he Pdf version of the presentation for the completed ONLINE webinar on “Gas Hydrate, Theory, And Practice” by Professor Bahman Tohidi

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Gas Hydrates, Theory and Practice
Professor Bahman Tohidi
5 August 2020
World Class Training Solutions
www.petro-teach.com
• Expert on gas hydrates, flow assurance, PVT, phase behavior and properties of
reservoir fluids and H2S/CO2-rich systems, production technology and EOR.
• He leads Hydrate, Flow Assurance and Phase Equilibria Research Group at
Institute of GeoEnergy Engineering, Heriot-Watt University.
• He is the Director of International Centre for Gas Hydrate Research and the
Centre for Flow Assurance Research (C-FAR) at Institute of GeoEnergy
• His is a consultant to major oil and service companies.
• Managing Director of “HYDRAFACT LIMITED” a Heriot-Watt spin-out Company.
• Recipient of “Life-Time Achievement” from the 9th International Conference on
gas hydrate, Denver, USA
• Payed a major role in HWU winning of the Queen’s Anniversary Awards in 2015
• His research group work was recognized as one of the top 10 UK examples of
the role of Chemical Engineering in Modern World by the IChemE in 2016.
• He has more than 450 publications, several book chapters and 13 patents.
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Hydrogen Bonding
A hydrogen bond is the attractive
interaction of a hydrogen atom with
an electronegative atom, such as
nitrogen, oxygen or fluorine, that
comes from another molecule or
chemical group
Hydrate Structure and Thermodynamics
• The necessary conditions:
• Presence of water or ice
• Suitably sized gas/liquid molecules
(such as C1, C2, C3, C4, CO2, N2, H2S,
etc.)
• Suitable temperature and pressure
conditions
• Temperature and pressure conditions
is a function of gas/liquid and water
compositions.
Hydrate phase boundary
P
T
Hydrates
No Hydrates
Kihara potential for attraction
between molecules
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Gas Hydrate Structures
Gas molecule
(e.g. methane)
Water molecule
‘cage’
Methane,
ethane, carbon
dioxide….
Propane, iso-
butane, natural
gas….
Methane +
neohexane,
methane +
cycloheptane….
512
435663
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Structure I
Structure II
Structure H
3
16
2 1
8
6
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2
Hydrate Formation, Distilled Water + Methane
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Hydrate Formation, Distilled water + Dissolved CO2
Hydrate Stability of Pure Compounds (HydraFLASH)
H2S
CO2
C2
C1
C3
i-C4
N2
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Example
• C1: 85 mole%, C2: 5 mole%, C3: 4 mole%, i-C4: 3 mole%, n-C4: 2 mole%, i-C5:
1 mole%
• Calculate hydrate stability zone for the above gas from 5 to 100 bara (5 bar
pressure steps) for both sI and sII hydrates. Which structure is more stable?
sI
sII
Lean Gas sI vs sII
sI
sII
Component Mass %
N2 1.34
CO2 0.46
C1 97.77
C2 0.16
C3 0.02
iC4 0.02
nC4 0.02
iC5 0.02
C6 0.19
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sI and sII stability
Components Mole%
Methane 79.89
Ethane 2.05
Propane 0.22
i-Butane 0.04
n-Butane 0.07
i-Pentane 0.03
CO2 8.4
Nitrogen 7.2
H2S 2.05
n-Pentane 0.03
n-Hexane 0.02
Some of the Reasons for Hydrate Formation
• High pressure
• Low temperature
• Chokes
• Regulators
• Vents
• Safety valves
• Water in the pipelines (remaining from pressure
testing and/or off-spec gases)
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Avoiding Hydrate Problems
• Water removal (De-Hydration)
• Increasing the system temperature
