SHALE GAS EXPLORATION
M.Sc in Petroleum Geosciences
Department of Geology
Banaras Hindu University,Varanasi-221005,INDIA
What Is Unconventional Gas?
Unconventional gas formations
are “continuous”, deposited over
large areas rather than in discrete
unconventional gas is several
orders more complex than
•For coalbed methane and gas
shales, the gas source, trap and
reservoir are the same, not three
Shale Gas contained in absorbed form in the micro-pores and
micro fractures of shale which is a sedimentary rock. The gas
mostly thermogenic origin but cases of biogenic sources are
The shale gas exploration in India is relatively new but rapidly
gaining momentum, as India has huge shale deposits. The
Vindhyan, Gondwana, Cambay, Rajasthan, & other
sedimentary basins have being are field experimented. The
initial are encouraging and on par with U.S. producing shale.
The shale gas production pressure are generally low but
length of production on period compensates by volume.
Shale (Gas) Properties
Conventional gas reservoirs:
• created when natural gas migrates toward the earth‟s surface from an
organic-rich source formation into highly permeable reservoir rock,
where it is trapped by an overlying layer of impermeable rock.
Shale gas resources:
• form within the organic-rich shale source rock.
• The very low permeability of the shale greatly inhibits the gas from
migrating to more permeable reservoir rocks towards the surface.
• The gas is held in natural fractures or pore spaces, or is adsorbed onto
organic material (kerogen) in the shale which is the source material for
all hydrocarbon resources.
Generally, the higher the TOC (Total amount of Organic material) the better
the potential for hydrocarbon generation.
The amount and distribution of gas within the shale is determined by the
initial reservoir pressure, the petrophysical properties of the rock, and its
Shale gas is natural gas that is produced from a type of
sedimentary rock derived from clastic sources often
including mudstones or siltstones, which is known as ‘shale’.
Shales can be the source of the hydrocarbons that have
migrated upwards into the reservoir rock. Shales contain
organic matter (‘kerogen’) which is the source material for
all hydrocarbon resources.
As the rock matures, hydrocarbons are produced from the
kerogen. Hydrocarbons (a liquid or a gas) may then migrate
through existing fissures and fractures in the rock until they
reach the earth’s surface or until they become trapped by
strata of impermeable rock.
The very low permeability of the rock causes the rock to trap the gas
and prevent it from migrating towards the surface. The shale gas can
be held in natural fractures or pore spaces, or can be adsorbed onto
Aside from permeability, the key properties of shales when
considering gas potential are:
• Total amount of Organic Content (‘TOC’, kerogen in the rock)
• Thermal maturity
Generally, the higher the TOC, the better the potential for hydrocarbon
The thermal maturity of the rock is a measure of the degree to which
organic matter contained in the rock has been heated over time, and
potentially converted into liquid and/or gaseous hydrocarbons.
Shale Gas Challenges and Solutions
Key Techniques for Shale Gas Production
Due to very low permeability, special well design and well
stimulation techniques are required to deliver production rates of
sufficient levels to make a development economic.
Horizontal drilling and fracture stimulation are crucial in the
development of the shale gas.
Horizontal drilling allows the wellbore to come into contact with
significantly larger areas of hydrocarbon bearing rock than in a
Hydraulic Fracture Stimulation
Hydraulic fracture stimulation (‘fracking’) is a process to
create a large number of fractures in the rock, thus allowing
the natural gas trapped in formations to move through those
fractures to the wellbore.
Fracturing can both increase production rates and increase
the total amount of gas. Pump pressure causes the rock to
fracture, and water carries sand (‘proppant’) into the
hydraulic fracture to prop it open allowing the flow of gas.
Whilst water and sand are the main components of hydraulic
fracture fluid, small amount of chemical additives are often
added to improve fracturing performance.
Hydraulic Fracturing Fluid
Fracturing fluid is a mixture of water, proppants, and
Proppants are small particles of sand or engineered
materials, such as resins or ceramics.
