Extracting the Shales

1 Extracting the Shales
A SEMINAR REPORT
ON
Extracting the Shales
Submitted to
The M.S. University of Baroda
in partial fulfillment for the degree of Bachelor of Engineering
in Chemical Engineering
Prepared By: Guided By:
Vismay Harani Dr. K.S. Agrawal
2013-14
DEPARTMENT OF CHEMICAL ENGINEERING
FACULTY OF TECHNOLOGY AND ENGINEERING
THE MAHARAJA SAYAJIRAO UNIVERSITY
OF BARODA

DEPARTMENT OF CHEMICAL ENGINEERING
FACULTY OF TECHNOLOGY AND ENGINEERING
THE MAHARAJA SAYAJIRAO UNIVERSITY
OF BARODA
CERTIFICATE
Certified that the seminar work entitled ‘Extracting the Shales’ is a bonafide
work carried out in final year by Vismay Harani (Roll No. 804) in partial
fulfillment for the award of Bachelors of Engineering in Chemical Engineering
from the Maharaja Sayajirao University of Baroda during the academic year 2013-
2014, who carried out the seminar work under guidance and no part of this work
has been submitted earlier for the award of any degree.
Guide Head of Department
Dr. K.S. AGRAWAL Dr. BINA SENGUPTA

ACKNOWLEDGEMENT
I express my deepest gratitude to my respected guide Dr. K.S. AGRAWAL, for
his valuable guidance, constructive criticism and constant encouragement right
from the start to the completion of this seminar. Not only that, he provided me the
freedom to explore in the direction I wanted to, intervening only when I was
digressing from the topic. Without his valuable insights, this seminar report might
have been incomplete.
I would also like to express my sincere thanks to Head of the Department of
Chemical Engineering, Dr. BINA SENGUPTA for granting me the permission to
do work on this topic.
Presented By:
Mr. Vismay Harani,
B.E. IV Chemical

CONTENTS
CHAPTER
nO
TITLE PAGE NO.
1. INTRODUCTION 7
1.1 INDIAN ENERGY SCENARIO 7
1.2 SHALE OIL AND GAS: A VIABLE ALTERNATIVE 8
2. SHALES 9
2.1 ORIGIN OF PETROLEUM 9
2.2 FORMATION CHEMISTRY 9-10
2.3 OIL SHALES AND OIL/GAS BEARING SHALES 11-12
3. FRACKING 13
3.1 HYDRAULIC FRACKING 13
3.2 TYPE OF WELLS 14-16
3.3 FRACTURING FLUIDS 16-18
3.4 ENVIRONMENTAL IMPACT 17-18
3.5 HEALTH EFFECT 18
3.6 MINOR EARTH QUAKES 18-19
3.7 FRACKING WASTE WATER MANAGEMENT 19-21
3.8 NON-HYDRAULIC FRACKING 22
4. RETORTING 23
4.1 KEROGEN 23-24
4.2 RETORTING 24
4.3 SURFACE RETORTING 25-30
4.4 IN-SITU RETORTING 30-41
4.5 SHALE OIL UPGRADING 41
4.6 TRANSFORMING SHALE OIL INTO SYNTHETIC CRUDE 42
4.7 POLLUTION 42
5 INDIA’S SHALE SCENARIO 43
5.1 SHALE GAS 43
5.2 OIL SHALE 43
6. BIBLIOGRAPHY 44-46

LIST OF FIGURES
NO. TITLE PAGE NO.
1.1 INDIA’S ENERGY SCENARIO 7
2.1 FORMATION CHEMISTRY 10
2.2 GAS BEARING SHALE 11
2.3 OIL BEARING SHALE 11
2.4 OIL SHALE 12
3.1 HORIZONTAL AND VERTICAL WELL 14
3.2 DIAGRAM OF A TYPICAL WELL 15
3.3 HYDROFRACKING DETAILS 19
4.1 MAJOR STEPS IN SURFACE RETORTING 25
4.2 INTERNAL COMBUSTION 26
4.3 HOT RECYCLED SOLIDS: ALBERTA TACIUK PROCESS 27
4.4 IMPROVED IN-SITU RETORTING 35
4.5 MAJOR STEPS IN THERMALLY CONDUCTIVE IN-SITU
CONVERSION
36
4.6 SHELL IN-SITU CONVERSION PROCESS 37
4.7 TEMPERATURE PROFILE CURVES 38
4.8 TWO DIMENSIONAL TEMPERATURE PROFILE 39
4.9 SCHEMATIC DIAGRAM OF SHALE OIL PURIFICATION 41
4.10 TREATING SHALE OIL 42
5.1 INDIA’S SHALE SCENARIO 43

LIST OF TABLES
NO. TITLE PAGE NO.
4.1 TYPE OF KEROGEN AND THEIR HYDROCARBON POTENTIAL 23
4.2 UPGRADING CHALLENGES 41

Abstract
The recent sanctions on Iran had put India in a tight spot. We couldn’t import Oil from Iran and
this had put the Indian economy in dire straits. We must realize that this dependence on foreign
countries for our energy needs is not a viable option in a long term and hence we must try to
explore unconventional energy sources like Shale Gas and Shale Oil which has a potential to
partially address this problem.
Hence, the present seminar report is a humble attempt to shed light on the two processes
involved in the Extraction of Shales: Retorting and Fracking. These two extraction processes are
drastically different from the conventional oil/gas extraction process. And shale gas can
definitely become a viable alternative for the conventional natural gas in near future.
U.S. and China are furiously exploring the Shales. Recently ONGC has extracted shale gas for
the first time in this country at a pilot plant in Jambusar near Vadodara. Hence this Seminar
Topic is very relevant for today’s Chemical Engineer for future growth prospect.

Chapter 1: Introduction
Vadodara: ONGC had drilled the first well in Jambusar in the last week of October in 2013 to
exploit the natural gas trapped within the shale formations located in Cambay basin, which is
estimated to have a shale gas potential of 20 TCF (trillion cubic feet)," G C Katiyar, who took
over as the Basin Manager of Western Onshore Basin of ONGC (headquartered in Vadodara),
told PTI today. (The Economic Times, 2014)27
1.1 Indian Energy Scenario
Currently, India imports about 75% of conventional crude. During 2011-12 country imported 171.73
MMT crude oil while the production during 2011-12 at 38.09 million metric tons (CSO, 2013)17
. Most of
this comes from the Middle East. Figure (a) shows India’s production and imports of petroleum
products over the period 1975 – 2010 and Figure (b) India’s import from various sources in 2007.
Figure (a) Figure (b)
FIGURE 1.1: INDIA’S ENERGY SCENARIO (Olowonirejuaro, 2010)1
 Out of the total electricity production, 65.8% comes from thermal power plants, 26.3%
from hydroelectricity and only 3.1% from nuclear power. Non-conventional, renewable
energy sources like solar, wind energy constitutes nearly 4.9%
 In commercial energy consumption, coal constitutes 29%, Oil and gas 54% and
electricity 17%
 At the current rate of consumption, coal reserves would last for about 130 years and oil
for about 20-25 years (Abhyankar, 2006)32