• Insulation
• Heating
• Reducing the system pressure
• Injection of thermodynamic
inhibitors
• Methanol, ethanol, glycols
• Using Low Dosage Hydrate
Inhibitors
• Kinetic hydrate inhibitors (KHI)
• Anti-Agglomerants (AA)
• Various combinations of the above
• Cold Flow
Pressure
No Hydrates
Hydrates
Wellhead
conditions
Temperature
Downstream
conditions
Dehydration-Methane
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Hydrates in a Low Water Content Gas
CO2 Phase Behaviour
Pipe
Ships
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Hydrate Stability Zone
• CO2 Hydrates in the presence of free water
0
50
100
150
200
-10 -5 0 5 10 15 20
T/ o
C
P/bar
0
500
1000
1500
2000
2500
P/psia
Deaton and Frost (1946)
Unruh and Katz (1949)
Larson (1955)
Takeuchi and Kennedi (1964)
Robinson and Mehta (1971)
Ng and Robinson (1985)
Mooijer et al. (2001)
Seo et al. (2001)
This work
HWHYD 2.1, this work
Hydrate Zone No Hydrate
LCO2 - H
VCO2 - H
VCO2 - Lw
LCO2 - Lw
VCO2 - I
SPE 123778
0
10
20
30
40
50
60
70
80
90
100
0 0.002 0.004 0.006 0.008 0.01
P-bara
Water Content - mole fraction
Ethane Water Content at 5°C
Propane Water Content 5°C
CO2 Water Content at 5°C
H2S Water Content at 5°C
Water Contents: VLE and LLE
• VLE and LLE of Ethane, Propane, H2S and CO2 – Water systems
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Bubble Point
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Water Content of CO2 at 15 °C
0
20
40
60
80
100
120
140
160
180
200
0 0.5 1 1.5 2 2.5 3 3.5
yw (x103
)/ mole fraction
P/bar
Liquid CO2
Vapour CO2
2.7°C
3.0°C
Water Content in the vapour and liquid phases of the carbon
dioxide-water system at approximately 15 °C (Solid red lines)
SPE 123778
• Model Comparisons (CO2 system - 250 ppm water)
1
10
100
1000
-50 -40 -30 -20 -10 0 10 20
T/
o
C
P/bar
VCO2
LCO2
VCO2- H
LCO2- H
VCO2- I
Hydrate Prevention-Dehydration
Yellow triangles represent the operating conditions
SPE 123778
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• Hydrate Phase Boundary (98% CO2 + 2% H2 - 250 ppm water)
1
10
100
1000
-40 -30 -20 -10 0 10 20
T/ o
C
P/bar
V
V-I
V-Lc-H
Lc-H
V-Lc
Lc
V-H
Hydrate Prevention-Dehydration
Pink triangles represent the operating conditions
SPE 123778
Avoiding Hydrate Problems
• Water removal (De-Hydration)
• Increasing the system temperature
• Insulation
• Heating
• Reducing the system pressure
• Injection of thermodynamic
inhibitors
• Methanol, ethanol, glycols
• Using Low Dosage Hydrate
Inhibitors
• Kinetic hydrate inhibitors (KHI)
• Anti-Agglomerants (AA)
• Various combinations of the above
• Cold Flow
Pressure
No Hydrates
Hydrates
Wellhead
conditions
Temperature
Downstream
conditions
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Avoiding Hydrate Problems-Temperature
Pressure
Temperature
No Hydrates
Hydrates
Lw-LHC-H-V
Wellhead
conditions
Downstream
conditions
Reducing Heat Loss, or
Increasing TemperatureHEAT
Avoiding Hydrate Problems-Pressure
Pressure
Temperature
No HydratesHydrates
Lw-LHC-H-V
Wellhead
conditions
Downstream
conditions
Reducing
System
Pressure
Pressure is energy and pressure reduction is generally is not used for
hydrate prevention, but remediation
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Avoiding Hydrate Problems
• Water removal (De-Hydration)
• Increasing the system temperature
• Insulation
• Heating
• Reducing the system pressure
• Injection of thermodynamic
inhibitors
• Methanol, ethanol, glycols
• Using Low Dosage Hydrate
Inhibitors
• Kinetic hydrate inhibitors (KHI)
• Anti-Agglomerants (AA)
• Various combinations of the above
• Cold Flow
Pressure
No Hydrates
Hydrates