Proppants flow with the fracturing fluid and hold the
fractures open, maintaining porosity as the pressure
decreases in the formation with the return of fracturing
fluid and gas to the surface.
The mixture of chemical modifiers is determined by site
Hydraulic Fracturing Fluid
Purposes of the Typical Constituents of Hydraulic Fracturing Fluid
Water and Sand:
Expand fracture and
Some stays in formation while remainder returns with natural formation water
as “produced water” (actual amounts returned vary from well to well).
Allows the fractures to
remain open so the gas
Stays in formation, embedded in fractures (used to “prop” fractures open).
Helps dissolve minerals
and initiate cracks in
Reacts with minerals present in the formation to create salts, water, and
carbon dioxide (neutralized).
Prevents the corrosion
of the pipe
Bonds to metal surfaces (pipe) downhole. Any remaining product not bonded
is broken down by microorganisms and consumed or returned in produced
of metal (in pipe)
Reacts with minerals in the formation to create simple salts, carbon dioxide
and water all of which are returned in produced water.
Other additives: <2%
Other additives: <2%
Eliminates bacteria in
the water that produces
Reacts with micro‐organisms that may be present in the treatment fluid and
formation. These microorganisms break down the product with a small
amount of the product returning in produced water.
Prevents scale deposits
downhole and in
Product attaches to the formation downhole. The majority of product returns
with produced water while remaining reacts with micro‐organisms that break
down and consume the product.
“Slicks” the water to
Remains in the formation where temperature and exposure to the “breaker”
allows it to be broken down and consumed by naturally occurring
microorganisms. A small amount returns with produced water.
Used to increase the
viscosity of the fracture
Generally returned with produced water, but in some formations may enter the
gas stream and return in the produced natural gas.
pH Adjusting Agent
Reacts with acidic agents in the treatment fluid to maintain a neutral
(non‐acidic, non‐alkaline) pH. Reaction results in mineral salts, water and
carbon dioxide which is returned in produced water.
Monitoring Fracture Treatments
Micro-seismic Hydraulic Fracture Monitoring
During the fracturing process, the pressure created by the
pumping of fracture fluids creates stress on individual
contact points within the reservoir rocks.
As these points fracture, the movement at the point creates a
micro seismic event which can be recorded by offsetting
monitoring wells or seismic arrays using extremely sensitive
This process for monitoring fracture treatments is commonly
referred to as micro-seismic monitoring.
Overall Description of Block Flow Diagram
Incoming gas goes through a slug catcher and an inlet separator to remove
any free liquids.
Liquids separated from the slug catcher go to a condensate stabilizer to
meet the specification of the condensate of normally 9 ~ 12psia of RVP.
* RVP (Reid Vapor Pressure, @100°F)
Gas from the separator goes through an amine unit to remove acid gases
such as CO2 and H2S.
Sweetened gas from the amine unit is sent through glycol dehydration units
followed by molecular sieve dehydration to remove the water to the ppm
level in order to prevent hydrate formation in the systems and/or pipelines.
NGL can be recovered by cryogenic process.
The produced fluids (gas) flow to the Slugcatcher via gathering lines from CPFs.
The Slugcatcher provides for bulk separation of liquid and gas and acts as a
storage buffer for slugging and sphering operations.
It is intended to regularly sphere the pipeline to control slug volumes entering the
Slugcatcher which has been designed for a slug handling capacity („transient
Liquid from the Slugcatcher is sent into the condensate stabiliser.
