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 1
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 2
Necessary Conditions • The necessary conditions: – Presence of water or ice – Suitably sized gas/liquid molecules (such as C 1 , C 2 , C 3 , C 4 , CO 2 , P N 2 , H 2 S, etc.) – Suitable temperature and Hydrates pressure conditions • Temperature and pressure No Hydrates conditions is a function of T gas/liquid and water compositions. Hydrate phase boundary 3
Hydrates in Subsea Sediments T/K T/K 275 275 285 285 295 295 305 305 315 315 325 325 335 335 345 345 355 355 • There are massive 0 0 quantities of gas 35 35 5 5 30 30 hydrates in 25 25 hydrates 10 10 P/MPa P/MPa 20 20 15 15 permafrost and no hydrates 15 15 10 10 Depth Depth P/MPa P/MPa 5 5 ocean sediments. 20 20 0 0 275 275 285 285 295 295 305 305 T/K T/K 25 25 hydrates no hydrates 30 30 35 35 4
Hydrate Stability Zone in Subsea Sediments 273 283 293 0 Temperature / K Hydrothermal Gradient Depth/Metre 500 Hydrate Phase Boundary 1000 Sea Floor Geothermal Zone of Gradient Gas Hydrates in Sediments 1500 The Sediments are saturated with water 5
Hydrate Stability Zone in Permafrost 263 273 283 293 0 Temperature / K Geothermal Permafrost Gradient in Depth/Metre Permafrost 500 Depth of Permafrost Phase Zone of Boundary Gas Hydrates in Permafrost Geothermal 1000 Gradient 1500 The Sediments are saturated with water 6
Methane Hydrate Discoveries 7
Methane Hydrates Estimated at twice total fossil fuels 8
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 9
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 10
Avoiding Hydrate Problems • Water removal (De ‐ Hydration) • Increasing the system temperature – Insulation – Heating • Reducing the system pressure • Injection of thermodynamic inhibitors – Methanol, ethanol, glycols Wellhead • Using Low Dosage Hydrate Inhibitors Pressure Hydrates conditions – Kinetic hydrate inhibitors (KHI) – Anti ‐ Agglomerants (AA) • Various combinations of the above Downstream • Cold Flow conditions No Hydrates 11 Temperature
Hydrate Safety Margin Monitoring & Early Detection System Safety Margin • Methods for determining the hydrate Hydrate Stability safety margin (HSM) of pipeline fluids Zone Wellhead conditions – Determining chemical Hydrates Pressure concentrations – Ensuring adequate inhibition Downstream – Optimising inhibitor injection conditions No Hydrates practices Temperature • Detecting early signs of hydrate Hydrate risk formation Low safety margin • Ultimately to develop online hydrate Safe/optimised monitoring and warning systems Over inhibited 12
Hydrate Safety Margin: Requirements • Hydrate Stability Zone Safety Margin – Composition of hydrocarbon phase (normally Hydrate determined from PVT analysis) Stability Zone Wellhead – Hydrate inhibition characteristics of the aqueous conditions phase (composition in most cases) Pressure Hydrates – Salt – Chemical hydrate inhibitors (alcohols, Glycols, LDHI) Downstream conditions • Pressure and temperature profile and/or the No Hydrates worst operation conditions Temperature – Computer simulation and/or P & T sensors 13
Determining Inhibitor Concentration Artificial C Neural Network Salt, KHI, V (ANN) & inhibitor (MEG, MeOH…), concentration T,P Produced water sample analyser V t • 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 14
Hydrate Safety Margin Monitoring Over Under inhibited inhibited Wellhead conditions Pressure Hydrate model / Hydrocarbon Correlation composition No Hydrates Downstream conditions Aqueous phase Temperature composition %MEG, %Salt, Hydrate risk %MeOH, %KHI Low safety margin Safe/optimised Over inhibited • 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 15
Trials of Safety Margin Monitoring Techniques • High concentration of MEG by Statoil (Trondheim , Norway) • KHI systems by Dolphin Energy (Total) in Qatar 1 • 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 Sea 3 • 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 Sea 4 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. Bonyad, H., et al., Field Evaluation of A Hydrate Inhibition Monitoring System . Presented at the 10 th Offshore Mediterranean 2. 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 23 rd 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. 16
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; K v /K h ≈ 1 • Reservoir Pressure =155 bara • Temperature = 57 °C • C 1 = 98% • CGR = 2.1 E ‐ 6 Sm 3 /Sm 3 • Strong aquifer influx 17
Hydrate Phase Boundary 180 DW KF + EQ NaCl C ‐ V Optimised with C ‐ V 140 N1 manifold PT Pressure / bara 100 60 20 0 3 6 9 12 15 18 Temperature/ o C • Methanol injection was reduced to less than 5 wt% from designed 28 wt% • Savings in the order of millions of GBP per year 18
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 19
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 operating 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 20
Summary/Conclusions • A robust and quick technique based on Safety Margin measuring electrical conductivity and acoustic velocity has been developed Hydrate Stability for determining concentration of salts Zone Wellhead conditions and hydrate inhibitors in an aqueous Hydrates Pressure phase • The technique has been tested Downstream extensively (in various laboratories and conditions No Hydrates fields) Temperature • A hydrates safety margin monitoring technique based on measuring the amount of water in the gas phase has been developed 21
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