organic material contained in
the shale is called kerogen, a solid material intimately bound within
the mineral matrix Oil shale is distributed widely throughout the
world with known deposition every continent.
1.3 Origin of Organic Matter
Organic matter in oil shale includes the remains of algae spores,
pollen, plant cuticle and corky fragments of herb-ceous and woody
plants, and other cellular remains of lacu-trine, marine, and land
plants. These materials are composed chiefly of carbon, hydrogen,
oxygen, nitrogen, and sulfur. Some organic matter retains enough
biological structures so that specific types can be identified as to

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genus and even species. In some oil shale, the organic matter is
unstructured and is best described as amorphous (bituminite). The
origin of this amorphous material is not well known, but it is likely a
mixture of degraded algal or bacterial remains. Small amounts of
plant resins and waxes also contribute to the organic matter. Fossil
shell and bone fragments composed of phosphate and carbonate
minerals, although of organic origin, are excluded from the definition
of organic matter used herein and are considered to be part of the
mineral matrix of the oil shale. Most of the organic matter in oil shale
is derived from various types of marine and lacustrine algae. It may
also include varied admixtures of biologically higher forms of plant
debris that depend on the depositional environment and geographic
position. Bacterial remains can be volumetrically important in many
oil shale, but they are difficult to identify. Most of the organic matter
in oil shale is insoluble in ordinary organic solvents, whereas some is
bitumen that is soluble in certain organic solvents.

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1.4 Thermal Maturity of Organic Matter
The thermal maturity of an oil shale refers to the degree to which
the organic matter has been altered by geothermal heating. If the oil
shale is heated to a high enough temperature, as may be the case if
the oil shale were deeply buried, the organic matter may thermally
decompose to form oil and gas. Under such circumstances, oil shale
can be source rocks for petroleum and natural gas.
1.5 Classification of oil shale
Mixed with a variety of sediments over a lengthy geological time
period, shale forms a tough, dense rock ranging in color from lighten
to black. Based on its apparent colors, shale may be referred to as
black shale or brown shale.
Oil shale has also been given various names in different regions.
For example, the Ute Indians, on observing outcroppings burst into

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flames after being hit by lightning, referred to it as the rock that
burns. Oil shale has received many different names over the years,
such as cannel coal, bog head coal, alum shale, stellarite, albertite,
kerogenshale, bituminite, gas coal, algal coal, wollongite, schistes
bitumineux, torbanite, and kukersite. Oil shale divided into three
groups based upon their environments of deposition—terrestrial,
lacustrine, and marine (fig.1.1).
(fig1.1) classification of oil shale

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Terrestrial oil shale include those composed of lipid-rich organic
matter such as resin spores, waxy cuticles, and corky tissue of roots,
and stems of vascular terrestrial plants commonly found in coal-
forming swamps and bogs.
Lacustrine oil shale includes lipid-rich organic matter derived
from algae that lived in freshwater, brackish, or saline lakes. The
lacustrine oil shale of the Green River Formation, which was
discussed above, is among the most extensively studied sediments.
However, their strongly basic depositional environment is certainly
unusual, if not unique.
Marine oil shale are composed of lipid-rich organic matter
derived from marine algae, acritarchs (unicellular organisms of
questionable origin), and marine dinoflagellates. Marine oil shale is
usually associated with one of two settings (Figure 1.2). The anoxic
silled basin shown (Figure 1.2a) can occur in the shallow water of a

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continental shelf. High phytoplankton growth rates near the surface
will give a high deposition rate. The sill shields the trough from the
circulation of oxygen-laden water. Under these conditions, the
decomposition of organic sedimentary matter will rapidly deplete
oxygen within the confines of the basin, thereby providing the
strongly anoxic (reducing, low-Eh) environment that is needed for
efficient preservation.
Fig (1.2)

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The anoxic zone in an upwelling area (Figure 1.2b) arises from
circulation of an open-ocean current over a cold, oxygen-depleted
bottom layer. Mixing of a nutrient-rich current, such as the Gulf
Stream, into the carbon dioxide-rich and light-rich eutrophic zone
gives an environment capable of sustaining very high rates of organic
production.
The black marine shale formed in shallow seas has been
extensively studied as they occur in many places. These shale were
deposited on broad, nearly flat sea bottoms and therefore usually
occur in thin deposits (10–50m thick), which may extend over
thousands of square miles.
Cannel coal is brown to black oil shale composed of resins,
spores, waxes, and coriaceous and corky materials derived from
terrestrial vascular plants together with varied amounts of vitrinite
and inertinite. Cannel coals originate in oxygen-deficient ponds or

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shallow lakes in peat-forming swamps and bogs. This type of shale is
usually rich inoil-generating lipid-rich organic matter derived from
plant resins, pollen, spores, plant waxes, and the corky tissues of
vascular plants.
Lamosite is pale-and grayish-brown and dark gray to black oil
shale in which the chief organic constituent is lamalginite derived
from lacustrine planktonic algae. Other minor components in
lamosite include vitrinite, inertinite, telalginite, and bitumen.
Marinite is a gray to dark gray to black oil shale of marine origin
in which the chief organic components are lamalginite and bituminite
derived chiefly from marine phytoplankton. Marinite may also
contain small amounts of bitumen, telalginite, and vitrinite.Torbanite,
tasmanite, and kukersite are related to specific kinds of algae from
which the organic matter was derived; the names are based on local
geographic features.

