Flow assurance in sub-sea pipelines

www.conservaenergia.com

• MR Riazi, Characterization and Properties of Petroleum Fractions, ASTM International, (2005).

• Y Bai and Q Bai, Subsea Pipelines and Risers, Elsevier Science, 2nd Ed, (2005)

Reference Sources used:

Aims & Objectives

• to review the types of materials constituting petroleum fluids

• to identify and describe the types and the properties of materials which compromise pipeline flow assurance

• to relate how phase equilibria diagrams (PTx) can be used to predict conditions of precipitation of these materials

• to consider means to inhibit formation of these materials

1.E+00

1.E+02

1.E+04

1.E+06

1.E+08

1.E+10

0 10 20 30 40

No of carbons

No

of c

ompo

unds

C1

CH4

C2

C2H6

C3

C3H8

methane propaneethane

C4

C4 H10

C4 H8

n-butane

isobutane (methyl-propane)

Hydrocarbon structures

2-methylheptane

C8

n-octane

heteroatom

ethylcyclopentane o-xylene

naphthalene dibenzothiophene

Cycloalkanes

Component Dry Gas Wet gas Gas condensate

Volatile oil Black oil Crude oil+

CO2 3.7 0 0.18 1.19 0.09 0

N2 0.3 0 0.13 0.51 2.09 0

H2S 0 0 0 0 1.89 0

C1 96 82.28 61.92 45.21 29.18 0

C2 0 9.52 14.08 7.09 13.60 0.19

C3 0 4.64 8.35 4.61 9.20 1.88

iC4 0 0.64 0.97 1.69 0.95 0.62

nC4 0 0.96 3.41 2.81 4.30 3.92

iC5 0 0.35 0.84 1.55 1.38 2.11

nC5 0 0.29 1.48 2.01 2.60 4.46

C6 0 0.29 1.79 4.42 4.32 8.59

C7+ 0 1.01 6.95 28.91 30.4 78.23

Total 100 100 100 100 100 100

GOR 69917 4428 1011 855

M7+ 113 143 190 209.8 266

SG7+@ 15.5oC 0.794 0.795 0.8142 0.844 0.895

API7+ 46.7 46.5 42.1 36.1 26.6

From MR Riazi, Characterization and Properties of Petroleum Fractions, ASTM International, p6, (2005).

Composition (mol%) and Properties of Various Reservoir Fluids and Crude Oil*

*measured by analytical tools (gas chromatography, mass spectrometry, etc.)

+stock tank conditions

50 100 150 200 250 400300 350 500450 550

home.flash.net/~acqsol/BatchReport.htm

Infra-red and Near Infra-red spectroscopy

Aske, N, Kallevik, H, and Sjöblom, J., Energy & Fuels, 15, 1304-12, (2001)

Hydrocarbons M H% H/C V d,Å D Insoluble in

Asphaltene 1000-5000 9.2-10.5 1.0-1.4 900 14.2 4-8 n-hexane

Resin 800-1000 10.5-12.5 1.4-1.7 700 13 2-3 80:20 isobutyl alcohol:cyclohexane

Oil 200-600 12.5-13.1 1.7-1.8 200-500 8-12 0-0.7

Pan, H. and Firoozabadi, A., SPE Production and Facilities, 13, pp118-127, (1998)

Petroleum fluid fractions

Increasing molecular weight

Increasing complexity

A knowledge of the composition of a reservoir fluid can enable the phase equilibrium (vapour-liquid and solid-liquid equilibrium) modelling of the pressure – temperature properties of the fluid

www.jee.co.uk

40

200

160

120

80

300 400 700 800Temperature (K)

Pre

ss

ure

(b

ar)

240

500 600200

L+V

Lcritical pointdew pointbubble point

C7+ (1 component)

C7+ (5 components)

Pressure–Temperature–Composition (PTx): Effects on Phase Equilibria

• pressure reduction at valves• compositional changes from injection processes• temperature/pressure changes during pipeline transit (flow)

• phase separation (suspended solids agglomerates)• adhesion to transmission control system

• reduction in throughput (revenue)• blockage

There are three types of heavy hydrocarbons that exist in a heavy petroleum fluid which due to PTx effects can precipitate in transmission systems:

• waxes• asphaltenes• resins

Also, interactions between oil/gas constituents and injection media can lead to formation of:

• gas hydrates• salts

www.ifos.com

Waxes (or paraffins)

Pigging to remove wax from a subsea transfer line(http://www.hydrafact.com)

• typically long chain (C6- C36) normal (n-)alkane compounds that are naturally resident in crude oil – average molecular weight around 350 and freezing points in the range 30 – 70oC

• crystalline waxes (iso- and cyclo- paraffins, C30-60, M in the range 500- 800 and melting pt. 70-90oC)

• Consistency ranges from petroleum jelly to hard wax. Density around 0.8 g.cm-3

• can deposit from the oil as a result of temperature/pressure changes (particularly susceptible are sub sea production facilities and pipelines)

• forms as waxy elongated crystals.

