A Beginners Guide to using PVTSim for Multi-phase calculations for budding engineers. Typical operations performed in PVTSim are 1. Fluid Database Creation – Composition based 2. Fluid Characterization - Based on Plus fractions 3. Fluids Flashing - Fluid Property Determination 4. Fluid Mixing – for e.g. mixing of various reservoir fluids for their resultant composition 5. Water Saturation of Reservoir Fluid Compositions (dry basis) to arrive at wet composition 6. Viscosity Tuning of Oils based on Laboratory Data (e.g., ASTM D 341, Viscosity vs. Temperature) 7. Hydrate Curve Generation 8. Inhibitor Dosing and Hydrate Curve Shift study

1. PVTSIM FOR BEGINNERS
TABLE OF CONTENTS
1. INTRODUCTION TO PVTSIM 1
2. TYPICAL OPERATIONS IN PVTSIM 1
2.1. FLUID DATABASE CREATION – COMPOSITION BASED 1
2.2. FLUIDS FLASH OPERATION 6
2.3. FLUIDS MIXING 7
2.3.1. Case 1 Example: Gas Flow [MMSCFD], Oil Flow [STBOPD] and Water Cut [Vol%] 7
2.3.2. Case 2 Example: Min, Normal, Max Oil Flow [STBOPD], GOR [Scf/STB] & Water Cut [Vol%] 8
2.3.3. PVTSIM Simulation procedure – Mixing Operation 9
2.4. WATER SATURATION OF RESERVOIR FLUIDS (DRY BASIS) 11
2.4.1. PVTSIM Simulation procedure – Water Saturation of Reservoir Fluids (Dry Basis) 11
2.5. VISCOSITY TUNING OF OILS BASED ON LABORATORY DATA 12
2.5.1. Example Case: Gas Oil Viscosity Tuning 12
2.6. HYDRATE CURVE GENERATION AND INHIBITOR DOSING CALCULATIONS 14
2.6.1. Example Case: Hydrate Curve Generation 14
2.6.2. Example Case: Inhibitor Dosing Calculations 16
1. INTRODUCTION TO PVTSIM
PVTsim is a versatile PVT simulation program developed for reservoir engineers, flow assurance specialists, PVT
lab engineers and process engineers. Based on an extensive data collected over a period of more than 25 years,
PVTsim carries the information from experimental PVT studies into simulation software in a consistent manner
and without losing valuable information on the way. For Pipeline flow assurance studies in OLGA, PVTSIM acts as
an input to OLGA, i.e., it creates a database for the properties of selected materials with compositions,
temperature and pressure ranges, densities and viscosities. Other operations such as hydrate curves, hydrate
inhibitor dosing, wax formation, etc., can also be generated. PVTsim allows reservoir engineers, flow assurance
specialists and process engineers to combine reliable fluid characterization procedures with robust and efficient
regression algorithms to match fluid properties and experimental data. The fluid parameters may be exported to
produce high quality input data for reservoir, pipeline and process simulators.
2. TYPICAL OPERATIONS IN PVTSIM
The following typical operations are performed in PVTSim 19.2.
1. Fluid Database Creation – Composition based
2. Fluid Characterization - Based on plus fractions
3. Fluids Flashing - Fluid Property Determination
4. Fluid Mixing – for e.g. mixing of various reservoir fluids for their resultant composition
5. Water Saturation of Reservoir Fluid Compositions (dry basis) to arrive at wet composition
6. Viscosity Tuning of Oils based on Laboratory Data (e.g., ASTM D 341, Viscosity vs. Temperature)
7. Hydrate Curve Generation
8. Inhibitor Dosing and Hydrate Curve Shift study
9. Table file (*.tab) for OLGA input
2.1. FLUID DATABASE CREATION – COMPOSITION BASED
To perform various operations in PVTSim, a fluid database must be created which accepts fluid
composition. The following exercise stands essential for any case in PVTSIM.
1. Open the PVTSIM icon to get the PVTSIM user interface (Fig. 2.1.1)

2. Figure 2.1.1. PVTSim 19.2 User Interface
2. Go to “File” and select “Create new database” (Fig. 2.1.2).
3. Type a database name and save it in your preferred location in the computer. The database file is saved
with the extension “*.fdb”
Figure 2.1.2. PVTSim 19.2 Database Creation
4. As soon as the database is saved, the path of the database is displayed in the database information
bar.

