해양 자원 개발 시스템 개론 : Introduction to Offshore Petroleum Production System

Yutaek Seo

Period Contents

1 Week General introduction, outline, goals, and definition

2 Week

Type of reservoir fluids : Dry gas / Wet gas / Gas condensate / Volatile oil / Black oil PVT laboratory testing : Constant mass expansion / Differential vaporization / Compositional analysis / : Oil densities and viscosity / SARA, Asphaltenes, WAT

3 Week Fluid sampling and characterization : Bottom hole samples / Drill stem test samples / Case studies

4-5 Week Thermodynamics and phase behavior : Ideal gas / Peng-Robinson (PR) / Soave-Redlich-Kwong (SRK) : Peneloux liquid density correction / Mixtures / Properties calculated from EoS

6 Week Subsea Field Development : Field configuration / Artificial rift / Well layout

7 Week Well components : Well structures/Christmas tree

8 Week Subsea manifolds/PLEM and subsea connections : Components / design / installation

9 Week Umbilical / risers / flowlines : Design criteria/ analysis

10 Week Flow regime : Horizontal and vertical flow / Stratified flow / Annular flow / Dispersed bubble flow / Slug flow

11 Week Flowline pressure drop and liquid holdup : Frictional losses / Elevation losses / Acceleration losses / Errors in ΔP calculation / Pipe wall roughness

12 Week Thermal conductivity and heat transfer : Overall heat transfer coefficient / insulation design

13 Week Flow assurance issues : Hydrate/Wax/Asphaltene/Corrosion/Scale

14 Week Field operation : Operational procedures for offshore petroleum production

15 Week Homework exercise (22nd May) / Final test (24th May)

What are gas hydrates?

Four major changes

Hydrate stability zone

• P, T profile in offshore flowlines : 8.27 inch ID, 27.6 mile insulated flowline (overall U-value of 3.6 Btu/hr ft2 oF) : 28 APIo black oil (gas gravity 0.83, GOR 200 scf/bbl)

Where do hydrate form?

Three major hydrate hot spots 1) Water accumulation and hydrate blockage in riser 2) Hydrate deposition and blockage in flowline (well to platform) 3) Hydrate blockage by JT cooling in subsea and top side chokes → Shut-in & restart, water ingress in gas export line also cause hydrate incidents

Hydrate strategy change

- However, still avoidance concept is dominant for design and operation of oil and gas field, since industry is not ready to take the risk of hydrate management as hydrate troubles are too expensive

North Sea Plug Case History

• 16inch, 22mile pipeline in UK sector • MEG injection line had sheared • 1.2 mile long plug • Upstream of platform by <0.25 miles • FPSO brought in from Stavanger • Depressurized both sides of plug • 8 weeks total downtime, $3MM cost

Complete FPSO/Manifold Interface

Pipeline operating scenarios

Hydrate formation in gas dominant system

- Hydrate formation in gas condensate system 1) Emulsification of oil into water 2) Hydrate nucleation and growth 3) Adhesion and aggregation 4) Deposition 5) Jamming or plugging

- Hydrate formation in gas system 1) Hydrate coating on wall 2) Annulus growth of coating 3) Sloughing 4) Plugging • Coating of hydrate on pipe wall is resulted from

no emulsification and not enough interfacial tension

• Pipe material can make difference → Q. What cause the sloughing?

Hydrate formation of water in oil emulsion

- Liquid layer around hydrate particle results in 10 times higher attraction force than without layer

- Only 4% of hydrate formation can induce hydrate plug in emulsion - Viscosity of emulsions has been used to explain the flow behaviour of fluid

→ Q. What percent of hydrate in water phase can induce hydrate plug for gas or

gas/condensate system?

Hydrate formation process

- Hydrate do not act like hard spheres - Hydrate particles appear to aggregate (concentrated emulsion)

→ Q. During the hydrate formation process, which physical property it has to be

monitored? Viscosity?

Proposed hydrate deposition for annular flow

Proposed hydrate deposition for wavy flow

Proposed hydrate deposition for stratified flow

Pipeline pressure drops due to hydrate

Early warning signs of hydrates

(including top side separator)

Hydrate formation in Werner Bolley gas line

: Hydrate formation by coating and sloughing : Pressure spikes by onset of hydrate and partial plug at middle : Pressure surge by complete plug at final

sloughing plugging

Hydrate kinetic management

- Shell’s SE Tahoe field

Hydrate kinetic management

- Condensate flow loop (single-pass)

- Hydrates formed in bulk phase : No deposit on wall in absence of free H2O - Hydrates/ice formed at the pipe/hydrate/ice interface will remain on wall : Dissolved water yields uniformly dispersed deposit : Free water results in localized deposit - Hydrate/ice deposits can be dissociated with or without chemicals : Flowing an under‐saturated condensate past deposit/plug : Using MeOH dissolved in condensate - Mass and energy balances can be used to model deposition : Ice with a 67% void fraction reasonably matches P and temp profiles from three experiments → As long as there is flow, gas flow line can be dried that would induce hydrate melting

PT trace for hydrate formation

A: No hydrate P decrease with T for hrs B: Hydrates begin to form → Q. Does this metastable region really exist

in real gas flowline? Shut-in? Q. If does, is it useful to avoid hydrate

plug?

ΔT subcooling

Measurements of Hydrate Nucleation

Hydrate Nucleation Measurement Tools

Hydrate film growth at water-methane interface

Hydrate film growth at the water-HC interface and the effect of ΔT

Water droplet conversion to hydrate

Hydrate kinetics can be controlled by

Mass and heat transfer limitations

Hydrate plug: rule of thumb

Early warning signs of hydrates

How are hydrate plugs located?

