MEASUREMENT AND PREDICTION OF CONDENSATE GAS HYDRATES
FORMATION CONDITIONS. A CASE STUDY
SAMER Said
Laboratory of Materials Chemistry
Department of Chemistry
Faculty of Science
University Hadj Lakhdar, 05 avenue chahid
boukhlouf 05000 Batna, Algeria
Email: [email protected]
BELLOUM Mohamed
Laboratory of Materials Chemistry
Department of Chemistry
Faculty of Science
University of Batna, 05 avenue chahid boukhlouf
05000 Batna, Algeria
Email: [email protected]
OTMANINE Ghazi
Laboratory of Hydrocarbons technology
Department of Chemistry
Faculty of Hydrocarbons & Chemistry
University of Boumerdes, Avenue of
independence, 35000 Boumerdes, Algeria
Email: [email protected]
ABSTRACT
NOMENCLATURE
During field exploitation or in the expedition lines or even
during its handling process, natural gas is in permanent contact
with an aqueous phase. Under certain pressure and temperature
conditions, crystal deposits like ice are formed. These deposits,
commonly called hydrates, are considered as a nuisance which
can generate plugs, or even damage gas processing equipments
causing total shutdowns sometimes with fatalities.
A new field of gas condensate recently discovered in south
of Algeria caused a lot of difficulties and even accidents during
its operation due to hydrates formation. This is why identifying
the conditions of gas hydrates formation in this field and
possible solutions to prevent their formation have become
imperative. For this purpose, we took this real case which is
within the framework of a laboratory concrete study to identify
the hydrate formation and stability conditions (P,T)
experimentally, and identify curves which by identifying
integrity zones for operators to work outside these conditions,
and the influence of inhibitors on the prevention of hydrates.
Our approach is to reconstitute reservoir fluid by mean of
recombination of two validated separator liquid and gas
samples, by carrying out a PVT study of both fluids and
measuring the conditions of hydrate formation. In addition, a
numerical study was performed using PVTsim commercial
software, used to predict hydrate formation conditions and the
impact of inhibitors.
KEY WORDS
Hydrates, condensate gas, plug, PVT, safety
CME: Constant Mass Expansion
GOR: Gas Oil Ratio
GORcor : Corrected Gas Oil Ratio;
GORcha : Measured Gas Oil Ratio in field
d ch : Determined gas density in field
Z ch : Gas compressibility factor determined in field
d lab : Gas density determined in laboratory
Z lab : Gas compressibility factor determined in laboratory
Fc : Separator liquid contraction factor (cm3/cm3)
M m : Average molar mass of separator gas
M i : Molar mass of component i in the gas mixture
Yi : Molar fraction of component i in the gas mixture
n: Number of component of gas mixture
M m : Average molar mass of separator gas
M air : Molar mass of air
: Separator liquid mass density (g/cm3)
m pr : Filled Pycnometer mass (g)
m pv : Empty Pycnometer mass (g)
Vlt : Volume of the transferred liquid (cm3)
1
M l : Liquid mass molar
l
: Liquid mass density
Vl : Liquid volume
M i : Mass molar of component i in the gas mixture
INTRODUCTION
Hydrates belong to the class of clathrates, which are
inclusion compounds. The "clathrate" word was used the first
time by Powell in 1948, and derived from the Latin word
"clathratus" which means "in capping". Clathrates are solid
crystallized in which some atoms or molecules are trapped in
cages provided by the assembly of another type of molecules.
When the crystal lattice is formed by water molecules linked
together by hydrogen bonds and the cavities are occupied by
gaseous molecules, the formed clathrates are called hydrates.
[1].
The most common gas hydrates morphology is methane
hydrate (Fig.1). There are other gas molecules including ethane,
propane, butane, isobutane, pentane, nitrogen, carbon dioxide
and hydrogen sulfide.
show an accident during the well flow back test). This is why
identifying the conditions of gas hydrates formation in this field
and possible solutions to prevent their formation have become
imperative.
To clearly define the hydrates, predict their equilibrium
conditions and determine the relationship between pressure and
temperature under which those hydrates form and dissociate,
equilibrium curves were used. These curves can be generated
by a series of laboratory experiments, or are more commonly
conducted using thermodynamic software such as PVTsim
based on the hydrocarbons composition and aqueous phases in
the system [9, 10].
.
Picture-1: hydrate plug
formed in the pipeline
Picture-3: destroyed
pipeline
Fig.1: Clathrate structure of methane hydrate.
Three different crystal lattice structures have been
identified: cubic structure sI, cubic structure sII and hexagonal
structure sH. Their stability depends on pressure, temperature
and gas composition [2, 3, 4, 5].
