Pvt Deg 2009-2010

PROPERTIES OF RESERVOIR FLUIDS

René MIGNOT

PVT DEG 2009 2010

OIL AND GAS PHYSICAL PROPERTIES 1. Generalities 2. Chemical composition of petroleum fluids 3. Pure components,binary mixtures and petroleum fluids 4. Oil and Gas main properties 5. Correlations to estimate hydrocarbons properties 6. Equations of state 7. Sampling 8. Oil PVT Study 9. Gas condensate PVT study 10. Water properties

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PVT DEG 2009 2010

OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

1.GENERALITIES

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PVT DEG 2009 2010

GENERALITIES • Goal of a PVT study Determine characteristics (chemical and physical) of the reservoir fluids so as to predict its behaviour when pressure and temperature vary. • During the production process in the reservoir, fluids are depleted at constant temperature.

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PVT DEG 2009 2010

GENERALITIES

• Conclusions of a PVT study Parameters for hydrocarbons in-place evaluation Recovery-factor calculations Fluid composition analysis Phase behaviour during production Input to reservoir numerical simulation

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PVT DEG 2009 2010

GENERALITIES Who uses PVT data ? Reservoirs engineers - Understanding of the oil and gas behaviour in the reservoir -

Establish a coherent development plan Use for compositional simulation (equation of state)

Process engineers - Choice of the separation process -

Surface separation optimization

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PVT DEG 2009 2010

GENERALITIES • THE PVT FLUID analyzed must be the most representative of the RESERVOIR FLUID. • Representativity guarantees an accurate production prediction, exactness of the bubble or dew point, nature of the fluid in the reservoir, amount of oil produced. Requirements are: - acquisition of adequate volume of representative fluid samples - exact PVT data measurements with strict qualityassurance/quality control (QA/QC) • The PVT cost is minimal in regard to economical benefits or losses brought by the lack of knowledge of the fluid properties present in the reservoir. 7

PVT DEG 2009 2010

GENERALITIES Consequences ¾ Don’t hesitate to sample fluids for PVT analysis ¾ Representativity of the sampling is essential

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UNITS Quantity

Symbol

Unit

Conversion Factor

Pressure

Pa bar atm psi Mpa

Pascal Bar Atmosphere Pound per square inch Mega Pascal

SI unit (10-5 bar) 105 Pa or 14.5 psi 1.01325 bars 0.06895 bar 10 bars

Kelvin Degree Celsius Degree Fahrenheit

Temperature K °C °F

Volume

°R

Degree Rankine

T(°K)=T(°C)+273.15 T(°C)=T(°K)-273.15 T(°F)=32+1.8T(°C) T(°C)=[T(°F)-32]/1.8 T(°R)=T(°F)+459.67

cu ft bbl

Cubic foot Barrel

0.02831 m3 0.158987 m3 9

PVT DEG 2009 2010

UNITS Quantity

Symbol

Unit

Conversion Factor

GOR

cu ft/bbl

cu ft/bbl

0.17706 m3/m3

Salinity

ppm mg/l

part per million milligram per liter

10-3 g/m3 10-3 g/l

Viscosity

cp mPa.s Pa.s

centipoises millipascal.second Pascal.second

1 mPa.s 1 cp Unit SI (1000cp)

Interfacial tension

dyne/cm mN/m N/m

dyne per cm milliNewton per meter Newton per meter

mN/m or 10-3N/m 1 dyne/cm or 10-3 N/m Unit SI (1000 dyne/cm)

Compressibility

bar-1 psi-1

bar inverse square inch per pound

0.06895 psi-1 14.5 bar-1 10

PVT DEG 2009 2010

GENERALITIES Definitions Reference conditions generally used throughout Petroleum Industry Standard Conditions . Ps.c= 1.013 bara (ou 14.7 psia) . Ts.c= 15.6 °C (or 60 °F)

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UNITS metric Units Length Surface Volume Mass Time rate GOR pressure Viscosity Density

m m2 m3 kg day m3/day m3/m3 bar cp kg/m3

Customary units feet ft ft2 ft3, cu ft pound, lbm day bbl/d, STB/d, scf/d scf/STB psi cp lbm/cu ft

Temperature °C, °K

°F, °R

Permeability md

md

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PVT DEG 2009 2010

OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

2. CHEMICAL COMPOSITION OF PETROLEUM FLUIDS

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OIL AND GAS PHYSICAL PROPERTIES and PVT STUDIES

Immature zone

Hydrocarbon maturity Biogenic gas

130 °C

Oil

180 °C

Dry Gas

Condensate

Oil

60 °C

Heavy Hydrocarbons

PVT DEG 2009 2010

Catagenic Gas CH4

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CHEMICAL COMPOSITION OF PETROLEUM FLUIDS

• Petroleum fluids are mainly constituted of organic elements as hydrocarbons • Hydrocarbons contains only carbon and hydrogen • Also crude oils contains non hydrocarbons as nitrogen (N2), hydrogen sulfide (H2S), carbon dioxyde (CO2), carbon monoxyde (CO), and mercaptans (R-S-H) • Also contains elements as traces Hg, Ni, Va, S, O

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PVT DEG 2009 2010

CHEMICAL COMPOSITION OF PETROLEUM FLUIDS

.Compositional analysis of the gas phase by gas chromatography; N2, CO2, C1-C10 •Compositional analysis of the liquid phase by gas chromatography up to C20+, often (C11+, C7+) and/or distillation from C10 to C20+.

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GAS CHROMATOGRAM

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MAIN FAMILIES OF HYDROCARBONS

Hydrocarbons AROMATICS Aliphatics

(ex. benzene, toluene, xylene) SATURATED

Unsaturated

(or Alkanes)

Normal alkanes

Iso-alkanes

(ex. methane, ethane, propane)

(ex. iso-butane

)

Cycloalkanes (or Naphthenes)

Alkenes (ex. ethylene)

Alkynes (ex. acetylene)

(ex. cyclohexane)

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PVT DEG 2009 2010

CLASSIFICATION OF PETROLEUM RESERVOIR FLUIDS

ALKANES or PARAFFINS (saturated hydrocarbons) Normal alkanes Straight chain CnH2n+2 Methane CH4 ethane C2H6 propane C3H8 n-butane C4H10

Iso-alkanes branched chain CnH2n+2 i-butane i-C4H10 i-pentanes i-C5H12

Cycloalkanes or naphtenes CnH2n cyclopentane C5H10 cyclohexane C6H12

AROMATICS Benzene C6H6 Asphaltenes (ex naphtalene, anthracene) 19

PVT DEG 2009 2010

COMPOSITION OF A PETROLEUM FLUID

Cut Component Molar fraction Cut

Component Molar fraction

H2S N2 CO2 C1 C2 C3 C4

iso nonanes aromatics in C8 cyclanes in C9 n nonane iso decanes aromatics in C9 n decane undecanes dodecanes tridecanes tetradecanes pentadecanes hexadecanes heptadecanes octadecanes nonadecanes eicosanes plus

C5 C6 C7

C8

hydrogen sulfide nitrogen carbon dioxide methane ethane propane iso butane n butane iso pentane n pentane iso hexanes n hexane iso heptanes benzene cyclanes in C7 n heptane iso octanes toluene cyclanes in C8 n octane

0.000 0.075 1.536 77.872 7.691 3.511 0.469 1.267 0.343 0.581 0.391 0.304 0.338 0.201 0.423 0.154 0.367 0.150 0.239 0.121

C9

C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20+

0.242 0.134 0.180 0.146 0.348 0.094 0.095 0.427 0.315 0.295 0.239 0.229 0.166 0.168 0.134 0.070 0.685

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COMPOSITION OF A CRUDE OIL •

Nonpolar hydrocarbons such as - paraffins, naphtenes, aromatics of moderate M

•

Polar polyaromatic materials sudbdivided in resins (less polar than asphaltenes) asphaltenes Definitions asphaltene: fraction of crude oil insoluble in excess nC5, but soluble in excess benzene and toluene at room temperature resins: fraction of crude oil soluble in excess C3 liquid at room temperature

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ASPHALTENICS CRUDES

• Asphaltenes are the components of crude oil with maximum molecular weight (up to several hundreds of atoms). Their concentration varies from 0 to 15% by weight.

• Their structure is highly aromatic, but aliphatic structures and hetero-atoms (oxygen, nitrogen, sulfur) are also present.

• In reservoir conditions, asphaltenes are solubilized in the crude oil. • When thermodynamic conditions change (depletion, gas injection...) asphaltenes may gather in larger and larger clusters. This process, called flocculation, is responsible for solid deposits in wells or pipes..

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PVT DEG 2009 2010

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ASPHALTENICS CRUDES

•Asphaltenes precipitation occurs - in the reservoir - in production facilities - in pipelines And according to the type of fluids - light oils - not for some heavy oils - not for gas condensate Temperature has little effect on asphaltene precipitation Pressure decreases causes asphaltene precipitation 23

PVT DEG 2009 2010

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PARAFFINIC CRUDES Temperature has a strong effect on wax precipitation Pressure increase slightly increases cloudpoint T

WAX: solid precipitate can occur - in well - production facilities - pipelines Wax precipitation for: - gas condensate - light-oil fluid

at T < 150°F

- heavy-oil fluid

at T < 150°F 24

PVT DEG 2009 2010

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PARAFFINIC CRUDES • Pour point : the lowest temperature, expressed as a multiple of 5°F, at which the liquid is observed to flow when cooled under prescribed conditions. • Cloud point : temperature at which paraffin wax begins to solidify and is identified by the onset of turbidity as the temperature is lowered.