How do they dissociate?

Pictures of dissociating hydrate plugs

Hydrate dissociation with ice and water present

Plug dissociation guideline

Dissociation guidelines (cont’d)

Hydrate mitigation

• Insulation - Pipe-in-pipe - Wet Insulation

• Active heating systems - Hot Water - Electric

• Subsea Chemicals Injection - Methanol, MEG - LDHI

• Flowline Pressure Reduction

Hydrate remediation techniques

• Depressurization - One sided - Two Sided

• Active heating systems - Hot Water - Electric

• Subsea MeOH or MEG Injection (can you get it to the plug?) • Coiled Tubing

Thermodynamic Hydrate Inhibitors (THIs)

• Methanol : Low cost : Low viscosity : No fouling : More toxic : Too little can be worse than none at low levels : Inefficient to recover : Reduce hydrocarbon sales value : High loss to gas phase

• MEG : Less toxic : Under-treating not as bad : Efficient to recover : Does not affect hydrocarbon value : Loss to gas phase negligible : High viscosity : Salts precipitation : Fouling by salt deposition

Low Dosage Hydrate Inhibitors (LDHI)

• KHI : Liquid HC not needed : Any water cut : Doesn’t cause emulsions : Low pressure drop : Prolonged induction time : Can’t disperse hydrates : Medium subcooling (<14oC) : Affected by shut-in : Environmentally friendly

• AA : Require liquid hydrocarbon : Water cut limitation : Can be high pressure drop : Shot induction time : Disperse slushy hydrates : High subcooling : Less impact from shut-in : Mostly toxic

Application factors for THI

• Injection hardware • Delivery & storage - large volumes • Loss to hydrocarbon phase • Salt precipitation • Compatibility (materials & chemical) • In-situ vs average water production rate • Environmental, health & safety • Regeneration

Application factors for LDHI

• Injection point (subsea tree, manifold, and/or downhole) • Hydrocarbon effect on performance • Compatibility (materials & chemical) • Environmental impact • Solvent stripping • In-situ vs average water production rate • Other physical properties (flash point, pour point, viscosity) • Solids

Inhibitor injection rate

0

2000

4000

6000

8000

10000

12000

0 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100

Pre

ssur

e (p

sia)

Temperature (F)

Hydrate Curve and Wellbore Shut-in Conditions

Shut-in Wellbore Conditions

Mud Line 502 ftBML

1059 ftBML

2062 ftBML1505 ft

BML

3065 ftBML

3511 ftBML

4068 ftBML

4513 ftBML

5070 ftBML

5516 ftBML

6073 ftBML

2507 ftBML

MEG Regeneration Unit

MRU for Santos FPSO

MEG loop and challenges with salt precipitation

Main concerns

• Formation water : Monovalent cations, Na+, K+ : Divalent cations, Ca2+, Mg2+, Ba2+, Sr2+ : Organic acids, glycolic, formic acids : Precipitation of CaCO3, MgCO3 • Pipeline corrosion (CO2, H2S) : Iron (Fe2+) : pH controller NaOH, KOH, NaHCO3, Na2CO3, and amines : Precipitation of Fe2CO3, Fe2O3 • Completion fluids : Highly soluble salts, CaCl2, CaBr2, Ca(HCOO) 2

: Precipitation of BaCO3, etc

Control strategy

• Low soluble salts (Ca2+, Mg2+, Fe2+, CO32-)

: Divalent cations will easily precipitate and form scale : All salts must be removed with controlled precipitation (alkalinity and temperature control) • High soluble salts (Na+, K+, Cl-) : Monovalent cations may accumulate up to 75000 mg/l without precipitation and may be tolerable : Precipitation by supersaturation

• Other chemicals : Some components (acetate, corrosion inhibitor) will not precipitate but accumulates in the Reclaimer

Full stream

• Asgard B platform

• Ormen Lange

Slip stream

Vent

Condensate Flare, CO2

Off gas

Free Water

Treated MEG

Produced Water

Low Soluble Salt Removal

High Soluble Salt Removal

To Subsea

H2O MEG

Regeneration Rich MEG tank

Pre-treatment

Lean MEG tank

Reclamation

Distillation column design

• To determine distillation duty a. Select distillation operating temperature, Top. From the

boiling point of lean MEG

b. Calculate heat duty of pre-treatment stage c. Calculate the temperature of rich MEG entering distillation d. Calculate heat duty of distillation

where, Qdist : distillation duty, W z richMEG: rich MEG recycle rate, kg/s CrichMEG: average specific heat rich MEG, J/kg K ΔT: Tdist – Tin, oC X: total water removed, kg/s L: latent heat water, J/kg

MEG concentration

70 75 80 85

T (oC) 116 120 125 131

LXTCzQ richMEGrichMEGdist ⋅+∆⋅⋅=

Separator design

• MEG flash drum : Separation between MEG and hydrocarbon is critical to avoid excessive MEG losses and entrainment of hydrocarbon : Hydrocarbon carry-over may induce foaming problem : 20 to 25 minutes of residence time is recommended : Coalescer or filter should be considered on the hydrocarbon stream leaving the flash vessel : Horizontal 2-phase with weir was considered (ID1.2m*L4.8m) : Gas rate 3.0*10-5m3/sr, rich MEG 7542 kg/hr, water rate 0.002 m3/s (Inpex followed sizing basis of Total: GS EP ECP 103) • MEG reflux drum : 20 to 35 minutes of residence time : Reflux ratio depends on the residence time in reflux drum, rich MEG flow rate, and regeneration efficiency

Next Class : Wax Homework 10. Calculate the methanol injection rate using the Hammerschmidt equation