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Is a black oil shale whose organic matter is composed mainly of
telalginite derived largely from lipid-rich Botryococcus and related
algal forms found in fresh- to brackish-water lakes. It also contains
small amounts of vitrinite and inertinite.
Tasmanite, named from oil-shale deposits in Tasmania, is a
brown to black oil shale. The organic matter consists of telalginite
derived chiefly from unicellular tasmanitid algae of marine origin
and lesser amounts of vitrinite, lamalginite, and inertinite.
Kukersite, is a light brown marine oil shale. Its principal organic
component is telalginite derived from the green alga,
Gloeocapsomorphaprisca.
Fig(1.3) Fossils in Ordovician kukersite oil shale. Fig(1.4) Cannel coal from the Pennsylvanian of NE Ohio

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1.6 Composition and properties
It is a fact the term oil shale describes an organic-rich rock from
which little carbonaceous material can be removed by extraction
(with common petroleum-based solvents) but which produces
variable quantities of distillate (shale oil) when raised to temperatures
greater than 350°C(660°F). Thus, oil shale is assessed by the ability
of the mineral to produce shale oil in terms of gallons per ton by
means of a test method(Fischer assay) in which the oil shale is heated
to 500°(930°F).
1.6.1 Mineral Components
Oil shale has often been termed as (incorrectly and for various
illogical reasons) high-mineral coal. Nothing could be further from
the truth than this misleading terminology. Coal and oil shale are
fraught with considerable differences and such terminology should be
frowned upon. Furthermore, the precursors of the organic matter in

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oil shale and coal also differ. Much of the organic matter in oil shale
is of algal origin, but may also include remains of the vascular land
plants that more commonly compose much of the organic matter in.
In addition, the lack of recognizable biological structures in oil shale
that would help identify the precursor organisms makes it difficult to
identify the origin of the organic matter.
In terms of mineral and elemental content, oil shale differs from
coal in several distinct ways. Oil shale typically contains much larger
amounts of inert mineral matter (60–90%) than coal, which has been
defined as containing less than 40% mineral matter. The organic
matter of oil shale, which is the source of liquid and gaseous
hydrocarbons, typically has higher hydrogen and lower oxygen
content than that of lignit or bituminous coal. The mineral component
of some oil shale deposits is composed of carbonates including
calcite (CaCO3), dolomite (CaCO3 · MgCO3), siderite (FeCO3),

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nahcolite (NaHCO3), dawsonite [NaAl(OH)2CO3], with lesser
amounts of alumino-silicates—such as alum [KAl(SO4)2 12H2O]—
and sulfur, ammonium sulfate, vanadium, zinc, copper, and uranium,
which add by-product value.
Table (1.2) General composition of oil shales
General composition of oil shales
Inorganic matrix Bitumens Kerogens
quartz; feldspars; clays (mainly illite and chlorit
e; carbonates (calciteand dolomite); pyrite and
others
soluble
inCS2
insoluble in CS2;
containing uranium, iron, vanadium,nickel, molyb
denum, etc.

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Chapter II
Exploration of oil shale
Successful oil shale exploration and development generally
progresses through three basic operational phases include:
2.1 Geological investigation.
2.2 Geophysical investigation.
2.3 Geochemical investigation.
Exploration of oil shale depending on the oil shale deposit;
I- In-situ deposits (under layers)[geological, geophysical,
Palynological and geochemical investigation]
II- Ex-situ deposits (outcrop) [geological, Palynological and
geochemical investigation]

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2.1 Geological investigation: The geological investigation method
depends mainly on remote sensing, aerial and satellite photographs
and the mapping of outcrop rocks and the geologic section.
Fig (2.1) geologic section
2.2 Geophysical investigation: Seismic Reflection Survey is the
most common indirect method used for locating subsurface
structures that may contain oil shale. And well logging.

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 Geophysical characteristics of oil shale. This paper analyzes
log and seismic response characteristics based on the petrologic
characteristics of high organic matter of the oil shale. This constructs
a theoretical base to estimate oil shale.
 Single-well evaluation of oil shale. This paper analyzes the
ΔlogR technique based on the log response characteristics of oil
shale, and constructs the ΔlogR-TOC relational model., we mainly
adopt the method of log-seismic multi-attributes reconstruction to
predict the TOC of single wells.
 Seismic quantitative evaluation of oil shale. In this paper 3-
D seismic data is used. The inversion volume of wave impedance is
obtained through the sequence-log constrained seismic inversion
method and the inversion volume of TOC. The relationship between
TOC and oil yield (measured by the BGMR Fischer Assay method of
Royal Dutch Shell Plc) is used to obtain the inversion volume of oil
yield and realize the quantitative evaluation of oil shale.

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On the basis of above key steps, a technical flowchart for the
quantitative evaluation of oil shale with geophysical technique is
provided, as shown in fig (2.2)
Fig 2.2. Evaluation flowchart of geophysical technique of oil shale.
2.2.1 Seismic characteristics of oil shale
The oil shale Basin has the following seismic sedimentary
characteristics: (1) The oil shale presents the features of higher
frequency, better continuity, and medium-strong amplitude; (2) the
seismic reflection structure of oil shale is parallel to sub parallel
having mainly parallel sedimentation of lacustrine strata in deep

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(Fig. 2.3) illustrates the seismic reflection profile across the wells.
water environments. (Fig. 2.3) illustrates the seismic reflection
profile across the wells. The profile has four groups of strong
reflectors: (1) the seismic event above T2 shows low-frequency and
high-amplitude seismic reflection features. Affected by tectonic fault,
the seismic event has low continuity; (2) the seismic event about
1100 ms of well side shows low-frequency, good-continuity and
high-amplitude seismic reflection features; (3) the seismic event
above T1 shows double-track seismic reflection features with low

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frequency, good continuity, and medium-high amplitude; (4) the
seismic event above T07 corresponds to the maximum transgressive
period, and shows seismic reflection features with high frequency,
medium– high amplitude and good continuity.
Because of seismic resolution constraints, the identification of oil
shale on a regular seismic profile can be conducted based only on the
drilling calibration result. The seismic reflection feature with strong
amplitude is possibly the comprehensive response of the interbedding
of mudstone and oil shale. Accurate calibration of the oil shale on the
seismic profile is difficult; thus, it is identified by using other seismic
methods.
2.2.2 Log characteristics of oil shale
The log response characteristics of oil shale depend mainly on the log
response to organic matter and rock matrix. The oil shale with high
organic matter content has the following characteristics: (1) organic
matter has strong radioactivity, and its natural gamma value is higher