1.2 Shale Oil& Gas: A Viable Alternative
1.2.1 History
Small scale oil shale industries developed in Europe in the 19th
Century and have operated at
various times in parts of Europe, Africa, Asia, and Australia. China has operated an oil shale
plant for a number of years producing approximately 40,000 barrels of oil per day. Shale has
been burned directly as a solid fuel for domestic purposes and small industrial operations.
Estonia has used oil shale in solid form for fuel for electric power generation. The raw shale is
simply shoveled into furnaces. Oil shale operations in Sweden and Scotland, each producing 500
to 700 thousand barrels per year, were closed in 1962 (Youngquist, 1998)6
.
1.2.2 American Shale Oil and Gas Industry
The potential of oil shale is enormous. While found throughout the world, nearly 62 percent of
the world's potentially recoverable oil shale resource are concentrated in the United States. The
largest of the U. S. oil shale deposits is found in the 16,500 square-mile Green River formation in
northwestern Colorado, northeastern Utah, and southwestern Wyoming. The deposits are
estimated to contain 562 billion barrels of recoverable oil. This is more than 64 percent of the
world's total proven crude oil reserves.
90% of the World’s shale gas is currently produced by USA. Shale gas accounted for 39% of
total natural gas production in 2012. With 25.7 cubic feet per day, it makes U.S.A. the largest
producer of shale gas. This boom is mainly due to three factors which has made shale gas
production highly attractive:-
 Advancements in Horizontal Drilling Technology
 Advancements in Hydraulic Fracturing Technology
 A surge in natural gas prices due to increasing demand
Canada obtains 15% of natural gas from shale oil whereas China holds the world’s largest
potentially recoverable reserves of shale gas with estimated reserves of 1,115 trillion cubic feet
versus 665 trillion cubic feet for the US (Youngquist, 1998) 6
.

Chapter 2: Shales
2.1 Origin of Petroleum
Petroleum is theorized to have originated in the following manner (Speight, 2006)23
:-
 Petroleum is a naturally occurring hydrocarbon mixture, which is obtained as a product of
compression and heating of decayed remains of prehistoric marine life and terrestrial
plants by the action of bacteria.
 Over many centuries this organic matter mixed with mud, is buried under thick
sedimentary layers of material.
 The resulting high levels of heat and pressure cause these remains to metamorphose, first
into a waxy material known as kerogen(thought to be source rock), and then into liquid
and gaseous hydrocarbons in the process known as Catagenesis.
 These then migrate to adjacent rock layers until they become trapped underground in
porous rocks called reservoirs, forming an oil field, from which the liquid can be
extracted by drilling and pumping.
 These reactions are very temperature sensitive: reactions that produce recognizable oil
(conventional crude) commence at about 1308 0
C.
 Further breakdown of oil to natural gas commence at about 1808 0
C.
 The reactions that produce oil and natural gas are often modeled as first-order breakdown
reactions, where kerogen breaks down to oil and natural gas by a large set of parallel
reactions, and oil eventually breaks down to natural gas by another set of reactions.
2.2 Formation Chemistry
2.2.1 Diagenesis
Diagenesis is used to form kerogen. It is a process of compaction under mild conditions of
temperature and pressure. When organic aquatic sediments (proteins, lipids, carbohydrates) are
deposited, they are very saturated with water and rich in minerals.

Through chemical action, compaction and microbial action during burial, water is forced out and
proteins and carbohydrates break down to form new structures that comprise a waxy material
called “kerogen” and bitumen. This occurs at first several hundred meters of burial. The kerogen
will undergo further changes to make hydrocarbons (Fuel Chemistry Division) 29
.
2.2.2 Catagenesis
It is a CRACKING reaction which converts kerogen into liquid and gaseous hydrocarbon at
higher temperature and pressure (at greater depths). Now this process is catalyzed by the
minerals that are deposited.
Higher the temperature, more complete cracking would take place. But in order to produce more
liquid crude, one requires an oil window of 1308 0
C to 1508 0
C. If the temperature is still higher,
it would favor the production of natural gas (1808 0
C). But if it is too cold, oil would remain
trapped within kerogen (Fuel Chemistry Division) 29
.
Figure 2.1 gives the schematic representation of the Formation Chemistry:-
FIGURE 2.1: FORMATION CHEMISTRY (Fuel Chemistry Division)29

2.3 Oil Shales and Oil/Gas bearing shales
Shales are the rocks through which fuel with similar composition that of conventional crude and
natural gas are obtained by unconventional processes. There are 3 types of energy deposits with
very similar names, which are easy to confuse. Yet, these three types of shales are vastly
different in their physical properties, their commercial value and method to extract them. One is
a liquid, one is a gas and other is a solid (OSTSEIC, 2012)31
2.3.1 Gas Bearing Shale
 Black organic shales are the source rock for most
of the oil and gas reservoir, as shown in Fig. 2.2
 Much of the Shale Gas is obtained from these
rocks
 Shale gas is nothing but Natural Gas obtained
from unconventional means
FIGURE 2.2 GAS BEARING SHALE (OSTSEIC, 2012) 31
 Unlike Conventional Natural Gas, the gas bearing Shales are not porous
 Gas is obtained from these rocks by Hydraulic Fracking/ (fracturing + cracking)
 Shale gas is a commercially viable venture that is spreading throughout the world. It can
be developed using vertical or horizontal drilling techniques, followed by hydraulic
fracturing of the surrounding rock formations
2.3.2 Oil Bearing Shale
 Shale oil can be trapped within tight, impervious rock
formations like the one shown in Figure 2.3
 It differs from the conventional crude only in that conventional
crude is found in porous rock formation where it can easily flow
FIGURE 2.3: OIL BEARING SHALE (COGA, 2013)16

to a well, and shale oil is found in non-porous rock which cannot flow unless cracked
open by hydraulic fracturing
 Shale oil can be brought to the surface by horizontal or vertical drilling techniques,
followed by hydraulic fracturing of the surrounding rock formation
 This process is economically feasible at today’s oil prices and significant amount of oil is
being produced by this method
2.3.3 Oil Shale
 The term oil shale generally refers to any sedimentary rock (Figure 2.4) that
contains kerogen
 Over long periods of time, heat and
pressure transformed the materials into
oil shale in a process similar to the
process that forms oil; however, the
heat and pressure were not as great
FIGURE 2.4 OIL SHALE (OSTSEIC, 2012)31
 It is possible to liquefy kerogen through an energy intensive heating or conversion
process called RETORTING
 Further upgrading and refining can turn liquefied kerogen into synthetic petroleum
 If a drilling rig were to drill and frack oil shale deposits, as done for gas/oil bearing
shales, it would not produce any liquid fuel at all. It must be either mined from the
underground and heated on the surface, or heated underground and pumped to the surface
 It is not commercially viable, currently