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PVT DEG 2009 2010

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PHYSIOLOGICAL EFFECTS OF H2S Concentration

Danger of instant death

700 ppm

Danger of death after 30 minutes

350 ppm

Loss of sense of smell (within a few minutes)

100 ppm

Danger if exposure lasts several hours

50 ppm

Time weighted average for 8 hours exposure (TWA)

10 ppm

Initial sensitivity to smell

1 ppm

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PVT DEG 2009 2010

OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

3. PURE COMPONENTS BINARY MIXTURES & PETROLEUM FLUIDS

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PURE COMPONENTS PROPERTIES Physical properties of petroleum fluids are function of => PRESSURE, TEMPERATURE and COMPOSITION. = >PURE COMPONENTS PROPERTIES - Phase notion - Vapor pressure curve - Diagram Pressure-Volume (Clapeyron diagram) - Continuity of liquid and gaseous state - Isothermal compressibility - Isobaric compressibility

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PVT DEG 2009 2010

BINARY MIXTURES PROPERTIES

PROPERTIES OF BINARY MIXTURES - Pressure-Temperature Relationship - Pressure-Volume Relationship - Composition influence of the mixing - Retrograde condensation

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PVT DEG 2009 2010

PURE COMPONENTS PROPERTIES •

Pure components properties a pure component is characterized by one equation of state f(P,V,T) = 0

Pressure

P-T CURVE

Liquid

• Critical point Gas

Solid

• Triple Point

Temperature

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PVT DEG 2009 2010

PURE COMPONENTS PROPERTIES • Pure component properties : a pure component is characterized by one equation of state f(P,V,T) = 0

Pressure

Vapor pressure curve

Pc

C

• Liquid

Gas Tc Temperature 31

PVT DEG 2009 2010

PURE COMPONENTS DEPLETION

OIL

Psat

GAS

P2 = Psat

P3 = Psat

P4 = Psat

P5 = Psat

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PVT DEG 2009 2010

P -V CURVE PURE COMPONENTS

Pressure

T1

P sat

L

T2

T3

C

V Bubble point

L+V

dew point

Volume 33

PVT DEG 2009 2010

PURE COMPONENTS PROPERTIES Vapor pressure of normal paraffins Pressure Bar a.

Temperature °C 34

PVT DEG 2009 2010

BINARY MIXTURES PROPERTIES

Binary mixtures Properties . Diagram P-V . Diagram P-T . Composition influence of mixing

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PVT DEG 2009 2010

P -V CURVE MULTICOMPONENT SYSTEM

T2

T3

Pressure

T1

L P sat

CC

V

Bubble point

L+V

Dew point Volume 36

PVT DEG 2009 2010

BINARY MIXTURES PROPERTIES P - T diagram for C2/n-C7 mixture with 96,83 mol % ethane (from Standing26)

Pressure, psia

Pc

Tc Temperature, °F PVT DEG 2009 2010

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BINARY MIXTURES PROPERTIES P-T diagram for the C2/n-C7 system at various concentration of C2

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PVT DEG 2009 2010

PETROLEUM FLUIDS

Petroleum fluids properties • Crude oil - saturated oil - undersaturated oil

• Different gases - dry gas - gas condensate - wet gas

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PETROLEUM FLUIDS / BUBBLE POINT - DEW POINT Saturated fluid : One phase fluid at P and T conditions under study but which forms two phases if a P and T variation occurs (inside the phase envelope). In most cases, penetration inside the phase envelope creates a new phase, minor, with a different composition and density, while the preexisting phase is almost unchanged.

Bubble point : Thee pressure at which the first gas bubble appears (out of solution). Example : opening of a champagne bottle.

Dew point : The new phase is a liquid phase (mist or tiny droplets). Example : condensation of water vapor when breathing out in cold air.

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PETROLEUM FLUIDS

Pressure

• Saturated oil

Critical point

C Tres, Pres

Separator

Tc Temperature 41

PVT DEG 2009 2010

PETROLEUM FLUIDS

Pressure

• Undersaturated oil Tres, Pres

Critical point

C

Separator

Tc Temperature

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PETROLEUM FLUIDS • Dry Gas

Pressure

Critical point

C

Separator

Tres, Pres

P1

Tc Temperature 43

PVT DEG 2009 2010

PETROLEUM FLUIDS • Wet Gas Tres, Pres

Pressure

Critical point

C

Separator

Tc Temperature 44

PVT DEG 2009 2010

PETROLEUM FLUIDS • Gas condensate Tres, Pres

Pressure

Critical point

C

Séparateur

Tc Temperature 45

PVT DEG 2009 2010

Pressure

PETROLEUM FLUIDS / PHASE ENVELOPE OF A MIXTURE

œ



Oil reservoirs with dissolved gases

Ÿ

Cricondenbar

Pcc

Pc

Bu

p le b b

n oi

Gas reservoirs without retrograde condensation

ž

ve r u tc

Critical point Cricondentherm

Liquid + gas Dry gas

100% 75% 50%

Zone œ : No or poor contribution of dissolved gases 30% 20% 10% 5% 0%

De w

Zone  : Appreciable contribution of dissolved gases

e urv c t n po i

Zone ž : Retrograde with liquid deposit in the reservoir Tc Tcc

T

Zone Ÿ : Dry or wet gas 46

PVT DEG 2009 2010

PETROLEUM FLUIDS / PHASE ENVELOPE OF A MIXTURE

Pressure

Tcc

T1 Tc T2 Gas

T1 < Tc < T2 < Tcc Gas

RR2 Pc R2

B1 Liquid Liquid + vapor

R1

Volume 47

PVT DEG 2009 2010

TERNARY DIAGRAMS

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TERNARY DIAGRAM

The petroleum mixture is reduced to three components : - a light component (like methane) - intermediates (like C2 - C5) - a heavy component (like C6+) The phase behaviour of this three-component mixture is represented through an equilateral triangle, called the ternary diagram

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TERNARY DIAGRAM Lights

20% C6+ 30% C2-C5

50% C1 M

Heavies

Intermediates 50

PVT DEG 2009 2010

TERNARY DIAGRAM

- each corner of the triangle corresponds to 100 % of a single component - each side represents two-component mixtures - points within the triangle represents threecomponent mixtures Composition is plotted in mole fraction For a ternary diagram the pressure and the temperature are constant, only the composition changes 51

PVT DEG 2009 2010

TERNARY DIAGRAM Lights Dew point curve

G Bubble point curve

Critical equilibrium line

.

. M CP

Heavies

L

Intermediates 52

PVT DEG 2009 2010

VARIOUS FORMATION FLUIDS COMPOSITION (% mol.)

Components Oil

Oil

Oil

Condensate Condensate Wet gas gas gas

Dry gas

Nitrogen+CO2 2.16

2.12

2.37

4.09

1.01

0.40

63.91 8.29 4.37 0.94 2.21 0.72 1.15 1.86 14.43

64.19 11.18 6.20 0.75 2.31 0.64 1.03 1.22 10.11

73.80 9.43 4.43 0.87 1.63 0.71 0.66 0.91 3.47

88.54 5.32 2.30 0.56 0.59 0.27 0.23 0.27 0.91

94.32 3.90 1.17 0.08 0.13

100.00

100.00

100.00

100.00

100.00

H2S Methane Ethane Propane Isobutane n-Butane Isopentane n-Pentane C6 C7+

30.28 6.28 10.21 1.23 5.75 1.62 2.71 3.28 36.58

4.49 3.45 50.12 7.78 5.18 1.04 2.65 1.11 1.43 1.92 20.83

Total

100.00

100.00

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PVT DEG 2009 2010

PETROLEUM FLUIDS CLASSIFICATION

• Difficulty to distinguish between oil and gas • Requirement to determine: - fluid state in the reservoir - fluid properties in-situ

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PVT DEG 2009 2010

GRAVITY OF STOCK TANK OIL

Definition of API Gravity °API = 141.5/d -131.5 with d as oil density as referred to water to 60°F Condensate, very light oils : d ≤ 0.8 (more than 45°API) Light oils 0.8 ≤ d ≤ 0.86 (33 à 45°API) Black oils 0.86 ≤ d ≤ 0.92 (22 à 33°API) Heavy oils0.92 ≤ d ≤ 1 (less than 22°API)

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PVT DEG 2009 2010

PETROLEUM FLUIDS CLASSIFICATION BASIC DATA CHARACTERIZING WELL EFFLUENT 1 - Production data - A.P.I. Gravity if SG >0.8 (A.P.I.<45°) if SG <0.8 (A.P.I.>45°) - Gas-Oil Ratio GOR < 500 m3/m3 500 < GOR < 1000 m3/m3 GOR > 1000 m3/m3

OIL CONDENSATE

OIL OIL OR GAS CONDENSATE GAS CONDENSATE

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PVT DEG 2009 2010

PETROLEUM FLUIDS CLASSIFICATION BASIC DATA CHARACTERIZING WELL EFFLUENT 2 - Chemical composition - heavy oil C1 < 20% - black oil - light oil C1 – C5 > 60% - volatile oil/rich condensate - gas condensate - wet gas C1 > 80%

