Deep Sea Hydrate Flow Assurance Challenges

Transcription

1 Deep Sea Hydrate Flow Assurance Challenges Kelly Miller Center for Research on Hydrates and Other Solids Colorado School of Mines Norway - North America Petroleum Research Workshop November 2, 2005

2 The CSM Hydrate Flow Assurance Team John Boxall, Craig Taylor, Patrick Rensing, Joseph Nicholas, David Greaves, Simon Davies, Kelly Miller, Carolyn Koh, Dendy Sloan Industrial Collaborators Patrick Matthews, Alberto Montessi, Ron Morgan, Larry Talley, Douglas Turner, Zheng Gang Xu

3 Acknowledgements DeepStar CSM Hydrate Consortium Additional Funding: NSF, DOE, NURP

4 Hydrate Flow Assurance Challenges Oil & Gas Production Moving to Harsher Conditions Longer Flowlines Transient Behavior: Shut-in and Restart Traditional Hydrate Inhibition Impractical Need to Manage Hydrate Formation Thermodynamics Nucleation and Growth Kinetics Aggregation and Flow Behavior Hydrate Detection CSM Goal: Develop Tool to Predict Blockage Formation If Where Approximately When

5 CSM Hydrate Flow Assurance Approach Simulation CSMHyK / OLGA 2000 Laboratory Autoclave Cell Particle Size Analysis Rheometry Micromechanical Testing Calorimetry Flow Loops Texaco ExxonMobil University of Tulsa

6 CSM Hydrate Flow Assurance Approach Simulation CSMHyK / OLGA 2000 Laboratory Autoclave Cell Particle Size Analysis Rheometry Micromechanical Testing Calorimetry Flow Loops Texaco ExxonMobil University of Tulsa

7 CSMHyK Hydrate Kinetics Module OLGA 2000: Industry Standard for Transient Multiphase Flow Pipeline Section n-1 Pipeline Section n Pipeline Section n+1 fluid properties thermodynamic properties system properties growth rate amount of hydrate relative viscosity Yes Formation Model Driving Force Hydrates? No Dissociation Model Relative Viscosity Thermo Properties CSMHyK Module

8 CSMHyK Assumptions Formation model First order rate equation, proportional to: Subcooling Water surface area Rate constant regressed from Bishnoi s methane-water data Methane Consumed (mol / m 2 s) Moles consumed [mol/m 2 -sec] K 281 K 284 K Regressed Subcooling [K] T=T eq -T op Subcooling (K) Rheology model (Camargo & Palermo) Hydrate aggregation in oil 40 µm primary particles Aggregates partially broken by shear Aggregates flow as effective hard spheres Experimental Goal: Improve Model Assumptions

9 CSMHyK / OLGA 2000: Flow Loop Gas Consumption Predicted Pressure (psia) Data Model Time (hr) Two fitting parameters: Subcooling at nucleation (matched to experiment) Modified rate constant k = u k B Petronius Oil in Texaco Flow Loop, 35 GPM Flow Rate

10 Industrial Use of OLGA/CSMHyK: Heat Transfer from Flow Line Limits Formation % water cut Alberto Montessi, Chevron Temperature (F) hydrate formation T ambient T Distance (m) Understanding Hydrate Slurry Behavior is Key!

11 CSM Hydrate Flow Assurance Approach Simulation CSMHyK / OLGA 2000 Laboratory Autoclave Cell Particle Size Analysis Rheometry Micromechanical Testing Calorimetry Flow Loops Texaco ExxonMobil University of Tulsa

12 Conceptual Model for Hydrate Plug Growth Water Entrainment Hydrate Shell Growth Agglomeration Plug Gas Oil Water time, distance Hydrate Shells

13 Water Entrainment: Droplet Size Predictable From Oil Properties, Shear Mean Droplet Diameter (m) Conroe (Flow Loop) Conroe Petronius West African Albacora Leste / (m -1 ) d 10/9 1/2 3/5 250 d = mean diameter = shear rate = oil viscosity = oil/water interfacial tension

14 Hydrate Growth: Water Droplets Directly Convert to Hydrates Particle Size Distribution Unchanged Upon Hydrate Formation

15 Hydrate Growth From Water Droplets Gas Hydrates Grow as Shell on Droplet Surface Oil Water Hydrate Shell Three Kinetic Limitations Intrinsic crystal growth kinetics Mass transfer through oil, hydrate Heat transfer from hydrate Moving Toward Integrated Model Considering All Three Effects