Chapter 3: Fracking
This process is primarily used for extraction of Shale Gas & Shale oil by gas bearing and oil
bearing shales. Hydraulic fracturing or “fracking” is a technique that uses fluid, usually water,
pumped at high pressure into the rock to create narrow fractures (less than 1 mm) to create paths
for the gas to flow into the well bore and to surface. The water normally contains small quantities
of other substances to improve the efficiency of the process, e.g. to reduce friction. Once the
fractures have been created, small particles, usually of sand, are pumped into them to keep the
fractures open (King, 2012)20
.
The process of preparing any oil or gas well for production involve the use of small shaped
charges to “perforate” the steel tubing used to control the flow of fluids. The perforations are
very precisely designed and do not propagate into the surrounding rock. In a shale gas well, it is
the water pressure applied in the subsequent fracking operation which causes the rock to fracture.
3.1 Hydraulic Fracking
The technique of hydraulic fracturing is used to increase the rate at which fluids, such as
petroleum or natural gas can be recovered from subterranean natural reservoirs from shales.
Hydraulic fracturing enables the production of natural gas and oil from rock formations deep
below the earth's surface (generally 5,000–20,000 feet (1,500–6,100 m)), which is typically
greatly below groundwater reservoirs of basins if present. At such depth, there may not be
sufficient permeability or reservoir pressure to allow natural gas and oil to flow from the rock
into the wellbore at economic rates.
Creating conductive fractures in the rock is pivotal to extract gas from shale reservoirs because
of the extremely low natural permeability of shale, which is measured in the microdarcy to
nanodarcy range. The yield for a typical shale gas well generally falls off after the first year or
two, although the full producing life of a well can last several decades. (King, 2012) 20

3.2 Type of Wells
There are two type of wells associated with fracking, as shown in Figure 3.1:-
 Vertical Well
 Horizontal Well
FIGURE 3.1 HORIZONTAL AND VERTICAL WELL (AWWA, 2013)10
Horizontal drilling is a drilling process in which the well is turned horizontally at depth. It is
normally used to extract energy from a source that itself runs horizontally, such as a layer of
shale rock.
Since the horizontal section of a well is at great depth, it must include a vertical part as
well. Thus, a horizontal well resembles and exaggerated letter “J.” When examining the
differences between vertical wells and horizontal wells, it is easy to see that a horizontal well is
able to reach a much wider area of rock and the natural gas that is trapped within the rock. Thus,
a drilling company using the horizontal technique can reach more energy with fewer wells
(IEER, 2013)30
.

A horizontal well accesses thickness of the bed 1500-10000 feet whereas the vertical well can
only access 50-300 feet of rock layer. Hence fewer wells are needed in horizontal drilling to get
more oil.
In the Figure 3.1, there is a vertically drilled well and a horizontally drilled well. Vertically
drilled wells are only able to access the natural gas that immediately surrounds the end of the
well. Horizontal wells are able to access the natural gas surrounding the entire portion of the
horizontally drilled section.
As you can imagine, drilling a horizontal well is a more complicated process that drilling a
conventional vertical well. The driller must first determine the depth of the energy-rich
layer. That is done by drilling a conventional vertical well (Figure 3.2), and analyzing the rock
fragments that appear at the surface from each depth (IEER, 2013) 30
.
FIGURE 3.2: DIAGRAM OF A TYPICAL WELL (IEER, 2003) 30

Once the depth of the shale is determined, the driller withdraws the drilling assembly, and then
inserts a special bit assembly into the ground that allows the driller to keep track of its vertical
and horizontal location.
The driller calculates an appropriate spot above the shale in which the drill must start to turn
horizontally. That spot is known as the ‘KICKOFF POINT’. From there, the drill bit is
progressively angles so that it creates a borehole that curves horizontally. If done properly, the
well reaches the ‘entry point’ and makes its way into the rock where the natural gas is trapped.
The horizontal portion of the well is drilled, and provides much more contact with the rock than
a vertical well.
Historical records suggest that horizontal drilling dates back to as early as 1929. It became an
especially common practice during the 1980s when improved equipment, motors, and other
technology were developed. In recent years, horizontal drilling has been shown in many cases to
be more productive than vertical drilling, and a corresponding increase in the use of horizontal
drilling has occurred (IEER, 2013) 30
.
3.3 Fracturing fluids
High-pressure fracture fluid is injected into the wellbore, with the pressure above the fracture
gradient of the rock. The main purpose of fracturing fluid is to extend fractures, add lubrication
and to carry proppant (sand) into the formation.
There are two methods of transporting the fracking fluid into the well:-
 High Viscosity: - This type of fracturing causes large dominant fractures.
 High Rate: - This type of fracturing causes small spread-out microstructures.
The fracking fluid normally used is water. The main purpose of adding proppant (solid particles
like sand) is to ensure that the fractures created stays open to allow the gas/oil to escape.
Proppants can be silica sand, resin-coated sand and man-made ceramics.
Fluid injected in the rock is a slurry of water, proppants and chemical additives. The slurry
contains 90% water, 9.5% sand and 0.5% is the additives (USHR, 2011)19
.

Few of the chemical additives that are added are: -
 Acids—hydrochloric acid or acetic acid is used in the pre-fracturing stage for cleaning the
perforations and initiating fissure in the near-wellbore rock.
 Ethylene glycol—prevents formation of scale deposits in the pipe.
 Borate salts—used for maintaining fluid viscosity during the temperature increase.
 Glutaraldehyde—used as disinfectant of the water (bacteria elimination).
 Guar gum and other water-soluble gelling agents—increases viscosity of the fracturing
fluid to deliver more efficiently the proppant into the formation.
 Citric acid—used for corrosion prevention.
 Isopropanol—increases the viscosity of the fracture fluid.
3.3.1 Water Usage
As several million gallons of water is required, it is critical that large quantities of relatively
fresh water may be reasonably available. The quality of water is important because the
impurities in water can reduce the effectiveness of additives.
Most water used comes from surface water sources such as lakes, rivers, municipal supplies.
The spent or used fracking fluid is either disposed off or it is recycling the treated flowback
fluids in a close loop (King, 2012)20
.
3.4 Environmental Impact
Hydraulic Fracturing has raised environmental concerns including ground water contamination,
deterioration of air quality, migration of gases and hydraulic fracturing chemicals to the surface,
mishandling of waste, and the health effects of all these, as well as its contribution to raised
atmospheric CO2 levels by enabling the extraction of previously sequestered hydrocarbons
(King, 2012)20
.

3.4.1 Air
 The major impact of the air is in the form of methane leakage originating from the wells.
The U.S. Environmental Protection Agency (EPA) has estimated that methane leakage is
about 1.2% of the total shale gas produced by this method.
 Other effects include emissions from the diesel or natural gas powered equipments such
as compressors, pumps, drilling rigs. Also transportation of necessary water volume for
hydraulic fracturing, if done by trucks, can cause high volumes of air emissions,
especially particulate matter emissions.
3.4.2 Water
 Total amount of water required for hydraulic fracturing comes out to be around 1.2-3.5
million U.S. gallon of water per well, with the large projects consuming around 5 million
U.S. gallons. Additional amount of water is required when refracturing of the well is
done.
 In case, there is an aquifer underground, the chemical additives present in the water
pumped into the ground can contaminate these fresh water sources. And some of the
materials present inside these additives are carcinogens (cancer causing).
3.5 Health Effect
The additives used sometimes contain carcinogens. And if there is an aquifer present, it can
contaminate these sources, which proves to be toxic and undrinkable for animals and humans
(King, 2012)20
.
3.6 Minor Earth Quakes
Hydraulic fracturing routinely produces microseismic events (Figure 3.3) much too small to be
detected except by sensitive equipments. Now these microseismic events are induced in order to
map the horizontal and vertical extent of fracturing. So this in turn triggers quakes large enough
to be felt by the people upto 3.3 on the Richter scale. It may also damage the wells and pipes
used in a Shale Gas Extraction setup (Kim, 2013)18

