Flow Assurance: Gas Hydrates and Wax · Flow Assurance: Gas Hydrates and Wax – December 2004...

Flow Assurance: Gas Hydrates and Wax – December 2004 Steering Committee Meeting

Flow Assurance:

Gas Hydrates and WaxDecember 2002-November 2005 Programme


Objectives

• Hydrate formation in low water content gases

• Hydrate inhibition, inhibitor loss and/or salt

precipitation in methanol, glycol, and salt

systems

• Hydrate stability zone of oil systems at high

pressure conditions

• Gas hydrates in water-oil emulsions

• Wax phase boundary, and effect of wax on

hydrates (and vice versa)


Hydrates in low water content gases• Water content in gas systems

– Experimental measurements (gas, water, ice, hydrates)– Reliability of the measurements

– Extension to other conditions– Reliability of the assumptions

• Hydrate phase equilibria in low water content gases

Progress in the last six months

• Ultrasonic for water dew-point measurement

• QCM for water dew-point measurement

• Literature review on the available techniques for predicting the water content in the hydrate region

• Developing a correlation for predicting the water content in H-V region


Hydrate inhibition in methanol, glycol, and

salt systems• Salts and organic inhibitor systems

– Hydrate inhibition, Salting-out, and Inhibitor distribution


• Freezing and boiling point measurements for aqueous solutions of ethanol and calcium chloride

• Dissociation point measurements to ~480 bar– Methane with ethanol / CaCl2 (2 concentrations)

– Natural gas with methanol / NaCl (2 concentrations)

– Natural gas with 3 salts and 1 organic inhibitor (underway)

• Modelling of calcium chloride/ethanol implemented

• Correlation extended to calcium chloride/ethanol systems


Hydrate stability zone of oil systems at high

pressure conditions• Deepwater operations and long tiebacks

• Limited available data

• Measurement challenges– Visual techniques

– P vs T techniques


• Preparation of a new oil made by combining Brazillianheavy oil and natural gas

• Bubble point measurements at a range of temperatures

• Dissociation point measurements up to 1834 bar

• Extension of the HWHYD to high pressure conditions


Gas hydrates in water-oil emulsions

• Flow assurance in oil systems

– Water-oil emulsions

– Natural inhibition

– Effect of water cut, turbulence, etc.


• A new experimental rig with visual capabilities was

commissioned

• Effect of water cut and mixing rate were examined on a

Brazilian oil under shut-in and flowing conditions

• A theoretical approach on the effect of asphaltene on

emulsion stability hence hydrate transportability


Wax-hydrate combinations• Wax and hydrates in subsea pipelines

• Wax phase boundary determination– Experimental (WAT vs WDT, step-heating)

– Thermodynamic modelling


• Measurements of the effect of pressure and light components on the wax phase boundary of a separator condensate

• Measurements of the effect of cooling rate on the wax appearance temperature

• Extension of HWWAX to real reservoir fluids

Experimental Work:

PHYSICAL PROPERTY

MEASUREMENTS

Rod Burgass

Outline

• Freezing point measurements

– Aqueous solutions of et hanol and Calcium Chloride

• Boiling point measurements

– Aqueous solutions of et hanol and Calcium Chloride

Freezing point method schematic of sample temperature

probe

Aluminium

Tube

Test Sample

PRT

PTFE Sleeve

Example of freezing point measurement data for aqueous

solution of sodium chloride

2.4

2.7

3.0

3.3

3.6

-4.0 -3.6 -3.2 -2.8 -2.4 -2.0 -1.6 -1.2

T d

iffe

ren

ce b

etw

een

pro

bes/K

Freezing point

Sample Temperature/K

Freezing point measurements for aqueous solutions of

sodium chloride

255

258

261

264

267

270

273

0 5 10 15 20 25

Sodium chloride concentration/mass%

T/K

This work

CRC Handbook

Freezing point measurements for aqueous solutions of

ethylene glycol

238

243

248

253

258

263

268

273

0 10 20 30 40 50

Ethylene glycol concentration/mass%

T/K CRC Handbook

This work

Freezing point data for aqueous solutions of ethanol and

calcium chloride

Mass% water

0.1

Mass% ethanol

0.1

Mass% calcium

chloride

0.1

Freezing point

C 0.2

94.9 2.6 2.5 -2.7

90.0 5.0 5.0 -5.6

85.0 7.5 7.5 -9.1

80.1 9.9 9.9 -13.8

75.0 12.5 12.5 -19.6

79.1 5.3 15.7 -16.4

77.8 17.6 4.5 -14.0

Schematic of boiling point apparatus

Heating Mantle

Condenser

Thermocouple

Cottrell Pump

Schematic of modified funnel for boiling point

measurements

Boiling point elevation for aqueous solutions of sodium

chloride

373

375

377

379

381

383

0 5 10 15 20 25 30

Sodium chloride concentration/mass%

T/K

This work

ICT

Boiling point data for aqueous solutions of glycerol

373

378

383

388

393

398

403

0 10 20 30 40 50 60 70 80 90

Glycerol concentration/mass%

T/K

This work

ICT

Boiling point data for aqueous solutions of ethanol and

calcium chloride

Mass% water

0.1

Mass% ethanol

0.1

Mass% calcium

chloride

0.1

Boiling point

C 0.2

94.9 2.5 2.6 96.5

89.7 5.1 5.2 93.4

84.8 7.8 7.5 91.4

78.8 10.6 10.6 87.9

74.8 12.6 12.6 86.4

80.0 5.0 15.0 93.0

76.1 17.4 6.4 85.9

Experimental Work:

HYDRATES:

METHANE / NATURAL GAS WITH

SALTS AND ORGANIC INHIBITORS

Ross Anderson

Hydrates: Outline

• Experimental equipment and methods (detailed in

March 2003 Progress Report)