C7+ >40% 20% < C7+ < 40% 13% < C7+ < 20% 8% < C7+ < 13% C7+ < 8%

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PVT DEG 2009 2010

CLASSIFICATION OF HEAVY OILS • Medium heavy oil 100 cp > µ > 10 cp

25°> d°API > 18° mobile at reservoir conditions

. Extra heavy oil 10 000 cp > µ > 100 cp

20° > d°API > 7° mobile at reservoir conditions

. Tar sands and bitumen 12° > d°API > 7° µ > 10 000 cp non mobile at reservoir conditions . Oil shales Reservoir = Source rock, no permeability Mining extraction only 58

PVT DEG 2009 2010

PETROLEUM FLUIDS CLASSIFICATION

Pressure

GAS O

OTres,

O

Pres

GAS CONDENSATE OVOLATILE

OIL

BLACK OIL

O

critical point

Temperature 59

PVT DEG 2009 2010

PETROLEUM FLUIDS CLASSIFICATION

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OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

4. OIL & GAS MAIN PROPERTIES

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MAIN OIL PROPERTIES Surface conditions Reservoir conditions 200 m³ gas 1 m³ oil 0,8 m³ oil Formation volume factor (FVF) : Bo = 1/0.8 = 1.25 m³/m³ Gas oil ratio : GOR = 200/0.8 = 250 Sm³/m³

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PVT DEG 2009 2010

MAIN OIL PROPERTIES (BO, RS, CO) Formation Volume Factor Bo =

Vo Vstd ref

=

Volume of oil in reservoir P, T conditions Volume of stock tank oil in standard conditions

Solution gas/oil ratio (Rs) Rs =

Vg

std

Vstd ref

=

Volume of gas in standard conditions Volume of oil in standard conditions

Rs quantifies the amount of gaseous components which are dissolved in the oil at reservoir conditions.

Compressibility (Co) 1

Co = - V

∂V ) ( ∂P T

Co quantifies the volume changes arising from pressure depletion at reservoir temperature, above the bubble point pressure. 63

PVT DEG 2009 2010

MAIN OIL PROPERTIES (BO, RS, CO) Compressibility (Co) Average oil compressibility is often assumed constant (valid except for volatile oil at high pressure) and then: Bo = Bob [ 1 – Co (p-pb)]

Oil compressibility varies between 1 * 10-4 bar -1

4 * 10-4 bar -1

7 * 10-6 psi -1 volatile oil 30 * 10-6 psi -1

black oil

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PVT DEG 2009 2010

MAIN OIL PROPERTIES VOLATILE OIL Volatile oils are light oils where the liquid recovered in surface comes from one side of the oil phase and from the other side by liquid condensation of the gas phase. For a volatile oil - gravity sto > 35° API - Bo > 1.5 v/v and Co ≥ 30 * 10-6 psi -1 - 1,000 < Rs < 3,000 scf/STB - the bubble point is close to the critical point - oil behavior cannot be represented by traditional black oil PVT

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PVT DEG 2009 2010

MAIN OIL PROPERTIES

DEFINITIONS FOR OIL Bo =f(P) Bo VOLATILE OIL 1.9

1.6

BLACK OIL

1.3

P (barg) 1.0 100

200

300

400

500 66

PVT DEG 2009 2010

MAIN OIL PROPERTIES

DEFINITIONS FOR OIL

Rs = f(P)

Rs ( m3/m3) 300 VOLATILE OIL 200 BLACK OIL 100 P (barg) 100

200

300

400

500 67

PVT DEG 2009 2010

MAIN OIL PROPERTIES Viscosity The viscosity varies with the pressure, temperature and quantity of dissolved gas. In the reservoir, the following prevail for the hydrocarbon liquid: Order of magnitude: from 0,2 cP (very light oil) to 1 P, called heavy oil above 1 P, up to about 100 P. µo (cP) 1,5

30°API

1

0,5

45°API 100

200

300

400 P (bar) 68

PVT DEG 2009 2010

MAIN GAS PROPERTIES Surface conditions Reservoir conditions 200 m³ gas 1 m³ gas 0,2 m³ condensate Formation volume factor : Bg = 1/200 m³/m³ Ratio condensate/gas : CGR = 0.2/200 = 0.001 Sm³/m³ GOR = 1/CGR = 1000 Sm³/m³

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MAIN GAS PROPERTIES (Bg)

Formation Volume Factor dry gas Bg =

Vg Vgstd ref

=

Volume of gas in reservoir P, T conditions Volume of dry gas in standard conditions

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TWO PHASE FORMATION VOLUME FACTOR

OIL + GAS FORMATION VOLUME FACTOR

Bt = Bo + Rl * Bg Rl = Rsi - Rs

Rl : Free gas in the reservoir Bt = Bo + ( Rsi - Rs ) Bg

Bo

Rs Bt

Rsi

Pb

P

Pb

P 71

PVT DEG 2009 2010

MAIN GAS PROPERTIES (Bg) DEFINITIONS One mole of a material is a quantity of that material whose mass, in the unit system selected, is numerically equal to the molecular weight. According to Avogadro law, one mole of any gas contains the same number of molecules as one mole of any other gas, that is the Avogadro number. One mole of any gas occupies the same volume at a given pressure and temperature. At standard conditions the molar volume is 379.5 cu.ft/lb.mole at 14.7 psia and 60°F 23.646 l/gr.mole at 1 atm and 15°C The conversion factor is 1 lb.mole is equivalent to 453.6 gr.mole

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MAIN GAS PROPERTIES / GAS SPECIFIC GRAVITY

Gas Specific gravity is defined as ratio of gas density to that of air at standard conditions (60°F, 1 atm). γ (air =1) = ρgas/ρair = Mgas/Mair ρgas = Mgas/Vmolar

Gravity =

MW MWa

Where MWa is the molar mass of air (28.97 g/mol) The molar mass could be determined from gas composition 73

PVT DEG 2009 2010

MAIN GAS PROPERTIES / GAS SPECIFIC GRAVITY Definitions for gas : Vmolar = 23.645 l (1 atm, 15°C) Vmolar = 23.694 l (1 atm, 60°F) Vmolar = 379.4 scf/lbm mol (1 atm, 60°F) Mair = 28.9784 ρair =28.97/23.645 =1.225 kg/m³

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PVT DEG 2009 2010

MAIN GAS PROPERTIES / COMPRESSIBILITY FACTOR

Compressibility factor: Z for a perfect gas : PV = nRT for a real gas

: PV = ZnRT

Gas Formation Volume Factor: Bg = V/Vsc = PscZT / PZscTsc Expansion factor: E

= 1 / Bg

Density: m = nM et ρ = m/V ρ = PM/ZRT 75

PVT DEG 2009 2010

MAIN GAS PROPERTIES (Bg)

Formation Volume Factor dry gas Bg =

Vg Vgstd ref

=

Volume of gas in reservoir P, T conditions Volume of dry gas in standard conditions

Formation Volume Factor wet gas Bg =

Vg = Vgstd equ

Volume of gas in reservoir P,T conditions Volume of dry gas + equivalent gas vol of liquid in std

Equivalent gas volume of liquid is the number of moles of liquid multiplied by the molar volume or: Vsto * ( ρoil / Moil ) * 23.6 and the total volume of gas at std conditions: Vg std equ = Vsto [R + ( ρoil / Moil ) * 23.6] 76

PVT DEG 2009 2010

MAIN GAS PROPERTIES / GAS RICHNESS

GAS RICHNESS Definitions: in metric units : g/m3 in British units : GPM gallon per thousand cuft also most usually expressed in stb/MMscf Examples Poor gas condensate 50 stb/mmscf Rich gas condensate 250 stb/mmscf Colombian gas in the foothills 280 stb/MMscf Qatar gas 40 stb/mmscf 77

PVT DEG 2009 2010

MAIN GAS PROPERTIES / GAS RICHNESS

GAS RICHNESS Calculation in metric units : g/m3 C3+

(g/m3)

m

= Σ yiMi * 1000/23.6 i=3

C4+

(g/m3)

m

= Σ yiMi * 1000/23.6 i=4

C5+

(g/m3)

m

= Σ yiMi * 1000/23.6 i=5

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PVT DEG 2009 2010

MAIN GAS PROPERTIES / GAS RICHNESS

GAS RICHNESS Calculation in british units : GPM = gallons per thousand cubic feet m

GPM (C3+) = [Σ yiMi/ρi] * (28.3 / 3.785) / 23.6 i=3

m

GPM (C4+) = [Σ yiMi/ρi] * (28.3 / 3.785) / 23.6 i=4

m

GPM (C5+) = [Σ yiMi/ρi] * (28.3 / 3.785) / 23.6 i=5

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PVT DEG 2009 2010

PURE COMPONENTS PARAMETERS

Characteristic properties of pure compounds 1°/ This list is far from containing all hydrocarbons present in the light fraction of crude oils and natural gases (more than 250 individual hydrocarbons can be identified by gas chromatography) 2°/ Beyond C10, hydrocarbons decompose before their critical point can be properly investigated. Then critical parameters are extrapolated.

