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HYDRAFACT

New Techniques in Controlling Gas Hydrates

Professor Bahman Tohidi

Hydrafact Ltd. & Centre for Gas Hydrate ResearchInstitute of Petroleum Engineering

Heriot-Watt University

Edinburgh EH14 4AS, UK, B.Tohidi@hw.ac.uk

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

-Bond can be very weak to very strong

-In water, up to 4 bonds

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What Are Gas Hydrates?

• Crystalline solids wherein guest or “former” (generally gas) molecules are trapped in cages formed from hydrogen bonded water molecules (host)

• They are formed as a result of physical combination of water and gas molecules – Stabilization due to van der Waals forces

• No bonding exists between the guest and host molecules

• Guest molecules are free to rotate inside the cages

– Solid solution

• Unlike inorganic hydrates (e.g., CuSO4.5H2O) the ratio between water and gas is not constant

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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History of Gas Hydrates

• Scientific curiosity (1810)

• Hindrance to hydrocarbon production (1934)

• Potential source of energy (1960s)

• Some of the current issues:– Flow assurance, storage and transportation of natural gas, hydrogen and CO2,

wellbore integrity in hydrate bearing sediments, subsea landslides, potential hazard in deepwater drilling, separation of oil and gas, global climate change

• Potential gas production from hydrates

Gas Hydrate Formation

• The necessary conditions:

– Presence of water or ice

– Presence of suitable size non-polar or

slightly polar molecules

– Suitable condition of pressure and

temperature

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Where Can They Form?

• They can form anywhere, such as:

– Pipelines (offshore and onshore)

– Processing facilities (separators, valves, etc)

– Heat exchangers

– Sediments (permafrost regions and subsea sediments)

– Offshore drilling operations

– Etc

Interesting Properties

• Capture large amounts of gas (up to 15 mole%)

• Remove light components from oil and gas

• Form at temperatures well above 0 °C

• Generally lighter than water

• Need relatively large latent heat to decompose

• Non-stochiometric

• More than 85 mole% water in their structure

• Exclude salts and other impurities

• Result from physical combination of water and gas

• Hydrate composition is different from the HC phase

• Large amounts of methane hydrates exist in nature

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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 FlowP

ressu

re

No Hydrates

HydratesWellhead

conditions

Temperature

Downstream

conditions

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

Pre

ssu

re

No Hydrates

Wellhead

conditions

Temperature

Downstream

conditions

Hydrate

Stability Zone

Hydrates

Safety Margin

Extra Safety Factor by Measuring Actual Concentration of Inhibitor

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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 watersample analyser

C

V

Vt

Salt, KHI, & inhibitor (MEG, MeOH…),concentrationT,P

Hydrate Safety Margin Monitoring (HydraCHEK)

• Knowing the hydrocarbon composition the hydrate stability 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

Hydrocarboncomposition

Aqueous phasecomposition%MEG, %Salt, %MeOH, %KHI

Pre

ssu

re

No Hydrates

Wellhead conditions

Temperature

Downstreamconditions

Over

inhibitedUnder

inhibited

Hydrate risk

Low safety margin

Safe/optimised

Over inhibitedExtra Safety Factor

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Application of HydraCHEK in the North Sea

• Chemical and significant resources were required for the above

techniques

• Also the techniques were time consuming which was a constraint to

effectively monitor the hydrate inhibition in real time

• HydraCHEK was deployed for simultaneous monitoring of salt and

methanol

• As a result methanol injection was reduced to less than 5 wt% from

designed 28 wt%, savings in the order of millions of GBP per year

• See http://hydrafact.com/technology_hydrachek.html for the full paper

• NUGGETS is a gas reservoir in the North Sea

• The initial reservoir pressure was 150 bar with

a minimum seabed temperature of 5 °C

• Based on 3 °C safety margin injection of 28

wt% methanol was used

• Methanol and chloride content were

monitored using Karl Fischer and Mohr

titration techniques, respectly

Minimising Methanol Injection

• In 2011 the water production rate reached its

maximum

• On the other hand methanol was causing product

contamination

• Methanol injection was reduced to practically zero

– Methanol is being used only as a carrier fluid for corrosion

inhibitor

• The system was operated inside the Hydrate Stability

Zone

– Hydrate Slurry Transport (setting an upper limit of 10%)

– Salinity increase was used as a measure for monitoring

hydrate formation and concentration of hydrates in the slurry

SPE 166596

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Minimising Methanol Injection

SPE 166596

• Background salt concentration was 4.5 wt%

• Monitoring changes in salinity of aqueous phase was

used for determining the concentration of hydrates in

the slurry, while operating inside the hydrate stability

zone.