– Hydrate Rig-1 set-up

– Isochoric step-heating technique

• Dissociation point measurements: Mixed salt-organic

inhibitor systems (to 480 bar)

– Methane with ethanol / CaCl2

– Natural gas with methanol / NaCl

– Natural gas with methanol / NaCl / KCl / CaCl2

Hydrates: Rig-1 Set-Up

Hydrates: Experimental Methods

3.5

4.0

4.5

5.0

5.5

6.0

250 255 260 265 270 275 280 285

T/K

P/M

Pa

Cooling cycleHeating cycle (non-equilibrium points)Heating cycle (equilibrium points)Dissociation point

C1 - 15 mass% K2CO3

3.5

4.0

4.5

5.0

5.5

6.0

250 255 260 265 270 275 280 285

T/K

P/M

Pa


C1 - 15 mass% K2CO3

3.5

4.0

4.5

5.0

5.5

6.0

250 255 260 265 270 275 280 285

T/K

P/M

Pa


C1 - 15 mass% K2CO3

3.5

4.0

4.5

5.0

5.5

6.0

250 255 260 265 270 275 280 285

T/K

P/M

Pa


C1 - 15 mass% K2CO3

3.5

4.0

4.5

5.0

5.5

6.0

250 255 260 265 270 275 280 285

T/K

P/M

Pa


C1 - 15 mass% K2CO3

Hydrates: Methane with Ethanol/CaCl2

10

100

1000

-20 -15 -10 -5 0 5 10 15 20 25 30

T / C

P / b

ar

10% CaCl2 / 15% EtOH

5% CaCl2 / 30% EtOH

C1, Distilled water

C1, Distilled water data:

Deaton and Frost (1946)

Mcleod and Campbell (1961)

Jhaveri and Robinson (1965)

Hydrates: Natural Gas Compositions

1.70

89.00

1.655.50

1.50 0.16 0.31 0.07 0.110

20

40

60

80

100

N2

C1

CO

2

C2

C3

iC4

nC

4

iC5

(nC

5) +

C6+

Component

Mo

le%

NG-2 NG-1

N2 1.70 4.99

C1 89.00 86.36

CO2 1.65 1.12

C2 5.50 5.43

C3 1.50 1.49

iC4 0.16 0.18

nC4 0.31 0.31

iC5 0.07 0.06

(nC5) + C6+ 0.11 0.07

Total 100.00 100.00

NG-2 Composition

Hydrates: NG-2 with NaCl/methanol

10

100

1000

-10 -5 0 5 10 15 20 25

T / C

P /

ba

r

NG-2, 10% NaCl / 10% Methanol

NG-2, 7% NaCl / 20% Methanol

NG-2, Distilled water, This work

NG-2 Prediction

Hydrates: NG-2 with Methanol/NaCl/KCl/CaCl2

10

100

1000

-10 -5 0 5 10 15 20 25

T / C

P /

ba

r

6% NaCl / 3% KCl / 1% CaCl2 / 7% MeOH

NG-2, Distilled water, This work

Solid lines: Predictions (HWHYD GUI 1.1)

Flow Assurance: Gas Hydrate and Wax - December 2004 Steering Committee Meeting

Thermodynamic ModellingSalts and Organic Inhibitors

Rahim (Amir) Masoudi


Outline

• Thermodynamic modelling of CaCl2-

EtOH

• Validation of the model for gas

hydrate

• Extension of the newly developed

correlation for CaCl2-EtOH

• Conclusions


Thermodynamic modelling: salt precipitation

Temperature reductions as fluids are transported from the

reservoir to the surface.

Concentration of the brine increases as produced or

injected gas strips water, leaving the salt behind.

Reduction in CO2 concentration in the aqueous phase can

result in the deposition of bicarbonate as carbonates.

Incompatibility between formation water and sea water

Addition of hydrate organic inhibitors reduces salt solubility Addition of hydrate organic inhibitors reduces salt solubility

in the aqueous phase.in the aqueous phase.

Formation Water

Organic Inhibitors

Salt deposition


Effect of salt precipitation on hydrate formation

and vice versa

Gas

Saline

solution

Hydrate

formation

Salt formation

Remaining aqueous

phase becomes

concentrated

Less hydrate

inhibition effect for

aqueous phase

Salt

formation!!!

Hydrate

formation!!!


Thermodynamic modelling

• The new thermodynamic approach

Salt is treated as a pseudo component while its critical

properties and acentric factor are optimised.

Valderrama-Patel-Teja (VPT) EoS

Non-Density Dependent (NDD) Mixing Rules

Solid solution theory of van der Waals and Platteeuw

• Data requirements:

Initial guess for Critical properties of salt (TC, PC, VC)

Experimental data

Freezing point of salt aqueous solutions

Boiling point of salt aqueous solutions

Salt solubility


Thermodynamic modelling

• Binary Interaction Parameters (BIPs) Optimisation

Water-Salt

Salt-Salt

Salt-Organic Inhibitor

Hydrocarbon-Salt

• NaCl, KCl and CaCl2 as well as MEG have already

been modelled.


