PVT-May2015 (1)

PVTPressure Volume

Temperature

1

Dr. Mohammed Abdalla Ayoub

Reservoir Engineering I

PCB2023

Lesson’s Outcomes

To describe various tests under PVT study

To relate oil physical properties generated from

PVT study for MBE applications

To determine gas physical properties from PVT

study

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PVT - Scope

Reservoir fluid analysis provides key data to

the petroleum engineer.

Quality of the testing is important to ensure

realistic values used in design.

Sample quality is the first quality issue.

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PVT Analysis

Provides data for field evaluation and design

Reservoir calculations

Well flow calculations

Surface facilities

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PVT Analysis

Correlation between pressure and volume at

reservoir temperature.

Various physical constants in reservoir calculations;

viscosity, density, compressibility.

Effect of separator conditions on Bo & GOR. etc.

Chemical composition of the volatile components.

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PVT Analysis Scope of the analysis depends on the nature of the fluid.

Dry gas:

composition, specific gravity, Bg, z, and viscosity

Wet gas:

as above plus information on liquid drop out, quantities andcompositions.

Oil system:

Bubble point pressure, composition of reservoir and producedfluids, Bo, GOR, Bt and viscosity. All as function of pressure. Co.

Below Pb considerations.

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PVT Analysis

Gas condensate:

Reflect wet gas and oil.

Dew point pressure

Compressibility above Pd.

Impact of dropping below Pd

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Sampling

Clearly the sample has to be representative of

the reservoir contents or the drainage area.

Desirable to take samples early in the life of

the reservoir.

Either sub-surface or surface sampling.

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Surface Sampling

Samples of oil and gas taken from separator

connected with the well.

Fluids recombined in the laboratory on the basis

of the produced GOR.

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Sub-Surface Sampling

Can only be representative

when pressure at sampling

point is above or equal to the

saturation pressure.

At pressure close to saturation

pressure serious possibility of

sample integrity being lost.

In recent years considerable

advance in downhole fluid

sampling8/17/2015 10

Vertical and Horizontal Separators

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Wellhead sampling

A low cost option.

Only possible for very

undersaturated

systems.

Still single phase at

wellhead.

Phase Behavior

Fluids uniquely described

by phase diagram.

Within the phase diagram,

system is in two phase.

Whereas outside the

phase envelope is single

phase

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Single phase

Two phase

Phase Behavior

The oil exists at its bubble point .

The gas exists at its dew point.

This behavior has important implications on well sampling

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The separation of oil and

gas as predicted by the

phase diagram results in

each phase having its own

phase diagram.

Equipment for PVT Analysis

Apparatus for transfer and recombination of

separator oil and gas samples.

Apparatus for measuring gas and liquid volumes.

Apparatus for performing separator tests.

PVT cell and displacing pumps.

High pressure viscometer.

Gas chromatograph or equivalent.

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PVT Tests

To provide data for reservoir calculations

To provide physical property data for well flow calculations

For surface facility design

The reservoir calculations are the main driving force for the various

tests.

Over recent years reservoir simulation capability has generated the

need to extend compositional description from C7+ to in some cases

C29+.

PVT report provides source of all reservoir engineering properties

for behavior over exploration, development and production.

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Laboratory Tests

Primary tests

Routine laboratory tests

Special laboratory PVT tests

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Primary Tests

API

Gas specific gravity

Separator gas composition

GOR

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Routine Laboratory Tests

Constant-Composition Expansion - CCE

Differential Liberation

Constant-Volume Depletion – CVD

Separator Test

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Main PVT Tests

Flash vaporization or relative volume test (pressure-

volume relations, flash liberation, flash)

vaporization, or flash expansion.

Differential vaporization test.

Separator tests.

Viscosity measurements.

Compositional measurements.

Special studies: e.g. Interfacial tension.

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Simple layout of a PVT Facility

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Flash Vaporization ( Relative Volume ) Test

Determination of the correlation between pressure and

volume at reservoir temperature.

The system never changes during the test.

The gas remains in equilibrium with the oil through out the

test.

The behavior below the bubble point does not reflect reservoir

behavior, where gas has greater mobility than the oil.