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OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

5. CORRELATIONS

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CORRELATIONS

Knowledge of the fluid properties in PRESSURE and TEMPERATURE (P.V.T. properties) is required for reservoir evaluation P.V.T. properties of petroleum fluids are obtained: - from empirical laws - from P.V.T. analysis (laboratory) - by calculation from an equation of state (matching)

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CORRELATIONS •From experimental data obtained from a great number of fluids, various authors have established useful correlations concerning hydrocarbons fluids. – – – – –

Bubble point pressure Volumetric Factor viscosities densities compressibility Factor

•Using little experimental data, one can obtain relatively precise figures concerning fluid properties (whether it is oil or gas). • PVT coherence (measures) can be checked using correlations. 83

PVT DEG 2009 2010

CORRELATIONS • Black oil correlations are usually based on regional fluid data as for example North Sea, Middle East or Egypt • these correlations should not be used outside the range of data for which there were derived. • EOS matched against PVT data are used for reasonable extrapolation outside the data range

84

PVT DEG 2009 2010

CORRELATIONS OF OIL PROPERTIES DETERMINATION OF OIL PROPERTIES FROM EMPIRICAL LAWS based on GOR, gravity of stock-tank oil, gas gravity 1. Bubble point pressure Standing correlation (old Californian fields) Glaso correlation (derived from North Sea) Vasquez and Beggs etc… 2. Oil Formation Volume Factor Standing correlation Glaso correlation Vasquez and Beggs etc…

85

PVT DEG 2009 2010

CORRELATIONS OF OIL PROPERTIES 3. Oil density

ρo (P,T) =

( ρg × Rs ) + ρo ----------------------Bo

4. Compressibility STANDING correlation for Isothermal oil compressibility VASQUEZ and BEGGS correlation 5 . Viscosity CARLTON BEAL and, CHEW and CONALLY correlations

86

PVT DEG 2009 2010

STANDING CORRELATION / BUBBLE POINT PRESSURE

Pb = 18.2 ( A – 1.4 ) A = (Rsb/dg)0.83 10 (0.00091 Tr - 0.0125 χ API ) with : Pb bubble pressure (psia) Rsb solution GOR at bubble point (scf/STB) dg gas gravity (air=1) reservoir temperature (°F) Tr χ API gravity of sto (° API)

87

PVT DEG 2009 2010

Pb and GOR

GOR = 350

dg = 0.75

T = 180°F ρo = 30 API Pb = 1900 psi

88

PVT DEG 2009 2010

STANDING CORRELATION OIL FORMATION VOLUME FACTOR

Bo = 0.9759 + 0.00012 A1.2 avec : A = Rs (dg/do)0.5 + 1.25T Rs solution GOR , (scf/STB) dg gas gravity (air = 1) do gravity of sto (water = 1) T temperature (°F)

89

PVT DEG 2009 2010

OIL FORMATION VOLUME FACTOR

Standing 90

PVT DEG 2009 2010

GLASO CORRELATION / BUBBLE POINT PRESSURE / FVF Bubble point pressure: log pb = 1.7669 + 1.7447 log A – 0.30218 (log A)2 where A = (Rs/γg)0.816 (T0.172 / γAPI0.989 )

Oil formation volume factor: log(Bob – 1) = - 6.585 + 2.9133 log A – 0.2768(logA)2 where A = Rs(γg/γo)0.526 + 0.968 T with pb psia Rs solution GOR , (scf/STB) γg gas Specific Gravity (air = 1) γo gravity of sto (water = 1) T temperature (°F) 91

PVT DEG 2009 2010

OIL DENSITY ⇒ OIL . determination of density of saturated oil at reservoir conditions knowing the Bo. ρg × Rs + ρost ρo (p,T) = ---------------------------Bo . ρg being gas density at reference conditions (SG * ρ air) . ρost sto density in kg/m3 . Rs solution gas oil ratio in m3/m3 at ref cond . ρo (p,T) density at p and T in kg/m 3

92

PVT DEG 2009 2010

OIL COMPRESSIBILITY Compressibility (Co) Average oil compressibility is often assumed constant (valid except for volatile oil at high pressure) and then: Bo = Bob [ 1 – Co (p-pb)] and ρo = ρob [1 – Co (pb-p)] oil compressibility varies between 1 * 10-4 bar -1

4 * 10-4 bar -1

7 * 10-6 psi -1 volatile oil 30 * 10-6 psi -1

black oil

93

PVT DEG 2009 2010

OIL COMPRESSIBILITY ⇒ OIL determination of undersaturated oil compressibility - Vazquez and Beggs correlation for instantaneous oil compressibility Co = A/p A = 10-5 (5 Rsb + 17.2 T – 1.180 γgc + 12.61 γAPI - 1.433) with Co psi-1 Rsb scf/STB T °F p psia then

Bo = Bob (pb/p)A

Other correlations are available for Co (SPE Feb 2007) 94

PVT DEG 2009 2010

OIL VISCOSITY ⇒ OIL .determination of oil viscosity at reservoir conditions 1. Dead oil viscosity (sto) at reservoir temperature correlations of Beal, Standing, Beggs and Robinson, Vasquez,etc... 2. Bubblepoint oil viscosity Chew and Connaly, Standing, Beggs and Robinson etc… 3. Undersaturated oil viscosity same authors

- Lohrenz relationship for both phases (used in compositional reservoir simulation) 95

PVT DEG 2009 2010

OIL VISCOSITY

Oil viscosity, cp

« Beal » dead-oil (stock-tank-oil) viscosity correlation including data in « Frick » (from Standing)

Oil gravity, *API PVT DEG 2009 2010

96

OIL VISCOSITY Live-oil (saturated) viscosity as a function of dead-oil viscosity and solution gas/oil ratio (from Standing33, after Beal72 correlation)

97

PVT DEG 2009 2010

MAIN GAS PROPERTIES

⇒ LAW OF CORRESPONDING STATES The ratio of the value of any intensive property to the value of that property at the critical point, is related to the ratio of the prevailing absolute temperature and pressure to the critical temperature and pressure by the same function for all similar substances. Fluids are said in CORRESPONDING STATES when any of the two reduced variables Pr, Vr et Tr are the same.

98

PVT DEG 2009 2010

MAIN GAS PROPERTIES

⇒ CRITICAL POINT : that state of pressure and temperature (Pc) and (Tc) at which the intensive properties of liquid and gas are identical. ⇒ REDUCED VARIABLES = Pr = P/Pc

reduced pressure

Tr = T/Tc

reduced temperature

99

PVT DEG 2009 2010

MAIN GAS PROPERTIES Determination of Z: Experimental : P-V analysis of a mass of gas m at T (m known) Calculations and charts These methods are based on the law of corresponding states. A chart has been prepared giving Z, based on studies of many gases, as a function of : - Pseudoreduced pressure = absolute pressure / absolute pseudocritical pressure - Pseudoreduced temperature= absolute temperature / absolute pseudocritical temperature The pseudocritical pressure and temperature of a given gas (different from the critical pressure and temperature) are obtained by calculation from the composition, or by chart from the specific gravity. 100

PVT DEG 2009 2010

GAS COMPRESSIBILITY FACTOR ⇒PSEUDO-CRITICAL PROPERTIES FROM KNOWN COMPOSITION Ppc = pseudo critical pressure Ppc = Σ yi Pci Tpc = pseudo critical temperature i=1 Pci = critical pressure of i constituent Tci = critical temperature of i const. yi = molar fraction of i constituent m = number of constituents m Tpc = Σ yi Tci m

i=1

If not available pseudocritical properties of C7+ are obtained from Matthews correlation. TcC7+ = 608 + 364 log(MC7+ - 71.2) + (2.450 logMC7+ - 3.800) logγC7+ pcC7+ = 1.188 - 431 log(MC7+ - 61.1)+[2.319-852(logMC7+ -53.7)](γC7+-0.8) 101

PVT DEG 2009 2010

GAS COMPRESSIBILITY FACTOR ⇒ PSEUDO-CRITICAL PROPERTIES FROM CORRELATIONS 1. From Sutton correlation, derived for Associated gas and gas condensate - for Associated gas: TpcHC = 120.1 + 429 γgHC – 62.9 γg2HC in ° R and ppcHC = 671.1 + 14 γgHC - 34.3 γg2HC

in psia

- for gas condensate: TpcHC = 164.3 + 357.7 γgHC – 67.7 γg2HC in ° R and ppcHC = 744 – 125.4 γgHC + 5.9 γg2HC

in psia

102

PVT DEG 2009 2010

GAS COMPRESSIBILITY FACTOR ⇒ PSEUDO-CRITICAL PROPERTIES FROM CORRELATIONS Associated gas is defined as gas liberated from oil: - high gravity - rich C2-C5 - low C7+ (except for low separation presure and vollatile crude oil) Gas condensate being: - rich in C7+ 2. From Standing correlation as represented in the following chart

103

PVT DEG 2009 2010

GAS : Determination of Tpc AND Ppc

104

PVT DEG 2009 2010

GAS COMPRESSIBILITY FACTOR

⇒ GAS .determination of gas compressibility factor Z by Standing and Katz chart - determination of Tpc - determination of Ppc - calculation of Tpr and Ppr .or by Hall and Yarborough equations or Dranchuk and Abou-Kassem (DAK) which are digital representation of the Standing and Katz chart 105

PVT DEG 2009 2010

GAS COMPRESSIBILITY FACTOR

Standing & Katz PVT DEG 2009 2010

106

GAS COMPRESSIBILITY FACTOR Compressibility factors for natural gas near atmospheric pressure (McKetta et al. 4-83a)

107

PVT DEG 2009 2010

GAS COMPRESSIBILITY FACTOR

⇒ GAS .determination of gas compressibility factor Z when nonhydrocarbons are present, as N2, CO2 and H2S. The correlation derived by Wichert and Aziz allows to calculate pseudocritical properties of the mixture that will give reliable Z factors from the Standing correlation.

