4.0 Hydrates, Wax, Asphaltenes and Chemical Injection

5/24/2018 4.0 Hydrates, Wax, Asphaltenes and Chemical Injection

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Hydrates, Wax, Asphaltene Management

Chemical Injection System


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Flow Assurance Issues

Emulsion / Foam

Wax / Asphaltene

ScaleCorrosion

Gas Hydrates

Liquid Slugging

Optimize Deliverability

Sand / Erosion


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Gas Hydrates

Ice-like crystals that form withnatural gas and water

Occurs at combination of certainlow temperatures and highpressures

Typical causes Subsea low temperatures

Cooling from gas expansion

Poor dehydration in gas lift and gas export

lines


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Gas Hydrate Properties

Approx 170 ft3 gas is stored in 1

ft3 of hydrate

Plugs can form with black oil dueto associated gas

Pigging is NOT recommended;

pigging causes crystals to pack

and form solid blockage

Melting plug with large

differential pressure can create

projectile hazard

Burning Hydrate(Ref: D. Sloan, Clathrate Hydrates)


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Thermal Design Approach

Understand requirements

Implement as part of system design

Selection insulation material

Cold spot management plan

Final design based on analysis (FEA & CFD)

Full scale cool down test (if required)

0

500

0 60

Temperature, deg C

Pressure,

bars

Hydrates

No H drates

FlowingConditions

Shut DownConditions


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Thermal Management for Flowlines andRisers

3 feet

No Insulation Bury 3 feet

External Coating Pipe-in-Pipe

- Phase Change Material (Option)

External Coating

Insulated / Heated Flexibles

Heated Flowlines- Electric- Bundle

- Pipe-in-Pipe w/ flow in annulus


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30-Mile Subsea Tieback Example

30

40

50

60

70

80

90

100

110

120

0 5 10 15 20 25 30

Distance from Wellhead, miles

Temperature,degF Single Pipe-in-Pipe

Single (8-5/8" OD) and Dual (6-5/8" OD) Bare Pipe

Dual Pipe-in-Pipe

ASSUMPTIONS 20,000 BFPD

Water Cut = 0%


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Flowline Cool Down

50

60

70

80

90

100

110

0 5 10 15 20 25

Time After Shut Down, hours

FlowlineTemperature,

deg Pipe-in-Pipe

Externally Coated Line


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Hydrates Evaluation

0

2000

4000

6000

8000

10000

12000

14000

16000

0 50 100 150 200 250

Temperature, deg F

Pres

sure,psi

Hydrate Curve

Uninsulated

Bury 3 ft

2" ext. coatPipe-in-Pipe

Shut-In Conditions

Shut-In Conditions

At Wellhead

Flowing Temp

Profiles


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Thermal Management

Field-proven materials:

NovoTherm 250 F max, k = 0.13 Btu/hr-ft-F

NovoLastic HT 350 F max, k=0.1 Btu/hr-ft-F

Advanced Thermal Analysis

3D Conduction models

Computational Fluid Dynamics

Cold Spot management system for connectors


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Flowline and Riser Cool Down Analysis

-2200

-2000

-1800

-1600

-1400

-1200

-1000

-800

-600

-400

-200

0

0 1000 2000 3000 4000 5000 6000 7000

Horizontal Distance (m)

TVD

(m)

Boarding

Valve

End of Riser

Flowline -> Jumper -> Tree Tree

Well bore

Steady state Flow

Closure of boarding valveover a duration of 30seconds

Line packing over a durationof 5 minutes

Closure of subsea valve overa duration of 30 seconds

Riser and flowline cooldownover a duration of 10 hours

Open of boarding valve by30%, over a duration of 30seconds

Evaluate drop in flowlinepressure and liquid flow to

topsides


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Hydrate Formation Chart


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Timeline for Cool down

Activities


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Flowline Warm-up

It will take longer to warm up the flow line due to warming the soil

The thermal mass of the soil will give a longer cooldown time during shutdowns

0

20

40

60

80

100

120

0 2 4 6 8 10 12

Time after well restart, hours

RiserBaseTemperature,oF

0

50

100

150

200

250

CumulativeMethanolV

olume,bbl

Riser Base Temperature, F

Cumulative Methanol Volume, bbl


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Hydrate Inhibitors

Oil andCondensates

Gas and OilMethanol: Oil

MEG: Gas

condensates

Applicable

Effective forwater cut< 50%

Low allowablesub-cooling

High volumedemands, andeffect on refinery

Disadvantage

Dosageindependent of

T

Dosageindependent ofwater-cut

Proved andwidely applied

Advantage

Allow hydrate toform but controlparticle size

Delay hydrateformation andinhibit hydratecrystal growth

Lower thehydrate formationtemperature

Mechanism

Anti- agglomerants(AA)

Kinetic HydrateInhibitors

(KHI)

ThermodynamicInhibitors

(Methanol / MEG)


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Lift Gas Stream

Gas dehydration quality is critical to avoid water vapor in thelift gas stream

Poorly dehydrated gas could cause hydrates in lift gas stream

Pressure drop through the gas lift choke can result in hydrateformation

Improper chemicals mixing with dehydrated gas canpotentially cause chemicals to turn to a gunk that plugssubsea equipment.