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than that of rock matrix; hence, the oil shale has a high gamma log
value; (2) the organic matter is a non-conducting material and its
occurrence worsens the conducting property of the rock.
Fig (2.4) Log response characteristics of oil shale
Its resistivity is greater than that of rock matrix; thus, the oil shale has
a high resistivity log value; (3) the organic matter is the light-weight
medium that is not conducive to acoustic wave transmission. The
acoustic travel time is greater than that of rock matrix, endowing the
oil shale with a log value of high acoustic travel time log value; (4)
the organic matter has low density and its density is much lower than

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that of rock matrix, so the oil shale has a low-density log value; (5)
the organic matter has low density, and its hydrocarbon content is
considerably higher than that of rock matrix, presenting high-neutron
porosity values. Therefore, the log response of oil shale exhibits the
“four-high and one-low characteristics”: high-natural gamma, high
resistivity, high acoustic travel time, high-neutron porosity, and low
density.
2.2.3 Single-well evaluation of oil shale
I- Analysis of ΔlogR technique
During the logR analysis, three-porosity log curves (acoustic, density
and neutron) generally overlay with the resistivity curve. In this study
area, the natural gamma response and resistivity curve have good
overlay and the oil shale layer has prominent characteristics. Thereby
we take gamma/resistivity as the type of curve overlay for ΔlogR
analysis and assign physical meaning to it. In ΔlogR analysis, the
combination of log curves reflects the lithology of undisturbed

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formation correctly and the overlay of log and resistivity curves
corresponds to the most prominent log response of oil shale. Only
one type of curve cannot be applied blindly. Figure 7 shows the
gamma/resistivity overlay for ΔlogR analysis of oil shale. The natural
gamma response at this well has the most prominent response to oil
shale. Although the density curve exhibits good log response at the
oil shale layer, it is prone to wall collapse.
Fig. 2.5 Analysis of ΔlogR of well
Hence, ΔlogR analysis is carried out through gamma/resistivity
overlay. Assume that the natural gamma response and resistivity
overlay equation for the calculation of ΔlogR is: Δlog R = log10 (R /
Rbaseline ) + 0.02 × (GR −GRbaseline ),

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where ΔlogR is the curve separation measured in logarithmic
resistivity cycles; R, Rbaseline present the resistivity log value and
the baseline of the overlaid resistivity in Ω·m, respectively; GR
GRbaseline denote the gamma log value and the baseline of the
overlaid gamma response in API, respectively; 0.02 is based on the
ratio of 50 API per one resistivity cycle mentioned above, an
empirical parameter. According to the baseline of curve overlay,
GRbaseline is 62.03 API and Rbaseline is 5.02 Ω·m. These are
introduced into equation (1) to obtain ΔlogR curve, combined with
the measured TOC for linear regression analysis (Fig. 2.5) and the
relational model between the TOC and ΔlogR ,
TOC = 7.3211× Δlog R + 0.2771, (2) where TOC is the total organic
carbon content measured in wt%; ΔlogR is the curve separation
measured in logarithmic resistivity cycles; 0.2771 is the baseline
value of TOC. The “0.2771” is very important to compensate the
background value of TOC, and it means that the TOC value is not
zero when the ΔlogR is zero, which can be proved by measuring
TOC from Fig. 8. The TOC and ΔlogR show an apparent positive

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correlation, with a correlation coefficient (R2) of 0.913, indicating
that TOC and ΔlogR have good correlation and TOC can be
predicted by using this relational model.
Fig.2.6. Correlation diagram of
ΔlogR vs. measured TOC
The following two aspects are being paid much attention to during
the application of ΔlogR technique: (1) the log curve is always
influenced by the well environment and cannot reflect the
information on undisturbed formation accurately. The accuracy of the
log response was monitored before application; (2) the baseline of the
ΔlogR method represents non source rocks, and the baseline TOC
value is defined as zero value of TOC. However, the TOC of “non-

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source rock” is not zero, but just lower than the defined value of
source rock. Hence, the background value of the TOC curve
predicted by the ΔlogR method is lower. Generally, a fixed
background value is directly added to compensate the baseline value
of TOC (e.g. equation (2)). However, in practice the background
value may be changed vertically depending on lithology of
formation.
2.2.4 Analysis of log-seismic multi-attributes
Regarding to potential issues in the application of ΔlogR
technique, log seismic multi-attributes are used to predict TOC. By
analyzing the oil shale log and seismic response features, a
comprehensive geophysical response is obtained. In this study the
TOC is predicted by choosing the prominent log seismic attributes
among the response multi-attributes of oil shale. Additional
information regarding the undisturbed formation is incorporated to
lay the foundation for improving the precision of TOC prediction.

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Using log seismic multi-attributes, the TOC from ΔlogR technique is
taken as the target curve and carefully chosen log-seismic multi-
attributes are integrated to obtain the predicted TOC.
The widespread application of the log-seismic multi-attributes
method is limited by data constraints in the study area. However, this
method still presents certain advantages: (1) the introduction of
seismic attributes of the well site that are not influenced by the well
environment to avoid the quality of the log curve to become
influenced by the environmental factor of the well; and (2) the good
usage of the log-seismic multi-attributes to determine that the shale
has better geophysical response, and the adoption of convolution
factor algorithm to predict TOC, so that the predictive result responds
more accurately to the strata information and allows for a vertically
compensated background value of TOC. This conforms to the
vertical geological variations of strata in the TOC.