108

PVT DEG 2009 2010

GAS VISCOSITY

Oil & Gas journal, May 1949 109

PVT DEG 2009 2010

OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

6. EQUATIONS OF STATE

110

PVT DEG 2009 2010

EQUATIONS OF STATE

Equations of state : f(P, V, T, n) = 0 . ideal gas law : (Mariotte, 1650)

PV = nRT

. equation of state for real gas :

PV = ZnRT

. cubic equations of state Van der Waals

P = RT/(V-b) - a/V2

(1873)

Redlich-Kwong

P = RT/(V-b) -a/V(V-b)T½

(1949)

Soave-Redlich-Kwong P = RT/(V-b) - a(T)/V (V+b) Peng-Robinson

(1972)

P = RT/(V-b) - a(T)/(V2+2bV-b2) (1976)

111

PVT DEG 2009 2010

EQUATIONS OF STATE Van der Waals equation of state P = RT/(V-b) - a/V2 or

(P+ a/V2) (V-b) = RT

a : attraction parameter, the pressure exerted on the walls (cell) is reduced by the attraction between molecules b : repulsion parameter or covolume,volume occupied by the molecules reducing the total volume available a and b are determined from the law of corresponding state and are function of Pc,Tc and Vc. writting at the critical point (δP/δV)T = 0 and (δP2/δV2)T = 0

Van der Waals EOS can also be expressed in reduced parameters (Pr + 3/Vr2) (3Vr - 1) = 8 Tr 112

PVT DEG 2009 2010

EQUATIONS OF STATE Cubic equations of state : These equations are called « cubic » because volume determination at fixed pressure and temperature needs to solve a third order polynomial equation. Simple cubic equation of state Z3 + UZ2 + VZ + W = 0 with Z = PV/RT and U, V, W depending of two constants A and B. A = aP/R2T2 and

b = bP/RT

113

PVT DEG 2009 2010

EQUATIONS OF STATE Acentric factor ω : Reflect the deviation from the law of corresponding states of the vapor pressure curve for pure substances ω = - 1 - log10 (Pvap/Pc) for Tr = 0.7 (defined by Pitzer) the vapor pressure curve becomes: log10 (Pr) = -7/3 (1+ ω) [1/Tr-1] Originally represented the nonsphericity of a molecule, at present it is used as a parameter supposed to measure the complexity of a molecule with respect to geometry and polarity. It increases with molecular weight and polarity. Mixing rule for mixture 114

PVT DEG 2009 2010

DEFINITION of ACENTRIC FACTOR

Critical 1 point 0

1/Teb

1/0.7

1/Tr

log(Patm/Pc)

ω=0 -1

-1- ω

(ω = 0) Ideal behaviour log 10 (Pr)

-2

115

PVT DEG 2009 2010

EQUATIONS OF STATE Redlich-Kwong : the second term is made dependent of temperature by 1/T½ Soave-Redlich-Kwong : α correcting factor dependent of composition a = α * 0.42748 R2Tc2/Pc α depends of m and Tr m depends of ω Peng-Robinson : very similar to SRK m expression is slightly different

116

PVT DEG 2009 2010

EQUATIONS OF STATE

Parameters of the Peng-Robinson equation component)

(for a pure

P = RT/(V-b) - a(T)/(V2+2bV-b2) b = 0.077796 RTc / Pc a(T) = α * 0.457235 R2Tc2/Pc

α ={ 1 + m [1-(T/Tc)½]}2

m = 0.37464 + 1.54226 ω - 0.26992 ω2 for ω ≤ 0.49 m = 0.379642 + 1.48503 ω - 0.164423 ω2 + 0.016666 ω3 for ω > 0.49

117

PVT DEG 2009 2010

EQUATIONS OF STATE

Mixing rule : previous equations were developed for pure components n

for mixtures

n

a = Σ Σ xi xj (1-kij) (ai.aj)½ j=1 i=1 n

b = Σ xi bi i=1

kij = binary interaction coefficient, between ith and jth component, independent of pressure and temperature. It is equal to zero for HC/HC interactions, except C1/C7+, and different from zero between HC and non HC and between non HC together.

118

PVT DEG 2009 2010

EQUATIONS TO STATE VOLUME TRANSLATION Peneloux shift : Purpose : improve the computation ol liquid densities, which are poorly predicted by classical cubic equations of state, without changing vapourliquid phase equilibria. Gas density is little affected. - If V is the molar volume computed from the equation of state the corrected volume is : Vcorr = V -c where c is the volume translation (cm3/mol) -For a monophasic mixture of composition, xi c = Σ xi c i i

where ci is the volume translation of component i -Correlations are available for ci determination

119

PVT DEG 2009 2010

EQUATIONS TO STATE APPLICATION TO PHASE EQUILIBRIA Definitions zi = component i mole fraction in the mixture Σ zi = 1 L = liquid molar fraction in the mixture V = vapour molar fraction in the mixture L + V = 1 molar fraction in equilibrium xi = component i mole fraction in the liquid in equilibrium yi = component i mole fraction in the vapour in equilibrium Σ xi = 1 Σ yi = 1 Overall balance in the mixture: zi = xi L+ yi V

zi = xi (1-V)+ yi V 120

PVT DEG 2009 2010

EQUATIONS TO STATE RACHFORD-RICE EQUATION Equilibrium constants ki = component i equilibrium ratio k i = y i / xi zi = (1-V) xi + V yi = (1-V) xi + V ki xi = xi [1+V(ki-1)] xi = zi / [1+V(ki-1)]

yi = kizi / [1+V(ki-1)]

Rachford-Rice equation Σ ( yi- xi) = Σ zi(ki-1)/[1+V(ki-1)] = 0 or F(V) = 0 With mixture composition and k values known, the remaining unknown is V and F(V) is solved mathematically by iteration using the Newton-Raphson algorithm 121

PVT DEG 2009 2010

EQUATIONS TO STATE DETERMINATION OF EQUILIBRIUM CONSTANT K values are a function of pressure, temperature and overall composition They are derived either by - calculation from laboratory data - empirical correlation Calculations of phase equilibrium by EOS use values derived by correlations to initiate the iterative calculation - for low pressure Wilson equation - for high pressure Whitson and Torp equation

122

PVT DEG 2009 2010

EQUATIONS TO STATE THERMODYNAMICAL EQUILIBRIUM From EOS Liquid Phase composition Gas Phase composition

xi yi

They should be in chemical equilibrium Condition: chemical potential of each component identical in the liquid and gas phase condition satisfied by the equal fugacity constraint, fugacity calculated by the equation of state

123

PVT DEG 2009 2010

EQUATIONS OF STATE APPLICATION TO PHASE EQUILIBRIA Step by step procedure - Estimate k values from empirical correlations - Solve the Rachford-Rice equation for V - Compute xi and yi - Compute components fugacity coefficients in each phase from the EOS and check the equal fugacity constraint - If convergence is not reached update the k values Same approach apply to - liquid-vapour equilibria - bubble point calculation - dew point point calculation

V=0 L=0

xi = zi yi = zi 124

PVT DEG 2009 2010

EQUATIONS TO STATE Rachford-Rice equation

Σ zi(ki-1)/[1+V(ki-1)] = 0

APPLICATION TO BUBBLE POINT

V=0

Σ zi(ki-1) = 0 Σ ziki = Σ zi = 1 Σ ziki = 1 APPLICATION TO DEW POINT

V=1

Σ zi(ki-1)/ki = 0 Σ (zi- zi/ ki) = 0 Σ zi/ki = 1

125

PVT DEG 2009 2010

EQUATIONS OF STATE APPLICATION OF EQUATION OF STATE Data : Detailed composition from GC (10 to 200 components) Experimental PVT data Matching parameters : to reproduce PVT data Tc heavy fraction Pc heavy fraction acentric factor kij C1 - C7+ molecular weight heavy fraction Simplified composition : 2 to 7 pseudo-components ex : C1-N2, C2-CO2-C3, C4-C5, C6-C10, C11+ (5 comp) C1-N2, C2-CO2, C3-C4, C5-C6, C7-C8, C9-C10,C11+ (7comp) pseudo component properties calculated according to mixing rules 126

PVT DEG 2009 2010

EQUATIONS OF STATE MATCHING PARAMETERS Crude oils : Pb increases when Pc, Tc, kij increase GOR sep increases when Pc increases GOR sep decreases when Tc increases Gas condensates : . Tc heavy fraction : when Tc increases - dewpoint pressure increases - liquid deposit increases - GOR sep decreases . Pc heavy fraction : - when Pc increases, dew point pressure sensible at low temperature and liquid deposit decreases

127

PVT DEG 2009 2010

EQUATION OF STATE FLUID MODELING Reservoir Fluid modeling is necessary for Simulation studies as : - natural depletion: volatile oil - gas injection: gas cycling, miscible gas injection - composition changing with depth: compositional gradient with rich gas condensate, near-critical fluids, highly volatile oil, light oil etc… - regional thermodynamic studies: geochemistry, oil migration, oil degradation etc..