FIGURE 3.3: HYDROFRACKING DETAILS (AWWA, 2013)10
3.7Fracking Wastewater Management
Now as the water resource required for fracking is quite large, there is a growing concern of the
Wastewater Management. Upto 60% of the water injected into a wellhead during the fracking
process will discharge back out of the well shortly thereafter, as flowback wastewater.
Thereafter, and for the life of wellhead, it will discharge upto 378 m3
/day of wastewater. This
wastewater needs to be captured, and disposed off or recycled (Easton, 2013)24
.
3.7.1 Wastewater Disposal Limitations
Many fracturing wells (in U.S.) use surface ponds to store hydraulic fracturing fluids (flowback
and produced wastewater) for evaporation or until arrangements are made for disposal. Almost
50% of the wastewater generated might be stored in these surface ponds in few of these places.
But the future use of the surface ponds is sure to become more regulated. The EPA is currently
industry practices and state requirements, and is considering the need of technical guidance on

the design, operation, maintenance, and closure of the surface ponds under the Resource
Conservation and Recovery Act (RCRA) in order to minimize potential environmental impacts.
3.7.2 Deep Well Injection
In many places, deep-well underground injection is a popular method for the disposal of fracking
fluids and other substances from the shale oil and gas extraction operations. Not only it might
damage the ground water resources, in this case, the Wastewater has to be transported (by trucks)
from the fracking wells to the deep-well injection. To haul water off-site for a disposal over the
20 years life of a hydraulic fracturing well project, it is estimated to cost around $160 million
(including trucking costs, water disposal costs and labor).
3.7.3 Wellhead Wastewater Treatment
Wastewater associated with the shale oil and gas extraction can contain high levels of total
dissolved solids (TDS), fracturing fluid additives, total suspended solids (TSS), hardness
compounds, metals, oil and gas, bacteria and bacteria disinfection agents, and naturally occurring
radioactive materials.
These contaminants are partially a combination of chemicals and agents inserted deep into the
well which facilitate fracking by modifying the water chemistry to increase the viscosity, carry
more sand and improve conductivity. Effectively, the fracking process is pushing the water down
into the rock formation, trying to wedge the rock cracks open. The sand fills in between the
cracks that the hydraulic fluid has propped open.
Once the fracking is done, much of the water comes back up the well as flowback water. Along
with it come bacteria and characteristics of the geological formation, including minerals,
radioactive materials and oil and gas.
Some drilling operators elect to re-use a portion of wastewater to replace and/or supplement
fresh water in formulating fracturing fluid for a future well or re-fracturing the same well. Reuse
of the waste water is dependent on the levels of pollutants in the waste water and the proximity
of other fracturing sites that might reuse the wastewater. This practice has the potential to reduce
discharges to surface ponds, minimize underground injection of wastewater, and conserve and
reuse water resources (Easton, 2013)24
.

3.7.4 Centralized Water Management
Centralized treatment of waste water is emerging as a viable solution for long-term efficiency in
managing water sourcing and wastewater treatment in hydraulic fracturing. Centralized treatment
facilities handle both the flowback wastewater and produced wastewater from oil and gas wells
within a region, at a radius of 40 to 50 miles. Pipelines connect all wellheads directly with
central treatment plant.
Wastewater received by the plant is identified as originating from a specific well. The targeted
usage requirements for that wastewater are specified and the wastewater is then processed to
meet that usage. Once processed, the waste water is then piped directly to the targeted well site.
Central wastewater treatment facilities processes can include:
 Primary three-phase separation to remove dissolved natural gas, floating gel, oil, sand
and suspended solids, followed by storage for equalization of chemical composition and
flow
 Secondary separation utilizing dissolved air or gas flotation for removal of a wide variety
of contaminants including polymers, oils and suspended solids. Bactericide is added to
control bacterial growth
 Removal of metal by precipitation, and removal of salts by reverse osmosis
 Sludge management for dewatering collected solids
Such centralized plants can be integrated with alternative sources of water to supplement fresh
water needs for fracking, such as from abandoned mines, storm water control basins, municipal
treatment plant effluent, and power plant cooling water. Such initiatives are required which
emphasize future trends in water use for oil and gas drilling which should represent more reuse
of water for fracking, and more use of other waters, such as treated wastewater and acidic mine
drainage, in the hydraulic fracturing process (Easton, 2013)24
.

3.8 Non-Hydraulic Fracking
As we have seen, hydraulic fracturing suffers from number of significant disadvantages. Mainly
there is contamination of water stream which is used. As well as some existing hydraulic
fracturing techniques are energy and capital intensive.
Thus, there is a need for non-hydraulic fracturing systems and methods which are less energy
intensive, do not require liquids for fracking and proppant delivery, do not add contamination or
waste to the fracking process, and has the potential to increase hydrocarbon recovery.
According to a U.S. Patent (Vandor, 2012)5
, it is possible to alleviate to a great extent, the
disadvantages of known fracturing processes by providing non-hydraulic fracturing systems,
methods and processes using metacritical phase Natural Gas as a fracturing and proppant
transport medium. The metacritical phase of a gas is that set of conditions where gas is above its
critical pressure and is colder than its critical temperature. The meta NG, which is pumped to a
high pressure, is used to create or extend fissures in subterranean formations and hold those
fissures open to release hydrocarbons contained in those formations.
The meta-NG is pumped to a high pressure, warmed and used to deliver suitable proppant to the
fissures in the subterranean formations. This meta NG can be produced on site. The proppant is
delivered into the subterranean formation by meta NG. The proppant may be lubricated and
delivered via warm compressed natural gas at a high pressure. Hence this is one of the alternative
methods which can be used for getting fracked gas out of the ground.

Chapter 4: Retorting
4.1 Kerogen
Kerogen is the complex carbonaceous (organic) material that occurs in sedimentary rocks and
shales. It is for the most part insoluble in the common organic solvents. It is a solid, waxy,
organic substance that forms when pressure and heat from the Earth act on the remains of plants
and animals. When kerogen occurs in shale, the entire material is often referred to as oil shale.
A synthetic crude oil is produced from oil shale by the application of heat so that the kerogen is
thermally decomposed (cracked) to produce the lower molecular weight products. Kerogen is
also reputed to be a precursor of petroleum. For comparison with tar sand, oil shale is any fine-
grained sedimentary rock containing solid organic matter (q.v., kerogen) that yields oil when
heated (Speight, 2006)23
.
The Table 4.1 gives the types of kerogen and their hydrocarbon potential:-
TABLE 4.1: TYPES OF KEROGEN AND THEIR HYDROCARBON POTENTIAL (CPH)33

4.1.1 Composition of Kerogen
As kerogen is a mixture of organic material, rather than a specific chemical, it cannot be given a
chemical formula. Indeed its chemical composition can vary distinctively from sample to sample
(Speight, 2006)23
. Kerogen from the Green River Formation oil shale deposit of western North
America contains elements in the
proportions: Carbon 215: hydrogen 330: oxygen 12: nitrogen 5: sulfur 1
Average Molecular Weight: 3000
Approximate Formula: C200H300SN5O11
4.2 Retorting
The term oil shale generally refers to any sedimentary rock that contains solid bituminous
materials that are released as petroleum-like liquids when the rock is heated. To obtain oil from
oil shale, the shale must be heated and resultant liquid must be captured. This process is called
retorting, and the vessel in which retorting takes place is known as a retort.
Extracting oil from oil shale is more complex than conventional oil recovery. Hydrocarbons in
oil shale are present in the form of solid, bituminous materials and hence cannot be pumped
directly out of the geologic reservoir. The rock must be heated to a high temperature, and the
resultant liquid must be separated and collected. The heating process is called retorting (Bartis
et. al., 2005)13
. Processes for producing shale oil generally fall into one of two groups:
1) Surface Retorting
2) In-Situ Retorting
Before going for either In-Situ Retorting or Surface Retorting, following steps are performed:-
 Explosives are positioned at suitable places inside the reservoir, which are exploded.
 Large oil shales are converted into smaller rock fragments (or rubble)
 This is called a rubblized bed.
 Rubblized shale is heated at a large temperature, thermally decomposing the kerogen.