Measurement of wax appearance characteristics(http://www.hydrafact.com)

The WAT is not an equilibrium point; wax appearance is a kinetically-controlled nucleation process;

influenced by temperature, (e.g. temperature gradients from wall cooling), cooling rates and availability of nucleation sites (e.g. small particles).

Below the WAT, crystals may form and be transported with the remaining fluid or deposit on a cold surface, leading to fouling.

The pour point is the temperature at which a fluid ceases to pour – the formation of a 3D network spanning the pipe - can occur when flow is interrupted.

Wax deposition characteristics

In subsea systems:

• wax deposition in pipelines is gradual but can lead to blockage

• crude oil gelation can occur during shut-in (zero flow)

• leads to high start-up pressures and high pumping pressures due to increased viscosity

• temperature gradients can be reduced by insulating pipes (increased capital expense)

The temperature at which wax begins to form is called the ‘cloud point’ or the wax appearance temperature (WAT).

Wax precipitation models• solid solution • multisolid phase model – calculation of cloud point temperature (CPT) – equivalent to WAT

Both models are based on the relationship:

),,(),,(),,( Si

Si

Li

Lii

Vi xPTfxPTfyPTf

iii xKy and Li

SLi

Si xKx

WAT values derived from solid solution models are close to the pour points of oilWAT values derived from multisolid phase models are close to the cloud point

Pan, H., Firoozabadi, A and Fotland, P., SPE Production and Facilities, 12, 250-8, (1997)

Effect of temperature and Pressure on WAT

VLE SLE

Wax Inhibition

Cloud points for crude oils are generally in the range 300-315K (80-110oF)Protection strategies may include:

• temperature control at CPT + 15oF• readily achieved in the wellbore and subsea tree• subsea flowlines may require electric or hot fluid heating

• thermodynamic wax inhibitors (TWI), e.g. solvents • polyalkyl acrylates, low molecular weight polyethylene waxes, ethyl-vinyl acetate (EVA) • wax-saturated solvents must be removed to avoid re-precipitation elsewhere

• pour point depressants/dispersants/surfactants• modify crystal structure and reduce viscosity, i.e. additives with wax-like (n-alkane) part to bind the wax but non-wax-like terminating group as in surfactants, e.g. linear sulphonates.

EVA

Remediation strategies:• mechanical – pigging.• NGS (nitrogen generating system) – combines thermal, chemical, and mechanical effects by controlling nitrogen gas generation to comprise the reversible fluidity of wax/paraffin deposits

dispersant/crystal modifier properties

Asphaltenes

Pipeline asphaltene fouling(http://www.hydrafact.com)

• a black, brittle component of the bitumen in petroleum

• organic materials consisting of aromatic and naphthenic ring compounds which carry the main inorganic components of crude oil,

including nitrogen, sulfur, oxygen, nickel and vanadium

• insoluble in non polar solvents but soluble in toluene or other aromatics-based solvents.

• frequently occurs with wax deposition

• generated as a result of pressure drop, high shear (turbulent flow), acids, soluble CO2 (EOR), injected condensate, mixing of incompatible crudes, etc.

• deposition is non-reversible, i.e. difficult to remove by manipulation of pressure/ temperature.

• colloidal suspensions in resins in the oil. Dispersion stability depends on the ratio of resin to asphaltene molecules.

Molecular Structure of asphaltene proposed for 510C

Residue of Venezuelan Crude by Carbognani [INTEVEP S.A.

Tech. Rept., 1992]

Molecular structure of asphaltene proposed for Maya crude (Mexico) by Altamirano, et al. [IMP

Bulletin, 1986]

Various shapes of asphaltene micelles formed in the presence of large amounts of polar or aromatic

solvents

http://tigger.uic.edu/~mansoori/Asphaltene.Molecule_html

Asphaltenes – molecular characteristics

Pan, H. and Firoozabadi, A., SPE Production and Facilities, 13, pp118-127, (1998)

Rapid physical methods of assessing asphaltene on-set

• refractive index• electrical conductivity• kinematic viscosity…..

500

2500

2000

1500

1000

25 50 75 100

Mole % CO2

Pre

ss

ure

(p

si)

LL

LV

Tank Oil specifications Asphaltene specifications

Mol% C1+ C2 0.6 Wt% resin in oil 14.1

Mol% C3 - C5 10.6 Wt% asphaltene in oil 4.02

Mol% C6 4.3 Density (g/cm3) 1.2

Mol% C7+ 84.5

M 221.5 (M7+ = 250) M (precipitated) 4500

SG 0.873 (SG7+ = 0.96)

900

1300

1200

1100

1000

98 98.5 99 100

Mole % CO2

Pre

ss

ure

(p

si)

99.5

1400

L

LS

LVSLV

Px diagram for an oil-CO2 system at 24oC

Kawanaka, S., Park, SJ, and Mansoori, GA, SPE Reservoir Engineering, 6, 185-192, (1991)

- asphaltene precipitation predicted in LS and LVS fields

Relevance of Equilibrium Phase Diagrams to asphaltene management

Region of asphaltene precipitation

asphaltene solubility

saturation pressure

reservoir pressure

Temperature

Pre

ssu

re

P-T diagram for asphaltene precipitation predictions

Relevance of Equilibrium Phase Diagrams to asphaltene management

Once formed – difficult to remove by manipulation of PT conditions

• chemical treatments

Y Bai and Q Bai, Subsea Pipelines and Risers, Elsevier Science, 2nd Ed, 2005

Asphaltene precipitation from tank oil in presence of C5-C10 diluents at 295K and 1 bar.

