Advances in Avoiding Gas Hydrate Problems Prof Bahman Tohidi Centre - - PowerPoint PPT Presentation

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Advances in Avoiding Gas Hydrate Problems

Prof Bahman Tohidi

Centre for Gas Hydrate Research & Hydrafact Ltd.

Institute of Petroleum Engineering Heriot‐Watt University Edinburgh EH14 4AS, UK, B.Tohidi@hw.ac.uk

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What Are Gas Hydrates?

• Hydrates are crystalline solids wherein

guest (generally gas) molecules are trapped in cages formed from hydrogen bonded water molecules (host)

• They look like ice, but unlike ice they can

form at much higher temperatures

• Presence of gas molecules give extra

attraction, hence stability, fixing the position of water molecules, i.e., freezing at temperatures higher than 0 °C

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Necessary Conditions

• 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

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Hydrates in Subsea Sediments

• There are massive

quantities of gas hydrates in permafrost and

• cean sediments.

5 10 15 20 25 30 35 275 285 295 305 315 325 335 345 355 T/K P/MPa

5 10 15 20 25 30 35 275 285 295 305 T/K P/MPa

Depth

5 10 15 20 25 30 35 275 285 295 305 315 325 335 345 355 T/K P/MPa

5 10 15 20 25 30 35 275 285 295 305 T/K P/MPa

Depth

hydrates no hydrates hydrates no hydrates

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Hydrate Stability Zone in Subsea Sediments

Sea Floor 273 283 293

Temperature / K Depth/Metre

1500 500 1000 Zone of Gas Hydrates in Sediments Hydrate Phase Boundary Hydrothermal Gradient Geothermal Gradient

The Sediments are saturated with water

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Hydrate Stability Zone in Permafrost

Depth of Permafrost Phase Boundary Zone of Gas Hydrates in Permafrost Geothermal Gradient

Depth/Metre

273 283 293

Temperature / K

1500 500 1000 263 Geothermal Gradient in Permafrost

The Sediments are saturated with water Permafrost

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Methane Hydrate Discoveries

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Methane Hydrates

Estimated at twice total fossil fuels

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Scope

• Why hydrates can be dangerous
• Techniques for avoiding gas hydrate problems
• Hydrate safety margin monitoring
• Hydrate early detection system
• Kinetic hydrate inhibitors
• Conventional testing techniques for KHIs
• New testing techniques
• KHI: challenges and opportunities
• Conclusions

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Why Hydrates Can be Dangerous

• Hydrate formation can block pipelines, wellbore/tubing
• Preventing production and/or normal operation
• Prevent access to wellbore
• Therefore, a hydrate blockage should avoided/removed
• There are various options associated with respect to

avoiding/removing hydrate blockages

• There are serious risks associated with techniques used for

removal of a hydrate blockage

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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

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Hydrate Safety Margin Monitoring & Early Detection System

• Methods for determining the hydrate

safety margin (HSM) of pipeline fluids – Determining chemical concentrations – Ensuring adequate inhibition – Optimising inhibitor injection practices

• Detecting early signs of hydrate

formation

• Ultimately to develop online hydrate

monitoring and warning systems

Hydrate risk Low safety margin Safe/optimised Over inhibited

Pressure No Hydrates

Wellhead conditions

Temperature

Downstream conditions Hydrate Stability Zone

Hydrates

Safety Margin

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Hydrate Safety Margin: Requirements

• Hydrate Stability Zone

– Composition of hydrocarbon phase (normally determined from PVT analysis) – Hydrate inhibition characteristics of the aqueous phase (composition in most cases)

– Salt – Chemical hydrate inhibitors (alcohols, Glycols, LDHI)

• Pressure and temperature profile and/or the

worst operation conditions

– Computer simulation and/or P & T sensors

Pressure No Hydrates

Wellhead conditions

Temperature

Downstream conditions Hydrate Stability Zone

Hydrates

Safety Margin

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Determining Inhibitor Concentration

• 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 Artificial Neural Network (ANN)

Produced water sample analyser

C V Vt

Salt, KHI, & inhibitor (MEG, MeOH…), concentration

T,P

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Hydrate Safety Margin Monitoring

• 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 Hydrocarbon composition Aqueous phase composition %MEG, %Salt, %MeOH, %KHI

Pressure No Hydrates

Wellhead conditions

Temperature

Downstream conditions

Over inhibited Under inhibited

Hydrate risk Low safety margin Safe/optimised Over inhibited

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Trials of Safety Margin Monitoring Techniques

• 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 Sea
• Salt + Inhibitor, ConocoPhillips, North Sea
• Salt + MEG, Petronas (Turkmenistan) and Cameron (Pilot Plant, University of Manchester)
• KHI systems, Champion Technologies
• Salt + Methanol, NUGGETS, North Sea4

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. 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.