4.3 Surface Retorting
In this approach (Figure 4.1), oil shale is mined with conventional mining methods and
transported to a retorting plant. After heating and removal of fine solid particles, the liquid
product is upgraded to produce a crude oil substitute that can enter the nation’s existing oil
pipeline and refinery infrastructure. After retorting, the spent shale is cooled and disposed of,
awaiting eventual reclamation.
FIGURE 4.1: MAJOR STEPS IN SURFACE RETORTING (Bartis et. al., 2005)13
4.3.1 Mining Oil Shale
Oil shale can be mined using one of the two methods: underground mining, most likely using the
room-and-pillar method, or surface mining. In general, surface mining is the most efficient
approach for mining oil shale. Room-and-pillar mining can recover about 60 percent of the oil.
Surface mining can recover much higher percentages of in-place resources.
Commercial oil shale plants will likely be designed to produce at least 50,000 barrels, and more
likely well over 100,000 barrels, of shale oil per day. At a minimum, a mine designed to serve
such plants will need an annual output of more than 25 million tons (Bartis et. al., 2005)13
.
4.3.2 Surface Retorting
Surface retorting involves crushing the mined oil shale and then retorting it at about 900 to 1,000
degrees F. The vessel in which this heating occurs is called a retort. The hot shale oil leaving the
retort is not stable and must be sent directly to an upgrading plant for catalytic processing with
hydrogen to remove impurities and produce a stable product. This stable shale oil can be used as
a refinery feedstock and should compete favorably with sweet, light crude oil.

An oil shale plant operating on a commercial scale—that is, producing a minimum of 50,000
barrels per day—would need to incorporate multiple retorts. Because the residence time of oil
shale in the hot zone of a retort is nearly a half hour, a retort designed to produce 50,000 barrels
of shale oil per day would need to be sized to contain more than 1,500 tons of oil shale, which is
well beyond the state of the art.
For many years, surface retorting of oil shale has been used to yield a crude oil substitute in
Brazil, China, and Estonia. A small plant may also be operating in Russia. All of the current
operating plants are small, with total world production estimated at 10,000 to 15,000 barrels per
day.
There are 6 methods involved in surface retorting (Lee, 1991)26
:-
1. Internal Combustion
2. Hot Recycled Solids
3. Conduction through walls
4. Externally generated hot gases
5. Reactive fluids
6. Plasma Gasification
4.3.2.1 Internal Combustion
FIGURE 4.2: INTERNAL COMBUSTION
(Louw SJ, et. al., 1985)21

 A vertical shaft is used in Internal Combustion retorting as shown in Figure 4.2
 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)
 Condensed shale oil is collected, while non-condensable gas is recycled and used to carry
heat up the retort
 Internal Combustion Retorting process is thermally efficient since the heat from the non-
condensable gases and the ash is used as a heating source in the retort
 Common drawbacks of internal combustion technologies are that the combustible oil
shale gas is diluted by combustion gases and particles smaller than 10 millimeters (0.4 in)
cannot be processed. Uneven distribution of gas across the retort can result in blockages
when hot spots cause particles to fuse or disintegrate
4.3.2.2 Hot Recycled Solids
FIGURE 4.3: Hot Recycled Solids: Alberta Taciuk Processor (U.S. DOE, 2004)22
 It delivers heat to the oil shale by recycling hot solid particles—typically oil shale ash
 It employs rotating kiln or fluidized bed retorts, fed by fine oil shale. The recycled
particles are heated at 800 °C and then mixed with the raw oil shale to cause the shale to
decompose at about 500 °C as shown in figure 4.3

 Oil vapor and shale oil gas are separated from the solids and cooled to condense and
collect the oil
4.3.2.3 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
 A general drawback of ‘conduction through a wall’ technologies is that the retorts are
more costly when scaled-up due to the resulting large amount of heat conducting walls
made of high-temperature alloys
4.3.2.4 Externally generated Hot Gas
 In general, externally generated hot gas technologies are similar to internal combustion
technologies in that they also process oil shale lumps in vertical shaft kilns. Significantly,
though, the heat in these technologies is delivered by gases heated outside the retort
vessel, and therefore the retort vapors are not diluted with combustion exhaust
 In addition to not accepting fine particles as feed, these technologies do not utilize the
potential heat of combusting the ash and thus must burn more valuable fuels
 However, due to the lack of combustion of the spent shale, the oil shale does not exceed
500 °C (932 °F) and significant carbonate mineral decomposition and subsequent
CO2generation can be avoided for some oil shales
 Also, these technologies tend to be the more stable and easier to control than internal
combustion or hot solid recycle technologies

4.3.2.5 Reactive Fluids
 Kerogen is tightly bound to the shale and resists dissolution by most solvents. Despite
this constraint, extraction using especially reactive fluids has been tested
 Reactive fluid technologies are suitable for processing oil shales with low hydrogen
content. In these technologies, hydrogen gas (H2) or hydrogen donors (chemicals that
donate hydrogen during chemical reactions) react with coke precursors (chemical
structures in the oil shale that are prone to form char/ash during retorting but have not yet
done so)
 Reactive fluid technologies include the IGT Hytort (high-pressure H2) process, donor
solvent processes, and the Chattanooga fluidized bed reactor. In the IGT Hytort oil shale
is processed in a high-pressure hydrogen environment. The Chattanooga process uses
a fluidized bed reactor and an associated hydrogen-fired heater for oil shale thermal
cracking and hydrogenation
 Laboratory results indicate that these technologies can often obtain significantly higher
oil yields than pyrolysis processes. Drawbacks are the additional cost and complexity of
hydrogen production and high-pressure retort vessels
4.3.2.6 Plasma Gasification
 Several experimental tests have been conducted for the oil-shale gasification by
using plasma technologies
 In these technologies, oil shale is bombarded by radicals (ions). The radicals crack
kerogen molecules forming synthetic gas and oil
 Air, hydrogen or nitrogen is used as plasma gas and processes may operate in
an arc, plasma arc, or plasma electrolysis mode
 The main benefit of these technologies is processing without using water