Capabilities of the modelCapabilities of the model

• Salt precipitation

• Hydrate stability zone

• Maximum hydrate inhibition effect

• Gas solubility

• Freezing point prediction

• Boiling point prediction

• Vapour pressure prediction

• Composition of all present equilibrium phases


Modelling CaCl2 and ethanolModelling CaCl2 and ethanol• Experimental and calculated freezing point temperature for ternary

CaCl2/EtOH/water mixtures

Freezing Point temperature

CaCl2 EtOH Experimental Calculated AD

(mass%) (mass%) (C ± 0.2) ( C ) ( C )

2.55 2.56 -2.72 -2.41 0.31

5.00 5.00 -5.57 -5.41 0.16

7.50 7.50 -9.10 -9.22 0.12

9.93 9.93 -13.76 -13.76 0.00

4.47 17.65 -14.00 -14.08 0.08

15.66 5.28 -16.35 -16.93 0.58

12.49 12.49 -19.62 -19.62 0.00


Modelling CaCl2 and ethanolModelling CaCl2 and ethanol• Experimental and calculated boiling point temperature for ternary

CaCl2/EtOH/water mixtures

Boiling Point temperature

CaCl2 EtOH Experimental Calculated AD

(mass%) (mass%) (C ± 0.2) ( C ) ( C )

2.6 2.5 96.5 96.9 0.4

5.2 5.1 93.4 93.9 0.5

15.0 5.0 93 93.0 0.0

7.5 7.8 91.4 91.0 0.4

10.6 10.6 87.9 88.1 0.2

12.6 12.6 86.4 86.3 0.1

6.4 17.4 85.9 85.9 0.0


Outline


EtOH


hydrate



• Conclusions


NG hydrate phase boundaries in the presence of NaCl

and MeOH aqueous solutions

1

10

100

1000

-23 -18 -13 -8 -3 2 7 12 17 22 27

T /oC

P /

ba

r

distilled water

10 mass% NaCl / 10 mass% MeOH

7 mass% NaCl / 20 mass% MeOH

Predictions


Outline


EtOH


hydrate



• Conclusions


Existing correlations

• No general correlation for a combination of

salts and/or organic inhibitors

• Shortcomings:

Effect of the system pressure

Effect of the gas/oil composition

Effect of the type of the inhibitor


New CorrelationNew Correlation

- P: Pressure of the system (kPa)

- W: Concentration in the solution (mass%)

- P0: Dissociation pressure in the presence of

distilled water at 273.15 K (kPa)

- Ci and D1: Constants

PDP

WWT

PWW

WT

WPW

WT IS

I

IS

IS

IS

SSI *

*021.0*

**

* 1

orST 1)1000()ln( 0654

3

3

2

21 PCCPCWCWCWCT IIII


Methane hydrate phase boundaries in the presence

of NaCl aqueous solutions

10

100

1000

-13 -8 -3 2 7

T / C

P /

ba

r

Exp., 11.8 mass% NaCl

Exp., 21.5 mass% NaCl

New Correlation

Hammerschmidt Correlation

Yousif & Young Correlation

Exp. data: de Roo et al. 1983



of NaCl and KCl aqueous solutions

10

100

-11 -6 -1 4 9

T / C

P /

ba

r

Exp., 3 mass % NaCl + 3 mass% KCl

Exp., 5 mass% NaCl + 10 mass% KCl

Exp., 5 mass% NaCl + 15 mass% KCl

New Correlation

Yousif & Young Correlation

Pure water, HWHYD model

CH4 Hydrate

exp. data: Dholabhai, 1991



of CaCl2 and EtOH aqueous solutions

10

1000

-10 -5 0 5 10 15 20 25 30

T / C

P /

distilled water, HWHYD model

10 mass%CaCl2/ 15 mass% EtOH

Exp. data: this work

P / b

ar


Conclusions

• Modelling CaCl2-EtOH was successfully

implemented.

– The validation of the model for gas hydrate in this system

will be presented at next meeting.

• The results show that the model can also be

reliably applied to predict hydrate stability zone for

gas mixtures.

• Newly developed correlation capable of predicting

hydrate inhibition effect of salts and/or organic

inhibitors was extended to CaCl2-EtOH systems.

Experimental Work:

HYDRATE MEASUREMENTSOIL SYSTEMS UP TO HIGH PRESSURE

Rod Burgass

Outline

• Apparatus and method

• Test Fluids

• Bubble point measurements

• Hydrate dissociation point measurements

Schematic of ultra high pressure cell

(up to 2000Bar)