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2.2.5 Seismic quantitative evaluation of oil shale
2.2.5.1 The log-constrained seismic inversion
Seismic inversion is a common and effective method for
interpreting lithology. No report on the interpretation of oil shale
using the inversion method has been published because the
realization process is subject to numerous constraints, such as the
seismic response and seismic resolution of oil shale.
The marking of seismic geological horizon is taken as the
sequence constraint. The initial inversion model is constructed by
interpolating and extrapolating the log data in the 3-D seismic
volume.
Fig.2.7 Inversion profile
of wave impedance
along a cross section of
wells

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The inversion volume of wave impedance is used to predict the
spatial distribution of oil shale by displaying relatively low velocity
through the adjustment of color marks, continuity and vertical change
in thickness; this does not achieve the target of quantitative
assessment of the spatial distribution of oil shale. To achieve the
seismic quantitative evaluation of oil shale, the quantitative
parameters like TOC and oil yield of oil shale must be predicted.
2.2.5.2 Prediction of the inversion volume of TOC
In combining the TOC curves of single-well obtained through
log-seismic Multi-attributes method and the inversion volume of
seismic inversion, we calculate the relationship between the TOC of
well site and seismic wave impedance from well side, and then use
above relationship to extrapolate from the well to the entire 3-D
study area. Finally we obtained the inversion volume of TOC to
realize the seismic quantitative evaluation of oil shale. Spatial
quantitative evaluation based on the inversion volume of TOC allows

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predicting the spatial distribution of oil shale and also enables the
quantitative evaluation of oil shale quality.
Fig.2.8 Inversion profile of TOC along a cross section of well
The TOC inside the oil shale layer changes both transversely and
vertically. In this Fig, the curves of well-points are the prediction
TOC of single-well. Comparing the single-well TOC and inversion
TOC of well site shows that the two have good correspondence
which indicates that the seismic method enables the rational
prediction of TOC.

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2.2.5.3 Prediction of the inversion volume of oil yield
Oil yield is a direct parameter for quantitative evaluation of the
oil shale and the inversion volume of oil yield must be obtained for
the seismic quantitative evaluation of oil shale. By determining the
relationship between the TOC and oil yield, the inversion volume of
oil yield is obtained through the inversion volume of TOC. To obtain
the reliable quantitative relationship between the TOC and oil yield,
the data should satisfy the following conditions: (1) to avoid the
influence of tectonic factors on oil shale formation, collecting data
from wells at different positions of the study area is a more favorable
approach; (2) to eliminate model instability resulting from
incomplete rules in the section disclosed by the data, collecting data
from the continuously cored well is a better technique.
OY = 0.8015×TOC −0.6645
Where OY is the oil yield measured in wt% and TOC is the total
organic carbon measured in wt%.

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Fig.2.9 Correlation diagram of TOC vs. oil yield
Shows a good linear relationship between the TOC and oil yield, and
the correlation (R2) is as high as 0.968. When the TOC is 5.0 wt%,
the oil yield is about 3.5 wt%. Hence, OY>3.5 wt% and TOC >5.0
wt% are taken as the criteria for the quantitative evaluation of oil
shale.

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Fig.2.10 Inversion profile of oil yield along a cross section
The inversion profile of oil yield the black layer is the section with an
oil yield greater than 3.5 wt%. It can be directly and quantitatively
assessed as oil shale. The spatial distribution of oil shale has features
similar to the inversion result for the wave impedance and TOC. It is
continuous in trans-verse extension and has the distribution features
of multi-layers at the vertical direction. The inversion results of oil
yield can provide more accurate evaluation. The oil yield curve of
well and inversion oil yield of well site show better consistency;
hence, the inversion result for oil yield is quite rational.

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Fig.2.11 3-D diagram for spatial quantitative evaluation of oil shale
This figure show the 3-D diagram for the spatial quantitative
evaluation of oil shale the layer with oil yield greater than 3.5 wt% is
marked as the oil shale. According to the evaluation result, the
spatial distribution of oil shale has multi-layers and good continuity.
However, the spatial distribution varies among different oil shale

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layers. Indicates that continuity, oil yield, quality, horizontal and
vertical distribution. The higher value of oil yield in transverse
upward inversion appears at the edges of basin with smaller
variations and faults in the secondary tectonic unit. The inversion
result for oil yield enables quantitative evaluation not only of the
spatial distribution of oil shale, but also of the grade of oil shale.

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2.3 Geochemical exploration: Evaluate and compare petroleum
yield from pyrolysis methods
2.3.1 Rock Eval pyrolysis
2.3.2 Fischer Assay
2.3.3 Hydrous Pyrolysis Oil Yields

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2.3.1 Rock Eval pyrolysis: heating of organic matter in the
absence of oxygen to yield organic compounds,
• Programmed Pyrolysis: – Pulverized samples are gradually
heated under an inert atmosphere – Heating distills the free organic
compounds (bitumen), and then cracks pyrolyti products from the
insoluble organic matter (kerogen).
Pyrolysis to measure:
• Hydrocarbon Content – S1
• Remaining Hydrocarbon Generation Potential – S2
• Organic richness – TOC
• Maturation, type, environment
• Thermal Maturity – Tmax

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2.3.2 Fisher Assay (fig2.14): The Fischer assay is a standardize
laboratory test for determining the oil yield from oil shale to be
expected from a conventional shale oil extraction. A 100 gram oil
shale sample crushed to <2.38 mm is heated in a small aluminum
retort to 500 °C (930 °F) at a rate of 12°C/min (22°F/min), and held
at that temperature for 40 minutes. The distilled vapors of oil, gas,
and water are passed through a condenser
and cooled with ice water into a
graduated centrifuge tube. The oil yields
achieved by other technologies are often
reported as a percentage of the Fischer
Assay oil yield.
Oil product yield and composition is
comparable to surface retorting methods.
Fig 2.14

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2.3.4 Hydrous Pyrolysis
Heating in the presence of liquid water
 Estimating yield from TOC is not optimal, Rock Eval S2 and Fischer
Assay yields are comparable

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Chapter III
Extraction of oil shale
Fig 3.1 oil shale extraction
3.1 Ex-Situ Processing:
Oil shale is crushed into smaller pieces, increasing surface area for
better extraction. The temperature at which decomposition of oil shale
occurs depends on the time-scale of the process.