4.3.3 Environmental Effects
There are a few environmental effects associated with this method:-
 Popcorn Effect
One factor which makes the extraction of oil from oil shale challenging is that spent shale
occupies 20-30% greater volume after processing as compared to the raw shale due to the
popcorn effect from the heating. This means that a 50,000 Barrel of Oil per day oil shale
plant would produce 7500 cubic meters partially powdered rock waste per day in excess
of that returned to the mine. Hence we require larger areas to dump this spent shale
(Saether, 2004)25
.
 Large Open Mines
Now the retorted shale is often dumped in large open mines. Due to rains, leaching might
occur of the particulate matter from the spent shale and it may deteriorate the quality of
ground water (aquifers) which may eventually harm the living organisms.
 Emissions
Combustion of oil shales release greenhouse gases like CO2, derived from oxidation of
organic matter and decomposition of the carbonates. If carbonates are present in high
proportions, this renders the oil shales inefficient in terms of energy per unit CO2 emitted.
Furthermore, oil shale combustion emits acidic gases like NOX and SO2 derived both
from inorganic sulfides and organically bound nitrogen and sulfur. Although the
emissions of CO2, NOX and SO2 are at the same level or lower than those from oil- or
coal-based power plants with comparable capacity, the combustion of oil shales also
yields particulate emissions (potentially enriched in variety of metals, metalloids and
organics) at a rate 20 to 50 times (Saether, 2004)25
.
4.4 In-situ Retorting
In-situ retorting entails heating oil shale in place, extracting the liquid from the ground, and
transporting it to an upgrading facility. Various approaches to in-situ retorting were investigated
during the 1970s and 1980s (Bartis et. al., 2005)13
. The methods involved are:
 True in-situ process
 Modified in-situ process

4.4.1 True In-Situ Process
None of the shale is mined; holes are drilled in the formation, explosively rubblizing the shale,
burning a portion of the oil shale underground to produce the heat needed for retorting the
remaining oil shale. This is the true in-situ retorting. Much of this prior work was not successful,
encountering serious problems in maintaining and controlling the underground combustion
process and avoiding subsurface pollution.
4.4.2 Modified In-Situ Process
A variant on this approach—modified in-situ retorting—appears to have made progress in
addressing these problems. In modified in-situ retorting, a volume beneath the retort zone is
mined and the shale to be retorted is rubblized by a series of staged explosions. This process
provides improved access for the air needed for combustion as air pockets are created in place of
the shale which has been mined. The rubblized shale is retorted in place, and the mined shale is
sent to surface retorts. Occidental Petroleum was the principal developer of modified in-situ
retorting technology.
4.4.3 Problems Associated
While efforts are made to explosively rubblize the oil shale into uniform pieces, in reality the
rubblized mass of oil shale contains numerous different sized fragments of oil shale which create
vertical, horizontal and irregular channels extending sporadically throughout the bed and along
the wall of the retort. As a result, during retorting, hot gases often flow down these channels and
bypass large portions of the bed, leaving significant portions of the rubblized shale unretorted.
Different sized oil shale fragments, channeling and irregular packing, and imperfect distribution
of oil shale fragments cause other deleterious effects including tilted (nonhorizontal) and
irregular flame fronts in close proximity to the retorting zone and fingering, that is, flame front
projections which extend downward into the raw oil shale and advance far ahead of other
portions of the flame front. Irregular flame fronts and fingering can cause coking, burning, and
thermal cracking of the liberated shale oil. Irregular, tilted flame fronts can lead to flame front
breakthrough and incomplete retorting.

In the case of severe channeling, horizontal pathways may permit oxygen to flow underneath the
raw unretorted shale. If this happens, shale oil flowing downward in that zone may burn. It has
been estimated that losses from burning in in-situ retorting can be as high as 40% of the product
shale oil.
Furthermore, during retorting, significant quantities of oil shale retort water are also produced.
Oil shale retort water is laden with suspended and dissolved impurities, such as shale oil and oil
shale particulates ranging in size from less than 1 micron to 1,000 microns and contains a variety
of other contaminants not normally found in natural petroleum (crude oil) refinery wastewater,
chemical plant waste water or sewage. Oil shale retort water usually contains a much higher
concentration of organic matter and other pollutants than other waste waters or sewage causing
difficult disposal and purification problems.
The quantity of pollutants in water is often determined by measuring the amount of dissolved
oxygen required to biologically decompose the waste organic matter in the polluted water. This
measurement, called biochemical oxygen demand (BOD), provides an index of the organic
pollution in the water. Many organic contaminants in oil shale retort water are not amenable to
conventional biological decomposition. Therefore, tests such as chemical oxygen demand (COD)
and total organic carbon (TOC) are employed to more accurately measure the quantity of
pollutants in retort water. Chemical oxygen demand measures the amount of chemical oxygen
needed to oxidize or burn the organic matter in waste water. Total organic carbon measures the
amount of organic carbon in waste water (Forgac et al., 1987)2
.
4.4.4 Improved In-Situ Retorting: A Patent Overview (US Patent 4637464, 1987)
An improved in situ process is provided to retort oil shale which increases product yield and
quality. In the novel process, flow of the flame front-supporting feed gas to the underground
retort is intermittently stopped with a water purge to alternately extinguish and ignite the flame
front in the underground retort while continuously retorting raw oil shale in the retort. This
alternate extinguishment and ignition of the flame front is referred to as “pulsed combustion.”
The water purge can be purified water, condensed steam, or retort water recycled from an
underground or aboveground retort. Retort water typically contains oil shale particulates, shale

oil, ammonia and organic carbon. The flame front-supporting feed gas as can be air, or air
diluted with steam, water, and/or recycled retort off gases.
Pulsed combustion promotes uniformity of the flame front and minimizes fingering and
projections of excessively high temperature zones in the rubblized bed of shale. When the
combustion-sustaining feed gas is shutoff, combustion stops and burning of product oil is
quenched and the area in which the flame front was present remains stationary during shut off to
distribute heat downward in the bed. Upon reignition, a generally horizontal flame front is
established which advances in the general direction of flow of the feed gas. Intermittent injection
of the feed gas lowers the temperature of the flame front, minimize carbonate decomposition,
coking and thermal cracking of liberated hydrocarbons.
The pulse rate and duration of the feed gas control the profile of the flame front. During purging,
heat is dissipated throughout the bed where retorting was incomplete or missed and these regions
are retorted to increase product recovery. Thermal irregularities in the bed equilibrate between
pulses to lower the maximum temperature in the retort. During periods of noncombustion,
sensible heat from the retorted and combusted shale advances downward through the raw colder
shale to heat and continue retorting the bed. Continuous retorting between pulses advances the
leading edge (front) of the retorting zone and thickens the layer of retorted shale containing
unburned, residual carbon to enlarge the separation between the combustion and retorting zones
when the flame front is reignited in response to injection of the next pulse of feed gas. Greater
separation between the combustion and retorting zones, decreases flame front breakthrough, oil
fires and gas explosions.
During shutoff of the flame front-supporting feed gas, the liberated shale oil has more time to
flow downward and liquefy on the colder raw shale. Drainage and evacuation of oil during
noncombustion moves the effluent oil farther away from the combustion zone upon reignition to
provide an additional margin of safety which diminishes the chances of oil fires. Additional
benefits of pulsed combustion include the ability to more precisely detect the location and
configuration of the flame front and retorting zone by monitoring the change of off gases
composition.
During retorting, oil shale retort water is formed from the thermal decomposition of kerogen
which is referred to as “water of formation.” Oil shale retort water can also be derived from in-