HIGH PRESSURE

CELLWATER

JACKETPRESSURE

TRANSDUCER

CONSTANT

TEMPERATURE

BATH PRT

Example of dissociation point determination at high

pressure above the bubble point

300

320

340

360

380

400

420

440

460

17 19 21 23 25 27

T/C

P/b

ar

Equilibrium points prior to dissociation

Equilibrium points after dissociation

Dissociation point

Composition of live fluid made by combining stabilised

dead crude with natural gas

Component Mass% Mole% Component Mass% Mole%

CO2 0.13 0.50 C10s 2.53 3.26

N2 0.19 1.20 C11s 2.41 2.83

C1 2.99 32.22 C12s 2.63 2.82

C2 0.36 2.09 C13s 2.61 2.58

C3 0.16 0.62 C14s 2.16 1.96

iC4 0.03 0.08 C15s 2.67 2.24

nC4 0.05 0.15 C16s 2.18 1.69

iC5 0.55 1.32 C17s 2.45 1.78

nC5 0.83 1.99 C18s 2.19 1.50

C6s 1.38 2.83 C19s 1.53 1.00

C7s 2.11 3.79 C20s 62.38 23.18

C8s 2.88 4.64

C9s 2.60 3.71

Bubble point measurement using constant volume

method

290

300

310

320

330

340

350

360

12 14 16 18 20 22 24 26

T/C

P/b

ar

BUBBLE POINT 310bar @ 19C

Bubble point measurements made on oil at temperatures

between 12 and 75°C

190

195

200

205

210

215

220

0 10 20 30 40 50 60 70 80

T/C

P/b

ar

Hydrate dissociation points measured on oil in the

presence of distilled water

0

500

1000

1500

2000

0 5 10 15 20 25 30 35 40

T/C

P/b

ar

Bubble point line

Hydrate dissociation points measured on oil in the

presence of distilled water

10

100

1000

10000

0 5 10 15 20 25 30 35 40

T/C

P/b

ar

Bubble point line

Hydrate dissociation points measured on oil in the presence of

distilled water compared with measurements from previous oil system

0.0

200.0

400.0

600.0

800.0

1000.0

1200.0

1400.0

1600.0

1800.0

2000.0

0 5 10 15 20 25 30 35

T/C

P/b

ar

Heavy Brazillian oil with Natural Gas

North Sea crude

with Natural Gas

Hydrate dissociation points measured on oil in the presence of

distilled water compared with measurements from previous oil system

10.0

1000.0

0 5 10 15 20 25 30 35

T/C

P/b

ar

Heavy Brazillian oil with Natural Gas

North Sea crude

with Natural Gas


HYDRATE STABILITY ZONE IN OIL

SYSTEMS

AmirAmir H.H. MohammadiMohammadi

December 2004December 2004


Objective

• To develop the HWHYD model for

predicting hydrate stability zone at

high-pressure conditions.

• To investigate the effect of different

parameters on prediction of hydrate

phase boundary.


Various hydrate stability zones and phase

envelope for a multi-component system.P

ressu

re

Temperature

•C

Q1

Bubble point

line

Dew point

line

I-H-V Lw-H-V

Lw-LHC-H-V

Lw-LHC-HLog scaleIce line

Pre

ssu

re

Temperature

•C

Q1

Bubble point

line

Dew point

line

I-H-V Lw-H-V

Lw-LHC-H-V

Lw-LHC-HLog scaleIce line


Thermodynamic model

• Equality of fugacity:

– Fluid Phases: VPT-EoS and NDD mixing rules

– Hydrate Phase: van der Waals-Platteeuw theory

• Equation of State:

– Using a new function for water

– Tuning EoS using bubble point data at low-

temperature conditions


Hydrate dissociation conditions for black oil in the

presence of distilled water (The error bands show 1 K

temperature difference)

1

10

100

1000

278 283 288 293 298 303 308

T /K

P/M

Pa

Experimental (HWU)

This Prediction (33.33 mol% Aqueous Solution)

Bubble Point (Hydrocarbon Phase)

Component Mol%

CO2

N2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7+

0.67

2.92

51.52

3.24

0.89

0.11

0.26

1.39

1.92

2.42

34.68



presence of 16 wt.% aqueous solution of ethanol

(The error bands show 1 K temperature difference)

1

10

100

1000

275 280 285 290 295 300 305

T /K

P/M

Pa

Experimental (HWU)

This Prediction

Bubble Point



presence of 30 wt.% aqueous solution of ethanol (The

error bands show 1 K temperature difference)

1

10

100

1000

270 274 278 282 286 290 294 298 302

T /K

P/M

Pa

E xperimenta l (HW U)

This P red iction

B ubble P oint


Hydrate dissociation conditions for synthetic

mixture-A in the presence of distilled water (The error

bands show 1 K temperature difference)

Component Mol%

N2 1.46

C1 39.42

CO2 0.61

C2 2.56

C3 0.76

i-C4 0.10

n-C4 0.18

i-C5 0.05

C10 53.49

C21 0.46

C22 0.32

C23 0.23

C24 0.16

C25 0.11

C26 0.08

1

10

100

277 281 285 289 293

T /K

P/M

Pa

E xperim ental (HW U)

This P redic tion

B ubble P oint

Component Mol%

N2

C1

CO2

C2

C3

i-C4

n-C4

i-C5

C10

C21

C22

C23

C24

C25

C26

1.4639.420.612.560.760.100.180.0553.490.460.320.230.160.110.08


Hydrate dissociation conditions for synthetic

mixture-B in the presence of distilled water (The

error bands show 0.2 K temperature difference)

10

100

290 291 292 293 294 295 296 297

T /K

P/M

Pa

Experimental (HWU)

This Prediction

Bubble Point

Component Mol%

N2

C1

CO 2

C2

C3

i-C4

n-C4

i-C5

C10

C21

C22

C23

C24

C25

C26

2.2460.240.943.911.160.160.280.07

30.240.260.180.130.090.060.04


Discussion

• Effect of Heavy Hydrate Formers– Single carbon numbers (SCN): No information on single heavy

hydrate formers is available

• Effect of Water Cut– Experimentally under investigation

• Effect of Fluid Characterisation– Little Effect, Under Investigation

• Effect of Bubble Point Measurement – Bubble point measurement at low-temperature conditions,

Little Effect, Under Investigation

• Effect of Kihara Potential Parameters – Important Effect??, Effect on Hydrate Structure, Under

Investigation



presence of distilled water (The error bands show 1 K

temperature difference)

1

10

100

1000

278 283 288 293 298 303 308

T /K

P/M

Pa

Experimental (HWU)

This Prediction (33.33 mol% Aqueous Solution)

Bubble Point (Hydrocarbon Phase)

Component Mol%

CO2

N2

C1

C2

C3

i-C4

n-C4

i-C5

n-C5

C6

C7+

0.67

2.92

51.52

3.24

0.89

0.11

0.26

1.39

1.92

2.42

34.68


Conclusions

• Low temperature bubble point data were

used for tuning the thermodynamic model.

• The results for hydrate formation conditions were relatively comparable with experimental data, except at very high-pressures.