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Hydrate Inhibitor Monitoring System in a North Sea Gas Field

• Location
• 4 Gas bearing Eocene Structures
• 40 ‐ 70 Km tie‐back
• Reservoir Characteristics
• Frigg Sandstone
• Ф=30%, k=2000 ‐ 4000mD; Kv/Kh ≈ 1
• Reservoir Pressure =155 bara
• Temperature = 57 °C
• C1 = 98%
• CGR = 2.1 E‐6 Sm3/Sm3
• Strong aquifer influx

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Hydrate Phase Boundary

20 60 100 140 180 3 6 9 12 15 18

Pressure / bara Temperature/ oC DW KF + EQ NaCl C‐V Optimised with C‐V N1 manifold PT

• Methanol injection was reduced to less than 5 wt% from designed 28 wt%
• Savings in the order of millions of GBP per year

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Minimising Methanol Injection

Nuggets Gas Field – Pushing the Operational Barriers (SPE 166596)

• In 2010 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 – Salinity increase was used as a measure for monitoring hydrate formation and concentration of hydrates in the slurry SPE 166596

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Results

• Nuggets field life has been extended by three years with an

incremental production of nearly 3 million BOE to date

• Steady production operations below nominal turndown and
• perating within hydrate zone
• Significant reduction of Methanol usage
• Field life has been extended by 3 years with the possibility of

further prospects being tied‐in to the existing facilities

• 2% increase in Recovery Factor
• Extra income of tens of millions GBP per year

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Summary/Conclusions

• 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 hydrates safety margin monitoring

technique based on measuring the amount of water in the gas phase has been developed

Pressure No Hydrates

Wellhead conditions

Temperature

Downstream conditions Hydrate Stability Zone

Hydrates

Safety Margin

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Hydrate Early Detection System

• It is believed initial hydrate formation does not result in pipeline

blockage in many systems

• Therefore, detecting the signs of initial hydrate formation could

provide an early warning system

• Hydrates prefer large and round molecules (e.g., C3 and i‐C4 for sII

hydrates) in their structures

• Hydrate formation results in a reduction in the concentration of

large and round molecules in the gas phase

• Can we use this property as an early detection technique against

background compositional changes?

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Detecting Early Signs of Hydrate Formation

• Hydrates prefer large and round molecules (e.g., C3 and i‐C4 in

sII hydrates) in their structures

51264

Pressure, MPa Temperature, K

Methane Ethane Propane I‐Butane

268 278 288 298 273 283 293 303 0.1 80 40 10 20 8 4 2 1 0.8 0.4 0.2

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Potential Implementation Configuration

Another Another

Slug catcher

Hydrate formation results in a reduction in the concentration

• f large and round molecules in the gas phase

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Field Demonstration/Trial

• Mature gas field
• Very high gas to condensate ratios
• High water cut, hence switched to AA for Hydrate Blockage Control
• Online Gas Chromatograph was installed to see if hydrate formation

can be detected

• The field trail was successful, detecting early signs of hydrate formation
• Hydrates were forming mainly at night times
• The results could be used to optimise AA injection
• A paper is being prepared and will be presented at the 8th International

Conference on Gas Hydrates in July 2014

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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

• 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

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Avoiding Hydrate Problems‐Kinetic Hydrate Inhibitors

Pressure Temperature

No Hydrates Hydrates Lw-LHC-H-V Upstream conditions Downstream conditions

T

200 400 600 800 1000 1200 1400 1600 1800 2000

500 1000 1500 2000

Time/min P /p sia

2 4 6 8 10 12 14 16 18 20

T /oC

P/psia T/C

Induction Time

Induction time should be longer than the fluid residence time!

Test Conditions: Minimum Temperature & Maximum Pressure!!!