Hydrates are considered as a nuisance because they block
transmission lines, plug blowout preventers, endanger the
foundations of deepwater platforms and pipelines, cause tubing
and casing collapse, and foul process heat exchangers, valves,
and expanders [6].
In 1934, Hammerschmidt [7, 8] recognized first that
natural gas transport lines failure is due to the formation of
hydrate plugs. Since that time, the gas industry has invested
significant human and material resources for further research to
determine the conditions of hydrate formation then took a
number of preventive measures.
A new field of gas condensate recently discovered in south
of Algeria caused a lot of difficulties and even accidents during
its operation due to hydrates formation (pictures -1, 2, 3 and 4
Picture-2: hydrate plug
dissociation in the pipeline
Picture-4: damaged
pipeline
SAMPLING METHODS
Two sampling methods are applied today; downhole
sampling and surface sampling [11, 12, 13, 14]. The first
method is applied in the case of a single-phase effluent. The
second one is much applied in the case of natural gas. In the
case of gas with condensate leading to the production of a twophase effluent, sampling is performed at high pressure separator
by taking gas sample (separator gas) and liquid sample
(separator liquid).
SAMPLES VALIDATION
For the separator liquid, we should first determine bottles
opening pressure and saturation pressure at the separation
temperature, which must be identical to the separation pressure.
Since our gas is a condensate gas, we should determine the
saturation pressure of the separator liquid which is performed
2
by a CME test. It should be noted that the CME is a
conventional study conducted at separation temperature to
determine the saturation pressure of the separator liquid [11].
Validation of separator gas is performed by
chromatographic analysis and the opening pressure should be
equal or close to the separation pressure [11].
Fluid Contraction Factor "Fc" ;
Gas Oil Ratio "GOR" ;
Liquid Volume Factor "Bo" ;
Separation Effluents Composition.
Separator liquid mass density is calculated as:
m pr
RESERVOIR FLUID RECONSTITUTION
m pv
. (1.4)
V lt
The properties of field fluids can be known by a
recombination which requires precise rates measurement of
gaseous phase and liquid phase. The recombination can be
either physical or mathematical [11].
The physical recombination is a mixing operation
performed between the separator liquid and the separator gas to
obtain a fluid representing reservoir fluid. The volumes of
separator gas and separator liquid to be mixed are calculated so
that their ratio is equal to the GOR value measured after their
platform separation [11].
For mathematical recombination, the overall mixture
composition is calculated from the composition of each phase
and their respective proportions [13].
Obtaining a representative reservoir fluid requires a PVT
study of separator gas and separator liquid [15]. The physical
parameters provided by the PVT study of separator gas and
separator liquid will be used to correct the field GOR to obtain
the reservoir gas.
The corrected GOR is calculated from the field and
laboratory data with the following formula:
GOR cor
( d .Z ) ch
( d .Z ) lab
GOR cha Fc
n
Yi M i
Determined Gas Oil Ratio in laboratory
15
15 )
The molar composition is obtained by carrying out a
material balance:
nl
ng
zi
nl xi
nl xi
n g yi
xi
n g yi
nl
(1.5)
nt
(nt ) z i
ng
(
ng
1 (
nl
ng
.. (1.6)
) yi
nl
.. (1.7)
)
Supposing
that a liquid volume V generates a gas volume Vg and a liquid
mass, we will get:
ng
Vg M l
nl
V mol
l
.. (1.8)
Vl
. (1.2)
ng
i 1
Mm
M air
xi
(
1 (
;
3
. (1.9)
l
GOR
zi
The parameters are as follows:
15
15 "
xi M i
V mol
. (1.3)
The PVT study of separator liquid is used to calculate the
following parameters and mathematical recombination of liquid
flash and gas flash.
Storage Liquid Mass Density "
GOR
nl
The separator gas density, given by the following
formula:
d
GORlab
Mass Density of storage liquid at 15°C (
Molar Volume at 15°C
. (1.1)
The PVT study of the separator gas includes the
determination of the separator gas chemical composition that
used to determine:
The average molar mass of separator gas, calculated
by its composition.
Mm
The purpose of the mathematical recombination of flash
liquid and flash gas is to reconstitute the separator liquid. The
parameters of this recombination are:
V mol
GOR
V mol
xi M i
) yi
.. (1.10)
l
xi M i
l
)
EXPERIMENTAL SET-UP
1. SAMPLES VALIDATION
The PVT apparatus was used to validate samples,
reconstitute of reservoir fluid and measure the hydrate
formation conditions. This apparatus has several elements and
the most important are the volumetric pump, the visual high
pressure cell, the displacement and volume measurement
system, the air bath and the sampling cylinder (Fig.2)
The visual high-pressure cell had been connected to a
volumetric pump and therefore the pressure of the cell could be
controlled by injecting and withdrawing the hydraulic fluid to
the hydraulic fluid side. On the other hand, the high pressure
cell temperature was very precisely stabilized by a digital
controller. The cell internal volume was divided into two parts,
separated from each other by a sealed piston. One side of the
piston was connected to a volumetric pump and the other side
had been filled with the fluid sample and water.