Experimental Work:

WATER-HYDROCARBON EQUILIBRIA

Jinhai Yang

Rod Burgass

Outline

• Ultrasonic method

– Apparatus

– Method

– Results

• QCM method

– Apparatus

– Method

– Results

Schematic Ultrasonic rig

Example of accoustic responses on cooling a sample of

compressed air

0.20

0.40

0.60

0.80

1.00

0 5 10 15 20 25 30 35

Temperature /oC

Am

plitu

de

an

d F

FT

0.33

0.34

0.34

0.35

0.35

0.36

Ve

loc

ity

km

/s

amplitude

FFTvelocity

Repeat of test with compressed air

0.00

0.20

0.40

0.60

0.80

1.00

0 5 10 15 20 25 30 35

Temperature /oC

Am

plitu

de

an

d F

FT

0.33

0.34

0.34

0.35

0.35

0.36

Ve

loc

ity

km

/s

amplitude

FFTvelocity

Schematic of QCM apparatus

QCM Electric feedthroughsPressure transducer

Water jacket

Magnetic mixer

Inlet valveT probe

Example of resonant frequency measurement

0

1

2

3

4

5

6

7

4977000 4978000 4979000 4980000 4981000 4982000 4983000 4984000 4985000

Frequency/Hz

Co

nd

ucta

nce/m

S

Resonant frequency at

peak conductance

Plot of QCM resonant frequency at different temperatures

for dry air

4986050

4986100

4986150

4986200

4986250

4986300

0 5 10 15 20 25 30 35

T/C

QC

M r

es

on

an

t fr

eq

ue

nc

y/H

z

Plot of QCM resonant frequency at different temperatures

for laboratory air sample

4986080

4986090

4986100

4986110

4986120

4986130

4986140

4986150

4986160

0 4 8 12 16 20 24 28

T/C

QC

M r

eso

sn

an

t fr

eq

uen

cy/H

z

Developments

• Response to dewpoint associated with QCM surface

contamination

• Adding contaminants to QCM enhances response

• Creation of “target” for water in the centre of the

QCM found to be the best method

Example of QCM response on cooling air equilibrated

with water at laboratory temperature

5004740

5004780

5004820

5004860

5004900

5004940

5004980

9 12 15 18 21 24 27 30 33 36 39 42 45

T/C

QC

M r

es

on

an

t fr

eq

ue

nc

y/H

z

Plot of resonant frequency vs temperature in a test with methane

saturated with water at 289.7 bar and 21.2 C, dewpoint taken as

20.1 C at 228 bar

5003000

5003500

5004000

5004500

5005000

5005500

5006000

5006500

10 15 20 25 30 35 40 45 50

T/C

QC

M r

eso

nan

t fr

eq

uen

cy/H

z

Plot of conductance at resonant frequency for test with

methane saturated with water at at 289.7 bar and 21.5 C

0.008

0.012

0.016

0.02

0.024

0.028

0.032

0.036

0.04

-1 4 9 14 19 24 29 34 39

T/C

Co

nd

cta

nce a

t re

so

nan

t fr

eq

uen

cy

Plot of rate of change in conductance at resonant frequency for test

with methane saturated with water at at 289.7 bar and 21.5 C

-0.0008

-0.0007

-0.0006

-0.0005

-0.0004

-0.0003

-0.0002

-0.0001

0

2 4 6 8 10 12 14 16 18 20 22 24 26 28 30

T/C

Rate

of

ch

an

ge i

n c

on

du

cta

nce a

t re

so

nan

t

freq

uen

cy S

/seco

nd

Plot showing predicted dewpoints for methane equilibrated with water

at 289.7 bar and 21.5 C and experimentally measured dewpoint

using proposed graphical method

45

95

145

195

245

295

345

5 10 15 20 25

T/C

P/b

ar

Measureddewpoints


WATER CONTENT OF GASES




Previous Work

• Collecting the solubility data in the literature

• Tuning the HWHYD model using reliable data

• Developing a new semi – empirical approach for I-V and Lw-Vregions

T

log

(P

)

H - LHC

H-V

HC Vapour Pressure

I-V

LW - V

Q 2

Q 1

I-H-V Water Vapour Pressure

H-V

H - LHC

L W -H-V

LW -H-L HC

Ice Line


Outline

• Collecting the existing H-V data of

methane and gas mixtures

• Review of the existing correlations

• Developing a semi – empirical

approach for H-V region


Experimental Data

• Water content of methane: Sloan et al. (1976),

Aoyagi et al. (1979) and Song et al. (2004)

• Water content of a mixture of methane (94.69

mol%) and propane (5.31%): Song & Kobayashi

(1982)

• Water content of carbon dioxide and also a

mixture of carbon dioxide and methane: Song &

Kobayashi (1986)


Correlations

• Kobayashi et al. (1987): Graphical method,

Requires different steps and it is not easy to

use it.

• Carroll (2003): Graphical method, gives

higher values of water content for gases with

higher gas gravities


Semi – Empirical Approach

fwg= fw

H

fwH

= fwMT

expRT

MT

w

H

w

RT

MT

w

H

w =- )1ln(4CHi

i

i fCv =iv

i

CHifC )1ln(

4

fw

MT= P

w

MTexp

RT

PPvMT

w

MT

w)(

fwg= yw w

gP


Semi – Empirical Approach (Continue)

yw= ])1()1[(])(

exp[ arg

arg

elsmallv

el

v

small

MT

w

MT

w

g

w

MT

wPCPC

RT

PPv

P

P -- +×+×-

×

Pw

MT= exp(17.440 -

T

9.6003) (Dharmawardhana 1980)

Csmall = )107088.2

exp(107237.3

33

TT

×× -

(Parrish and Prausnitz 1972)

Clarge = )107379.2

exp(108373.1

32

TT

×× -

(Parrish and Prausnitz 1972)

MT

wv = 0.022655 m3/kgmol (von Stackelberg and Müller 1954)

vsmall =23

1(Sloan 1998)

vlarge =23

3(Sloan 1998)



g

w =exp(BP + CP2+DP

3)

B = a + T

b

C = c +T

d

D = e +T

f


Experimental water content data of methane for tuning

parameters a-f

0

10

20

30

40

0 10 20 30 40

Experimental values (ppm)

Ca

lcu

late

d v

alu

es (

pp

m)

0

30

60

90

120

150

180

210

0 30 60 90 120 150 180 210


Ca

lcu

late

d v

alu

es (

pp

m)