3. Figure 2.1.3. Database Information Bar
5. In the “Option” bar which is found below the tabs, there are five drop down list boxes whose option are
crucial to start a case.
6. In the first drop down list box, select “User defined1 units”
7. From the second drop down box, the fluid property package to compute the fluid properties is selected.
8. A study can be made during fluid definition stage to understand if the Peng-Robinson (PR) is sufficient
to estimate the H2S or CO2 properties (if present). In case if PR model is able to predict well, select “PR
Peneloux”. (Note: The Peneloux option performs rigorous calculations to estimate accurate densities of
the hydrocarbon fluids.).
Figure 2.1.4. Database Information Bar
9. After establishing the database, go to “Fluid” and select “Enter New Fluid” option. PVTSIM displays a
window for the fluid whose properties, such as composition, mol %, and density are to be fed. The field
“Fluid” is essential which denotes the name of the fluid in the database; hence type a name which
appropriately defines the fluid. If the feed contains fractions beyond C20, select the button “Add Comps”
to add more fractions.
Figure 2.1.5. Fluid Creation

4. Figure 2.1.6. Fluid Composition Entry
Figure 2.1.7. New Components Addition
10. Make sure the molecular weights and densities of PVTSim match with that of the data supplied by
client. Otherwise, it becomes essential to override the properties of PVTSim to match the data supplied
by client. (Note: If the molecular weight of any fraction of the feed supplied is greater than that of
PVTSim, make sure that “Plus fraction” radio button is clicked. This is so because the molecular weight
of plus fraction of a particular alkane is always higher due to presence of other molecular weight
compounds)
Figure 2.1.8. Plus Fraction
11. After entering the all the feed compositions, make sure that the check box “Save Char/Regress” is
checked. Upon checking this option, PVTSIM creates a characterized file, which would be used for
further calculation otherwise, PVTSIM cannot do further calculations though the entered data is saved, it
is unfit for further calculations. Click “OK” button. PVTSIM now displays a confirmation message that
the fluid has been characterized.

5. Figure 2.1.9. Saving Fluid Plus Fraction
Figure 2.1.10. Confirmation Message
12. Click OK again. Now go to “Fluid” tab and select “Database”. This open a small window is displayed
where both the open fluid and characterized fluid is listed.
Figure 2.1.11. Database Check after entering Fluid Composition
13. The characterized fluid is the fluid with the type “Char” and when opened, the file is locked from further
editions, with the radio button “Characterized” checked without options.
Figure 2.1.12. Database Check after entering Fluid Composition

6. 2.2. FLUIDS FLASH OPERATION
Flashing is an operation through which PVTSim estimates the feed properties based on specified
temperature and pressure.
1. Select the “Simulations” button (Fig. 2.2.1)
Figure 2.2.1. Flash operation in Simulations Explorer
2. Flashing is found as the first option under the expansion list of “Flash & Unit Operation”. Double click it.
PVTSIM displays “Flash” window which lets you enter many points of pressure with corresponding
temperatures for which PVTSIM generates separate flash summaries. Click the radio button “PT multi
phase” and click “OK” (Fig,. 2.2.2)
Figure 2.2.2. Operating Conditions for Flash operation
3. The flashed summary can be viewed now.