• Increasing the salt concentration in free aqueous

phase to 5 wt% indicates the presence of 10%

hydrate slurry in the aqueous phase

• Monitoring other production parameters (pressure

drop, changes in the production rates of gas and

water, separator temperature, etc)

HydraCHEK provided 24-48 hours advanced warning prior to blockage

Results

• The field life has been extended by three years with an incremental production of

more than 5 million BOE to date

• Steady production operations below nominal turndown and operating within hydrate zone

• Significant reduction of Methanol usage

• Preventing condensate containmation

• Extra income in the range of 100s millions GBP (based on a rough calculations) from sale of the gas, payback period of less than 1 day

• Online HydraCHEK ready for field trials

Online HydraCHEK

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Trials of HydraCHEK

• High concentration of MEG by Statoil (Trondheim , Norway)

• KHI systems by Dolphin Energy (Total) in Qatar1

• MeOH + salt systems by Petronas in their FPSO lab (Mauritania)

• MEG + salt systems by NIGC (South Pars Gas Complex (SPGC) Field)2

• Methanol + salt, Total, Alwyn, North Sea3

• Methanol + salt, Woodgroup (Triton FPSO) and Shell (Shearwater) North Sea4

• Salt + Inhibitor, ConocoPhillips, North Sea

• Salt + MEG, Petronas (Turkmenistan) and Cameron (Pilot Plant, University of

Manchester)

• KHI systems, Champion Technologies

• Salt + Methanol, NUGGETS, North Sea5

1. Lavallie, O., et al., Successful Field Application of an Inhibitor Concentration Detection System in Optimising the Kinetic

Hydrate Inhibitor (KHI) Injection Rates and Reducing the Risks Associated with Hydrate Blockage, IPTC 13765,

International Petroleum Technology Conference held in Doha, Qatar, 7–9 Dec 2009.

2. Bonyad, H., et al., Field Evaluation of A Hydrate Inhibition Monitoring System. Presented at the 10th Offshore

Mediterranean Conference (OMC), Ravenna, Italy, 23-25 Mar 2011.

3. Macpherson, C., et al., Successful Deployment of a Novel Hydrate Inhibition Monitoring System in a North Sea Gas

Field. Presented at the 23rd International Oil Field Chemistry Symposium, 18 – 21. Mar 2012, Geilo, Norway.

4. Henderson, S., Smith, A., Mazloum, S., Tohidi, B., “Methanol Partitioning and Optimisation Study Using an Innovative

Hydrate Inhibitor Monitoring Technology”, ICGH9, June 2017, Denver, USA

5. Saha, P., Parsa, A. Abolarin, J. “NUGGETS Gas Field - Pushing the Operational Barriers”, SPE 166596, at the SPE

Offshore Europe Oil and Gas Conference and Exhibition held in Aberdeen, UK, 3–6 September 2013.

Other Potential Applications

• Monitoring LDHI concentration in produced/disposal water

• Detecting formation water breakthrough

• Determining water production rate by measuring inhibitor

concentration in the aqueous phase (assuming inhibitor

injection rate is known)

• Monitoring efficiency of processes with monitoring

concentrations in the aqueous phase (e.g., MEG regeneration)

• Monitoring quality of chemicals (e.g., fluids introduced into

umbilicals)

• Integration with Multi-Phase Flow Meters (MPFM) could

potentially improve the flow measurements in MPFM

• Could potentially be used for detecting hydrate formation

(sudden change in the concentration of salts and/or inhibitors)

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Summary/Conclusions

• Techniques have been developed for monitoring hydrate safety

margin and detecting early signs of hydrate formation (patents

pending)

• A robust and quick technique based on measuring electrical

conductivity and acoustic velocity has been developed for

determining concentration of salts and hydrate inhibitors in an

aqueous phase

• The technique has been tested extensively (in various laboratories

and fields)

• A technique based on measuring the amount of water in the gas

phase has been developed

• Extra safety measure against changes in the system, etc.