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In ex situ retorting processes, it begins at 300 °C (570 °F) and
proceeds more rapidly and completely at higher temperatures. The
amount of oil produced is the highest when the temperature ranges
between 480 and 520 °C (900 and 970 °F). The ratio of oil shale gas
to shale oil generally increases along with retorting temperatures.
Hydrogenation and thermal dissolution (reactive fluid processes)
extract the oil using hydrogen donors, solvents, or a combination of
these. Thermal dissolution involves the application of solvents at
elevated temperatures and pressures, increasing oil output
by cracking the dissolved organic matter. Different methods produce
shale oil with different properties.
In ex situ processing, also known as above-ground retorting, the
oil shale is mined either underground or at the surface and then
transported to a processing facility. In contrast, in situ processing
converts the kerogen while it is still in the form of an oil shale

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deposit, following which it is then extracted via oil wells, where it
rises in the same way as conventional crude oil. Unlike ex
situ processing, it does not involve mining or spent oil shale disposal
aboveground as spent oil shale stays underground.
By heating method: The method of transferring heat from
combustion products to the oil shale may be classified as direct or
indirect. While methods that allow combustion products to contact
the oil shale within the retort are classified as direct, methods that
burn materials external to the retort to heat another material that
contacts the oil shale are described as indirect
Fig 3.2 oil shale retorting

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3.2 Ex situ technologies
"Ex-situ" technologies are sometimes classified as vertical or
horizontal. Vertical retorts are usually shaft kilns where a bed of
shale moves from top to bottom by gravity. Horizontal retorts are
usually horizontal rotating drums or screws where shale moves from
one end to the other. As a general rule, vertical retorts process lumps
using a gas heat carrier, while horizontal retorts process fines using
solid heat carrier.
Fig 3.4 Ex situ technologies
The spent shale from the separation processes could be used in
road filling or it could be returned to the mine area.

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3.2.1 Internal combustion
Internal combustion technologies burn materials (typically char
and oil shale gas) within a vertical shaft retort to supply heat for
pyrolysis. Typically raw oil shale particles between 12 millimeters
(0.5 in) and 75 millimeters (3.0 in) in size are fed into the top of the
retort and are heated by the rising hot gases, which pass through the
descending oil shale, thereby causing decomposition of the kerogen
at about 500 °C (932 °F) . Shale oil mist evolved gases and cooled
combustion gases are removed from the top of the retort then moved
to separation equipment. Condensed shale oil is collected, while non-
condensable gas is recycled and used to carry heat up the retort. In
the lower part of the retort, air is injected for the combustion which
heats the spent oil shale and gases to between 700 °C (1,292 °F) and
900 °C (1,650 °F). Cold recycled gas may enter the bottom of the
retort to cool the shale ash. The Union A and Superior Direct

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processes depart from this pattern. In the Union A process, oil shale
is fed through the bottom of the retort and a pump moves it upward.
In the Superior Direct process, oil shale is processed in a horizontal,
segmented, doughnut-shaped traveling-grate retort.
3.2.2 Hot recycled solids
Hot recycled solids technologies deliver heat to the oil shale by
recycling hot solid particles—typically oil shale ash. These technologies
usually employ rotating kiln or fluidized bed retorts, fed by fine oil shale
particles generally having a diameter of less than 10 millimeters (0.4 in);
some technologies use particles even smaller than 2.5 millimeters
(0.10 in). The recycled particles are heated in a separate chamber or
vessel to about 800 °C (1,470 °F) and then mixed with the raw oil shale
to cause the shale to decompose at about 500 °C (932 °F). Oil vapor and
shale oil gas are separated from the solids and cooled to condense and
collect the oil. Heat recovered from the combustion gases and shale ash

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may be used to dry and preheat the raw oil shale before it is mixed
with the hot recycle solids.
In the Galoter and Enefit processes, the spent oil shale is burnt in a
separate furnace and the resulting hot ash is separated from the
combustion gas and mixed with oil shale particles in a rotating kiln.
Combustion gases from the furnace are used to dry the oil shale in a dryer
before mixing with hot ash. The TOSCO II process uses ceramic balls
instead of shale ash as the hot recycled solids. The distinguishing feature
of the Alberta Taciuk Process (ATP) is that the entire process occurs in a
single rotating multi–chamber horizontal vessel.
Fig 3.5 Alberta Taciuk Process (ATP)

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3.23 Conduction through a wall
These technologies transfer heat to the oil shale by conducting it
through the retort wall. The shale feed usually consists of fine particles.
Their advantage lies in the fact that retort vapors are not combined with
combustion exhaust. The Combustion Resources process uses a
hydrogen–fired rotating kiln, where hot gas is circulated through an
outer annulus. The Oil-Tech staged electrically heated retort consists of
individual inter-connected heating chambers, stacked atop each other. Its
principal advantage lies in its modular design, which enhances its
portability and adaptability.
3.3 In-situ processing
In situ processing converts the kerogen while it is still in the form of
an oil shale deposit, following which it is then extracted via oil wells,
where it rises in the same way as conventional crude oil unlike ex
situ processing, it does not involve mining or spent oil shale disposal
aboveground as spent oil shale stays underground.