7. Figure 2.2.2. Flash Operation Output Window
2.3. FLUIDS MIXING
If the reservoir data supplied contains more then one reservoir fluid fluids, then it becomes essential to mix
them, if the combined properties are required. i.e., Individual reservoir compositions have to be mixed in the
various fractions to arrive at a single stream. Often reservoir data is provided in terms of expected fluids
production versus time (years). The reservoir production data is provided in two formats as shown below.
1. Case 1: Gas Flow [MMSCFD], Oil Flow [STBOPD] and Water Cut [Wt% or Vol%]
2. Case 2: Min, Normal, Max Oil Flow [STBOPD] with GOR [Scf/STB] and Water Cut [Wt% or Vol%]
2.3.1. Case 1 Example: Gas Flow [MMSCFD], Oil Flow [STBOPD] and Water Cut [Vol%]
For a given year,, the following production flow rates are expected. Calculate the individual mass fractions of
each component and the total mass flow expected for the year in question
Table 2.3.1.1. Case 1: Example Production Profile
Example Case 1: Production Profile
Note 1
Year
Oil Rate Gas Rate Water Cut
[STBOPD] [MMSCFD] [Vol%]
2020 25,000 40 12
Standard Density
Note 2
Year
Oil Density Gas Density Water Density
[Std. kg/m
3
] [Std. kg/m
3
] [Std. kg/m
3
]
2020 850 1.2 1,000
Note 1: 1 Barrel (oil)/ hour = 4.4163137×10
-5
m
3
/s
Note 2: In the example production profile (Table 2.3.1.1); the densities are given at standard conditions as the
individual flow rates are also given at standard conditions. In practice, the standard density or actual density must be
appropriately chosen depending on the conditions of the input flow rates to calculate the volumetric flow rates.

8. Therefore from table 2.3.1.1, the individual mass flows are computed as,
1. Oil Mass Flow = sQ OilOil kg1027.39850104163137.4
24
25000 5
 

2. Gas Mass Flow = sQ GasGas kg7316.151.2107.8657907
24
1040 6-
6



3. Water Volume Flow STBOPDW
W
W
5682
25000
12.0 


4. Water Mass Flow = sQ WaterWater kg4556.100001104163137.4
24
5682 5
 

Therefore the mass fraction of individual fluids is as follows,
Table 2.3.1.2. Case 1 Example: Calculated Mass Fractions
Mass Fractions
Year 2020 Units Oil Gas Water Total
Mass Flow kg/s 39.1027 15.7316 10.4556 65.2899
Mass Fraction [-] 0.5989 0.2409 0.1601 1.0000
2.3.2. Case 2 Example: Min, Normal, Max Oil Flow [STBOPD], GOR [Scf/STB] & Water Cut [Vol%]
For a given year, the following production flow rates are expected. Calculate the individual mass fractions of
each component and the total mass flow expected for the Year 2020.
Table 2.3.2.1. Case 2: Example Production Profile
Example Case 2: Production Profile
Note 1
Year
Minimum Normal Maximum Water Cut GOR
[STBOPD] [STBOPD] [STBOPD] [Vol%] [Scf/STB]
2020 8,000 10,000 12,000 12 2,200
Standard Density
Note 2
Year
Oil Density Water Density Gas Density
[Std. kg/m
3
] [Std. kg/m
3
] [Std. kg/m
3
]
2020 850 1,000 1.2
Note 1: 1 Barrel (oil)/ hour = 4.4163137×10
-5
m
3
/s
Note 2: In the example production profile (Table 2.3.1.1); the densities are given at standard conditions as the
individual flow rates are also given at standard conditions. In practice, the standard density or actual density must be
appropriately chosen depending on the conditions of the input flow rates to calculate the volumetric flow rates.
Therefore from table 2.3.2.1, the individual mass flows are computed as,
1. Minimum Oil Mass Flow = sQ OilOil kg5129.12850104163137.4
24
8000 5
 

2. Normal Oil Mass Flow = sQ OilOil kg6411.15850104163137.4
24
10000 5
 

3. Maximum Oil Mass Flow = sQ OilOil kg7693.18850104163137.4
24
12000 5
 

4. Water Volume Flow STBOPDW
W
W
5682
25000
12.0 


5. Water Mass Flow = sQ WaterWater kg4556.100001104163137.4
24
5682 5
 


9. The mass flow of gas is computed as,
6.
Std
OilOilOilOilGas
m
kg
Day
STB
Q
STB
Sm
STB
Scf
GORQGORM 























 3
3
70.02831684 
Therefore the mass flow of gas is computed for minimum, normal and maximum conditions as,
7.   skg
m
kg
Day
STB
STB
Sm
M
Std
MinGas 9219.6
360024
1
2.1800070.028316842200 3
3
, 














8.   skg
m
kg
Day
STB
STB
Sm
M
Std
NorGas 6524.8
360024
1
2.11000070.028316842200 3
3
, 














9.   skg
m
kg
Day
STB
STB
Sm
M
Std
MaxGas 3828.10
360024
1
2.11200070.028316842200 3
3
, 














