Reducing the Cost of Hydrate Management by Under-Dosing Thermodynamic Inhibitors

Transcription

1 Reducing the Cost of Hydrate Management by Under-Dosing Thermodynamic Inhibitors Professor Eric F. May The University of Western Australia Australasian Oil & Gas Conference: New Trends in Flow Assurance 11 March 2015

2 Hydrates & Flow Assurance Team Eric May Mike Johns Brendan Graham Zach Aman Paul Stanwix Agnes Haber Tom Hughes Clayton Locke Reuben Wu Mauricio Di Lorenzo (CSIRO) Song Ng Masoumeh Akhfash Bruce Norris Shane Morrissy John Boxall (now Chevron ETC) Sang Yoon Ahn (Hyundai Heavy Industries) 2

3 Pressure (MPa) Current solution for deepwater oil & gas production: thermo hydrate inhibitors Inhibitors reduce H-bond availability - suppress hydrate formation Two primary types of inhibitor : - Methanol (released into sea after use) - MEG (recycled using large onshore plant) Large amounts of MEG required to completely avoid hydrate formation in deepwater means new approach is needed to: 1) Reduce energy & capital required to inhibit 2) Reduce impact on environment 3) Increase accessibility to future sources of energy 3

4 Previous work suggested insufficient MEG may increase hydrate plugging risk Hydrate plugging potential Xiaoyun Li, Pal Hemmingsen (Statoil, 2008, 2011) Oil dominant system (Water+MEG at 20 vol% of oil volume) Plugging potential increased to max at 10 to 15 wt% MEG 0~5% 5~20% > 20% Hard plugs High degree of agglomeration Softer plugs Deposits on wall Gel-like plugs Concentration of MEG Why is it so? Can the effect & risk be quantified? Is it the same in water- & gas-dominant systems? Systematic study Visual sapphire autoclave for liquid systems Single-pass flow loop for gas dominant systems 4

5 Tools to investigate the effect of MEG Visual sapphire autoclave Gas-dominant flow loop Hydrate growth kinetics gas consumption with shear rate, Transportability Torque measurement, image analysis, impact of shear Realistic gas pipeline conditions High pressure, low temperature, annular flow, single-pass Hydrate formation and deposition 5

6 Hydrates slurries can flow until they plug Video Speed:

7 Critical Hydrate Fraction (Φ transition ) Means Bed Formation with Plugging Inevitable Φ transition Joshi, Koh et al., Chem. Eng. Sci., 2013 Regional boundaries (A-D) identified from pressure data Region C onset corresponds to Φ transition in autoclave Homogeneous to heterogeneous slurry 7

8 Torque (Ncm) MEG delays bed formation & decreases max resistance-to-flow in water-dominant system % 18.6 % NO Bed formation point 10% 0% 15% Hydrate Volume Fraction (%) Bed formation point increased from 10 to > 45 vol% hydrate - Delayed onset of plug behavior Max torque decreased with MEG - Slurry remains flowable MEG enhanced hydrate slurry transportability 8

9 Torque (Ncm) In oil-dominant systems MEG also lowers Max Torque % 0% However at steady-state, (no further gas consumption) torque peaks at 5% MEG % 15% 20% Hydrate Volume Fraction (%) Quantitative measure of plugging potential for under-inhibition in oil 9

10 Torque At steady-state, unconverted water leads to larger hydrate aggregates 0% 20% Under-inhibition enables unconverted water to remain Increases capillary cohesion in oildominant system MEG-rich water inhibits hydrate Time 10

11 Torque (Last 30 min) (Ncm) More MEG = more unconverted water = more transportable Steady-state torque peaks at 5% MEG More MEG leads to large water phase Envelops hydrate particles Prevents capillarity MEG Concentration (wt %) 300 RPM 900 RPM Large Capillary force Weaker Capillary force 11