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3.4 In-Situ Technologies:
3.4.1 Shell In Situ Conversion Process (ICP).
3.4.2 American Shale Oil Process.
3.4.1 Shell In Situ Conversion Process (ICP)
• Deep vertical holes are drilled through a section of oil shale.
• Heating underground oil shale using electric heaters placed in the
deep vertical holes.
• The entire oil shale is heated over a period of two to three years
until it reaches 650–700 °F (340 and 370 °C).
Fig 3.6 Shell In Situ Conversion Process
(ICP)

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3.4.2 American Shale Oil Process Conduction, Convection,
Reflux (CCR) Process
• Horizontal wells are drilled beneath the oil shale layer.
• Superheated steam or another heat transfer medium is circulated through the
horizontal pipes
• As the organic matter within the rocks boils, it will break the rocks apart and
free the oil and gas to be collected.
Fig 3.7 (CCR) Process

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Chapter IV
Evaluation of Oil-Shale Resources, production
Fig4.1 global oil shale sources
Resource Estimates Vary in Quality
Fig 4.2 quality
of oil shale

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How Much Has Been Produced (Fig 4.3)
Fig 4.3
4.2Projected Global Oil Shale Production (Fig 4.4)
Fig 4.4

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How Aggressively Can it Grow? (Fig 4.5)
Fig 4.5 Grow carve with year of oil shale

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4.3 oil shale in Egypt
Oil shale was discovered in 1940s during phosphate mining (Fig 4.6)
Researches in 1970s showed that Egypt has plenty of Oil shale with shale oil
reserves at:
• Western Desert: Abu Tartor
• Eastern Desert: Red Sea (Quiser , Safaga)
• Nile of valley: Edfu
Safaga
Quiser
Abu Tartor Area
Edfu

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Evaluation and Analysis of Oil Shale in Quseir-Safaga eastern Desert,
Egypt:
Qusier phosphate mine in the Red Sea coast (Cretaceous -
Eocene) The Qusier and Safaga areas are part of the Eastern Desert of
Egypt at the Red Sea Coast, and gained importance since five decades
when the phosphate deposits of the Gebel Duwi RangeDuwi
Formation U. Campanian - L. Maastrichtian.
Geological settings of the Duwi Formation:
The Precambrian granite and metamorphic rocks (gneiss, schist)
compose the basement complex in Egypt. They form a rough terrain
at the Eastern Desert of Egypt along the Red Sea coast and Sinai.
The Upper Cretaceous to Lower Cenozoic sedimentary rocks cover
the basement complex in some areas.
The Duwi Formation is a part of the Upper Cretaceous– Lower
Cenozoic sedimentary sequence and is widely distributed in the

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Eastern Desert, Nile Valley and Western Desert areas. The Duwi
Formation unconformably overlies the fluvial shale sequence of the
mid Campanian Qusseir Formation, and conformably underlies the
deep marine shales and marls of themid Maastrichtian Dakhla
Formation. Thus, deposition of the Duwi Formation represents an
initial stage of the Late Cretaceous marine transgression in Egypt.
The Gebel Duwi region extends in a northwest direction along the
western coast of the Red Sea from south of Al-Qusseir to Safaga,
between latitude 25500 and 26670N and longitude 33450 and
34250E, covering an area of about 500 km2
The general lithological compositions of the Duwi Formation
The Duwi Formation is usually subdivided into three members by
Said and Temraz .In, Said extended the use of the term Duwi
Formation to laminated gray clays and chert phosphatic bands at
Safaga and subdivided the whole section in the Red Sea area into

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three members, which are Atshan or ‘‘A’’, middle Duwi or ‘‘B’’
member and lower Abu Shegela or ‘‘C’’ member. The Atshan or
‘‘A’’ member is separated from the middle Duwi or ‘‘B’’ member by
an Oyster limestone bed 6–16 m in thickness; while the lower Abu
Shegela, or ‘‘C’’ member, is separated from the middle member by a
shale unit of variable thickness (6–10 m). In the present time, the
Duwi Formation is subdivided into four members, which are the
lower, the middle, the upper and the uppermost members by Baioumy
and Tada and Baioumy et al. The oil shale beds are concentrated in
the Atshan or ‘‘A’’ and middle Duwi or ‘‘B’’ members.

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Fig 4.7 Image showing the locations of the mines where the studied
materials were collected.

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Table 4.1 Guidelines for pyrolysis parameters of quality, quantity and thermal maturity (adapted and
modified after both Tyson, Peters and Cassa .
Table 4.2 Geochemical parameters that measured by the rock eval pyrolysis for the studied oil shale samples. The
sample numbers referred to the palynological samples. The samples without indicative numbers are omitted from
the palynological investigations.

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Geochemical analyses
Fig 4.9 HI versus Tmax diagram (modified from Tyson)
Fig 4.8 Van Krevelen-type diagram
Fig 4.10 Production index versus the Tmax (C)
adapted after, adopted after GeoMark sheet.

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The thermal maturity is shown in Figs. 4.8 – 4.10 respectively. All the
samples that were geochemically analyzed from the different locations varied
between poor and excellent production potential according to the standard
guidelines of Peters and Cassa (Table 4.1). The samples from El-Nakheil
(19.18–22.23 wt%) have the highest TOC values and they are considered as
excellent producers. The samples from El-Beida (11.45–11.61 wt%),
Mohamed Rabah (9.66 wt%) and Wasif (8.39 wt%) are much lower than El-
Nakheil however still excellent producers. The samples from Umm Hueitat
(2.6– 5.18 wt%) have a lower potentiality as it is ranging from very good to
excellent. The samples from Younis mine (0.04– 1.77 wt%) have the lowest
production potentiality of all samples and are considered as poor to good. The
(S1) values are generally low in the samples of Mohamed Rabah (1.30 mg
HC/grock), Wasif (0.10–0.98 mg HC/grock), Umm Hueitat (0.23–0.39 mg
HC/grock) and are mainly related to low maturity of these samples despite
their high content of TOC. Whereas, the sample from Younis (0.14 mg
HC/grock) is mainly related to low maturity of the rock samples and low TOC
Content. The low values of (S1) should reduce production potentiality (S1 +
S2). The values of S1 of the samples from El-Nakheil (4.05–4.18 mg