Using the various oil, gas and water mass flow rates computed, the mass fractions for the minimum, normal
and maximum water conditions are estimated as follows,
Table 2.3.1.2. Case 2 Example: Calculated Mass Fractions
Mass Fractions - Minimum Case
Year 2020 Units Oil Gas Water Total
Mass Flow kg/s 12.5129 6.9219 10.4556 29.8904
Mass Fraction [-] 0.4186 0.2316 0.3498 1.0000
Mass Fractions - Normal Case
Year 2020 Units Oil Gas Water Total
Mass Flow kg/s 15.6411 8.6524 10.4556 34.7491
Mass Fraction [-] 0.4501 0.2490 0.3009 1.0000
Mass Fractions - Maximum Case
Year 2020 Units Oil Gas Water Total
Mass Flow kg/s 18.7693 10.3828 10.4556 39.6077
Mass Fraction [-] 0.4739 0.2621 0.2640 1.0000
2.3.3. PVTSIM Simulation procedure – Mixing Operation
Based on the calculations made in the previous sections and taking case 1 as an example study, the mixing
operation is performed as follows,
1. Click the “Fluid Management” tab, under “Fluid” and double click “Mix”. PVTSIM now displays “Mixing of
fluids” window.
2. The different fluids can be mixed in terms of molar fraction or mass fraction.
Figure 2.3.3.1. Mixing of Fluids Input Window

10. 3. Click the “Select Fluids” button after which a “Select Fluids to Mix” window appears. Select the
characterized fluids to be mixed and click “OK”. The fluids appear in the “Mix” window and ensure that
the box “Save Char Fluid” is checked.
Figure 2.3.3.2. Adding Fluids to Mix Fluids
4. Click OK. The fluids are mixed and PVTSIM displays a characterized report for the mixing operation.
Going for another flash operation is not essential; however it is a good practice to ensure that the
characteristics of the stream at standard conditions are established.
Figure 2.3.3.3. Mixed Fluids Output

11. 2.4. WATER SATURATION OF RESERVOIR FLUIDS (DRY BASIS)
This operation is done whenever reservoir fluids are obtained without water content (i.e., dry basis). As it is
inevitable for all reservoir feeds to have water content, such fluids need to be saturated in PVTSIM to arrive
at the exact water content.
The conditions at which the reservoir fluids need to be saturated depends on the conditions of the dry basis-
reservoir fluids. This means we have two conditions for saturation
1. If the reservoir fluids are available at well conditions, then water needs to be added at well conditions till
saturation.
2. If the reservoir fluids are available at standard conditions, then water needs to be added at standard
conditions till saturation.
2.4.1. PVTSIM Simulation procedure – Water Saturation of Reservoir Fluids (Dry Basis)
In the following example, a certain reservoir composition is saturated at standard conditions assuming that
the reservoir fluids composition is known at standard conditions.
1. Repeat the flashing operation again with the composition mentioned in the previous section. To have
the composition flashed with water, the “Flash” Operation is invoked under the simulation window.
Select the radio button “Saturate w.water”. The pressure should be 1.01325 bara and temperature
15.6°C i.e., fluid shall be saturated at standard conditions. Make sure the box “Save water saturated
fluid” is checked only after which the fluid is balanced for water content and saved in the database. This
is done if the reservoir data is available at standard conditions else actual conditions shall be accounted
for. Completing the above steps displays the fluid characterized with water (Fig. 2.4.1.1).
Figure 2.4.1.1. Water Saturation of Reservoir Fluids Output

