Post on 02-Jun-2018
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PVTPressure Volume Temperature
(Parts 1 & 2)
Reservoir Engineering I
(PCB2023)
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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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Importance of PVT Analysis
Provides data for field evaluation and design
Reservoir calculations
Well flow calculations
Surface facilities
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Scope of PVT Analysis Scope of the analysis depends on the nature of the fluid.
Oil systems: Black oil and volatile oil
Bubble point pressure, composition of reservoir and produced fluids, Bo, GOR, oil
viscosity, Co.
Below Pbconsiderations: Bg, Bt, Z, gas viscosity.
Properties are measured as functions of pressure.
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Scope of PVT Analysis Dry gas:
composition, specific gravity, Bg, z, and viscosity Wet gas:
as above plus information on liquid drop out, quantities and compositions.
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Scope of 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 representative of
the reservoir contents or the drainage area.
Desirable to take samples early in the life ofthe reservoir.
Either sub-surface or surface sampling.
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Sub-Surface Sampling
Can only be
representative whenpressure at sampling
point is above or equal
to the saturation
pressure.
At pressure close to
saturation pressure
serious possibility of
sample integrity beinglost.
In recent years
considerable advance in
downhole fluid sampling
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Surface Sampling
Samples of oil and gas taken from a specialseparator connected with the well called the
test separator.
Fluids recombined in the laboratory on thebasis of the produced GOR.
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Surface Sampling The separation of oil
and gas as predicted
by the phase diagramresults in each phase
having its own phase
diagram.
The oil exists at itsbubble point .
The gas exists at its
dew point.
This behavior has
important implications
on well sampling
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Equipment for PVT Analysis
Apparatus for transfer and recombination ofseparator 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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Main PVT Tests
Quality check of surface samples
Compositional measurements
Flash vaporization (Constant composition
expansion, CCE) or relative volume test
Differential vaporization test
Separator tests
Density measurements
Viscosity measurements
Special studies: e.g. Interfacial tension
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Quality check of Surface samples
Samples received in the laboratory are evaluated for theirintegrity, primarily by measuring the opening pressure and
comparing with the reported sampling conditions.
This may be examined by heating the sampling bottles to
the sampling temperature.
Any leakage from a sampling bottle containing a gas-liquid
mixture will change the sample composition.
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Compositional measurements
An important test on all reservoir fluid samples is the
determination of the fluid composition.
The most common method of compositional analysis of high
pressure fluids is to flash a relatively large volume of the
fluid sample at the atmospheric pressure to form generallytwo stabilized phases of gas and liquid. The gas and liquid
phases are commonly analyzed by gas chromatography and
distillation, respectively.
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Flash Vaporization (CCE or 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 Pointpressure
corresponding to the reservoir temperature.
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Flash Vaporization (CCE or
Relative Volume ) Test
Liberated gas remains in equilibrium with oil
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Flash Vaporization (CCE or Relative Volume ) Test
By plotting P versus V, a break in the slope is obtained at
the Bubble Point pressure.
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Flash Vaporization (CCE or
Relative Volume ) Test
Tests at constant pressure
and varying temperature
enables thermal expansion
coefficient to be obtained for
well flow calculations.
12
2 2 1
1 1 2 2
V VThermal expansion,V T T
V volume at T , V volume at T
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Flash Vaporization (CCE or Relative Volume )
Test
Above bubble point compressibility ofoil at reservoir temperature can be
determined.
No free gas
2 1
2 1 2
2 2
1 1
V Vc
V P P
V =volume at pressure P
V =volume at pressure P
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Exercise 1 Flash vaporization
The data from a flash vaporization on a black oil at 220 oF are
given. DeterminePband prepare a table of relative volume forthe reservoir fluid study. (data in example 10-1, Mc Cain)
Pressure (psig) Total Volume (cc)
5000 61.030
4500 61.435
4000 61.866
3500 62.341
3000 62.8662900 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
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Differential Vaporization
Differential liberation process
Flash liberation process
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Differential Vaporization
The test has been designed to simulate gas-
liquid equilibrium system in oil reservoirs atpressures below the bubble point pressure.
The test starts from the bubble point pressure.
By this test it can be determined: solution gas-oil ratio, relative oil volume, total solution gas-
oil ratio at the bubble-point pressure, Z factor,
gas formation volume factor, and relative total
volume.
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Differential Vaporization 8-10 pressure reduction steps at reservoir temperature.
Final step to 60oF.