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HC/grock) and El-Beida (1.97–2.01 mg HC/grock) are relatively high, which
in turn indicate that they are very good to excellent producers. The values of
Hydrogen index (HI) in the samples from El-Nakheil (679–716 mg HC/g
TOC), Mohamed Rabah (603 mg HC/ g TOC) and El-Beida (566 mg HC/g
TOC) indicated high quality oil prone kerogen type I. The other samples are
oil prone as well; however, type II kerogen was detected. Two samples from
Wasif (38 mg HC/g TOC) and Younis (94 mg HC/g TOC) indicated gas prone
type IV kerogen. The measured Tmax (409–427 _C) in all samples indicated
immature kerogens to yield hydrocarbons (Figs. 4.9 and 4.10).
Reserves in Egypt
• Safaga and Quiser
• Contain 9.1 Billion tons
• Geological reserves: 2.3 Billion bbls
• Nile Valley
• Very large amounts compared to Safaga & Quiser

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Chapter V
Introduction of shale gas
Shale gas is defined as unconventional gas that is trapped within
shale formation, usually in organic-rich shale with ultra-low porosity and
permeability. Shale gas is not new, but only recently has it become so
important. The formation and distribution of shale gas were special, and
were characterized by large resources potential and long development
history. Shale gas reservoirs are complicated, including organic rich shale
and interbedded silts. Diversity is obvious among different shale gas
reservoirs. The targets for shale gas exploration are organic-rich shale
that was deposited in such a manner as to preserve a significant fraction.
Shale gas reservoirs are characterized by ultra-low porosity and
permeability, leading to no natural productivity or low productivity.
Large multistage hydraulic fracturing and horizontal well techniques are
needed in economic recovery, leading to a long production period in a
single well.

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5.1 Different between shale gas and natural gas
Conventional and unconventional gases are the same thing in that they
are both natural gas and are chemically the same. Where they differ is in the
geological characteristics of the rocks in which they are found, referred to as
the reservoir rock. Although we might think of a reservoir a continuous body
or pool of fluid (or in this case gas) this is not the case with a gas reservoir
which is made up of small amounts of gas trapped with the spaces between
the fine grains that make up the reservoir rock with the characteristics of the
reservoir rock being determined by its porosity and its permeability.
Figure 5.1: Schematic showing the geometry of conventional and unconventional natural gas
resources Source: U.S. Energy Information Administration

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The growth in maturity of many conventional gas fields and concerns
over declining production has prompted greater investment in the exploration
and exploitation of unconventional gas resources. By combining new drilling
technologies, especially horizontal drilling, with hydraulic fracturing it has
been possible to tap into huge volumes of natural gas within deep seated shale
beds that had previously been considered unrecoverable. The result has been a
significant increase in estimates in natural gas reserves with some estimates
suggesting that unconventional gas may be as, or even more abundant, and
with a much wider geographical distribution than conventional gas sources.
5.2 Types and characteristics of shale gas
Typically, shale types include black shale, carbonaceous shale, siliceous
shale, ferruginous shale, and calcareous shale. When sandy components are
mixed in with shale, it can form sandy shale. According to the size of the sand
grains, sandy shale can be divided into silty shale and sandy shale. Organic-
rich shale is the major rock type for the formation of shale gas, which includes
black shale and carbonaceous shale. Black shale includes large amounts of
organic matter, fine and scattered pyrite, and siderite, where TOC is usually

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3%-15% or more with extremely laminated bedding. Carbonaceous shale
contains large amount of fine and scattered carbonaceous organic matter
(usually TOC is 10%-20%), which is characterized by black color staining
and large amounts of fossil plant. Regardless of the kind of shale, their anti-
weathering capacity is weak, where low mountains and valleys were usually
formed in natural topography
5.3 Basic Characteristics of Shale Gas (Table 5.1 )
Shale gas can be formed when the organic-rich shale is developed and
enters into the gas-generation period in sedimentary basins. Therefore, if gas
source rock is dark organic-rich shale, shale gas can be found in basins with
conventional gas. Only source rock with good quality can form shale gas with
commercial value for development. Based on evaluation of geological
characteristics, potential commercial value for shale gas exploration and
development can be confirmed. Now, shale or core area for commercial
development of shale gas usually refers to the effective shale, where the TOC
is more than 2% in the gas generation window and brittleness mineral content
is over 40%. Requirements for commercial development can be met when the

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thickness of effective shale is more than 30-50m (more than 30 m when
effective shale was continuously developed, cumulative thickness is more
than 50 m when effective shale was discontinuously developed or TOC was
less than 2%). The minimum effective thickness of gas-generation shale in
North America is 6 m (Fayetteville), and the maximum is 304 m (Marcellus).
Effective thickness of shale in the core areas is more than 30 m. Based on the
exploration and development of shale gas in North American, statistical
analysis, and critical experiments, it can be concluded that favorable shale gas
and core area are characterized by following geological and development
characteristics.
Table 5.1

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5.4 CHARACTERISTICS OF SHALE RESERVOIR
Shale is the source rock, and also the reservoir, formed by the typical
mechanism of “in-situ saturation reservoiring.” During the biochemical gas
generation phase, natural gas or oil cracking gas initially adsorbed on the
organic matter or rock grain surface or accumulated within the organic pore
space and stayed there until saturation. Then, the oversaturated natural gas
experienced primary migration in free phase or dissolved phase to the pore
space of the overlying inorganic shale interval. Part of it will be stored within
the intergranular and intragranular pores or fractures in free phase. After re-
saturation, part of the natural gas will be migrated to conventional reservoir
rock through secondary migration and will form a conventional gas reservoir.
Fig 5.2 shale gas reservoir