Tmin & Pmax

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KHI Performance Testing

3 vol% KHI+10 Wt% MEG 4 vol% KHI 4 vol% KHI + 15 wt% MEG + 25 ppm Corrosion Inhibitor 3 vol% KHI+10 Wt% MEG Repeat

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KHIs: New Evaluation Method

• Problems associated with induction‐time based approach

– Lack of repeatability, suitability questions in shut‐in conditions, hydrate formation at the top of the pipeline, time requirements – Lack of predictability – Poor operator confidence: hindering KHI adoption

• Benefits of the new approach

– Faster KHI evaluation process – Providing robust, repeatable and transferable KHI data – Increasing operator confidence in KHI performance – Improving our understanding of KHI inhibition mechanisms

• New ‘CGI (Crystal Growth Inhibition)’ method developed

2009‐12 at Heriot‐Watt University

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KHIs: Standard Lab Equipment

High pressure autoclaves or rocking cells – as standard for hydrate studies – can be used for KHI CGI and ti evaluation studies

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KHIs: CGI Method Basics

Example CGI cooling and heating data for water with methane (no KHI)

20 30 40 50 60 70 80 2 4 6 8 10 12

T (C) P (bar)

Cooling, no history, 1 °C / hr Cooling, hydrate present, 1 °C / hr Heating, with hydrate, rapid (stepped) F = 2C(H20,CH4) − 3P(H+L+G) + 2 = 1 CH4, s-I

4.7% hydrate 0.0% hydrate Hydrate growth rate = 14.2% / hr 1.4% hydrate

With no KHI, if hydrate is present, growth / dissociation occurs rapidly in response to temperature changes as expected

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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 5 10 15

T / C P / bar

RFR

60 65 70 75 80 5 10 15

T / C P / bar

RFR

60 65 70 75 80 5 10 15

T / C P / bar

RFR Dissociation inside HSZ

60 65 70 75 80 5 10 15

T / C P / bar

RFR Dissociation inside HSZ

60 65 70 75 80 5 10 15

T / C P / bar

CIR RGR

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RFR Dissociation inside HSZ

60 65 70 75 80 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

VS M-R SGR RGR

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Amount of Hydrates Formed vs Subcooling

Example CGI cooling run at constant pressure for 0.5 mass% PVCap aqueous with

• methane. Points are every 5 minutes

CGI Results are identical whether constant pressure or constant volume approaches are used

0.0 0.4 0.8 1.2 1.6 2.0 2.4

• 10
• 9
• 8
• 7
• 6
• 5
• 4
• 3
• 2
• 1

Ts-I (°C) Mass% H2O as hydrate

P = 77.9 bar (constant) CIR Average growth rate = 2.00% / hr Average growth rate = 0.00% / hr Average growth rate = 0.07% / hr RGR (S) RGR (M-R) SGR(S) SGR(M)

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KHIs: CGI and ti

Measured CGI regions and ti data vs. subcooling for 0.5 mass% PVCap aqueous with methane

20 40 60 80

• 10
• 8
• 6
• 4
• 2

Tsub / C ti / hrs

ti data CIR RGR RGR RFR

S M-R

• Open symbols

nucleation not

• bsereved
• bserved

RGR SGR SGR

80 bar

Induction times closely linked to CGI regions Explains ‘scatter’

• ver short

subcooling range & why ti impossible to measure at low subcoolings….

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Hydrate Phase Boundary of a Lean Natural Gas

50 100 150 200 250 300 350 5 10 15 20 25

Temperature/oC

Pressure/bar

Structure I Structure II

Operating conditions

C1 98.95 C2 0.070 C3 0.020 CO2 0.150 N2 0.810

Role of Hydrate Structure

50 100 150 200 250 300

• 2

2 6 10 14 18 22 26

T / °C P / bar

CIR RGR SDR VS 1 S 2 RFR

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KHIs: Evaluation using CGI method

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

2 4 6 8 10 12 KHI G KHI F KHI E KHI D KHI C KHI B KHI A

T

s-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)

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KHIs: CGI and ti

Measured CGI regions and ti data vs. subcooling for 0.5 mass% PVCap aqueous with standard North Sea natural gas

20 40 60

• 16
• 14
• 12
• 10
• 8
• 6
• 4
• 2

Ts-II (C) ti (hrs)

CIR P = 207 bar s-I RGR S VS s-I+s-II s-II

SGR RGR

Induction times closely linked to CGI regions Explains ‘scatter’

• ver short

subcooling range & why ti impossible to measure at low subcoolings….