Gas is sent into the Inlet Separator where any liquid carryover droplets are
removed. The pressure in the separator is maintained at a fixed set point by
controlling the gas flow from the Slugcatcher. This strategy ensures that pipeline
slugging and sphering do not cause pressure fluctuation (swings) in the gas
Sweetening Process (Amine Process) cont‟d
Natural gas consists of the followings light components:
• methane(CH4), ethane(C2H6), propane(C3H8), and butane(C4H10)
• small amounts of heavier hydrocarbons such as pentane, hexane, and
heptane. A mixture of natural gas heavier than butane is called natural
Natural gas contains impurities called „acid gases‟ as the following:
• hydrogen sulphide(H2S), carbon dioxide(CO2), and carbonyl
sulphide(COS), etc. and these are also called „sour gas‟.
• The impurities must be removed to meet the specifications of NGL.
The presence of sour gas would cause severe corrosion problems, especially
where free water is present.
When the acid gases have been removed it is called „Sweet Gas‟. Changing
sour gas into sweet gas is called „sweetening‟ and „amine process‟ is widely
used for a gas sweetening.
Sweetening Process (Amine Process) cont‟d
The feed gases are contacted with an „amine solution‟. An amine
solution is an alkaline solution which attracts and absorbs acid
gases. There is a chemical reaction between the amine solution and
the acid gases called „absorption process‟.
Absorption process takes place in an „amine contactor‟. The sour
gas comes into contact with the amine solution. When the sour gas
is contacted with the amine solution the acid gases are removed
but the hydrocarbons remain in the gas.
Sweetening Process (Amine Process) cont‟d
The sweetened gas leaves the top of the column it contains in ppm
level of H2S and CO2. The amine which comes out from the bottom
of the column has absorbed a lot of acid gases which is called „rich
The acid gases is removed from the rich amine and the solution is
used again. Removing the acid gas from the rich amine is called
„regeneration‟ and it takes place in an „amine regenerator‟. The
regenerated amine is called „lean amine’
Glycol and wet gas are brought into intimate contact in a contactor.
Glycol absorbs water vapour from the gas. The wet glycol, water
rich glycol is regenerated by fractionation in a still column and
reboiler where the rich glycol is heated and the absorbed water
vapour boiled off.
The regenerated lean glycol is cooled and pumped back into the
The regenerator may produce the regenerated glycol containing
approximately 0.9% ~ 0.05% water.
Water in wet gas from glycol dehydration unit should be further removed in
molecular sieve to the ppm level to avoid the formation of hydrates in NGL
recovery process and to protect the system.
Mol-sieve dehydration contains two or three towers filled with dry desiccant.
The gas flows through an inlet separator where free liquids and solid
particles are removed. Free hydrocarbon liquid should be removed because
they may damage the desiccant bed and solids may plug it.
Then the gas flows to the tower in the adsorption cycle and passes from top
to bottom through the desiccant bed where natural gas and water vapours
are adsorbed. Natural gas are preferentially adsorbed, but as the gas
continues to pass they are gradually displaced by water. When the desiccant
is saturated with water, the gas stream is switched to the second tower and
the first tower is regenerated.
Cryogenic Process (Natural Gas Liquid Recovery)
Generally the NGL recovery process consists of the following three main stages.
• Feed Gas Compression and 1st Chilldown
• Vapour and Liquid Dehydration
• 2nd Chilldown, Expander/Compressor and Demethaniser.
The gas from mol-sieve dehydrations is cooled by mechanical refrigeration, back
exchange with cold residue gas, and NGL, as well as expansion through a turboexpander.
The turbo-expander extracts energy from the inlet gas by expanding it from
about ~1000 psig to ~ 200 psig while recompressing the low pressure sales gas.
Expansion of the gas through the turbo-expander reduces the temperature of the
gas to about -100°C.
Produced Water Management
Drilling and Hydraulic Fracturing
During the flowback period which usually lasts up to two weeks,
approximately 10 ~ 40% of the fracturing fluid returns to the surface.
The volume of flowback depends on the formation characteristics and
operating parameters. Once active gas production has begun, aqueous
and nonaqueous liquid continues to be produced at the surface in much
lower volumes (2~8 m3/day) over the lifetime of the well.