This test determines the Bubble Point pressure

corresponding to the reservoir temperature.8/17/2015 22

Flash Vaporization (Relative Volume ) Test

Liberated gas remains in equilibrium with oil

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By plotting P versus V, a break in the slope is obtained at the BubblePoint pressure.

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CCE Test Procedures

GasLiquid

Hg

Second

Step

Liqui

d

Hg

LiquidLiqui

d

Hg

First

Step

Hg

Third

Step

Hg

Fourth

Step

Liquid

GasVtLiquid

Vt

LiquidVtVt LiquidVt

pb


Tests at constant pressure andvarying temperature enablesthermal expansion coefficient tobe obtained for well flowcalculations.

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Flash Vaporization(Relative Volume) Test

Above bubble point compressibility of oil atreservoir temperature can be determined.

No free gas

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Main objectives:

Reservoir bubble point

pressure.

Together with information

from separator tests,

formation volume factor

above bubble point.

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Exercise 1 – Flash vaporization

The data from a flash vaporization on a black oil at 220 oF are given. Determine Pb and prepare a table of relative volume for the reservoir fluid study. (data in example 10-1, Mc Cain)

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Solution (Mc Cain):Plot of Pressure vs. VtTable 10-1 pg. 4

Pressure (psig) Total Volume (cc)

5000 61.030

4500 61.435

4000 61.866

3500 62.341

3000 62.866

2900 62.974

2800 63.088

2700 63.208

2605 63.455

2591 63.576

2516 64.291

2401 65.532

2253 67.400

2090 69.901

1897 73.655

1698 78.676

1477 86.224

1292 95.050

1040 112.715

830 136.908

640 174.201

472 235.700

Differential Vaporization

Below bubble point in reservoir gas liquid separation in the

reservoir is a constant changing system.

A test has been designed to attempt to simulate this process.

In the differential vaporization test liberated gas is

removed from the cell step wise.

At each step below bubble point, volumes densities , gas

expansion and compressibility determined.

Bubble point starting point.

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Differential Liberation Test

The experimental data obtained from the test include:

Amount of gas in solution as a function of pressure

The shrinkage in the oil volume as a function of pressure

Properties of the evolved gas including the composition of

the liberated gas, the gas compressibility factor, and the gas

specific gravity

Density of the remaining oil as a function of pressure

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Differential Liberation Expansion Test Procedures

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VoLiquid

Hg

Gas

Hg

Liquid

Gas

First step

Hg

Liquid

GasLiquid

Hg

Vo

Gas

Vo

Hg

Liquid

pb


8-10 pressure reduction steps at reservoir temperature.

Final step to 60oF.

Remaining oil Residual Oil

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1. Relative Oil Volume, BoD

Volume of oil at each pressure divided by volume of oil at std conditions

(14.7 psia & 60 oF)

2. Relative Total Volume, BtD

3. Z factor

4. Gas formation volume factor,

5. Solution gas oil ratio, RsD

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OUTPUTS from Differential Vaporization test

Exercise 2: Differential Vaporization

The data from a differential vaporization on a black oil at 220 oF are

given. Prepare a table of solution gas-oil ratios, relative oil volumes,

and relative total volumes by this differential process. Also include

z-factors and formation volume factors of the increments of gas

removed.

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(Solution (Mc Cain example2):

Exercise 2: Differential Vaporization

Notes on answers

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1. Solution gas oil ratio, Rs has units at surface

conditions (scf/stb)

2. Oil formation volume factor has units at reservoir

conditions & surface condition (res. bbl/stb)

3. Gas formation volume factor has units at reservoir

conditions & surface condition (res. bbl/scf)

Differential Vaporization vs. Flash Vaporization

Flash liberation considered to take place between

reservoir and surface.

Differential liberation considered to be

representative of the process in the reservoir below

bubble point pressure.

Differential tests carried out to obtain oil formation

volume factors and GOR’s to predict behavior below

bubble point pressure.

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Separator Tests

Objective: to determine impact of separator conditions on

Bo, GOR, and produced fluid physical properties.