• This technology played an important role in IPE winning the

Queen’s Award in 2015

Detecting Early Signs of Hydrate Formation

• Hydrates prefer large and round molecules (e.g., C3 and i-C4 in sIIhydrates) in their structures

51264

Pre

ssure

, M

Pa

Temperature, K

Methane

Ethane

Propane

I-Butane

268 278 288 298273 283 293 3030.1

80

40

10

20

8

4

2

10.8

0.4

0.2

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Effect of Hydrates on Gas CompositionPredictions by HydraFLASH Fluid Phases/mole% Hydrate/mole%

Component(s) Feed Vapour Polar Overall

Overall,

WFB

Methane 91.3306 91.3854 0.0571 7.9486 62.4718

Ethane 5.6430 5.6078 0.0057 1.9568 15.3794

Propane 1.0690 1.0144 0.0009 2.2150 17.4087

i-Butane 0.1546 0.1441 0.0000 0.4207 3.3065

n-Butane 0.1938 0.1917 0.0001 0.0973 0.7645

i-Pentane 0.0592 0.0594 0.0000 0.0000 0.0000

CO2 0.7819 0.7785 0.0172 0.0698 0.5490

Nitrogen 0.7679 0.7698 0.0000 0.0153 0.1201

WATER 0.0488 99.9189 87.2765

Amount of water converted to Hydrates 10.2%

C1/C3 85.436 90.088 3.589

C1/iC4 590.659 634.180 18.894

Hydrate density (g/cc): 0.944354

Hydrate mf: 0.020728

Molar phase fraction 0.797604 0.181668 0.020728

Hydrates in a Mature Field

• Very high gas to condensate ratios

• High water cut, hence switched to AA for Hydrate Blockage

Control

• Online Gas Chromatograph was installed on gas outlet to see

if hydrate formation can be detected

Philippe Glénat, Jean-Michel Munoz, Reza Haghi, Bahman

Tohidi, Saeid Mazloum and Jinhai Yang, “FIELD TEST

RESULTS OF MONITORING HYDRATES FORMATION BY GAS

COMPOSITION CHANGES DURING GAS/CONDENSATE

PRODUCTION WITH AA-LDHI”, Proceedings of the 8th

International Conference on Gas Hydrates (ICGH8-2014),

Beijing, China, 28 July - 1 August, 2014

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ResultssII hydrates use C3 and iC4, hence an increase in C1/C3 and C1/iC4 ratios

Gas Released from Hydrates

• When hydrates dissociate the remnant of hydrate structure will remain in the aqueous phase for considerable time (hydrate memory)

• As a result, dissociation of hydrates will result in an unusually high concentration of large and round molecules (e.g., C3 and i-C4) in the aqueous phase– Can we use this property as an early warning technique?

• Feasibility of the technique

• Can it be applied in field condition?

• Amount of gas released from degasser may increase (i.e., increased gas/water ratio)

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Potential Implementation Configuration

Another

Another

Obviously gas based detection

techniques are preferred to minimise

the delay and maximise time available

for taking mitigation measures

Slug catcher

ComponentHydrates

Mole%

Blank test

mole%

Methane 76% 93%

Ethane 15% 5%

Propane 8% 1%

i-Butane 1% 0%

n-Butane 1% 0%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

Methane Ethane Propane i-Butane n-Butane

Component

mo

le%

Hydrate water

Blank test

• Simulating pipeline

condition and

forming about 35%

hydrate based on

aqueous phase

C1 mole%-50

Composition of Gas Released from Aqueous Phase

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Potential Implementation Configuration

Another

AnotherKnowing the slip velocity (i.e.,

velocity difference between gas and

water phase) is it possible to

estimate the location of hydrate

formation?

Slug catcher

Integration of HSMM and HED Systems

Another

Another

HydraCHEK

Integration of hydrate

safety margin monitoring

and early detection

systems to optimise

inhibitor injection rate and

minimise risk of hydrate

formation

Slug catcher

Pre

ssu

re

No Hydrates

Wellhead

conditions

Temperature

Downstream

conditions

Hydrate

Stability Zone

Hydrates

Safety Margin

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Summary/Conclusions

• A technique for detecting early signs of hydrate formation

from monitoring changes in the gas composition has

been developed and extensively tested in the lab

• Hydrate formation could be detected by monitoring the

gas phase composition

• Composition of the gas released from the aqueous phase

(first stage separator, or samples taken from aqueous

phase) can potentially be used for detecting early signs of

hydrate formation

• Sudden increase in the amount of gas released from the

aqueous phase could potentially be used as another

indication

Summary/Conclusions

• Knowing the slip velocity (i.e., velocity difference between

gas and water phase) it might be possible to estimate the

location of hydrate formation

• A field trial of the technique was successful

• If you had a near miss, it would be good to test the

technique against gas compositional/volume data

• Integration of hydrate safety margin monitoring and early

detection could provide a powerful tool for minimising

inhibitor injection rate and improving the reliability of

hydrate prevention techniques