(Experimental data from Song et al. 2004)(Experimental data from Aoyagi et al. 1979)



Curves: Water content of methane

Points: Water content of gas mixture

Curves: Water content of methane

Points: Water content of gas mixture

1

10

100

1000

230 240 250 260 270 280

T/K

Wa

ter

conte

nt(p

pm

)

(P=2.07 MPa)

(P=2.07 MPa)

(P=6.89 MPa

P=6.89 MPa

1

10

100

1000

230 240 250 260 270 280

T/KW

ate

r conte

nt(p

pm

)

(P=3.45 MPa)

(P=3.45 MPa)

(P=10.34 MPa)

(P=10.34 MPa)

The differences of water contents of methane and gas mixture are

independent of temperature and are only a function of pressure


Experimental water content data of a mixture of methane (94.69 mol%)

and propane (5.31%) used for taking into account the effect of gas

gravity (Experimental data from Song and Kobayashi 1982)

ln(,

, 4

w

CHw

y

y)=-2.1851+4.0813 -0.2221P+0.4149P

0

50

100

150

200

250

300

350

400

450

0 50 100 150 200 250 300 350 400 450


Ca

lcu

late

d v

alu

es (

pp

m)


A comparison between the results of this approach and

the method of Kobayashi et al. (1987)

Determine the water content of a gas whose gravity is

0.575 in equilibrium with hydrate at 6.895 MPa & 260.04 K.

Answer:

Kobayashi et al.’s (1987) method: 3.21E-05 (Sloan 1998)

This approach: 2.92E-05


Conclusions

• A literature survey was made on the existing water content data of methane & gas mixtures in equilibrium with gas hydrates.

• A quick review on the existing correlations showed a need for developing a new approach.

• A semi-empirical approach based on equality of water fugacity between gas and hydrate phases was developed for estimating the water content of sweet natural gases in equilibrium with gas hydrates.

• The results of water content predictions are comparable with a previously recommended predictive method.

Experimental Work:

WAX MEASUREMENTS

Hongyan Ji

Rod Burgass

Outline

• Apparatus and method

• Test Fluids

• WAT and WDT measurements

• Effect of cooling rate on WAT

Schematic of QCM apparatus

QCM Electric feedthroughsPressure transducer

Water jacket

Magnetic mixer

Inlet valveT probe

Schematic of high pressure (52MPa) visual rig

Example of WAT/WDT measurement for North Sea dead

crude using QCM

-2600

-2100

-1600

-1100

-600

-100

28 33 38 43 48 53 58 63

T/C

Ch

an

ge i

n r

eso

nan

t fr

eq

uen

cy/H

z

Cooling

Heating

WAT

WDT

Composition of separator condensate


C3 0.03 0.12 C11s 5.77 6.07

iC4 0.07 0.18 C12s 4.95 4.75

nC4 0.32 0.84 C13s 4.58 4.09

iC5 0.60 1.28 C14s 4.93 4.10

nC5 1.07 2.29 C15s 4.45 3.39

C6s 3.53 6.13 C16s 3.74 2.69

C7s 7.93 13.32 C17s 3.23 2.18

C8s 10.99 16.5 C18s 3.34 2.10

C9s 8.30 11.06 C19s 2.94 1.76

C10s 6.94 8.19 C20s 22.31 8.98

Composition of fluid made by combining separator

condensate and natural gas (Bubble point 101 bar at 15ºC)


CO2 0.20 0.49 C10s 6.51 5.26

N2 0.31 1.16 C11s 5.41 3.90

C1 4.73 31.26 C12s 4.64 3.05

C2 0.58 2.03 C13s 4.29 2.63

C3 0.28 0.68 C14s 4.63 2.63

iC4 0.11 0.20 C15s 4.18 2.18

nC4 0.37 0.68 C16s 3.51 1.73

iC5 0.58 0.86 C17s 3.03 1.40

nC5 1.00 1.47 C18s 3.13 1.35

C6s 3.29 3.94 C19s 2.76 1.13

C7s 7.44 8.55 C20+ 20.92 5.76

C8s 10.31 10.59

C9s 7.78 7.10

WAT and WDT measurements for separator condensate

at different pressures

0

50

100

150

200

250

300

350

400

20 25 30 35 40 45 50

T/C

P/b

ar

WAT

WDT

WAT and WDT measurements for live fluid at different

pressures

0

50

100

150

200

250

300

350

400

15 20 25 30 35 40 45 50

T/C

P/b

ar

WAT separator condensate

WDT separator condensate

WAT live fluid

WDT live fluid

Bubble point line

WAT and WDT measurements for live fluid at different

pressures (comparing 2 rigs)

0

50

100

150

200

250

300

350

400

15 20 25 30 35 40 45

T/C

P/b

ar

WAT live fluidWDT live fluid

WAT Visual rig (QCM)WDT Visual rig (QCM)

WAT Visual rig (visual)WDT Visual rig (visual)

Effect of cooling rate on WAT for North Sea dead crude

sample (WDT 50°C)

25

30

35

40

45

50

0 5 10 15 20 25

Cooling rate degrees C per hour

T/C

Flow Assurance: Gas Hydrates and Wax - December 2004 Steering Committee Meeting

Thermodynamic Modelling -

Wax

Hongyan Ji


Heriot-Watt WAX (HWWAX) model

Background

• Developed using n-paraffin mixtures.– Tuned with binaries.

– Validated with multi-component systems.– Good agreement between the model predictions and

experimental data of WDT, wax amount and wax composition.

• Full compositional data required.

Objective of this study

• To extend HWWAX for real reservoir fluids.


To Extend HWWAX for Reservoir Fluids

• A real reservoir fluid contains n-paraffins as well

as large amounts of non-normal paraffins.