Remaining oil Residual Oil
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Differential Vaporization
1. Solution gas oil ratio RsD
OUTPUTSfrom Differential Vaporization test
2. Relative Oil Volume, BoD
Volume of oil at each pressure divided by volume of oil at std conditions
(14.7 psia & 60 oF)
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Differential Vaporization
OUTPUTSfrom Differential Vaporization test
3. Total solution gas oil ratio at Pb, RsD
4. Z factorRscsc
scRR
TpV
TpVz
5. Gas formation volume factor,p
zTBg 0282.0
6. Relative Total Volume,BtD
)( sDsDbgoDtD RRBBB
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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 oilvolumes, 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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Exercise 2: Differential Vaporization
Solution:
E i 2 Diff ti l V i ti
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Exercise 2: Differential Vaporization
Solution:
E i 2 Diff ti l V i ti
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Exercise 2: Differential Vaporization
Solution:
Exercise 2: Differential Vaporization
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Exercise 2: Differential VaporizationSolution:
Exercise 2: Differential Vaporization
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Exercise 2: Differential VaporizationSolution:
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Separator TestsObjectives To determine impact of separator conditions on Bo, GOR, and
produced fluid physical properties. To determine the optimum operating conditions of the separator
Procedure
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Separator Tests
Separator volume factor = L1/L2
PVT Cell pressure kept atbubble point
Separator volume factor = L1/L2
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Separator TestsCalculations
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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 andtemperature before it was released to the stock tank. Calculate the
formation volume factor and solution gas oil ratio.
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 ConditionsThe optimum operating pressure 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 (atbubble point), and a maximum in stock-tank oil gravity (API).
Example of selecting optimum separator conditions for Good Oil
Co. Well No. 4.
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Flash vaporization is used to characterize reservoir fluid above and below reservoir
bubble point pressure.
Differential vaporization considered to be representative of the process in the
reservoir below bubble point pressure.
Separator test considered to be representative of the process from the bottom of the
well to the stock tank when the reservoir pressure is equal or less than Pb.
COMPARISON BETWEEN THE
THREE TESTS
Under these assumptions, fluid properties abovebubble
point pressure can be estimated by a combination of Flashvaporization and separator test.
Fluid properties belowbubble point pressure can be simulated
by a combination of differential vaporization and separator test.
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OIL FORMATION VOLUME FACTOR
FOR MBE & RESERVOIR STUDIES
At pressures above bubble-point pressure, oil formation volume factors
are calculated from a combination of flash vaporization data and
separator test data.
P Pb
At pressures below the bubble-point pressure, oil formation
volume factors are calculated from a combination of
differential vaporization data and separator test data.
P Pb
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Example of Oil Formation Volume Factor Data
Oil Formation Volume Factor at 200 F
1.000
1.100
1.200
1.300
1.400
1.500
1.600
0 1000 2000 3000 4000 5000
Pressure, psig
OilFormationVo
lumeFacto
bbl/stb
exp sim
SOLUTION GAS OIL RATIO
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SOLUTION GAS OIL RATIO
FOR MBE & RESERVOIR STUDIES
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
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GAS FORMATION VOLUME FACTOR
FOR MBE & RESERVOIR STUDIES
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
Total formation volume factors may be
calculated as
If relative total volumes, Btare reported as a part of the results of the
differential vaporization, total formation factors can be calculated as:
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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
Density measurements
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Density measurements
Oil Density at 200 F
0.700
0.720
0.740
0.760
0.780
0.800
0.820
0.840
0 1000 2000 3000 4000 5000
Pressure, psig
OilDensity,g
/cc
exp sim
Density of oil at reservoir temperature and different pressures
can be measured by an instrument attached to the PVT cell.
Example of Density Data
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Viscosity measurements
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Oil and Gas Viscosity
0.000
0.500
1.000
1.500
2.000
2.500
0 1000 2000 3000 4000 5000
Pressure, psig
Viscosity
,cP
Oil viscosity Gas viscosity
Example of Viscosity Data
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Special Studies of Reservoir Fluids:
Different methods of enhanced oil recovery (EOR)
require different reservoir fluid studies.
Examples:
EOR by miscible gas injection requires measuring the
minimum miscibility pressure.
EOR by surfactant flooding requires measuring the interfacial
tension.
EOR by foam flooding requires measuring foaming ability ofthe surfactant used in presence of reservoir fluids.
High Pressure / High Temperature, HP/HT
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High Pressure / High Temperature, HP/HT
Fluids
Recent years exploration activity has moved deeper.
High pressure and temperature accumulations found
Conventional PVT facilities do not enable testing
these fluids. Ranges 250oC and 20,000 psi.
At these conditions role of water cannot be ignored.