Pipelines & Flow Assurance

Transcription

1 Pipelines & Flow Assurance

2 Jamie Littler Technical Disciplines and Assurance Manager Shell UK

3 Flow Assurance Wax Study on the Ravn Field Production System Wood Group Kenny: Hooman Haghighi, Jamie Littler, Fujiang Zhu, Temitope Solanke Wintershall: Leif H. Blidegn, Amir Mofidi

4 Agenda Introduction to the Risks of Wax Deposition Fluid Tuning Ravn Field Overview Results of In-field and Export Lines Conclusions and Recommendations 4 -

5 Wax deposition risks Wax is long-chain simple hydrocarbons. Long Chain n-paraffin Branched chain paraffin Cyclo-paraffin (Naphthene) Wax deposition can cause: Reduction in flow area Change in wall friction Blockage of the pipeline These pictures are from public domain.

6 Wax management Maintain the system temperature above the wax appearance and/or fluid pour point. Insulation Displacement with stabilized crude, diesel or condensate Active heating of the pipeline Physical removal of wax Periodic scraping of the wax layer via pigging operations. Heating Chemical treatment Blideng et al. (2011), Running-in a new Platform, 22nd International Oil Field Chemistry Symposium

7 Wax deposition (Molecular Diffusion) Turbulent Core Molecular Diffusion is the dominant wax deposition mechanism Radial diffusion of dissolved wax molecules in the oil Concentration gradient between dissolved wax in the turbulent core and the wax in solution at the pipe wall Dissolved wax diffuses towards the wall where it precipitates

8 Wax testing There are a few lab techniques available for wax measurements: Viscosimetery Cold finger Differential Scanning Calorimetry (DSC) Cross Polarization Microscopy Filter Plugging Fourier Transform Infrared Spectroscopy (FTIR) Wax Appearance Temperature (WAT): The temperature below which the paraffin's start to precipitate as wax crystals is defined as crude cloud point or WAT. Pour Point: The temperature at which oil sample movement stops is defined as the crude oil pour point. These pictures are from public domain.

9 Wax properties Lab Data WAT [ o C] 27.5 WDT [ o C] 55 Wax Paraffinic content [wt%] NOTE Cold Finger Test Note 1: C17+ Static Cold Finger Set-up Hayduk Minhas correlation was used to calculate the diffusion Coefficient (9.78E-08 cm 2 /s) Wax Inhibitor from lab test was shown to reduce the deposition rate by 40-80% (40% has been assumed as a conservative approach in this study)

10 Dynamic Viscosity mpa.s [cp] Viscosity tuning A shear-thinning behaviour of the fluid has been observed at low temperature. The shear rate has been identified to represent the actual flowing condition (for each flow rate) and viscosity has been tuned based on the selected shear rate. Shear Rate Calculation-Catcher Shear rate 10 S-1 Temp= 15 C μ= 22 cp ID= m 4" ρ= kg/m3 QLT= 1950 bpd m3/s non-newtonian Behaviour at Low temperature Steady State Dynamic Viscosity Profiles For Ravn Oil 1 s-1 10 s s-1 u= m/s Velocity Re= Re<2300 Laminar Re>4000 Turbulent Laminar τ= 1.0 N/m2 s= S-1 Turbulent s= S-1 Laminar note: use the lab data with shear rate =10 S Temperature C

11 Pressure [bara] Fluid modelling Effect of pressure & light end component on WAT 250 Wintershall Ravn Field Fluid Modelling in-field Line Wax Appearance Temperature (WAT) as a Function of GOR and Pressure Bubble Line (Case 1+GL - GOR = 1900 Scf/bbl) WAT (Case 1+GL - GOR = 1900 Scf/bbl) Bubble Line (Case 2 - GOR = 533 Scf/bbl) WAT (Case 2 - GOR = 533 Scf/bbl) Bubble Line (Case 3+GL - GOR = 986Scf/bbl) WAT (Case 3+GL - GOR = 986 Scf/bbl) Temperature / Wax Appearance Temperature [ o C] Note: The dynamic changes in the fluid composition (e.g. Gas Oil Ratio) in the pipeline and the effect on WAT has been considered in thermo-hydraulic simulation. However the model has not taken into account the composition change due to wax drop-out (conservative).