12 Hytra: Single-Pass Gas-Dominant Flowloop Simulate deep-water gas field conditions Liquid loading below 10 vol% High gas velocity, wavy-annular flow regimes Steady-state flow and transient-flow tests Test section Conditions Fluids Flow rates Instruments TECHNICAL SPECIFICATIONS 1 inch SS 360 pipe, 40 m long Pipe-in-pipe temperature control Pressure: <120 bar Temperature: -8 to 30 C Aqueous solutions, light oils, natural gas Liquid: 1-8 Litres/min V SL : m/s Gas: scfm V SG : m/s 7 pressure transducers, 7 RTD sensors Gas and liquid flow meters Viewing windows, high speed camera Hytra flow loop test section 12

13 Pressure drop (MPa) As subcooling decreases, stenosis determines transportability P 0 =10 MPa T av =9.6 C 0% MEG DT=8.8 C oscillatory Window 1 0% MEG Window 4 - exit % MEG DT=5.9 C % MEG DT=4.2 C Window 1 20 % MEG film growth and sloughing 30% MEG DT=-0.6 C 0.5 fully inhibited Time (min) 3 min 24 min 13

14 Pressure drop (MPa) Constant subcooling used to probe secondary effects of MEG Tests performed at closely matched subcoolings DT 3 C are compared as a function of MEG concentration Film growth and sloughing are prevalent at these conditions Sloughing events increase with MEG concentration DT=3.4 C - T=12.8 C DT=3.1 C - T=13.1 C DT=1.9 C - T=11.2 C DT=3.4 C - T=9.9 C 10% MEG 20% MEG DT=3.1 C - T=5.8 C 30% MEG Time (min)

15 Gas consumption (mol/s) Evolution in average loop pressure gives measure of formation rate gas liquid hydrate 20 wt% MEG droplets hydrate film liquid film hydrate particles Intrinsic kinetics model (film + droplets) Intrinsic kinetics model (film) Mass transfer limited model (film) Subcooling ( C) Intrinsic kinetics model dn dt h K 1 = kg m -2 C -1 s -1, K 2 = K, u= 1 Mass transfer limited model dn dt h 1 W i mol k i u K 1 K exp T eq c i ci As 2 A s DT k i : mass transfer coefficient c i and c i eq from flash calculation (CPA model) A s = A drops + A pipewall = ( ) m 2 Hydrates are mostly formed in the droplets with low mass transfer resistance Hydrate growth in the film may be limited by mass transfer Growth 250 times faster than in oildominant system 15

16 Film growth model for pressure drop Assumptions of the model Deposit uniformly distributed along the pipe Constant film growth rate G Quasi-steady-state approximation Pressure drop gradient in a horizontal pipe DP DL 1 m v f 2 D h 2 m [Beggs and Brill (1999)] m, v m average density and velocity of the fluid mixture f: friction factor, D h : hydraulic diameter G Variable hydraulic diameter D h t D pipe 2 G t G is the only fitting parameter of the model 16

17 Pressure drop (MPa) Formation-film growth rate (L/min) Pressure drop (MPa) Evolution in pressure drop can provide deposition rate estimate at low DT experiment model DT=5.5 C G=76 mm/min Time (min) Deposition and formation rates compared at low subcooling (negligible sloughing) % MEG 10% MEG 20 % MEG formation rate experiment model DT=3.1 C G=67 mm/min Time (min) Subcooling ( C) deposition rate At low subcooling a volume fraction of 30-50% of total hydrates deposits at the pipe wall 17

18 Conclusions Under-inhibition with MEG in Water-dominant systems Delays bedding onset & decreases max resistance-to-flow Under-inhibition with MEG in Oil-dominant systems Peak in steady-state resistance-to-flow at 5 wt% MEG Unconverted water allows capillaries that sustain aggregates More MEG results in enough water to suppress capillarity Under-inhibition with MEG in Gas-dominant systems Hydrate formation rate is high because of entrainment but is reduced by MEG through decreased subcooling Hydrate deposition rate at low subcooling DT 3 to 6 K appears relatively constant: limited to 30-50% of formation rate Hydrate stenosis most apparent at low subcooling. At constant subcooling, DT 3 K sloughing frequency increased with MEG 18

19 THANK YOU Mike Johns Zach Aman Mauricio Di Lorenzo (CSIRO) Masoumeh Akhfash Bruce Norris Sang Yoon Ahn (Hyundai Heavy Industries)