Wellhead
conditions
Temperature
Downstream
conditions
Thermodynamic Inhibitors
Pressure
Temperature
No Hydrates
Hydrates
Lw-LHC-H-V
Wellhead
conditions
Downstream
conditions
Thermodynamic Inhibitor
Injection
Limitations:
- water cut
- cost (CAPEX and OPEX)
- environmental impact
- flow regime
- operational difficulties
- other problems
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Salting-Out
• Hydrates exclude salts from their structures, hence
hydrate formation could result in salt formation (salt
plug)
• Effect of temperature and pressure on the solubility
of salts in aqueous phase
• Alcohols and glycols are very
soluble in water and their
presence could result in a
reduction in the solubility of
salts (salt formation)
• Check solubility in highly
saline-organic inhibitor
systems
Avoiding Hydrate Problems
• Water removal (De-Hydration)
• Increasing the system temperature
• Insulation
• Heating
• Reducing the system pressure
• Injection of thermodynamic
inhibitors
• Methanol, ethanol, glycols
• Using Low Dosage Hydrate
Inhibitors
• Kinetic hydrate inhibitors (KHI)
• Anti-Agglomerants (AA)
• Various combinations of the above
• Cold Flow
Pressure
No Hydrates
Hydrates
Wellhead
conditions
Temperature
Downstream
conditions
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CO2 Hydrates with and without LDHI-A
0.2 mm
CO2 Without LDHI CO2 With LDHI-A
Avoiding Hydrate Problems
• Water removal (De-Hydration)
• Increasing the system temperature
• Insulation
• Heating
• Reducing the system pressure
• Injection of thermodynamic
inhibitors
• Methanol, ethanol, glycols
• Using Low Dosage Hydrate
Inhibitors
• Kinetic hydrate inhibitors (KHI)
• Anti-Agglomerants (AA)
• Various combinations of the above
• Cold Flow
Pressure
No Hydrates
Hydrates
Wellhead
conditions
Temperature
Downstream
conditions
Maximum Pressure
MinimumTemperature
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Evaluating Kinetic Hydrate Inhibitors
0
200
400
600
800
1000
1200
1400
1600
1800
2000
0 500 1000 1500 2000
Time/min
P/psia
0
2
4
6
8
10
12
14
16
18
20
T/o
C
P/psia
T/C
Induction Time
Pressure
No Hydrates
Hydrates
Wellhead
conditions
Temperature
Downstream
conditions
Maximum PressureMinimumTemperature
DTmax
Fluid Residence Time for test = Normally much higher than the Actual Residence Time
Hydrate Induction Time from test = Should be higher than the above Residence Time
Induction Time Method
KHIs: New CGI Approach Test Procedure
Growth/dissociation behaviour in a simple methane-water system
20
30
40
50
60
70
80
0 2 4 6 8 10 12
T / C
P/bar
Cooling
Growth
Univariant
equilibrium
(growth)
Rapid heating / dissociaiton
Re-cooling
into HSZ
Univariant
equilibrium
(growth)
F = 2C(H20,CH4) - 3P(H+L+G) + 2 = 1
Crystal Growth Inhibition (CGI)
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KHIs: New CGI Approach Test Procedures
Determination of CGI regions for 0.25 mass% PVCap with methane
60
65
70
75
80
0 5 10 15
T / C
P/bar
RFR
60
65
70
75
80
0 5 10 15
T / C
P/bar
RFR
60
65
70
75
80
0 5 10 15
T / C
P/bar
RFR
Dissociation
inside HSZ
60
65
70
75
80
0 5 10 15
T / C
P/bar
RFR
Dissociation
inside HSZ
60
65
70
75
80
0 5 10 15
T / C
P/bar
CIRRGR
1
RFR
0
Dissociation
inside HSZ
60
65
70
75
80
0 5 10 15
T / C
P/bar
RFR
SDR
SDR = Slow
Dissociation
Region
CIR = Complete
Inhibition Region
SGR = Slow
Growth Rate
region
RGR = Rapid
Growth Region
V
S
M-
R
SGRRGR
CGI Approach: Methane-PVCap Systems
Experimental CGI regions for 1.0 mass% PVCap with methane
CGI boundaries at
DTsub = ~5.3 C
and ~7.2 C are
shared with 0.5%
PVCap. Related
to underlying
crystal growth
patterns?