Carried out to give an indication of oil shrinkage and GOR

when fluids produced to surface.

There are no unique values for Bo & GOR. They depend on

separator conditions.

Starting point for the test is the bubble point pressure.

Fluid produced at surface conditions Stock tank oil

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Separator Test Procedures

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LiquidHg

Liquid

Stock

tank

Gas

Gas

Liquid

Hg

pb

Res(bbl)

STB

resbbl

STBBob =

scf

scf

Rsb =scf

STB

Separator Tests

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PVT Cell pressure kept at bubble point

Separator volume factor = L1/L2

Separator Tests

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Separator Tests

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Separator Tests

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Separator Tests

V res

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Separator Test Data

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Viscosity

Measured at different pressures above and

below bubble point pressure.

Below bubble point pressure carried out under

differential conditions.

Rolling ball or capillary tube methods of

measurement

Exercise 3: Separator Test

Data from a separator test on a black oil are given. Note that the volume of separator liquid was

measured at separator pressure and temperature before it was released to the stock tank. Prepare a

separator test for the PVT study. (Example 10-3 Mc Cain)

Volume of oil at Pb and Tres = 182.637 cc

Volume of separator liquid at 100 psig and 75 oF = 131.588 cc

Volume of stock-tank oil at 0 psig and 75 oF = 124.773 cc

Volume of stock-tank oil at 0 psig and 60 oF = 123.906 cc

Volume of gas removed from separator = 0.52706 scf

Volume of gas removed from stock tank = 0.07139 scf

SG of stock tank oil = 0.8217

SG of stock separator gas = 0.786

SG of stock tank gas = 1.363

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Solution of Exercise 3

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Selection of Separator Conditions

The first step in calculating fluid properties is selection of separator

conditions.

There may be circumstances for a particular field which dictate a specific

separator pressure. If not, the separator pressure which produces the

maximum amount of stock-tank liquid is selected. This pressure is known as

optimum separator pressure.

It is identified from the separator tests as the separator pressure which

results in a minimum of total gas-oil ratio, a minimum in formation volume

factor of oil (at bubble point), and a maximum in stock-tank oil gravity

("API). Most black oils have optimum separator pressures of 100 to 120

psig at normal temperatures.

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Exercise 4

Select optimum separator conditions for Good Oil Co. No. 4. Identify Rssb and Bosb.

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Solution of Exercise 4

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Outcomes

To describe various tests under PVT study

To relate oil physical properties generated

from PVT study for MBE applications

To determine gas physical properties from

PVT study

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Flash vaporization is used to characterize reservoir fluid above and belowreservoir bubble point pressure.

Differential vaporization considered to be representative of the process inthe reservoir below bubble point pressure.

Separator test considered to be representative of the process from thebottom of the well to the stock tank when the reservoir pressure is equalor less than Pb.

Comparison between the Methods

Under these assumptions, fluid properties above bubble point pressurecan be estimated by a combination of Flash vaporization and separatortest.

Fluid properties below bubble point pressure can be simulated by acombination of differential vaporization and separator test.

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At pressures above bubble-point pressure, oil formation volume factors arecalculated from a combination of flash vaporization data and separator testdata.

P ≥ Pb

At pressures below the bubble-point pressure, oil formationvolume factors are calculated from a combination ofdifferential vaporization data and separator test data.

P ≤ Pb

Pressure Bo

5000 1.4214500 1.4304000 1.4403500 1.4513000 1.4642900 1.4662800 1.4692700 1.4712620 1.4742350 1.4322100 1.3961850 1.3631600 1.3311350 1.3011100 1.273850 1.245600 1.216350 1.182159 1.146

STB

P@ oil of bbl res.

oSb

Fb

to B

V

VB

STB

P@ bbl res.

oDb

oSboDo

B

BBB

Oil Formation Volume Factor


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Solution Gas Oil Ratio (Rs)

Solution gas-oil ratio at pressures above bubble-point pressure is a constant equal

to the solution gas-oil ratio at the bubble point.

@ P ≥ Pb

Solution gas-oil ratios at pressures below, bubble-point

pressure are calculated from a combination of differential

vaporization data and separator test data.