Tank Oil specifications Asphaltene specifications

Mol% C1+ C2 0.6 Wt% resin in oil 14.1

Mol% C3 - C5 10.6 Wt% asphaltene in oil 4.02

Mol% C6 4.3 Density (g/cm3) 1.2

Mol% C7+ 84.5

M 221.5 (M7+ = 250) M (precipitated) 4500

SG 0.873 (SG7+ = 0.96)

Pan, H. and Firoozabadi, A., SPE Production and Facilities, 13, pp118-127, (1998)Wu, J., Prausnitz, JM, and Firoozabadi, A., AICE Journal, 44, 1188-99, (1998)

Micelle–based model of asphaltene precipitation (and dissolution)

resins

• Onset of asphaltene precipitation shown where curve levels off

• Lighter solvents cause higher precipitation

• Dilution ratio (RS, i.e. the volume in cm3/g of crude) at the onset is a function of solvent

molecular weight, MS, i.e. increases with MS

• The amount of solid precipitated in the presence of propane increases with temperature but decreases for n-heptane.

• Effect of pressure above the bubble point of oil decreases precipitation but below, precipitation increases.

propane n-heptane

Effects of chemical treatments on asphaltene solubility

Strategy is to maintain asphaltenes in the fluid (dispersed or solubilised state)

Natural Gas Hydrates

Gas hydrates removed from a subsea transfer line (courtesy of Petrobras, Brazil).

• formed at high pressure and low temperature from combination of water and constituents of hydrocarbon fluid stream (e.g. CH4, C2H6, C3H8, N2, CO2, H2S)• increasingly important in O&G operations in deeper waters• most commonly encountered during

drilling and production

One volume of this saturated methane hydrate contains up to 189 volumes of methane gas at STP. This large gas-storage capacity of gas hydrates may represent an important source of natural gas.

www.csiro.au/files/files/pl1k.pdf A gas hydrate

Image courtesy U.S. Geological Survey

Hydrate Formation Requires Five Ingredients:

Water

Pressure

Temperature

Nucleation Site

Gas - CH4, CO2, C2H6, H2S, etc.

Hydrate Structures - variable

http://www.telusplanet.net/public/jcarroll/HYDR.HTM

http://www.telusplanet.net/public/jcarroll/HYDR.HTM

Hydrates Formation and Dissociation

Stable Hydrate Region

Hydrate-free Region

Metastable Region

hydrate dissociation

curve

hydrate formation

curve

Pre

ssur

e (p

si)

Temperature

Stable Hydrate Region

Hydrate-free Region

Metastable Region

hydrate dissociation

curve

hydrate formation

curve

Pre

ssu

re (

psi

)

Temperature

Hydrate Inhibition

• Inhibitors (10-50 wt%) can reduce hydrate formation temperature (HFT) to

below the hydrate dissociation curve.

• Low dose hydrate inhibitors (LDHI 0.3- 0.5 wt%) – interfere with crystallisation.

• Cold flow technology – controlled growth of hydrates to unsure stable suspensions.

)100( WM

KWT

T- temperature shift (oC)W – inhibitor concentration (wt%)M – molecular weight of inhibitor/molecular weight of water

Inhibitor K Value

Methanol 2335

Ethanol 2335

Ethylene glycol 2700

Diethylene glycol 4000

Triethylene glycol 5400

Low dose hydrate inhibitors

• hydrate surface has open cavities – penetrated by hydrocarbon component• amide group hydrogen bonds to hydrate surface via carbonyl• adhesion to hydrate surface prevents further hydrate growth• limited growth keeps hydrates in suspension

Tutorial Questions

1. Identify factors during fluid transfer from a wellbore which can lead to precipitation and conductivity problems in flowlines.

2. Sketch the basic features of a PT diagram for the methane-water system and describe the effect of sub-cooling. Use the diagram to illustrate why this presents a threat to the integrity of a sub-sea flow line.

3. Explain why dehydration is a possible approach to the inhibition of natural gas hydrates in a pipeline and what type of chemical treatment might be suitable.

4. How do low does hydrate inhibitors (LDHIs) function in comparison to thermodynamic hydrate inhibitors (THIs).

5. Discuss the benefits of dispersion over dissolution in the remediation of flow.

6. Discuss the role of resins in maintaining flow where there is a realistic risk of asphaltene precipitation. What specific properties do these have which enable this function?

7. Distinguish between the various constituents of a petroleum fluid and explain the chemical principles involved in defining a remediation treatment for fouled valvework and pipelines.

8. Identify an equilibrium thermodynamics approach to predicting precipitation under various PTx conditions, i.e. how to construct a PTx phase diagram.