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Chapter VI
Shale gas exploration
Exploration stage: finding depth, thickness and areal extent of promising
shale. Structural and stratigraphic interpretation of seismic data Assessment of
source potential: finding effective source rock. Geochemical,
sedimentological, log evaluation and basin modelling methods. The factors
which make good source rocks (TOC, maturity etc.) also influence the seismic
response and hence can be inferred from seismic attributes.
6.1 GEOLOGICAL EVALUATION TECHNIQUE
The objective of geological evaluation for shale gas is to optimize
favorable accumulation area. Except for the conventional methods (such as
the geological survey, geophysical exploration, drilling of parameter wells,
analysis, and testing), the core is to gain key parameters (such as buried depth
of shale, thickness, rock texture, mineral composition, rock physical
properties, organic geochemistry, geophysics, well drilling, and fracturing) to
make fundamental maps. According to regional geological characteristics,

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each geological evaluation standard can be confirmed to identify, evaluate,
and optimize favorable areas synthetically
6.2 RESERVOIR EVALUATION TECHNIQUE
Reservoir evaluation seeks to describe the spatial distribution
characteristics of shale reservoir both qualitatively and quantitatively and to
simulate the storage and production status of gas in shale. Five major steps are
included in the evaluation flow : (1) Carry out analysis on the physical
properties of cores, basic parameters of geochemistry, rock mineral
composition, and the like in key wells; (2) carry out gas desorption and
adsorption tests of cores in the field and calculate the isothermal adsorption
curves to gain the adsorbed capacity of shale in theory, which can determine
the gas saturation to calculate the content of adsorbed gas; (3) based on well
logging curves (calibrated by core data), an interpretation model can be
established via a core-logging comparison to gain gas saturation, water
saturation, oil saturation, porosity, organic matter abundance, rock types, and
so on; (4) boundaries of gas-bearing shale can be confirmed by sedimentary
facies, characteristics of rock assembly, and interpretation results of well

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logging; (5) economical evaluation can be carried out by 3D seismic data and
various parameters (such as original oil/gas in place, mineral composition,
fluid saturation, relative proportion between adsorbed gas and free gas, buried
depth, temperature, and pressure) to optimize exploration targets and to
determine the distribution scales of “sweet spots.”
6.2.1 Seismic evaluation
The shale gas presents the features of higher frequency, better continuity,
and medium-strong amplitude; (2) the seismic reflection structure of shale gas
is parallel to subparallel having mainly parallel sedimentation.
Fig 6.1 seismic response character

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Seismic sections showing signature of shale layers. a. Thick shales with thin
coal, limestone, silt etc. b. thin shales interbedded with coal, limestone,
sandstone etc. Both sections are flattened at upper sequence boundary.
6.2.2 LOGGING EVALUATION TECHNIQUES
Compared to normal shale, gas-bearing shale is characterized by enriched
organic matter and high gas-bearing
amounts. The development of clay and
organic matters decreases the formation
bulk density. So, the response of gas-
bearing shale in well-logging curves is
characterized by four high and two low
(high GR, high resistivity, high AC,
high neutron porosity, low density
logging, and low photoelectric effect
6.2

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6.2.3 EXPERIMENTAL ANALYSIS TECHNIQUE
Geochemical analysis of gas shale included the following: TOC
content of cores and debris samples;
Rock Eval pyrolysis analysis of cores and debris: measurement
of S1, S2, HI, Tmax; measurement of vitrinite reflectance (Ro) in
cores and debris; analysis on composition and carbon isotope of gas
samples. Testing of gas-bearing amount: First, seal the shale rock
samples in the metal desorption tank; and then heat it to the
formation temperature in a water bath to test the total gas-bearing
amount of the core.
Isotope Geochemistry: Genetic origin of natural gases and Thermal
maturity of natural gases: Maturity of source material, Onset of low-maturity
and high-maturity thermogenic gas generation, Recognition of gas leakage
and gas destruction (“preservation basement”) .Correlation of natural gases
with their sources.

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Chapter VII
Shale gas extraction
The fracturing treatment technique for the shale reservoir can improve the
production of shale gas substantially, which plays a determinative role in
commercial development of shale gas. Fracturing treatment techniques for the
shale reservoir mainly include foam fracturing and hydraulic fracturing
(including repetitive fracturing, multistage continuous tube fracturing, sliding
sleeve completion, and hydro jet fracturing and anhydrous fracturing [N2 and
CO2, liquefied oil and gas].).
An important characteristic of well production for shale gas is that it can
perform repetitive fracturing many times. Generally, after the primary
fracturing, open fractures, which were sustained by proppant, will gradually
close along with the time lapse and pressure release, leading to production
decrease to a large extent. Production can be recovered through repetitive
fracturing, where production after the second fracturing can be close to or
even over the production of primary fracturing. The recovery ratio, which is
estimated after the primary well completion, is usually about 10%. However,

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the recovery ratio can increase by 8%e10% after repetitive fracturing, and the
recoverable reserve can increase by 60%.
Fig 7.1 shale gas extraction

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Chapter VIII
8.1 Evaluation of Shale-Gas Resources, production (fig 8.1)
Fig 8.1
8.2 Shale Gas in EGYPT
Egypt has four basins in the western Desert with potential for shale gas
and shale oil Abu Gharadig, Alamein, Natrun and shoshan-Matruh fig 8.2 The
target horizon is the organic-rich Khatatba shale, sometimes referred to as the
kabrit shale or safa shale, within the large Middle Jurassic Khataba
Formation.

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Reserves in Egypt
 Approximately 535 Tcf of Shale Gas in-place
 Expected Recovery Factor is 20%
 Recoverable Shale Gas is approximately100 Tcf

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