12. 2.5. VISCOSITY TUNING OF OILS BASED ON LABORATORY DATA
Though PVTSIM generates viscosities for oils at desired process conditions, the predicted viscosities
sometimes are erroneous. PVTSIM provides an option to match the viscosities with laboratory data.
2.5.1. Example Case: Gas Oil Viscosity Tuning
The viscosity curve for a certain finished product namely Gas Oil with the following composition (Table
2.5.1.1) is shown in Fig. 2.5.1.1. Using this data, the gas oil viscosity in PVTSim needs to be tuned with that
of the Laboratory ASTM D 341 Curve.
Table 2.5.1.1. Example Case: Gas Oil Composition
Gas Oil Property Estimation (Density @ 15.6 C - 860.5 kg/m
3
)
Component Mol % Mol Fraction Mol wt Liquid Density [kg/m³]
C8 1 0.01 107 765
C9 1 0.01 121 781
C10 1 0.01 134 792
C11 1 0.01 147 796
C12 3 0.03 161 810
C13 5 0.05 175 825
C14 5 0.05 190 836
C15 19.5 0.195 206 842
C16 18.5 0.185 222 850
C17 45 0.45 237 884
Note1
Note 1: C17 fraction is not a plus fraction
The ASTM D 341 Kinematic Viscosity versus Temperature Curve is as follows,
Table 2.5.1.2. Viscosity vs.
Temperature
ASTM D 341 K.V vs. T
Temperature K. Viscosity
[F] [C] [cSt]
45 7.22 14
50 10.00 12.5
75 23.89 8
100 37.78 5.50
125 51.67 4.00
150 65.56 3.00
175 79.44 2.50
200 93.33 2.00 Figure 2.5.1.1. ASTM D 341 Kinematic Viscosity vs. Temperature
Therefore to tune the viscosities with respect to Laboratory data, the following procedure is employed.
1. Obtain Laboratory data, e.g., ASTM D 341 Kinematic Viscosity versus Temperature Curve (Fig. 2.5.1.1)
2. PVTSIM requires temperature in Celsius, pressure in Bara and dynamic viscosity in cP (Table 2.5.1.2)
3. In the “Simulation” tab, under “Flow Assurance”, double click “Viscosity Tuning”. A window named
“Tuning of viscosity models” is displayed.

13. Figure 2.5.1.2. Tuning of Viscosity Input Window
4. Click “Select Fluids” and select the characterized fluid and click “OK”
Figure 2.5.1.3. Selecting Fluids in Tuning of Viscosity Input Window
5. The selected fluid appears in the “Tuning of Viscosity models” window.
Figure 2.5.1.4. Fluids Added in Tuning of Viscosity Input Window
6. Select the “Visc Data” button. “Viscosity Data” window appears. Enter the viscosity data shown in Table
2.5.1.2. Pressure should be the value stated in the lab report of the considered oil. If the laboratory data
is available under atmospheric conditions then enter the value as 1.01325 Bara.
Figure 2.5.1.5. Viscosity Data Window
Figure 2.5.1.6. PVTSim Viscosity Data updated with
characteristic fluid

14. 7. Click “OK” after which the window disappears leaving the “Tuning of viscosity models” window.
8. Click “OK” tab. PVTSIM displays an excel based summary which states the tuned viscosoties,
percentage of deviation before and after tuning.
9. Ensure that “CSP Visc/Thermal cond” is selected in the “Options” bar before tuning the fluid.
Figure 2.5.1.7. PVTSim Viscosity Data Output Window
2.6. HYDRATE CURVE GENERATION AND INHIBITOR DOSING CALCULATIONS
Hydrates are a mixture of water and gas molecules that crystallize to form a solid “ice plug” under
appropriate conditions of temperature and pressure. Well head streams almost always contain water and
are prone to form hydrates. Hydrates restrict the normal flow of gas causing flow assurance failure & hence
need to be avoided. The various methods of restricting hydrate formation in Pipelines are
1. Heating the fluids (For e.g., prior to entering the pipeline)
2. Addition of Chemical Inhibitors such as MeOH, MEG, DEG or TEG.
3. Heat Tracing of Pipelines
4. Periodical pigging of pipelines to scrape the accumulated hydrates.
Hydrate inhibitors of three types namely
1. Thermodynamic Inhibitors – These inhibitors prevent hydrate formation by altering the hydrate formation
temperatures. Examples are Glycols such as MEG, DEG and TEG.
2. Kinetic inhibitors – These inhibitors alter the kinetics of the hydrate formation process and delay the
nucleate formation of the clathrate structures although they cannot prevent the nucleate formation
3. Anti-Agglomerates – Anti-agglomerants are inhibitors which prevent the hydrate nucleates from
agglomerating as a result of which hydrate plugs can be avoided. These types of inhibitors are used in
smaller concentrations and are known as low dosage inhibitors.
2.6.1. Example Case: Hydrate Curve Generation
1. To establish a hydrate curve, click “Simulations” tab, under “Flow Assurance”, double click “Hydrate”.

