Transcript Shrinkage Losses

Introduction to Shale Gas
2012.08.
Jinjung Kim
Shale Gas vs. Conventional Gas
Shale Gas vs. Conventional Gas

Natural Gas Resources-Two Categories
 Conventional Gas

is typically found in reservoirs with permeabilities
greater than 1 millidarcy(mD) and can be extracted
via traditional techniques.

is relatively easy and inexpensive to extract. A large
proportion of the gas produced is conventional.
 Unconventional Gas

is found in reservoirs with relatively low
permeabilities (< 1mD) and hence cannot be extracted
via conventional methods.
Shale Gas vs. Conventional Gas (cont’d)

Natural Gas Resources-Two Categories
 Unconventional Gas

the three most common types of unconventional gas
resources:
 tight gas,
 coal bed methane,
 shale gas

Given the low permeability of these reservoirs, the gas
must be developed via special techniques including
fracture stimulation (or ‘fraccing’) to be produced
commercially.
Shale Gas vs. Conventional Gas (cont’d)

Gas Reservoir Types
Conventional
Unconventional
Matrix Permeability Increases
Source: Halliburton
Conventional Gas
∙MilliDarcy Range (>1mD)
∙Fluid type varies
∙Rock type varies
Complex Gas
∙Retrograde Gas with High Dew Point
∙MilliDarcy Range (Relatively low permeability ~ 1mD or less)
∙Sandstone
Tight Gas
∙Micro Darcy Range
∙Dry Gas - Wet Gas
∙Primarily Sandstone
Shale Gas
∙NanoDarcy Range
∙Dry Gas - Wet Gas
∙Mostly free gas - some adsorbed gas
CBM (Coal Bed Methane)
∙Flow mostly trough fractures (cleats)
∙Adsorbed Dry Gas
∙Coal
Shale (Gas) Properties

Shale Gas

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
adsorption characteristics.
Shale (Gas) Properties



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.
Shale Gas vs. Conventional Gas (cont’d)
Source: US Energy Information Administration
Shale (Gas) Properties




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
organic material.
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 generation.
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
 Horizontal drilling allows the wellbore to come into
contact with significantly larger areas of hydrocarbon
bearing rock than in a vertical well.
Shale Gas Challenges and Solutions

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.
 Fracking 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.
Overview of Hydraulic Fracturing for Shale Gas
Source: Encyclopedia Britannica, Inc.
Hydraulic Fracturing for Shale Gas Production
Overview of Hydraulic Fracturing for Shale Gas Production
Hydraulic Fracturing for Shale Gas Production
Hydraulic Fracturing Fluid

Fracturing Fluid

Fracturing fluid is a mixture of water, proppants, and chemical modifiers.

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 characteristics.
Source: Chesapeake—Hydraulic Fracturing Fact Sheet
Hydraulic Fracturing Fluid

Purposes of the Typical Constituents of Hydraulic Fracturing Fluid
Product
Purpose
Downhole Result
Water and Sand:
>98%
Water
Expand fracture and
deliver sand
Some stays in formation while remainder returns with natural formation water
as “produced water” (actual amounts returned vary from well to well).
Sand Proppants
Allows the fractures to
remain open so the gas
can escape
Stays in formation, embedded in fractures (used to “prop” fractures open).
Acid
Helps dissolve minerals
and initiate cracks in
the rock
Reacts with minerals present in the formation to create salts, water, and
carbon dioxide (neutralized).
Corrosion Inhibitor
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
water.
Iron Control
Prevents precipitation
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%
Source: Chesapeake—Water Use Fact Sheet
Hydraulic Fracturing Fluid