– Non-n-paraffin hydrocarbons need to be added.

• Compositional data for a real reservoir fluid are

limited.

– An approach needed for estimating compositional data.


• Different hydrocarbon types and their roles in wax formation

• Modelling of wax in real reservoir fluids– Splitting of the plus fraction into SCN groups

– Estimation of n-paraffin concentration

– Estimation of non-n-paraffin melting point temperature

• Discussions

• Application to Independent Reservoir Fluid Systems

• Conclusions

Outline


• Different hydrocarbon types:

– N-paraffins, Iso-paraffins, Naphthenes, Aromatics

• Density

• Melting point temperature

iso-paraffins n-paraffins naphthenes aromatics

Different Hydrocarbon Types and Their

Roles in Wax Formation

DensityLow High

n-paraffins >iso-paraffins

naphthenes

aromatics


• Difficult to experimentally detect which

hydrocarbon type initiates wax formation.

• Roles of different hydrocarbon types in wax

formation were examined.

• First observation - (Srivastava et al., 2002)



WDT for

n-paraffin fraction

WDT for

iso-paraffin & naphthene fraction

as well as

aromatic fraction

40 – 60 oC


Mixtures with higher n-paraffin concentrations showed

higher WDT values.

• Second observation - (Srivastava et al., 2002)



-5

5

15

25

35

45

55

0 10 20 30 40 50 60 70 80 90 100

n-paraffin mass%

WD

T/o

C

Distillate

mixtures formed by mixing n-paraffinswith iso-paraffins & napthenes

mixtures formed by mixing n-paraffinswith aromatics


• Third observation – (Pedersen et al. 1991; Srivastava et al. 1993;

Roehner et al., 2002)

– N-paraffins, iso-paraffins and naphthenes found in wax

deposits.

– The predominant hydrocarbon types in wax depends on reservoir

fluid and deposition temperature.

– Little amount of aromatics found in wax deposits.

• Role of hydrocarbon types speculated as

– N-paraffin concentrations determine wax phase boundary.

– Iso-paraffins and naphthenes affect wax accumulation.

– Aromatics do not precipitate to form wax.




• However, it is difficult to differentiate all

hydrocarbon types with available exp. data.

• Iso-paraffins, naphthenes and aromatics in

each SCN group are considered as a pseudo-

compound (referred as non-n-paraffin).

• To model wax in reservoir fluids

– N-paraffin concentrations need to estimate.

– Melting point temperatures for non-n-paraffins are

required.

Modelling of Wax in Real Reservoir Fluids


• N-paraffin concentrations estimated using

conventional fluid property data.

– concentrations

– molecular weights

– and specific gravities

• Numerical methods developed for

– Splitting the plus fraction into SCN groups.

– Then separating each SCN into a n-paraffin and a

non-n-paraffin pseudo-compound.

SCN groups up to C19

& for the C20+ fraction.




• Splitting the plus fraction into SCN groups

– SCN mole fraction and molecular weight calculated with

a Gamma distribution function.

– SCN specific gravity calculated with

• Separating each SCN into an n-paraffin and a non-

n-paraffin pseudo-compound

SGiSGi bMWlnaSG

npC

np,i

np,iSCN,i

inpnpSCN,inp,iSG

SGSGMWBA.zz 01


Modelling of Wax in Real Reservoir FluidsnpC

np,i

np,iSCN,i

inpnpSCN,inp,iSG

SGSGMWBA.zz 01

• Anp, Bnp and Cnp determined by matching the experimental WDT data for 13 North Sea crude oils.

Constant Value

A np 0.8133

B np5.737x10

-4

C np 0.1281


• Melting point temperatures of non-n-paraffins are

dependent on

– Carbon number

– Molecular structure

• The effect of molecular structure on melting point

temperature is ignored in this work

– Lack of experimental data about detailed molecular

structures of compounds in real reservoir fluids.



• Melting point temperatures for non-n-paraffins

estimated from the n-paraffin with the same

carbon number.

• D is optimised as 70 oC

– Determined by matching the wax amount measured

at -40 oC for a waxy North Sea crude oil.

DTT f,np,inp,if,non



Discussions

Exp. data Calculated WDT and

deviation (Dev.)

Oil number WDT/oC WDT/oC Dev./oC

1 50 50 0

2 51 48 -3

3 53 52 -1

5 50 54 4

6 53 53 0

7 53 50 -3

8 51 48 -3

9 46 52 6

10 42 44 2

11 50 50 0

12 38 48 10

15 50 44 -6

17 42 50 8

• For the majority of oils

– Good agreements.

• For Oils 9, 12, 15 and 17

– Significant deviations.

Experimental data and the calculated WDTs for 13 North Sea crude oils


Discussions

Reasons for the deviations

• Accuracy of experimental data

– A visual technique

– Continuous heating (0.5 oC/min)

• The methods used for estimating n-paraffin

concentrations

– Based on specific gravity with an implicit assumption

– all non-n-paraffins have higher specific gravities than the n-

paraffin with the same molecular weight

– However, the specific gravities of iso-paraffins are

generally lower than n-paraffins.


Discussions

Exp. dataCalculated WDT and

deviation (Dev.)

Oil No. WDT/oC WDT/oC Dev./oC

7 53 50 -3

8 51 48 -3

17 42 50 8

• A higher WDT value calculated for Oil 17

– a close molar distribution

– a low specific gravity

• Oil 17 might contain a relatively high quantity of

iso-paraffins.


SCN (heavier than C35) molar distributions and specific

gravities estimated for the North Sea Crude Oils 7, 8 and 17

0.000

0.002

0.004

0.006

500 600 700 800 900

SCN molecular weight

SC

N m

ole

fra

ctio

n

Oil 7

Oil 8

Oil 17

0.90

0.92

0.94

0.96

0.98

1.00

500 600 700 800 900

SCN molecular weight

SC

N s

pe

cific

gra

vity

Oil 7

Oil 8

Oil 17


Application to Independent Reservoir Fluid

Systems

Experimental data and calculated (HWWAX) SCN molar distributions for Base Condensate LTB98-1.