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KHI Testing Techniques: Conclusions

• KHIs provide an effective means to mitigate hydrate problems

while offering significant CAPEX/OPEX savings

– Being used increasingly and with success in the field

• Novel crystal growth inhibition (CGI) studies show:

– KHIs induce well‐defined CGI regions as a function of subcooling ranging from complete inhibition (even dissociation), through severely to moderately reduced growth rates, to final rapid/catastrophic growth as subcooling increases – Closely related to induction time patterns – Method provides a means to assess KHIs more rapidly and reliably – Increased confidence as for worst case scenario (hydrate present) – Can be used to better understand inhibition mechanisms / effect of

• ther chemicals

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KHIs: Opportunities and Challenges

KHI in Stratified Flow Past

• KHIs cannot be used under stratified flow, as there would be no KHI in the gas

phase, hence hydrate can form from the condensed water at the top of the pipeline

• This can block the pipeline on its own, or hydrates from the top of the pipeline

coming into contact with the liquid containing KHI will result in KHI failure in the liquid phase

Now

• We now know that KHIs can act as thermodynamic inhibitor within CIR

(Continuous Inhibition Region), so if the system is within CIR hydrate crystals will not result in KHI failure

• In fact tests show that hydrates could melt if they come into contact with

aqueous phase containing KHI within CIR

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KHIs: Opportunities and Challenges

KHI in Produced Water Processing/Re‐Injection Past

• KHIs are polymers and their cloud point could be around 40 °C
• They can cause problem in pumps inlet strainers in hot environment
• They can cause blockage in produced water re‐injection wells

Now

• We can now remove KHIs from produced water by a solvent extraction

technique

• The technique is based on adding a solvent to the aqueous phase after

3‐phase separator

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Components

Mole%

Methane

56.14

Ethane

8.26

Propane

3.36

i‐Butane

0.56

n‐Butane

1.00

i‐Pentane

0.40

CO2

6.76

Nitrogen

0.35

n‐Pentane

0.34

n‐Heptane

0.42

n‐Octane

0.53

n‐Nonane

0.57

n‐Nonane

0.32

n‐Decane

0.98

Hydrate stability zone of the above fluid in the presence of condensed water. The green line is the estimated Complete Inhibition Region (CIR) where KHI can provide indefinite inhibition, similar to thermodynamic inhibitors. The results showed that KHI can replace 26‐35 wt% MEG, depending on the operating (or worst) conditions.

KHIs: MEG Equivalent

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KHIs: Opportunities and Challenges

KHI in Produced Water Processing/Re‐Injection Past

• KHI can replace large quantities of MEG (e.g., 20 to 40 wt%)
• This can result in a reduction in MEG regeneration units and/or handling

higher water cuts, longer field life, higher recovery factor

• However, due to problems associated with gunking in MEG regeneration units,

the full advantages of this combination have not been realised

Now

• We can now remove KHIs from produced water by a solvent extraction

technique

• The technique is based on adding a solvent to the aqueous phase after 3‐

phase separator

• The produced water, free of KHI, can be sent to MEG regeneration units

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KHIs: Opportunities and Challenges

KHI in Well Testing Past

• KHI can replace large quantities of thermodynamic inhibitors (e.g., 20 to 40 wt%)
• This can result in a reduction in the usage of thermodynamic inhibitors, and discharge

to the environment

• However, most KHI formulations are regarded as environmentally unacceptable

Now

• We can now remove KHIs from produced water by a solvent extraction technique
• The technique is based on adding a solvent to the aqueous phase after 3‐phase

separator

• The produced water, free of KHI with much reduced inhibitor concentration, can be

discharged to the environment

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KHIs: Opportunities and Challenges

Costs and Environmental Issues Associated with KHI Past

• KHIs are injected in upstream and disposed with produced water
• KHI are expensive and in general environmentally unfriendly
• This, combined with uncertainties in their effectiveness has limited their

application

Now

• We can now remove KHIs from produced water by a solvent extraction

technique

• The KHI‐rich solvent can be removed from the aqueous phase

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Conclusions

• Technique for determining hydrate safety margin could minimise inhibitor

injection rates, increase reliability, increase field life

• An online system has been developed and ready for field trial
• Early detection systems could play an important role in avoiding gas hydrate

blockages and minimising inhibitor injection rates

• New testing techniques are reliable and repeatable
• It is now possible to predict if KHI could be an option for a certain

development

• New understandings open new opportunities, e.g., shut‐in conditions, re‐

starts, hydrates at top of pipelines, KHIs can replace large quantities of MEG

• KHI removal eliminates some of PWRI problems and allows combined

KHI+MEG allocations

• KHI removal potential could play a major role in future KHI design

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Acknowledgements

• We would like to take this opportunity and thank all our

sponsors for their technical and financial support.

• B.Tohidi@hw.ac.uk