128

PVT DEG 2009 2010

SATURATION PRESSURE GRADIENT Saturation pressure - Depth Depth

Dew point Reservoir pressure Transition zone Bubble point Pressure 129

PVT DEG 2009 2010

EQUATION OF STATE FLUID MODELING C7+ characterisation and component selection C7+ is a mixture of paraffinic, naphtenic and aromatic compounds and is a key parameter in fluid modeling and fluid behaviour C7+ pseudocomponent selection will depend of the fluid type and the production process

130

PVT DEG 2009 2010

EQUATIONS OF STATE

CONCLUSIONS . Cubic equations like Peng-Robinson and Soave-RedlichKwong used with volume translation are commonly used and give good results after matching . EOS matching against Experimental PVT data is indispensable. . EOS as predictible tool without matching is of low value

131

PVT DEG 2009 2010

OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

7. SAMPLING

132

PVT DEG 2009 2010

SAMPLING

Objectives : The first requirement - and difficulty - in taking measurements is that of obtaining a truly representative sample of the formation fluid. The fluid which gets into the production casing must be identical to the formation fluid. In any case, one has to know that the formation fluid is not homogeneous on the full height of the reservoir.

133

PVT DEG 2009 2010

SAMPLING

Representativity : -

monophasic flow at the bottom of the well

-

only one layer per sampling

-

stabilized flow regime for well flowing in surface → pressure → GOR → flow rates, etc...

134

PVT DEG 2009 2010

SAMPLING Surface sampling: . fluids are collected at the well head or the production line : - one phase flow (rarely) - or isokinetic sampling . Fluids collected in the separator, gas and oil, (most frequent case). Gas and oil samples collected in the separator are recombined in the laboratory in proportion to their flow rates. For this purpose, we must have : good precision of the measured flow rates, stabilized well production, oil and gas sampling realized almost simultaneously. 135

PVT DEG 2009 2010

SAMPLING

Gas sampling bottle

gas Psep, Tsep GORsep = Qgas/Qoil

Oil sampling bottle

Reservoir fluid Pr, Tr

Psto, Tsto

GORsto

Tank oil ambient conditions

136

PVT DEG 2009 2010

SAMPLING

Surface sampling : Essential data for the recombination : - pressure and temperature in the separator - gas flow rate at the separator (orifice meter) - oil flow rate at the separator (oil meter) - gas density and compressibility factor for the gas measurement flow rate - oil tank flow rate (shrinkage)

137

PVT DEG 2009 2010

SAMPLING

Surface sampling of an oil under saturated reservoir: . bottom hole flowing pressure ≥ bubble pressure . no liberation of gas in the reservoir The well being stabilized GOR remains constant during sampling

138

PVT DEG 2009 2010

SAMPLING

Surface sampling of an oil saturated reservoir: . bottom hole flowing pressure < bubble pressure . liberation of gas in the reservoir should be minimized . gas saturation should remain below the critical gas saturation Recommendations . sample the well initially . produce the well with small drawdown GOR should remain constant and minimum during sampling 139

PVT DEG 2009 2010

PRESSURE PROFILE IN THE DRAINAGE AREA

140

PVT DEG 2009 2010

GAS- OIL RELATIVE PERMEABILITIES

Relative permeability

2 π r h k k rg dp g qg = ( ) dr µg 2 π r h k k ro dp o ) ( qo = µo dr

qg / qo =

k rg k ro

µo x µg

Liquid saturation, % PV 141

PVT DEG 2009 2010

SAMPLING TEST SEQUENCE

480.

Pws

460.

Pwf

440.

pressure BARS

500.

1980/12/16-0800 : OIL

20.

40.

60.

80.

100.

120.

Echantillonnage Bottom fond hole sampling

sampling

tp

Initial shut-in

100.

300.

Qmaxi Echantillonnage Surface de surface Stabilized rate

Dégorgement Clean up

0.

rates M3/D

0.

0.

Built UP Qmin

dt 20.

40.

60.

T

80.

100.

120.

Decimal Hours

142

PVT DEG 2009 2010

SAMPLING Bottom hole sampling : This type of sampling is preferred since it guarantees the best fluid representativity. Disadvantage : high cost Two possibilities Open hole: wireline tools RFT (Repeat Formation Tester) , MDT (Modular Formation Dynamics Tester, Schlumberger), RCI (Baker), RCI (Halliburton) Cased hole: DST Tools, wireline samplers

143

PVT DEG 2009 2010

SAMPLING Bottom hole sampling : MDT Sampling configuration: Pump out module to eliminate the filtrate in the sample pumping time duration up to one hour Analyzer module to monitor fluid quality during pumping time by - resistivity measurement - optical measurement by LFA (Life fluid analyzer) -Sample module: 6×450 cc bottles or 4l,10l and 23 l chambers Drawback: contamination by filtrate (oil base mud)

144

PVT DEG 2009 2010

145

PVT DEG 2009 2010

146

PVT DEG 2009 2010

SAMPLING

Bottom hole sampling : wireline during production : tools are lowered in the string. .SRS (Single-phase Reservoir Sampler) Transfer : In sample bottles (oil or gas), under pressure, for transportation.

147

PVT DEG 2009 2010

SAMPLING

Bottom hole sampling : DST Under saturated oil reservoir: - well flowing with BHFP ≥ Bubble point pressure on minimal choke to control drawdown Saturated oil reservoir - well closed and reopened just before sampling - well flowing at smaller drawdown allowing to remain at constant GOR

148

PVT DEG 2009 2010

SAMPLING GAS CONDENSATE RESERVOIR Bottom hole sampling is not recommended for gas condensate or wet gas . volume of fluid sampled gives low liquid recovery and unrepresentative heavy components analysis . possible segregation of the liquid at the well bottom . liquid not totally recovered during transfer of bottom hole sample Surface sampling . sample the well initially . produce the well with small drawdown to minimize formation of a condensate ring near the well bore . stabilize the well rate above minimum gas velocity Difficulties encountered during surface sampling of gas condensate . possible liquid carryover at the separator

149

PVT DEG 2009 2010

SAMPLING CONDENSATE GAS

Water, mud oil

DST Bottom sample Pressure Packer

Reservoir pressure

P, T

Dew point

Perforation

Distance 150

PVT DEG 2009 2010

SAMPLING : SUMMARY

Produced fluid

Fluid flow and reservoir characteristics

Sampling type Bottom hole sampling

Surface sampling

Undersaturated oil

GOR=GORi=Ct

Well in production with Pwf > Pb

Stabilized well with Pwf>Pb

Saturated oil

GOR > GORi Pwsi = Pb

To bean back progressively. Well closed and stabilized. Sampling at minimum flow rate.

To bean back to have GOR≈ GORi Stabilized flow rate with ∆P min

Gas

GOR=GORi=Ct

Not recommended

Minimum flow rate possible ; compatible with - homogeneous flow in the tubing - separator stability

151

PVT DEG 2009 2010

SAMPLING Fluid amount necessary : For oil : The sampling type is also dependent on the necessary fluid quantity : - bottom hole sampling enough for a normal PVT study - not enough for a heavy fraction decomposition for which surface sampling is necessary For gas : No bottom hole sampling, as the liquid fraction collected is insufficient, again surface sampling is necessary

152

PVT DEG 2009 2010

SAMPLING FLUID QUANTITY TO SAMPLE BOTTOM HOLE SAMPLING minimum of 3 representatives samples SURFACE SAMPLING . Liquid 2 samples of 600 cm3 minimum . Gas GOR < 1500 cuft/bl 2 bottles ( 20 liters) 1500 < GOR < 3000 cuft/bl 3 bottles GOR > 3000 cuft/bl 4 bottles 153

PVT DEG 2009 2010

SAMPLING : MOBILE PVT LABORATORY Purpose : obtain PVT properties on site, analysing the sample immediately after collection

Equipment : HP cell, Gas chromatograph, viscosimeter Physical properties obtained : bubble point at T reservoir, Rs, Bo, reservoir fluid composition, oil API gravity, dead oil viscosity, viscosity at T reservoir above Pb, oil mud contamination

Objectives : - decision on testing - obtain earlier PVT information 154

PVT DEG 2009 2010

SAMPLING : DOWN HOLE ANALYSIS OF FORMATION FLUID SAMPLES Purpose : know nature of formation fluid, GOR and composition in down hole conditions

Equipment : Wireline tool associated to MDT Based on optical absorptions of crude oil in the Near Infrared Region(NIR) Crude oils have two types of absorption : - color absorption - molecular vibration absorption

155

PVT DEG 2009 2010

SAMPLING : DOWN HOLE ANALYSIS OF FORMATION FLUID SAMPLES

Tools developed on these techniques

Life Fluid Analyser (LFA) gives - GOR - gas detection by refraction index

Composition Fluid Analyser (CFA) gives - weight % C1 , C2-C5 , C6+ , CO2 (eventually) - retrograde due detection by fluorescence