0
50
100
150
200
250
300
-2 2 6 10 14 18 22 26
T / °C
P/bar
CIRRGR SDR
VS
1
S
2
RFR SGR
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KHIs: Effect of KHI Formulation
Measured CGI regions for a range of commercial KHIs with a synthetic
natural gas and real field condensate (real field development evaluation)
CGI regions can be
used to robustly
compare relative
KHI hydrate
inhibition
performance at
pipeline conditions
-16 -14 -12 -10 -8 -6 -4 -2 0 2 4 6 8 10 12
KHI G
KHI F
KHI E
KHI D
KHI C
KHI B
KHI A
DTs-II / C at 80 bar
RFR
RGR(M)
RGR(VS)
CIR (s-I)
CIR (s-II)
SDR
LF (%)
0.6%
1.2%
Hs-I Hs-II
RGR
SGR
(M,S,VS)
CGI Approach: Natural Gas-PVCap Systems
Experimental CGI regions for 1.0 mass% PVCap with natural gas
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CGI Approach: Natural Gas-PVCap Systems
Experimental CGI regions for 1.0 mass% PVCap with natural gas
CGI Approach: Natural Gas-PVCap Systems
Experimental CGI regions for 1.0 mass% PVCap with natural gas
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CGI Approach: Natural Gas-PVCap Systems
Experimental CGI regions for 1.0 mass% PVCap with natural gas
KHIs: Effect of Hydrate Structure
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Hydrate Safety Margin: Requirements
• Hydrate Stability Zone
• Composition of hydrocarbon phase
• Hydrate inhibition characteristics of the
aqueous
• Salt
• Chemical hydrate inhibitors
• Pressure and temperature profile and/or the
worst operation conditions
• Computer simulation and/or P & T sensors
• Why there could be a risk of hydrates
• Uncertainty in water cut
• Inhibitor partitioning in different phases
• Equipment malfunctioning and/or human error
• Changes to the system conditions
• Off-spec Inhibitor
Pressure
No Hydrates
Wellhead
conditions
Temperature
Downstream
conditions
Hydrate
Stability Zone
Hydrates
Safety Margin
Extra Safety Factor by Measuring Actual Concentration of Inhibitor
Determining Inhibitor Concentration (HydraCHEK)
• Measuring electrical conductivity (C) and acoustic velocity (V) in the
produced water
• Temperature and pressure are also measured to account for their effect
• The measured parameters are fed into an ANN system which in turn
gives salt, KHI and organic inhibitor concentrations within few seconds
Artificial
Neural
Network
(ANN)
Produced water
sample analyser
C
V
Vt
Salt, KHI,
& inhibitor
(MEG, MeOH…),
concentration
T,P
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Monitoring Hydrate Safety Margin
• Knowing the hydrocarbon composition the hydrate zone can be determined
• Superimposing the operating conditions, safety margin is determined
• Alternative option for conditions where there is no free water sample
Hydrate model /
Correlation
Hydrocarbon
composition
Aqueous phase
composition
%MEG, %Salt,
%MeOH, %KHI
Hydrate risk
Low safety margin
Safe/optimised
Over inhibited
Pressure
No Hydrates
Wellhead
conditions
Temperature
Downstream
conditions
Over
inhibited
Under
inhibited
Extra Safety Factor
Detecting Early Signs of Hydrate Formation (HydraSENS)
• Hydrates prefer large and round molecules (e.g., C3 and i-C4 in sII
hydrates) in their structures
51264
H2S
CO2
C2
C1
C3
i-C4
N2
HydraSENS can detect early signs of hydrate formation,
and hydrate dissociation.
It also estimate the point of hydrate formation.
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Hydrate Blockage Removal
• It should be noted that hydrate blockages are case
specific and each case should be investigated on its
own merits.
• General guidelines
• Depressurisation
• Heating
• Injection of thermodynamic inhibitors
• Changing the gas composition
• Combinations of the above
Burning Snow Ball
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Thank you
Any question?
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Gas Hydrates, Theory and Practice
Professor Bahman Tohidi
14 – 18 September 2020 and 16 – 20 November 2020
Register@petro-teach.com or train@petro-teach.com
The main objective of this five-day course is to provide solid theoretical background and
hands-on experience in the evaluation of gas hydrate problems during different
production/process/drilling scenarios. Various methods for hydrate prevention and
mitigation will be discussed. A new topic is effect of heat transfer and time on hydrate
formation/blockage and melting/mitigation will be discussed with several case studies. A core
focus of the course is the practical application of theory to solve various hydrate related
operational problems and delegates are encouraged to participate with examples and case
studies from their own experience. A one month license for our hydrate prediction software
(HydraFLASH) will be provided to the participants for simulating various scenarios and going
over the course exercises during/after the course.
Learning Objectives:
• Learn about how and why hydrates can form and how to evaluate the risk
• Understand the methods for avoiding hydrate formation
• Find out how to model hydrate formation at various scenarios
• Discuss practical solutions to hydrate problems that can arise
• Learn various techniques that can be used for hydrate blockage removal
• Calculate time required for hydrate partial/complete blockage and/or dissociation
• Case studies
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