Purposes of the Typical Constituents of Hydraulic Fracturing Fluid, cont’d
Product
Purpose
Downhole Result
Other additives: <2%
Anti-Bacterial Agent
Eliminates bacteria in
the water that produces
corrosive byproducts
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.
Scale Inhibitor
Prevents scale deposits
downhole and in
surface equipment
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.
Friction Reducer
“Slicks” the water to
minimize friction
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.
Surfactant
Used to increase the
viscosity of the fracture
fluid
Generally returned with produced water, but in some formations may enter the
gas stream and return in the produced natural gas.
pH Adjusting Agent
Maintains the
effectiveness of
chemical additives
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.
Source: Chesapeake—Water Use Fact Sheet
Monitoring Fracture Treatments
Micro-seismic Hydraulic Fracture Monitoring
Source: Geospace Technologies
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 detectors.
 This process for monitoring fracture treatments is
commonly referred to as micro-seismic monitoring.
Surface Production Facilities
Overall Block Diagram for Surface Facilities
Mixing Condensate
if required
* Based on Anadarko Gas Processing Plant
F
Oil
Oil Handling
Facilities
CPF
Truck
Loading
Abbreviation
CPF: Central Production Facilities
CGF: Central Gathering Facilities
CDP: Central Delivery Point
LACT: Lease Automatic Custody Transfer
F stands for LACT (Flow Meter)
Sales Oil
Pipeline
Production
Wells
F
CPF
F
Oil & Gas
CPF
Gas
CGF
CDP
F
CPF
10~15
wells
connected
to one CPF
F
CPF
CPF consists of the followings:
∙Separators,
∙Compressor,
∙Tanks,
∙Produced (Waste) Water Treatment,
∙LACT, etc.
CGF and CDP consists of the followings:
∙Slug Catcher
∙Condensate Stabilizer
∙Amine Process (Sweetening),
∙1st Dehydration (TEG),
∙2nd Dehydration (Mol-Sieve),
∙Cryogenic Plant Process,
∙Produced (Waste) Water Treatment,
∙Tanks, etc.
Sales Gas Pipeline
Example: Block Flow Diagram of CGF and CDP
Sour Gas
Amine Process (Sweetening)
Liquid-Gas
Two Phase
Stream
Acid Gas to
Thermal Oxidizer
Sweetened Gas
Slug Catcher
Lean
Amine
Sour
Gas
Condensate
Inlet
Separator
Regenerator
Rich Amine
Incoming Gas - Gathering Lines
Glycol Dehydration
Dry
Gas
Water Vapor
Flare
Stack
Thermal
Oxidizer
Acid Gas
to Thermal
Oxidizer
Lean
Glycol
Scrubber
Rich Glycol
Slop Oil
Tank
Cryogenic Process
Residue Gas
Residue
Gas
Compressor
Mol. Sieve Dehydration
Condensate Stabilizer
To Gas Treating
Gas/Gas HX
De-Methanizer
Condensate
Storage Tank
Water
RVP < 9psia
To Export Pipeline
NGL Products
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.
Description of Block Flow Diagram

Slug Catcher

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 analysis’).

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 process.
Description of Block Flow Diagram

Sweetening Process (Amine Process)
Description of Block Flow Diagram

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 gasoline, ‘C5+’.
 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.
Description of Block Flow Diagram

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.
Description of Block Flow Diagram

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 amine’.
 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’.
Description of Block Flow Diagram

Glycol Dehydration
Vapors to Vapor
Recovery Unit
STILL
COLUMN
TC
REFLUX
CONDENSER
TEG
CONTACTOR
LEAN TEG /
DRY GAS HX
SURGE DRUM
REBOILER
Heating
Medium
COLDFINGER
Dry Gas
HEATING
BUNDLE
Condensate
Rich TEG
LC
Lean TEG
Wet Gas
LC
INLET
SCRUBBER
Flashed Gas
RICH TEG
FLASH DRUM
STAND
PIPE
LC
Free
Liquid
LC
Liquid
Hydrocarbons
TEG
CIRCULATION
PUMP
* This system was applied in Donghae-1 Gas Plant.
TEG
PREHEATER
HX
CHARCOAL
FILTER
CARTRIDGE
FILTER
RICH/LEAN
TEG HX
Description of Block Flow Diagram