156

PVT DEG 2009 2010

SAMPLING : OIL BASE MUD DECONTAMINATION OBM filtrate miscible with reservoir fluid and modify composition fluid sampled by MDT

OBM composition limited to C11 - C20 no aromatic compound

OBM Decontamination Procedure - Scaling method : with reference uncontaminated sample - Statistical method : with samples of different contamination levels - Skimming method : based on regular trend of hydrocarbone molar percentage versus carbon number 157

PVT DEG 2009 2010

SAMPLING : OIL BASE MUD DECONTAMINATION Obvious contamination between C12/C16 MDT decontamination

mole fraction (scaled)

2.5

171 447

2

83 653

1.5

857 429

1

167 651

0.5 0 5

7

9

11

13

15

17

19

21

cuts 158

PVT DEG 2009 2010

SAMPLING : OIL BASE MUD DECONTAMINATION PVT properties of Decontaminated oil - using trend versus contamination rate - mixing rules - the fluid being divided in 3 fractions ( C11- , C11+ and mud ) - EOS

159

PVT DEG 2009 2010

OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

8. OIL PVT STUDY

160

PVT DEG 2009 2010

PVT STUDIES • Objectives - compositional analysis - volumetric properties and phase behaviour - production simulation (from bottom to surface) • High pressure equipment - high pressure pumps - oil PVT cell - gas PVT cell (window cell) - etc... • Low pressure equipment - gas meters - vacuum pump - gas chromatographs - density meters - etc... 161

PVT DEG 2009 2010

SAMPLING AND RECOMBINATION WELL SITE Gas sampling bottle

Psep, Tsep Oil sampling bottle

Reservoir fluid Pr, Tr

LABORATORY

gas Reservoir fluid

GORsep = Qgas/Qoil

GORsep Psto, Tsto

GORsto

Tank oil ambient conditions

Oil separator

Gas separator

GORsto

Oil tank Gas tank

162

PVT DEG 2009 2010

OIL PVT STUDY - PROGRAMME 1. Quality control of samples - opening pressure (surface sampling) - saturation pressure (bottom or surface sample) 2. Compositional analysis - gas analysis : gas chromatography (C9) - oil analysis ( atmospheric sample) . gas chromatography C11+ composition . distillation simulated by chromatography: C20+ composition or atmospheric and subatmospheric distillation . density, paraffins content, naphtenes or aromatics analysis 163

PVT DEG 2009 2010

OIL PVT STUDY - PROGRAMME

3. Physical recombination - field GOR correction 4. Mass constant study - P-V curve at reservoir temperature . bubble point pressure . relative volume . specific volume (calculated) . isothermal compressibility

164

PVT DEG 2009 2010

MASS CONSTANT STUDY / OIL

OIL

P1>P sat P1 P2 P3 P4 P5

GAS

P2>Psat

P3=Psat

P4
P5
Saturation pressure (at T reservoir)

165

PVT DEG 2009 2010

P - V CURVE

pressure

Volatile oil

P sat P sat

volume 166

PVT DEG 2009 2010

OIL PVT STUDY - PROGRAMME

5. Differential vaporization - objective: simulate the initial liquid fraction remaining in the reservoir - realization: depletion and gas production at reservoir temperature by successive pressure drops - result: GOR cumulated, oil volume at each pressure step

167

PVT DEG 2009 2010

DIFFERENTIAL VAPORIZATION OIL

GAS gas

gas

-

P1>P sat volume

P2
P2

P3
P3

V13 v12 v02 v03

P3

P2

Psat P1

pressure

168

PVT DEG 2009 2010

DIFFERENTIAL LIBERATION

DIFFERENTIAL LIBERATION LIQUID DENSITY vs PRESSURE 0.850

Density (g/cm3)

0.800

CALCULATED 0.750

0.700

0.650

0.600 0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

Pressure (psia)

ρo =

ρos + Rs ρgs Bo

Surface (dead) oil density measured (gg/cc or Deg API) 169

PVT DEG 2009 2010

DIFFERENTIAL LIBERATION

DIFFERENTIAL SEPARATION VISCOSITY OF LIBERATED GAS 0.026 0.024

Viscosity (cP)

0.022 0.020 0.018 0.016 0.014 0.012 0.010 0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

Pressure (psia)

170

PVT DEG 2009 2010

DIFFERENTIAL LIBERATION

1.000

0.20

0.990

0.18

0.980

0.16

0.970

0.14

0.960

0.12

0.950

0.10

0.940

0.08

0.930

0.06

0.920

0.04

0.910

0.02

0.900 0

500

1000

1500

2000

2500

3000

3500

4000

4500

Bg (cfRESERVOIR / scf)

Z (dimless)

DIFFERENTIAL SEPARATION COMPRESSIBILITY FACTOR (Z), GAS FORMATION VOLUME FACTOR (Bg) OF LIBERATED GAS

0.00 5000

Pressure (psia)

1/Z =

n . R . Tres Pres .Vres

Bg =

Pst .Tres Pres .Tst

.Z 171

PVT DEG 2009 2010

OIL PVT STUDY - PROGRAMME 6. Flash separation - objective: obtain the highest recovery at stock tank conditions - realization: in one or several stages in a laboratory separator - result: . GOR . oil formation volume factor (Bo) . stock tank oil gravity . compositional analysis 172

PVT DEG 2009 2010

ONE STAGE FLASH SEPARATION

• OIL PVT STUDY → One stage Flash

Gas Oil Oil Pi ,Ti “standard conditions”

• GOR • Formation volume factor (FVF) or Bo • OIL and gas composition

173

PVT DEG 2009 2010

TWO STAGES SEPARATION • OIL PVT STUDY → Two stages separation . at each stage : - GOR - Bo - oil specific volume - gas gravity (γ) .

and globally : - total GOR - total Oil Formation Volume Factor 174

PVT DEG 2009 2010

TWO STAGES SEPARATION

OIL PVT STUDY → Two stages separation

Gas

Gas

Oil Oil

P1 , T1

Oil

1st stage

2nd stage

P2 , T2

P3 , T3 175

PVT DEG 2009 2010

OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

9. GAS CONDENSATE PVT STUDY

176

PVT DEG 2009 2010

GAS CONDENSATE PVT STUDY PROGRAMME

1- Quality control of samples . opening pressure, saturation pressure 2. Compositional analysis . reservoir fluids composition up to C11+ or C20+ 3. Physical recombination . field GOR correction

177

PVT DEG 2009 2010

GAS CONDENSATE PVT STUDY PROGRAMME (cont.) 4. Constant Composition Expansion (CCE) . P-V relation at reservoir temperature . dew point, liquid condensation vs pressure

5. Constant Volume Depletion (CVD) . reservoir simulation of depletion at constant volume and reservoir temperature . pressure steps depletion : - liquid condensation - gas production and composition

178

PVT DEG 2009 2010

WINDOW CELL

179

PVT DEG 2009 2010

CONSTANT COMPOSITION EXPANSION

• •

+

P1>Psat

P2=Psat

P3
P4
P5
P6
P7
oil gas 180

PVT DEG 2009 2010

CONSTANT COMPOSITION EXPANSION

Pressure C •

• •

P1 P2=Psat P3 P4 P5 P6 P7

Temperature 181

PVT DEG 2009 2010

GAS CONDENSATE PVT STUDY ⇒ Validity of the recombination - constant composition expansion : saturation pressure - most often, gas condensates are saturated, in equilibrium with an oil ring in the reservoir - Psat = Pres : gas condensate saturated; production testing and recombination are correct - Psat > Pres : impossible ; example : commingle production from 2 zones, one of each being oil - Psat < Pres : undersaturated gas condensate, influence of the GOR, liquid deposit in the wellbore

182

PVT DEG 2009 2010

CONSTANT VOLUME DEPLETION

OIL

GAS gas

gas

Vsat

v2

vsat

v2

-

183

PVT DEG 2009 2010

GAS CONDENSATE PVT STUDY PROGRAMME 6. Flash separation - objective: verify the compositional analysis of the recombined sample - realization: in one stage in a laboratory separator - result: . GOR . gas formation volume factor (Bg) . stock tank condensate gravity . compositional analysis 184

PVT DEG 2009 2010

USE OF PVT FOR RESERVOIR STUDY

185

PVT DEG 2009 2010

PVT FOR RESERVOIR STUDY

WHICH PRESSURE WHICH PVT GOC X

DATUM WOC

186

PVT DEG 2009 2010

PVT FOR RESERVOIR STUDY

LABORATORY GIVES : Bo Rs – FLASH LIBERATION THROUGH SEPARATORS Bof, Rsf – DIFFERENTIAL LIBERATION Bodif, Rsdif BAD REPRESENTATION OF REALITY SO COMPOSITE PVT

187

PVT DEG 2009 2010

PVT FOR RESERVOIR STUDY

DIFFERENTIAL - COMPOSITE OIL FORMATION VOLUME FACTOR (Bo) vs PRESSURE 2.000

Bo (reservoir b / stb)

1.900 1.800 1.700 1.600

l ntia e r e f dif

1.500 1.400

osite comp

1.300 1.200 1.100 1.000 0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

Pressure (psia)