15. Figure 2.6.1.1. PVTSim Hydrate Generation Tool
2. It is to be noted that to establish a hydrate curve ensure the following are to be considered otherwise
hydrate curve establishment is not possible.
a. Stream for which hydrate curve is to be estabilished is saturated with water already.
b. Reservoir stream composition should contain water content.
c. Percentage water cut is to be mentioned in the “Hydrate” window.
3. In the current example, since the fluid was already saturated with water, “Hydrate” window shows the
amount of water generated by PVTsim, which is updated. Click “Hydrate PT Curve”.
Figure 2.6.1.2. Hydrate Curve Generation
4. Upon performing the above step, select “Hydrate PT Curve” for which opens a window that requests the
minimum temperature, maximum pressure, temperature step length and pressure step length.

16. Figure 2.6.1.3. Hydrate PT Curve Step Length
5. Enter a value which is well beyond the operating conditions and click “OK”. This generates a Hydrate
curve is generated along with the appropriate values of temperature and pressure.
Figure 2.6.1.4. Hydrate PT Curve Figure 2.6.1.5. Hydrate PT Data
points
2.6.2. Example Case: Inhibitor Dosing Calculations
In Fig. 2.6.1.4, the area within the curve, i.e., area on the left hand side of the curve is the hydrate region
within which hydrate formation is occurs. To check if the hydrate forming region occurs in the pipeline, the
pipeline’s temperature and pressure values need to be plotted on the hydrate curve to check if the data
points lie on the left hand side of the curve. In case if the data points lie on the left hand side of the curve,
hydrate formation occurs and plugs the pipeline over a period of time. To prevent hydrate formation,
thermodynamic inhibitors can be added that shift the curve further to the left hand side namely,
a. Methanol or Ethanol
b. Mono-Ethylene Glycol (MEG)
c. Di-Ethylene Glycol (DEG)
d. Tri-Ethylene Glycol (TEG)
The hydrate dosing rates can be evaluated roughly by using the Hammer-Schmidt equation which is
based on an empirical estimate whereby a shift in the hydrate depression point occurs depending on the
amount of inhibitor added to the hydrocarbon fluid. The following equation shows the Hammer-Schmidt
equation.
 WM
WK
T



100
(Eq. 2.6.2.1)

17. Where,
T = Temperature shift, hydrate depression [°F]
K = Constant [-] which is defined in the Table 2.6.2.1
W = Mass of inhibitor in kg/ kg water or weight% inhibitor in aqueous phase
M = Molecular weight of the inhibitor
The constant K defined for various thermodynamic inhibitors is as follows,
Table 2.6.2.1. Inhibitor Constants in Hammer-Schmidt Equation
INHIBITOR K
Methanol 2335
Ethanol 2335
Mono-Ethylene Glycol 2700
Di-Ethylene Glycol 4000
Tri-Ethylene Glycol 5400
The Hammer-Schmidt equation was generated based upon more than 100 natural gas hydrate
measurements with inhibitor concentrations of 5 to 25 wt% in water. The accuracy of the equation is 5%
average error compared with 75 data points. Considering a 10
0
C temperature shift, the inhibitor dosing can
be calculated for various thermodynamic inhibitors by re-arranging eq. 2.6.2.2 as,








M
T
K
M
W
100
(Eq. 2.6.2.2)
Table 2.6.2.2. Inhibitor Dosing calculations
Inhibitor Methanol Ethanol MEG DEG TEG
Molecular Formula CH3OH C2H5OH C2H6O2 C4H10O3 C6H14O4
Molecular Weight 32.04 46.07 62.07 106.12 150.17
Constant [K] 2335 2335 2700 4000 5400
T [
0
F] 10 10 10 10 10
W (Weight% Inhibitor) 40.69 49.66 53.48 57.02 58.17
From the above table, it can be concluded that Methanol is the inhibitor required in lower quantities and
TEG is required approximately twice the amount of Methanol, i.e., Methanol has a higher temperature shift
than the glycols, but MEG has a lower volatility than methanol and MEG may be recovered and recycled
more easily than methanol on platforms. The above calculations can be entered into PVTSim in the Inhibitor
specification window as follows,
Figure 2.6.2.1. Inhibitor Dosing Window