@ P < Pb

sSbs RR

STB

SCF

B

BRRRR

oDb

oSbSDSDbsSbs )(

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Gas Formation Volume Factor

Gas formation volume factors are calculated with z-factors measured

with the gases removed from the cell at each pressure step during

differential vaporization.

Total Formation Volume Factor, (Bt)

Total formation volume factors may be calculated as

If relative total volumes, Bt are reported as a part of the results of the

differential vaporization, total formation factors can be calculated as:

SCF

ftcures

p

zTBg

.

0282.0

)( ssbgot RRBBB

oDb

oSbtDt

B

BBB

Total Formation Volume Factor, (Bt)

The total formation volume factor is the volume in barrels (cubic meter) that 1.0 stock tankbarrel (cubic meter) and its initial complement of dissolved gas occupies at reservoirtemperature and pressure conditions.

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Coefficient of Isothermal Compressibility of Oil

The following Equation may be used with the flash vaporization data to

calculate oil compressibility at pressures above the bubble point.

When the pressure is below the bubble point pressure, the following

equation can be used to calculate the Co

21

1

2ln

PP

VV

VV

CFbt

Fbt

o

TsD

oDg

T

sD

oD

oR

BB

P

R

BC

1

Example A sample of reservoir oil from a nameless field was subjected to flashvaporization, differential and separator tests. Data from these PVT tests aresummarized in TABLES a, b and c.

62

Pressure (psig) Volume of fluid in PVT cell (cc)

1300 244.57

3500 249.90

Pressure (psig) Cumulative Gas

Volume (cc)

Volume of Oil

in cell

1300 0 177.66

1150 385 176.85

1000 938 175.50

850 1515 174.01

700 2140 172.39

550 2813 170.64

400 3558 168.75

250 4496 162.54

139 5386 144.50

0 8991 135.00

Oil displaced from PVT cell

(1st stage separator at 212 psig

and 71oF)

55 cc

Oil volume collected from the

last separator stage

(0 psig and 60oF)

45 cc

Gas volume collected at

standard conditions (0 psig

and 60oF)

2000

cc

TABLE c: Data from Separator Test

TABLE b: Data from Differential vaporization

TABLE a: Data from Flash vaporization

Note: Test done at reservoir temperature of 212oF.

Questions

1. Calculate the oil formation volume factor, Bo at 3500 psig.

2. Determine the Bo at 1000 psig.

3. Calculate the solution gas oil ratio, Rs (in scf/STB) at 3500

psig. (Note that 1 bbl = 5.615 ft3)

4. What is the expected value of Rs at 1000 psig? Justify.

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Answers

64

stbbblcc

ccB

V

VB oSb

Fb

to /249.1

45

55*

57.244

9.249

1.

stbbblrescc

cc

B

BBB

oDb

oSboDo /.208.1

135

66.17745

55

*0.135

5.175

2.

3. Since Rs is above Pb we use separator results

stbscfstb

ft

cc

ccRR sSbs /6.249

.1

615.5*

45

2000 3

4. The Rs @ 1000 psig will be lower than Rs @ 3500 psig because some gas >1000

has been released.

stbscf

B

BRRRR

oDb

oSbSDSDbsSbs

/5.198615.5*

135

66.17745

55

135

9383858991

135

89916.249

)(

Summary of results provided by an oil sample PVT test.

Saturation pressure, -bubble point.

Compressibility coefficient.

Coefficient of thermal expansion.

Relative total volume of oil and gas, Vt

Cumulative relative volume of gas. Vg

Cumulative relative volume of oil. Vo

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Summary of results provided by an oil sample PVT test.

Gas formation volume factor or gas expansion factor.

Gas compressibility factor.

Specific gravity of gas.

Liquid density.

Viscosity of liquids as a function of pressure.

Oil formation volume factor.

Solution gas- oil ratio. Shrinkage of separator oil to tank oil.

Hydrocarbon analysis of reservoir and produced fluids.

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Viscosity

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Solution Gas-Oil Ratio

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Density

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Documents

PVT-May2015 (1)