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

0.160

50 150 250 350 450 550 650 750 850

Molecular weight

SC

N m

ole

fra

ctio

n

exp. data: Reservoir Fluid Studies Group,HWU

HWWAX calculated data

Base Condensate LTB 98-1



Systems

0.70

0.75

0.80

0.85

0.90

0.95

1.00

80 180 280 380 480 580 680 780 880

molecular weight

SC

N s

pe

cific

gra

vity

exp. data

HWWAX calculations


Measured and calculated (HWWAX) specific gravities for SCN groups in Base Condensate LTB98-1.



Systems

Calculated (HWWAX) mole-fraction distributions for SCN groups

and n-paraffins heavier than C20 in Base Condensate LTB98-1.

0.000

0.002

0.004

0.006

0.008

0.010

0.012

280 380 480 580 680 780 880

Molecular weight

Mo

le f

ractio

n

SCN mole fractions: HWWAX calculations

n-paraffin mole fractions: HWWAX calculations




Systems

Measured WDT data and the HWWAX predictions for

the stabilised fluid of Base Condensate LTB98-1

Experimentaldata

Predictions andDeviations

P/bar WDT/oC WDT/

oC Dev./

oC

1 37 35 -2 52 38 36 -2 59 39 37 -2

154 41 39 -2 238 43 41 -2 376 46 44 -2



Systems

N-paraffin concentrations (calculated using HWWAX) in the live fluid (containing 6.2 mass% or 35.8 mole% natural gases) compared to the stabilised fluid.

0.0000

0.0005

0.0010

0.0015

0.0020

0.0025

0.0030

280 380 480 580 680 780 880

Molecular weight

Mo

le f

ractio

n

n-paraffin concentration: stabilised fluid

n-paraffin concentration: live fluid




Systems

Measured WDT data and the HWWAX predictions for

the live fluid of Base Condensate LTB98-1.

Experimentaldata

Predictions andDeviations

P/bar WDT/oC WDT/oC Dev./oC

2 38 35 -3 34 37 35 -2 61 37 35 -1 79 37 36 -1 96 37 36 -1 132 38 37 -1 193 39 38 0 288 40 41 1 364 41 42 1


• HWWAX has been extended for modelling wax in

real reservoir fluids.

• Required input data are conventional fluid

properties commonly measured in laboratory.

• Good agreement observed for independent

predictions and measured WDT data.

• HWWAX can be further improved

– Correlation for estimating n-paraffin concentration.

Conclusions


HYDRATES FORMATION IN WATER-OIL

EMULSIONS




Outline

• To study experimentally the kinetics of

gas hydrate formation in water-oil

(Brazilian Oil) emulsions.


Schematic of visual rig used for W/O emulsion tests

Window

CameraLight source

Window

PRT Pressuretransducer

Inlet/outlet

Magneticmixer

Waterjacket inlet

Water jacket outlet


Kinetics test conducted for the Brazilian oil with

20% water cut at 200 rpm

0

50

100

150

200

250

0 10 20 30 40 50

Time/hr

P/b

ar

or

Torq

ue

0

5

10

15

20

25

30

35

40

45

T/C

Torque

Pressure

Temperature

0

50

100

150

200

250

0 10 20 30 40 50

Time/hrP

/ba

r o

r T

orq

ue

0

5

10

15

20

25

30

35

40

45

T/C

Torque

Pressure

Temperature

Hydrate Hydrate

Few/No minutes induction time




0

100

200

300

400

500

600

0 10 20 30 40

Time/hr

P/b

ar

or

To

rqu

e

0

5

10

15

20

25

30

35

40

45

T/C

Torque

Pressure

Temperature

0

50

100

150

200

250

300

350

400

450

500

0 10 20 30 40 50 60 70 80 90

Time/hrP

/ba

r o

rT

orq

ue

0

5

10

15

20

25

30

35

40

45

T/C

Torque

Pressure

Temperature

HydrateHydrate





0

50

100

150

200

250

0 10 20 30 40 50

Time/hr

P/b

ar

or

To

rqu

e

0

5

10

15

20

25

30

35

40

45

T/C

Pressure

Torque

Temperature

0

50

100

150

200

250

0 10 20 30 40 50

Time/hrP

/ba

r o

r T

orq

ue

0

5

10

15

20

25

30

35

40

45

T/C

Torque

Pressure

Temperature

Hydrate Hydrate





0

100

200

300

400

500

600

0 10 20 30 40 50

Time/hr

P/b

ar

or

To

rqu

e

0

5

10

15

20

25

30

35

40

45

T/C

Torque

Pressure

Temperature

0

50

100

150

200

250

300

350

400

450

500

0 10 20 30 40 50

Time/hr

P/b

ar

or

To

rqu

e

0

5

10

15

20

25

30

35

40

45

T/C

Torque

Pressure

Temperature

HydrateHydrate



Conclusions

• Several experiments were conducted on a stable

water/oil emulsion with 20 and 30% water cuts,

prepared by mixing under different speed shearing.

• The experimental results have shown that hydrates

could form in the system during flowing (or mixing)

with a significant torque/viscosity increase after

hydrate formation. An induction time of few minutes

(or no induction time) was observed. At low mixing

conditions, this caused blockage while no blockage

was observed at higher mixing conditions.

Flow Assurance: Gas Hydrates and Wax · Flow Assurance: Gas Hydrates and Wax – December 2004...

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Transcript of Flow Assurance: Gas Hydrates and Wax · Flow Assurance: Gas Hydrates and Wax – December 2004...