situ steam injection (process water), aquifers or natural underground streams in in-situ retorts
(aquifer water), and in situ shale combustion (water of combustion). Raw retort oil shale water,
however, if left untreated, is generally unsuitable for safe discharge into lakes and rivers or for
use in downstream shale oil processes, because it contains a variety of suspended and dissolved
pollutants, impurities and contaminants, such as raw, retorted and spent oil shale particulates,
shale oil, grease, ammonia, phenols, sulfur, cyanide, lead, mercury and arsenic.
Oil shale water is much more difficult to process and purify than waste water from natural
petroleum refineries, chemical plants and sewage treatment plants, because oil shale water
generally contains a much greater concentration of suspended and dissolved pollutants which are
only partially biodegradable. For example, untreated retort water contains over 10 times the
amount of total organic carbon and chemical oxygen demand, over 5 times the amount of phenol
and over 200 times the amount of ammonia as waste water from natural petroleum refineries.
In accordance with one aspect of this type of retorting, raw retort oil shale water can be recycled
and injected into the retort for use as part or all of the purge water and/or part of the feed gas
thereby avoiding expensive, cumbersome, and complicated retort water purification processes
and treatments (Forgac et al., 1987)2
.
Following steps are followed to carry out In-Situ Retorting (Refer Figure 4.4)
 Through tunneling, 15-25% volume of oil shale is removed from the central region of the
retort to form a cavity or void space. This shale is then, surface retorted
 With the help of explosives, rubblize the shale bed
 Pipes are extended to the top of the retort. They include feed lines, purge lines and
ignition fuel lines which are controlled and regulated by a control valve
 Burners are located in proximity to the top of the bed
 In order to initiate retorting of a rubblized mass, fuel gas such as recycle off gases or
natural gas is fed into the retort through the fuel lines and an oxygen rich feed gas is
passed through the feed lines
 Burners are ignited to establish a flame front horizontally across the bed
 If economically feasible, the rubblized mass can be preheated to a temperature slightly
below the retorting temperature through inert gases like nitrogen, steam, etc

 After ignition, fuel valve 36 is closed to shut off inflow of fuel gas
 Once the flame front is established, residual carbon contained in the oil shale usually
provides an adequate source of fuel to maintain the flame front as long as the oxygen-
containing feed gas is supplied to the flame front
 The oxygen-containing feed sustains and drives the flame front downwardly through the
bed of oil shale. Feed air contains about 10-30% oxygen preferably
FIGURE 4.4: IMPROVED IN-SITU
RETORTING (Forgac et al., 1987)2

 Flame front emits combustion off gases and generates heat which move downwardly
ahead of flame front and heats the raw, unretorted oil shale in retorting zone 46 to a
retorting temperature from 8000
F. to 12000
F. to retort and pyrolyze the oil shale in
retorting zone
 During retorting, oil shale retort water and hydrocarbons are liberated from the raw oil
shale. The hydrocarbons are liberated as a gas, vapor, mist or liquid droplets and most
likely a mixture thereof. The liberated hydrocarbons include light gases, such as methane,
ethane, ethene, propane, and propene, and normally liquid shale oil, which flow
downwardly by gravity, condense and liquefy upon the cooler, unretorted raw shale
below the retorting zone, forming condensates which percolate downwardly through the
retort into access tunnel
 Side by side, a purging fluid, also referred to as a purge fluid or purge, is injected or
sprayed downwardly into combustion zone through purge line between pulses of feed.
The purge fluid extinguishes flame front and accelerates transfer of sensible heat from
combustion zone to retorting zone. In most cases, raw untreated shale water is used as
purging fluid
 Gas, water and oil obtained at the bottom of the well are separated in a gravity separator
and then taken to the top where gas and oil are refined and upgraded while the water is
used again in the process.
4.4.5 Thermally Conductive In-Situ Conversion
Shell Oil developed this type of technique. In Shell’s approach, a volume of shale is heated by
electric heaters placed in vertical holes drilled through the entire thickness (more than a thousand
feet) of a section of oil shale. After heating for two to three years, the targeted volume of the
deposit will reach a temperature between 650-7000
F. This very slow heating to a relatively low
temperature (compared with the plus-900 degrees F temperatures common in surface retorting) is
sufficient to cause the chemical and physical changes required to release oil from the shale.
On an energy basis, about two-thirds of the released product is liquid and one-third is a gas
similar in composition to natural gas. The released product is gathered in collection wells
positioned within the heated zone. The Major Steps involved in Thermally Conductive In-Situ
and the actual representation of the same are shown in Figure 4.5 and 4.6 respectively.

FIGURE 4.6: SHELL IN-SITU CONVERSION PROCESS (Bartis et. al., 2005)13
The process involved in this case:-
• The process involves heating underground oil shale, using electric heaters placed in deep
vertical holes drilled through a section of oil shale.
• The volume of oil shale is heated over a period of two to three years, until it reaches 650–
700 °F, at which point oil is released from the shale.
• The released product is gathered in collection wells positioned within the heated zone.
• An underground barrier surrounding the extraction zone ‘freeze wall’ is created by
pumping refrigerated fluid (brine at -10 0
C).
• Freeze wall prevents ground water from entering the extraction zone, and prevents the
hydrocarbon from leaving its perimeter.
FIGURE 4.5: MAJOR STEPS IN THERMALLY CONDUCTIVE IN-SITU CONVERSION
(Bartis et. al., 2005)13

4.4.5.1 Heat Balance on the reservoir (Brady et al., 2006)14
4.4.5.2 Reservoir Temperature Profile
Assumptions:-
 Thermal diffusivity assumed constant
 Models only include periods of time when no fluid flow is occurring in reservoir
 Heaters assumed to be in a hexagonal pattern in the earth
 Heat generation from reaction is calculated from average kinetic values of kerogen
cracking
 Heat lost to overburden by heaters not considered
FIGURE 4.7: TEMPERATURE PROFILE CURVES (Brady et al., 2006)14

FIGURE 4.8: TWO DIMENSIONAL TEMPERATURE PROFILE (Brady et al., 2006) 14
 Distance between the heater and the production well is about 30 feet
 Distance between the heater and the freeze wall is also around 30 feet
 Initial reservoir condition is around 150 0
F
 Freeze walls included as boundary conditions

4.4.5.3 Freeze wall construction
 Constructed of double wall pipes placed 8 feet apart
 Calcium chloride brine at -10 0
F is circulated
 Water in the soil freezes causing an impermeable barrier
4.4.5.4 Electric Heating Element
It is Chromel AA containing 68% Nickel, 20% Chromium and 8% iron. It is self regulating
with temperature about 1500 0
F.
4.4.5.5 Costs
The following costs must be taken into consideration:-
• Drilling Cost
In a ten acre plot, there are 250 heater wells and 80 producer wells. Total cost is $ 26.4
million ($80,000 per well)
• Refrigeration Costs
Q = 5*10^6 KW.
Purchase cost: $12.5 million
Operating Cost: $3.2 million/day
• Pumping Costs
Now 80 centrifugal pumps are used to remove ground water trapped in the freeze wall at
a rate of1.6 million gallons/hr for a period of 2 weeks.
Cost of Pump: $83,000/pump
$120,000 /day needed for electricity