16 THF Hydrate/Oil Slurries: Shear Thinning, Yield Stress Fluids 10 3 T = 4 o C 8 7 T = 4 o C Viscosity (mpa s) vol% 27 vol% 22 vol% 12.5 vol% 10 vol% 7.5 vol% 5 vol% 0 vol% Shear Rate (s -1 ) Yield Stress (Pa) Volume Fraction Strongly Suggests Particle Aggregation

17 Flow Loop: Aggregation Causes Large?P 35 P (psi) Anti-agglomerants No anti-agglomerants Speed: 520 RPM (+) Gas Fraction: 46% (+) Water Cut: 35% (+) Hydrate volume fraction Need to Understand Agglomeration Under Real Conditions

18 Hydrate Flow Assurance: Research Challenges

19 Hydrate Plug Growth Research Challenges Water Entrainment Hydrate Shell Growth Agglomeration Plug Gas Oil Water time, distance Hydrate Shells Need to Understand and Quantify Mechanisms Need Real World Flow Line Data

20 Water Entrainment: Emulsion Formation and Stability Water Entrainment Hydrate Shell Growth Agglomeration Plug Gas Oil Water time, distance Hydrate Shells

21 Emulsion Formation and Stability Hydrates Form at Water-Oil Interface Emulsion Formation: Predictable Drop Size? Crude Oil Properties Shear in Flow Lines Emulsion Property Quantification Stability and Aging Surface Properties of Water-in-Oil Emulsions Non-plugging Brazilian Crude Oils High Water Cuts End-of-Life Fields: Up to 90% Water

22 Hydrate Nucleation and Growth Water Entrainment Hydrate Shell Growth Agglomeration Plug Gas Oil Water time, distance Hydrate Shells

23 Hydrate Nucleation and Growth Nucleation Mechanisms Traditional Nucleation Induction subcooling: outrunning the hydrates Particle Collision Effect of Oil Chemistry Formation Rates and Mechanisms Shell Growth Interior Growth Kinetic Inhibitors Nucleation Inhibition Growth Inhibition

24 Hydrate Aggregation and Rheology Water Entrainment Hydrate Shell Growth Agglomeration Plug Gas Oil Water time, distance Hydrate Shells

25 Hydrate Aggregation and Rheology Even Small Amounts of Hydrates Could Cause Plugs Need to Understand and Quantify Complex Slurry Mechanical Properties Hydrate volume fraction Hydrate microstructure Shells, particle size, particle roughness, aggregate fractal dimension Oil properties Multiphase morphology Hydrates in oil, hydrates in water, hydrate slippage Hydrate Adhesion Strength Hydrate-hydrate and hydrate-wall Temperature dependence Anti-agglomerants

26 Hydrate Blockage Formation Water Entrainment Hydrate Shell Growth Agglomeration Plug Gas Oil Water time, distance Hydrate Shells

27 Blockage Formation: What Is A Plug? Qualitative Descriptions Slush-like, powder-like, dry hydrates, etc. Pass/fail results for flow loop, wheel tests Continuous behavior can masquerade as qualitative changes Need a Quantitative Answer for What is a Plug? Multiphase problem Complex fluid: hydrates, oil, gas, water, wax Answer Will Involve: Mechanical properties of multiphase mixture Yield stress, viscosity, shear thinning behavior, etc. Multiphase flow regime and fluid morphology Flow line dimensions, driving pressure In pipeline x, a plug has a yield stress, a viscosity, and spans the pipeline

28 Cold Slurry Flow Water Entrainment Gas Oil Water Hydrate Seeding and Growth Hydrate Flow time, distance Hydrate Shells Requires Understanding of Nucleation, Growth, Aggregation

29 Gas Dominated Systems Very Different Mechanisms from Oil Systems Need Basic Understanding of Mechanisms What is the conceptual picture? Hydrate formation in mist? Hydrate formation on contact with wall? Field Data is Available

30 Conclusions CSM is developing CSMHyK, a hydrate kinetics simulator integrated into OLGA2000 Need to understand and quantify hydrate formation mechanisms Emulsion formation and stability Hydrate nucleation and growth Hydrate aggregation and complex slurry rheology Quantitative definition of pipeline blockage Cold slurry flow Gas dominated systems