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Case Study: Long Distance Subsea Tieback

40 miles, 6000 ft Water Depth

Hydrates and Wax Management is challenging

Electrically heated, single pipe-in-pipe flowline

TO

SPAR

Well #2

SUTA

EFLHFL

Well #1

IUTA

EFLHFL

M

SUTA

S/D transformer

Wet Mate

11 kv Electric

Power Umbilical

HTEM/HCM

HIPPS

Mid-line Connectors

E-H PRODUCTION UMBILICAL

8" - in - 12" Pipe-in-Pipe (~36 miles)

11 kv 11 kv 11 kv

IUTA

Dry Mate

Typical Bulkhead

INFIELD E-H UMBILICAL

8" - in - 12"

Pipe-in-Pipe

(3.7 miles)

SLED TYPE C SLED TYPE B

M

ISUTA

SLED TYPE A

IUTA IUTAIUTA


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SCSSV Setting Depth Based on Formation

Water Salinity

SCSSV Setting Recommended: 1,100 ft

and below mudline


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Hydrate Plug Remediation Once a hydrate plug

forms it is verydifficult to get rid ofit

Requires a lot of time

Tahoe - 2 weeks

Arco North Sea a

month or more

The principletechnique is to use

depressurization todestabilize thehydrates. With alarge enough drop inpressure the hydrate

will melt


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Wax (paraffin)


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Blockages in Subsea Production System-Wax

Wax is a hydrocarbon string, namelyCnH2n+2 where n>20

Wax can deposit at very high-temperatures > 100 F

Typical Causes:

High wax concentration and high waxappearance temperature.

Wall-fluid temperature difference

Wax crystallization due to no-flow in

dead leg sections


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Wax Deposition Flowline deposition is non-uniform along length of flowline

Deposition rate is typically slow and rate depends on temperature

Wax ages over time (becomes harder)

To prevent wax from depositing

Keep FWHT (flowing wellhead temperature) above cloud point

Manage Wax Deposition in Flowline

Pigging ( requiring dual flowlines or subsea launcher )

Insulation effective for high flow rates and low cloud points (entire system:tubing, tree, jumpers, manifolds, & flowlines)

Chemicals help (as much as 5x decrease in deposition rate) but do noteliminate deposition


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Asphaltenes


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Asphaltenes & Resins

Asphaltene particles are stabilized by

resins at reservoir conditions.

Under certain conditions, the resins

coating the asphaltene particlesdisconnect, and particles stick to each

other & surroundings. Inhibitors act like

resins and will stand in for them;

stabilizing asphaltene particles which lost

some of their natural resins.


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Generic Asphaltene Precipitation


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Removing Asphaltene Deposits Remediation Wellbore

Primary Strategy inject solvent (xylene) soaks through umbilical, bullhead toformation, and then flow back the well

Option inject xylene/dispersant while flowing for a partial remediation.

Remediation Flowline

Primary inject xylene/dispersant downhole or at tree through umbilical while flowingfor partial remediation

Option displace xylene through umbilical into flowline, let sit for static soak, andthen flow well to surface to flush out xylene

Option non-rig intervention to pump xylene through flowline with drill pipe to thetree


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Pigging Philosophy

Progressive Pigging

Trade off between minimum risk to flow assurance and minimumrisk to subsea flexible flowlines and risers

Pig Types

Begin with least aggressive pig type, I.e. foam pigs and increase aggressivenesswith polyurethane scraper pigs

Frequency

Once or twice a week initially; reduce frequency based on pig returns, production

history and experience

Avoid pigging on the fly


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Chemical Injection


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Chemical Injection System Design

Proper selection of chemicals for treatment and remediation

Sufficient topside storage

Facilities to inject chemicals at the tree, upstream of well jumper,PLET/manifold

Subsea dosing valves

4.0 Hydrates, Wax, Asphaltenes and Chemical Injection

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Transcript of 4.0 Hydrates, Wax, Asphaltenes and Chemical Injection