• Heating Cost
$80,000 per heater
Electricity cost: $80,000/day
4.5 Shale Oil Upgrading
The shale oil obtained from all these processes contains variety of impurities, as given in Table
4.2. It cannot be used directly and hence it needs to be upgraded (Ackelson, 2012)8
.
TABLE 4.2: UPGRADING CHALLENGES
Upgrading Challenge Potential Challenge
Particulates Plugging
Arsenic Deactivation
Oxygen Gum Formation
Nitrogen Instability
Diolefins Plugging
4.5.1 Removing Impurities from Shale Oil
FIGURE 4.9: SCHEMATIC DIAGRAM OF SHALE OIL PURIFICATION (Xu, 2010)11

4.6 Transforming Shale Oil into Synthetic Crude
After doing the various pretreatment operations removing the impurities of Sulfur, Nitrogen, etc.,
we obtain crude which after cracking gives crude similar to what is obtained by conventional
method as shown in Figure 4.10.
FIGURE 4.10: TREATING SHALE OIL (Ackelson, 2012)8
4.7 Pollution
4.7.1 Air Pollution
 Due to kerogen, the emission of CO
2
increases, giving rise to global warming.
4.7.2 Water Pollution
 Disposal of spent shale is a menace as it causes water pollution.
 A good oil shale yields only 20-30 gallons of oil per ton of rock, with 85 to 90% of the
weight of the original rock appears as spent shale.
 When water falls on the spend shale, some material is leached out, which will in turn
pollute surface water as well as ground water.
4.7.3 Land Pollution
 Surface mining and in situ processing requires extensive land use.
 Mining, processing and waste disposal require land should be far away from high density
population areas.
 Sub-surface mining might cause caving-in of the mined out are.

Chapter 5: India’s Shale Scenario
5.1 Shale Gas
 India has huge shale gas deposits in Vindhyan, Gondwana, Cambay, Rajasthan
 ONGC has tied up with Schlumberger to explore shale gas in Gondwana and Cambay
basins
 In Cambay basin, Tarapur and Cambay Shale formations are being explored for shale
gas potential
5.2 Oil Shale
 On the other hand, it is estimated that greater than 15 billion tons of oil is present in
oil shales
 Oil Shales are found in north east India, Assam and neighboring areas of Arunachal
Pradesh
FIGURE 5.1: INDIA’S SHALE SCENARIO (The Hindu, 2013)28

Bibliography
Patents and Journals
1. Olowonirejuaro R., ‘What are the challenges and future prospects of India’s
Petroleum Products Refineries?’, University of Dundee
2. Forgac J., Hoekstra G., ‘In-Situ Retorting of Oil Shale with Pulsed Water Purge’,
U.S. Patent 4637464, January 1987
3. Cary D., Okla B., ‘In-Situ Retorting of Oil Shale’, US Patent 3017168, January
1962
4. Hatten P., ‘Coal Seam Gas Fracking Systems and Methods’, US Patent 2013/
0043164 A1, February 2013
5. Vandor D., ‘Non-Hydraulic Fracturing Systems, Methods, and Processes’, US
Patent 2012/0118566 A1, May 2012
6. Youngquist W., ‘Shale Oil- The Elusive Energy’, M. King Hubbard Centre For
Petroleum Supply Studies, Hubbard Centre Newsletter #98/4
7. ‘About Shale Gas and Hydraulic Fracturing’, Department of Energy and Climate
Change, July 2013
8. Ackelson D., ‘Challenges and Solutions for Shale Oil Upgrading’, UOP LLC,
32nd
Oil Shale Symposium, October 2012
9. Kenworthy T., Weiss D., ‘Drilling Down on Fracking Concerns’, Centre for
American Progress, March 2011
10. ‘Water and Hydraulic Fracturing’, a White Paper From the American Water
Works Association, 2013
11. Xu X., ‘Comprehensive Utilization of Oil Shale Resources in China’, Jilin
University, October 2010
12. Gupta N., Reddy V., Yadlapalli H., ‘Shale Gas, A Strategic Imperative for India’,
Deloitte, October 2010
13. Bartis J., LaTourrette T., Dixon L., Peterson D., Cecchine G., ‘Oil Shale
Development in the United States’, RAND, 2005

14. Brady J., Kerr L., Potts M., ‘Shale Oil: Exploration and Development’, Senior
Capstone Project, 2006
15. Kumar B., ‘India’s Initiative towards Exploration of Shale Gas and Oil Shale and
Underground Coal Gasification’, CERS
16. ‘The Basics’, Colorado Oil and Gas Association, 2013
17. ‘Energy Statistics 2013’, Central Statistics Office, National Statistical
Organization, Ministry of Statistics and Program Implementation, Government of
India
18. Kim W., ‘Induced Seismicity associated with fluid injection into a deep well in
Youngstown, Ohio’, Journal of Geophysical Research: Solid Earth, Vol. 118, 1-
13
19. ‘Chemicals used in Hydraulic Fracturing’, United States House of
Representatives, Committee of Energy and Commerce Minority Staff, April 2011
20. King G., ‘Hydraulic Fracturing 101: What every Representative,
Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor
and Engineer should know about estimating Frac Risk and improving Frac
performance in Unconventional Gas and Oil Well’, Apache Corporation, 2012
21. Louw SJ, Addison J., ‘Studies of the Scottish oil shale industry: History of the
industry, working conditions, and mineralogy of Scottish and Green River
formation shales Final report on US Department of Energy Project DE-ACO2 –
82ER60036’, 1985
22. ‘Strategic significance of America’s Oil Shale Resource’, Office of Naval
Petroleum and Oil Shale Reserves, U.S. Department of Energy, Vol.2, 2004

Books, Newspapers & Magazines
23. Speight J., The Chemistry and Technology of Petroleum , 2006; 3:3.1-3.2, 4:4.1-
4.5
24. Easton J., ‘Fracking Wastewater Management’, Water and Waste Water
International, October 2013; 44-46
25. Saether O., ‘Oil Shale, an Alternative Energy Source’, GEO ExPro, November
2004, 26-32
26. Lee S., ‘Oil Shale Technology’, 1991; 6:109-122
27. ‘ONGC to drill more wells in Cambay to explore Shale Gas’, The Economic
Times, January 1, 2014
28. ‘Between a Rock and a Hard Place’, The Hindu (Business Line), November 10,
2013
Web References
29. ‘Digenesis/ Catagenesis’ from Fuel Chemistry Division,
http://www.ems.psu.edu/~pisupati/ACSOutreach/Petroleum_2.html
30. ‘Horizontal and Vertical drilling’, The Institute for Energy & Environment
Research, energy.wilkes.edu/pages/158.asp
31. ‘Oil Shales’, 2012 Oil Shale and Tar Sands Programmatic EIS,
http://ostseis.anl.gov/guide/oilshale/
32. ‘Indian Energy Scenario’,
http://indiastatistical.wordpress.com/2006/10/03/indian-energy-scenario/
33. ‘Type of Kerogen’, Crain’s Petrophysical Handbook,
http://www.spec2000.net/11-vshtoc.htm

Extracting the Shales

Recomendados

Recomendados

Mais conteúdo relacionado

Mais procurados

Mais procurados (20)

Semelhante a Extracting the Shales

Semelhante a Extracting the Shales (20)

Último

Último (20)

Extracting the Shales