Glycol Dehydration
 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 contactor.
 The regenerator may produce the regenerated glycol
containing approximately 0.9% ~ 0.05% water.
Description of Block Flow Diagram

Mol-Sieve Dehydration
Regen Gas Filter
Heating
Medium
Supply
1st Heater
Filter
Sweet Wet
Gas from
TEG Unit
2nd Heater
Heating
Medium
Return
A
B
C
Regen Gas
Cooler
Mol. Sieve
Outlet Filter
Three Tower
Desiccant Dehydrator
- adsorption: downflow,
- regeneration: upflow for heating,
- cooling: downflow
Sweet Dry Gas to
Cryogenic Process
Description of Block Flow Diagram

Mol-Sieve Dehydration

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.
Description of Block Flow Diagram

Cryogenic Process (NGL, Natural Gas Liquid Recovery)
Example
Description of Block Flow Diagram

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 turbo-expander.

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

Water Usage for both Drilling and Hydraulic Fracturing

Hydraulic fracturing involves the introduction of aqueous fracturing
fluid to raise the downhole pressure above the fracture pressure of
the formation rock and to create fissures and interconnected cracks.

After hydraulic fracturing, the pumping pressure is relieved and the
fracture fluid returns to the surface through the well casing. This
water is referred to as ‘flowback’.

Hydraulic fracturing is commonly a one-time event, performed in
stages. However, additional hydraulic fracturing may be performed
over the lifetime of the well, if necessary.

About 4.5 million gallons (≈ 17,000m3 = 100,000bbls) of water for
the fracturing of a typical horizontal well is required. See the figure
iThe water is trucked to the drilling location or transported via
temporary pipelines.
Schematic Geology of Horizontal Drilling and Fracking
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.
Produced Water Management

Water Resources
 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 ~18,000m3.
 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 development.
Produced Water Management

Management of Flowback Water
 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.
Produced Water Management

Management of Flowback Water
 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 sea water.
 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.
Produced Water Management

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 (ppm).

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.
Produced Water Management

Management of Flowback Water
 Growing public concern about the flowback water due to
the potential for human health and environmental impacts
is associated with an accidental release of the flowback
water into the environment:

the large water volume,

the high concentration of dissolved solids, and

the complex physicochemical composition
Produced Water Management

Three options for the produced water management
 Underground Injection-most common?
 Surface Discharge
 Reuse
 Goals of the produced water treatment
 Reduce TDS (Total Dissolved Solids, desalination) for
discharge
 Reduce volume for disposal
 Reduce TDS, scaling, and/or bio-fouling for reuse or
UIC(Underground Injection Control)
Water Management Challenges
 Option of the produced water management
Benefits
Challenges
Injection
- Can be a low-cost option
- Well-established and (mostly) widely accepted
disposal method
- 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
issues
Surface
Discharge
-
- Treatment required
- Shale gas produced water not conducive to
most beneficial uses
∙ Small volume/well with scattered sources
∙ Water production is episodic and moves
over time
- Disposal of treatment concentrate
- Regulatory requirements
- Potential environmental issues
Reuse
- 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
fluid
- May require treatment for TDS, scale,
microbes
- Not necessarily a ‘no-treatment’ option
Produced Water Management

Treatment Challenges
 Shale gas produced water quality varies

between formations,

within formations, and

over time
 High TDS concentrations limit treatment options.
 All treatment processes result in a waste stream, liquid,
solid, or both. CAPEX/OPEX-related issues.
Produced Water Management

Logistics/Practical Considerations

Sources of the produced water change over time as new wells are
drilled and development expands.

Treatment facility location:

Mobile?

Permanent?

Semi-permanent?

Treatment facility ownership:

Commercial?

Owned and run by operator?

Contracted by operator?

Treatment for Surface Discharge

Available Technologies

Reverse Osmosis

Thermal Distillation and Crystallization
* It is the same with the water treatment method, Mechanical Vapor Compression which is
widely used at oil sand development in Canada .
Produced Water Management

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
produced water.

