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New Techniques in Corolling Gas Hydrates [Recovered] Techniques in Corolling Gas Hydrates... · New...

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  • 10/01/2018

    1

    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, [email protected]

    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

  • 10/01/2018

    2

    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

  • 10/01/2018

    3

    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

  • 10/01/2018

    4

    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

  • 10/01/2018

    5

    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

  • 10/01/2018

    6

    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

  • 10/01/2018

    7

    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

  • 10/01/2018

    8

    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

  • 10/01/2018

    9

    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, 79 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, 36 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)

  • 10/01/2018

    10

    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

    Queens 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

  • 10/01/2018

    11

    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 Glnat, 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

  • 10/01/2018

    12

    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)

  • 10/01/2018

    13

    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

  • 10/01/2018

    14

    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

  • 10/01/2018

    15

    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

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