12 72 m 66 m Ravn system schematic Fluid Properties API 38.2 Viscosity at 60 F (cp) 24.1 WAT ( C) 27.5 N-Paraffin Content (wt%) Pour Point ( C) -51 Ambient Conditions Ravn A6A Platform Export T = 55 C F3-FB Platform - 10 C 54 m/s 5 C 0.34 m/s 8 Infield Line (18 km) FWHT= 60 C 4 Oil Export Line (119 km)

13 Temperature [ C] Risk of wax deposition (in-field line, early life) Wintershall Ravn Ravan Field Wax Deposition Simulation In-field Line Temperature and Wax Depostion Profiles (Case 1+ GL) Fluid T WAT T Ambient Length [km]

14 Wax Thickness [mm] Wax deposition thickness (in-field, early life) days 20 days 10 days Wintershall Ravn Field Wax Deposition Simulation In-field Line Wax Depostion Profiles (Case 1+ GL) Risk of Wax Depostion at the Topsides Risk of Wax Depostion at the Subsea Length [km]

15 Total Wax Deposited [m 3 ] Total wax deposition (without inhibitor) Case 1 Case 2 Case 3 Case 4 Wintershall Ravn Field Wax Deposition Simulation In-field Line - No Inhibitor Volume of Wax Deposition Production Rates Case Oil Gas Water Gas Lift [m 3 /d] [m 3 /d] [m 3 /d] [m 3 /d] GL Time [days] Total growth rate of wax (in-field pipeline) is <0.4 m 3 /d without inhibitor

16 Total Wax Deposited [m 3 ] Total wax deposition (with inhibitor) Case 1 Case 2 Case 3 Case 4 Wintershall Ravn Field Wax Deposition Simulation In-field Line - With Inhibitor Volume of Wax Deposition Production Rates Case Oil Gas Water Gas Lift [m 3 /d] [m 3 /d] [m 3 /d] [m 3 /d] GL Time [days] Total growth rate of wax (in-field pipeline) is <0.3 m 3 /d with inhibitor

17 Summary of the results (in-field line) WAT is lower at higher pressure for the live fluid The effect of pressure is more pronounced for the fluids with a higher GOR (i.e. Gas Oil Ratio) As soon as the fluid reaches ambient temperature, no wax deposition would occur (No heat flux to drive the wax deposition cold slurry flow). The first location for wax to deposit depends on the flow rates, GOR, phase fractions, etc. After 30 days of operation <4mm and <13mm of (max) wax thickness can be expected at seabed and topside conditions respectively without inhibitor. The recommended frequency of pigging operation is every month (based on maximum 4mm of wax deposition in the system) without inhibitor and every 45 days with inhibitor injection (40% efficiency).

18 Temperature [ C] Risk of wax deposition (Export Line) Risk of Wax Depostion at the Subsea Wintershall Ravn Field Wax Deposition Simulation - Export Line Temperature Profile and Risk of Wax Deposition Ambient T WAT 1950bpd Fluid T 2500bpd Fluid T 3500bpd Fluid T 4500bpd Fluid T Risk of Wax Depostion at the Topsides Distance (km)

19 Wax Thickness [mm] Wax deposition thickness (Export line) days 10 days 15 days 20 days 30 days Wintershall Ravn Field Wax Deposition Simulation Export Line Wax Depostion Profiles (2500 bpd) Risk of Wax Depostion at the Topsides 8 6 Risk of Wax Depostion at the Subsea Length [km]

20 Pressure Drop [bara] Pressure drop vs. max wax thickness (Export Line) Wintershall Ravn Field Wax Deposition Simulation Export Line Pressure Drop vs. Max. Deposition Thickness 1950 bpd 2500 bpd 3500 bpd 4500 bpd Max Wax Thickness [mm]

21 Max Deposition Rate [mm/day] Max Wax Thickness [mm] Self insulation on wax deposition (Export Line) 1.6 Wintershall Ravn Field Wax Deposition Simulation In-Field Line Effect of Wax Thickness on Depostion Rates Case 1 - Deposition Rate Case 2 - Deposition Rate Case 3 - Deposition Rate Case 4 - Deposition Rate Case 1 - Max Wax Thickness Case 2 - Max Wax Thickness Case 3 - Max Wax Thickness Case 4 - Max Wax Thickness Time [days] Results are for the topsides (i.e. the highest deposition thickness and rates)

22 Summary of the results (Export line) Higher flow rate leads to longer section of the export line subject to wax deposition risk. Self-insulation effect was observed (Lower rate of deposition by time). The maximum wax thicknesses identified for the 4 cases are comparable, however the total wax deposited is more at higher flow rates. After 22 days and 31 days of operation <4mm of (max) wax thickness can be expected at seabed condition without and with inhibitor (40% efficiency), respectively. Pigging of 4 >100 km export line is challenging and is currently under further evaluation. Alternative wax mitigation strategy like wax dispersant, gas condensates has been considered.

23 Other Flow Assurance challenges Slugging in the in-field line at the early life and during the start-up and turn-down operations has been observed. The following mitigation methods has been considered: o o Increased back pressure (for start-up and turn-down operations) Gas lift injection (if required)

24 Questions? Special thanks to: