Hydrates petro teach-free webinar-5 august 2020

1. 06/08/2020 1 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. 2 1 2

2. 06/08/2020 2 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 3 4

3. 06/08/2020 3 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 51262 51264 Structure I Structure II Structure H 3 16 2 1 8 6 51268 2 Hydrate Formation, Distilled Water + Methane 5 6

4. 06/08/2020 4 Hydrate Formation, Distilled water + Dissolved CO2 Hydrate Stability of Pure Compounds (HydraFLASH) H2S CO2 C2 C1 C3 i-C4 N2 7 8

5. 06/08/2020 5 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 9 10

6. 06/08/2020 6 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) 11 12

7. 06/08/2020 7 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 13 14

8. 06/08/2020 8 Hydrates in a Low Water Content Gas CO2 Phase Behaviour Pipe Ships 15 16

9. 06/08/2020 9 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 18 Bubble Point 17 18

10. 06/08/2020 10 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 19 20

11. 06/08/2020 11 • 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 21 22

12. 06/08/2020 12 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 23 24

13. 06/08/2020 13 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 25 26

14. 06/08/2020 14 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 27 28

15. 06/08/2020 15 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 29 30

16. 06/08/2020 16 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) 31 32

17. 06/08/2020 17 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 33 34

18. 06/08/2020 18 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 35 36

19. 06/08/2020 19 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 37 38

20. 06/08/2020 20 CGI Approach: Natural Gas-PVCap Systems Experimental CGI regions for 1.0 mass% PVCap with natural gas KHIs: Effect of Hydrate Structure 39 40

21. 06/08/2020 21 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 41 42

22. 06/08/2020 22 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. 43 44

23. 06/08/2020 23 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 45 46

24. 06/08/2020 24 Thank you Any question? 47 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 48 47 48

Hydrates petro teach-free webinar-5 august 2020

Hydrates petro teach-free webinar-5 august 2020

Hydrates petro teach-free webinar-5 august 2020

Recomendados

Mais conteúdo relacionado

Mais procurados

Mais procurados(20)

Similar a Hydrates petro teach-free webinar-5 august 2020

Similar a Hydrates petro teach-free webinar-5 august 2020(20)

Último

Último(20)

Hydrates petro teach-free webinar-5 august 2020