These wastewater, known as ‘produced water’ contains very high TDS
concentrations as well as heavy and light petroleum hydrocarbons to be
separated and recovered from water.
The amount of water for the drilling per well is approximately 400 ~
4,000m3. This water is used to maintain downhole hydrostatic pressure,
cool the drillhead, and remove drill cuttings.
The amount of water for hydraulic fracturing of each well is about 7,000
These large volumes of water are typically obtained from surface waters
or pumped from a municipal source.
However, in regions where natural water sources are scarce, the limited
availability of water may be a significant impediment to gas resource
The highest rate of flowback occurs on the first day, and the rate
diminishes over time; the typical initial rate is 1,000 m3/d(≈ 6,290bbl/d).
The composition of the flowback water changes as a function of the time.
Minerals and organic constituents in the formation dissolve into the
fracturing water, creating a brine solution which includes high
concentrations of salts, metals, oils, and soluble organic compounds.
The flowback water is impounded at the surface for subsequent disposal,
treatment, or reuse.
Large volumes of the water containing very high levels of total dissolved
solids (TDS) return to the surface as the produced water (‘flowback’).
The TDS concentration in the produced water can reach 5 times that of
Currently, deep-well injection is the primary means of
management. However, deep-well injection sites are not
available in many areas.
Therefore, water management strategies and treatment
technologies of flowback water that will enable environmentally
sustainable and economically feasible natural gas extraction will
be critical for the development of the shale gas.
What is TDS (Total Dissolved Solids)?
the total amount of mobile charged ions, including minerals, salts or metals
dissolved in a given volume of water
expressed in units of mg per unit volume of water (mg/L), or parts per million
directly related to the purity of water and affects everything that consumes, lives
in, or uses water, whether organic or inorganic.
Why should we measure and remove the TDS in the water?
The EPA (Environmental Protection Agency, USA) advise a maximum contamination
level of 500mg/L (500ppm) for TDS.
When TDS exceed 1000mg/L, it is considered unfit for human consumption.
A high level of TDS is an indicator of potential concerns. High levels of TDS are
caused by the presence of potassium (K), Chlorides (Cl), and Sodium (Na). These
ions have little or no short-term effects, but toxic ions (lead arsenic, cadmium,
nitrate, etc) may also be dissolved in the water.
It is not strictly permitted that discharging of the produced waters including
flowback water that contain high TDS levels into the environment without proper
water treatment to protect groundwater and surface water resources.
Option of the produced water management
- Can be a low-cost option
- Well-established and (mostly) widely accepted
- Several States encourage as the preferred option
- Limited UIC(Underground Injection Control)
well capacity/locations in some shale plays
- Lack of near-by wells creates transportation
- Treatment required
- Shale gas produced water not conducive to
most beneficial uses
∙ Small volume/well with scattered sources
∙ Water production is episodic and moves
- Disposal of treatment concentrate
- Regulatory requirements
- Potential environmental issues
- Reduced withdrawals and associated concerns
- Reduced disposal needs
- Reduced environmental concerns
Returns water to the local ecosystem
Reduces disposal volume
Can help community relations
Can be a cost-effective management option
- Blended water must be suitable for fracture
- May require treatment for TDS, scale,
- Not necessarily a ‘no-treatment’ option
Treatment for Surface Discharge
Thermal Distillation & Crystallization
• These technologies use evaporating the produced water to
separate the water from its dissolved constituents.
• Distillation removes up to 99.5% of dissolved solids and is
estimated to reduce treatment costs by as much as 75% for
• Thermal distillation can treat flowback water containing up to,
and in some cases even exceeding, 125,000 mg/L of TDS, but
the technology is limited to low flow rates (300 m3/d).
• Mechanical vapor-compression systems to concentrate
flowback water and to create dry mineral crystals (i.e.
crystallization) improves water recovery.
• Crystallization is a feasible approach for treating flowback
water with TDS concentrations as high as 300,000 mg/L, with
requirement of high energy requirements and large capital