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 costs.
Produced Water Management

Water Treatment System-Mechanical Vapor Compression
Vertical Tube Falling Film Vapor Compression Evaporator Schematic
Source: GE Ionics
Produced Water Management

Water Treatment-MVC and Crystalllizer
MVC and Crystalllizer System (Zero Liquid Discharge)
Source: GE Ionics
Shale Gas Development Workflow
Evaluate Potential
Shale Formation
Data Validation
(Shale Screening)
Characterization
and Evaluation
Organic Shale Interval
Reservoir Extension
- Potential hydrocarbon
presence.
Estimated Principal
Stresses Directions
Review of data
Identification of Natural
Fractures
- Seismic
- Geological geochemical
Estimation of Mechanical
Properties
- Geomechanical data
Geochemical Properties
Petrophysical
Petrophysical Properties
- Mineralogy, Φ, TOC,
Estimated Mineralogy
- RO, Brittle, k
- Spectral Gamma Ray
- Fluid typing.
- Chemostratigraphy
Define data requirements
- Cores
- Core, well log etc.
DFIT (Diagnostic Fracture
Injection Test) Analysis
Workover candidate to
identify production
potential
Source: Halliburton
Determine Shale Analog
Drilling
- Casing Program
- Bit Selection
- Mud Program
- Trajectory
- Sidetracking
- Data Acquisition
Hydraulic Fracturing
- Completion Perforation
Strategy
-Material Selection: Fluids,
Additives, Proppants
-Stimulation Design: Job
Size, Hydraulic Horsepower,
Logistics & Environmental
Impact
Evaluation
-Production Potential
-Fracture Monitoring
Potential
Exploitation
Program
Lessons Learned/Best
Practices
Well Placement
-Reservoir drainage
Well architecture to
maximize production
-Vertical/high angle
-Horizontal
-Multilateral
Water Management
Logistics
생산시설 설계 시 고려할 사항???
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Shale Gas 생산 surface facilities 구성은 초기 hydraulic fracturing과 생산수 처리
(재생)과정을 제외하고는 전반적으로 일반 가스전 처리 공정과 비슷함.
Well streams에 포함된 sour gas 함량에 따라 sweetening process가 요구되기도
하는데 이것이 일반적임. 동해-1 및 베트남 11-2 의 경우 sweetening process가
없는 것은 타 가스 플랜트와 비교 시 가스가 너무 깨끗하기 때문임.
생산량에 따라 다르겠으나 amine unit은 plot space를 많이 차지하며 운전하기가
불편하고 OPEX가 많이 소요됨.
Shale gas well stream은 대부분 wet sour gas이므로 재질 선정 시 고려해야 함.
수많은 well들을 연결하기 위한 gathering line (system)과 제품 판매를 위한
pipeline 설계 및 운영이 중요함. Transient Analysis 요구됨.
Hydraulic fracturing에 필요한 막대한 water sources와 공급 방법(trucking 혹은
pipelines?)에 대한 조사 매우 중요.
생산수 처리 장치 (Water Treatment System) 투자비 및 운전 비용 (CAPEX,
OPEX-waste disposal cost/high energy, transportation, logistics 등)이 높을 것으로
예상되며, 실제 적용 가능한 수처리 기술선택의 어려움 존재.
수시로 바뀌고 강화되는 대기, 수질, 토양 등 환경 법규(규제) 파악이 매우 중요.
전기 공급, 도로 등 infrastructure 고려.
Shale gas의 국내 도입을 전제로 생산할 경우 가스를 LNG로 만들기 위한 LNG
terminal 건설이 요구되는데 경제성 고려 시 매장량은 최소 10 TCF이어야 함.
(2000년 초 기준) . 지역적 특성 고려 요구됨.
Shale gas 공정 처리 후 최종 제품은 크게 residue gas, NGL, 그리고 condensate로
나뉘어 지는데 시장 상황을 고려, 선택적 제품 생산을 위한 설계가 필요함.
Swing factor ? 적용.
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