Composite Bo curve deduced from Ê composite Bo at Pb 188

PVT DEG 2009 2010

PVT FOR RESERVOIR STUDY DIFFERENTIAL - COMPOSITE SOLUTION GAS (Rs) vs PRESSURE 1200

Rs (scf / stb)

1000 800 600

tial n e er diff

400

site o p c om

200 0 0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

Pressure (psia)

Composite Rs curve deduced from Ê composite Rs 189

PVT DEG 2009 2010

PVT FOR RESERVOIR STUDY

PVT ‘‘ Black oil’’

1 table composite

PVT ‘‘ Black oil ‘‘

1 table diff for reservoir 1 table separator wells

for PVT ‘‘ Compositional ’’

Equation of State from pseudoconstituents

190

PVT DEG 2009 2010

OIL AND GAS PHYSICAL PROPERTIES AND PVT STUDIES

10. WATER PROPERTIES

191

PVT DEG 2009 2010

WATER PROPERTIES ⇒ reservoir water are systematically associated with hydrocarbons . water from petroleum reservoirs - interstitial water in the hydrocarbon zone - aquifer water . water production - aquifer water - injected water - water dissolved in gas

192

PVT DEG 2009 2010

WATER PROPERTIES

⇒ no downhole sampling, or very seldom (then no PVT study) ⇒ water properties derived by correlations ⇒ water analysis at atmospheric pressure . salinity . chemical analysis . density, . Ph . resistivity 193

PVT DEG 2009 2010

WATER PROPERTIES ⇒ downhole sample under pressure . bubble point pressure: Pb . separation at standard conditions (flash) → GWR, Bw . density . compressibility ⇒ surface sample at Patm . salinity . ionic composition . density . pH . resistivity 194

PVT DEG 2009 2010

WATER PROPERTIES • salinity expressed in g/m3 or mg/liter or P.P.M.(g of solids by million g of brine)

• ionic analysis ions most often found : Na+, K+, Ca++, Mg++, Cl-, So4--, CO3--, HCO3graphical representation of water analysis.

• resistivity • solubility of natural gas in water • volumetric properties - isotherm compressibility Cw = - 1/V.(dV/dp) T=cte (close to 0.4*10-4/bar) - density (depending of salinity) - viscosity 195

PVT DEG 2009 2010

RESERVOIR WATER ANALYSIS

196

PVT DEG 2009 2010

DIAGRAMS OF WATER ANALYSIS Stiff diagram

Scale : meg/liter

197

PVT DEG 2009 2010

WATER PROPERTIES ⇒ IONIC COMPOSITION cations :

Na + } K+ } Ca 2+ } Mg 2+ }

sometimes Sr 2+, Ba 2+, Fe 2+ anions :

CO3 2HCO3 Cl SO4 2NO3 -

} } } } } 198

PVT DEG 2009 2010

EXAMPLE OF WATER ANALYSIS WATER ANALYSIS Water sample under atmospheric pressure ph = 6.28 @ 20°C Cations

Na+

K+

Ca2+

Mg2+

Sr2+

Ba2+

mg/l meq/l

43498.94 1892.08

875 22.38

1681 84.05

307.0 25.27

19.0 0.43

0.05 38.0 0.00 1.36

Anions

Cl-

HCO3-

CO3,2-

SO4,2-

NO3-

mg/l meq/l

69450 1956.34

842 13.80

2 0.07

2655 55.3

2 0.03

Iron 2025.6

2025.6

TDS (total dissolved salts) 119370 mg/l (calculation) TDS “ 107000 mg/l (measured)

199

PVT DEG 2009 2010

WATER ANALYSIS Conversion to milliequivalents per liter Component Concentration mg/l meq/l Na+ K+ Ca++ Mg+

17 595 765 0 0 2 960 148 927 76.3 989.3

Component

Concentration mg/l meq/l

SO4ClCO3HCO-

2 620 33 079 0 177

54.6 931.8 0 2.9 989.3

equivalent weight = ion atomic weight / valence example : equivalent of sulfate (SO4-) [ 32 + (4*16) ] / 2 = 48 g/eq wt and meq/l of SO4-

2620 mg/l / 48 mg/meq = 54.6 meq/l 200

PVT DEG 2009 2010

WATER PROPERTIES ⇒ DEFINITIONS Solubility of natural gas in water Volume of gas dissolved (at s.c.) Rsw = Volume of water(s.c.) for pure water Rs = f (P,T) for formation water Rs = f (P,T,salinity) Formation volume factor of water Bw = Volume of water at res cond. / Volume of water at s.c. Bw = f (P,T,Rsw)

201

PVT DEG 2009 2010

SOLUTION GAS - WATER RATIO

Dodson & Standing 202

PVT DEG 2009 2010

WATER PROPERTIES

⇒ DEFINITIONS ⇒ example : calculate solubility and water FVF for salinity = 20 mg/l, T = 200 °F, P = 3000 psig Rsw = 15.3 cuft/bl pure water Rsw = 15.3*0.92 = 14 cuft/bl brine Bw = 1.027 pure water Bw = 1.032 brine

203

PVT DEG 2009 2010

WATER PROPERTIES Water Formation Volume Factor (Bw) Water formation volume factor, bbl/bbl

•

Pressure, psia

Water-formation volume factor for pure water (dashedlines) and pure water saturated with natural gas (solid lines) as a function of pressure and temperature (from Dodson and Standing) 204

PVT DEG 2009 2010

WATER PROPERTIES ⇒ DEFINITIONS water compressibility Cw = f (P,T,Rsw) Cw = - 1/V (dV/dP)T water density ρ = f (P, T, salinity) correlation or ρw (p,t) = ρw (patm,15°C) / Bw ( neglecting the gas weight) water viscosity µ = f (T, salinity) see corelation

205

PVT DEG 2009 2010

WATER PROPERTIES ⇒ DEFINITIONS example : calculate water compressibility and water density for salinity = 20 mg/l, T = 200 °F, P = 3000 psig, Rsw = 14 cuft/bl brine Cw = 3.1 10-6 psi-1 pure water Cw = 1.12 * 3.1 10-6 = 3.5 10-6 psi-1 brine density = ρw = 0.985 g/cc (correlation) or ρw = 1.013/10.32 = 0.980 g/cc viscosity = 0.32 cp (correlation)

206

PVT DEG 2009 2010

WATER COMPRESSIBILITY •

Effect of dissolved gas upon the compressibility of water (from Dodson and Standing)

207

PVT DEG 2009 2010

gm/liter at standard conditions

DENSITIES OF NACL SOLUTIONS

Schlumberger, 1974 208

PVT DEG 2009 2010

WATER DENSITY VS SALINITY

Water gravity @ 20°C/4°C

SATURATION at 317,9 g/l sol or 264.000 ppm

ppm

Water salinity 209

PVT DEG 2009 2010

WATER VISCOSITY

Water viscosity, µwwf : Centipoises

Temperature, Twf : °C

Temperature, Twf : °F

Schlumberger, 1974 210

PVT DEG 2009 2010

WATER - HYDROCARBONS SYSTEMS • Mutual attraction between water and hydrocarbons is extremely small - low water solubility in hydrocarbon liquids - water content in natural gas relatively low - hydrates formation in natural gas • Solubility of water in hydrocarbons liquid not enough data to develop a correlation in P and T, solubility reported for some hydrocarbons vs temperature • Solubility of water in natural gas see correlation 211

PVT DEG 2009 2010

SOLUBILITY OF WATER IN HYDROCARBONS LIQUID

Mol fraction water in hydrocarbon liquid

Solubility of water in liquid

Temperature, deg F 212

PVT DEG 2009 2010

Water content, lb H2O per million cu ft total gas

WATER CONTENT OF NATURAL GAS

Water contents of natural gas in equilibrium with liquid water

Temperature, deg F PVT DEG 2009 2010

213

WATER - HYDROCARBON SYSTEMS • Gas hydrates Natural gas under pressure in contact with excess water liquid might form crystalline solids called hydrates. Crystals like ice with density = 900 kg/m3 Framework : water molecules and in between void spaces occupied by hydrocarbons molecules. First five alkanes only give hydrates Formation conditions : up to T = 25°C and P = 800 bars according to the nature of the gas See also the schematic phase diagram

214

PVT DEG 2009 2010

WATER - HYDROCARBON SYSTEMS

• Gas hydrates Inhibition : - by mechanical treament to remove free liquid water. - increasing the gas temperature or insulating the gas line to stay above the hydrate formation temperature at that pressure. - using an aqueous solutions of antifreezes, like methanol or glycol, polymers to prevent crystallisation of hydrates or antiagglomerate (AA)

215

PVT DEG 2009 2010

PHASE DIAGRAM / WATER - HYDROCARBONS • Phases in a water-oil system D

Pressure

Hydrate + Ice + HC liquid

G

F

Hydrate + water + HC liquid

E

C2 HC liquid + water

B

Hydrate + Ice + HC vapor

C1

Hydrate + water + HC vapor

HC vapor + water

A

J Ice + HC vapor

0°C

Temperature 216

PVT DEG 2009 2010

ALKANES HYDRATES • Hydrate-forming conditions for paraffin hydrocarbons (from

Pressure, psia

Handbook of Natural Gas Engineering by Katz)

PVT DEG 2009 2010

Temperature, deg F

217