The reservoir samples are two bottles containing 20 liters
of separator gas, two cylinders containing 700 ml of separator
liquid and one cylinder containing 700 ml of separator water.
The samples were heated to the separator temperature
(39°C), stirred and stabilized. The opening pressure was
determined using pump pressure indicator.
The obtained results for the samples of separator gas and
separator liquid are respectively shown in Table-1 and Table-2.
Table-1: Opening pressure of separator gas samples bottles
Sample N°
Cylinder N°
Separator
Pressure
(psig)
Separator
Temperature
(°C)
Lab Opening
Pressure
(psig)
Lab Opening
Temperature
(°C)
Separator Gas
1
2
CGS1
CGS2
270
270
39
39
268
260
39
39
Table-2: Opening pressure of separator liquid samples
Cylinders
Sample N°
Cylinder N°
Separator
Pressure
(psig)
Separator
Temperature
(°C)
Lab Opening
Pressure
(psig)
Lab Opening
Temperature
(°C)
Separator Liquid
1
2
CLS1
CLS1
270
270
39
39
270
260
39
39
CME TEST
Fig.2: PVT Apparatus (Jefri)
EXPERIMENTAL PROCEDURE
O
RESERVOIR FLUID RECONSTITUTION
The reconstitution of the reservoir fluid involves the following
steps:
Samples validation;
PVT study of separator gas;
PVT study of separator liquid;
Recombination of separator liquid and separator gas.
A constant mass expansion test (CME) was performed on
both separator liquid samples at separator temperature to
determine the saturation pressure which would normally
correspond to the separation pressure. For this, we introduced a
volume of 40 cm³ at 3000 psig in the PVT visual cell heated to
the separator temperature (39°C) in an air bath, set up at ±
0.2°C and after stabilizing in temperature and pressure by
propeller magnetic stirring, we decreased pressure and noted
corresponding fluid volume every time. The temperature of the
PVT cell is measured using a thermocouple connected to a
platinum RTD digital display with an accuracy of 0.01°C. The
pressure in the PVT cell is measured using a Heise type
digital gauge with an accuracy of 0.1%. The volumes are
determined using a cathetometer with a resolution of 0.01mm.
The kink point on the graph of the pressure-volume
relationship is the saturation pressure Pb .
4
1,800
Table-3: Composition, average mass molar and separator gas
density
Relative volume (cm3/cm3)
1,650
1,350
1,200
1,050
0,900
1000
2000
3000
Pressure (psig)
Fig-5: Pressure-volume relationship of the first
separator liquid sample during the CME at separator
temperature (39 °C).
1,650
1,500
Relative volume (cm3/cm3)
Separator Gas Molar Composition
"Yi" (%)
28.014
44.010
16.043
30.070
44.097
58.124
58.124
72.151
72.151
86.178
96.000
107.00
121.00
134.00
147.00
161.00
175.00
190.00
206.00
222.00
237.00
251.00
263.00
275.00
291.00
305.00
318.00
331.00
345.00
359.00
374.00
388.00
402.00
580.00
1.17
1.59
81.35
10.31
3.54
0.49
0.86
0.27
0.23
0.13
0.06
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
N2
CO2
C1
C2
C3
iC4
nC4
iC5
nC5
C6
C7
C8
C9
C10
C11
C12
C13
C14
C15
C16
C17
C18
C19
C20
C21
C22
C23
C24
C25
C26
C27
C28
C29
C30+
1,500
0
Molar Mass "Mi "(g/mole)
Total
Average Molar Mass "Mm" (g/mole)
Density "d" (air = 1)
1,350
100.00
20.05
0.692
3. PVT STUDY OF SEPARATOR LIQUID
1,200
1,050
0,900
400
900
1400
1900
2400
2900
3400
Pressure (psig)
Fig-6: Pressure-volume relationship of the second
separator liquid sample during the CME at separator
temperature (39°C).
The representative sample (validated) is the first sample
and it can be used for recombination to obtain reservoir fluid.
We have transferred a volume of 40 cm³ of validated
separator liquid sample in the visual high pressure cell raised to
the separator temperature (39°C) in an air bath, set up at ±
0.2°C and to a pressure higher than the separation pressure
(3000 psig) to ensure a single-phase transfer of the sample.
After stabilization of temperature and pressure by the
magnetic stirring, we measure the mass of the empty
pycnometer and then we transfer a volume of 14.9 cm³ of
separator liquid of the PVT cell towards the pycnometer at a
pressure of 3000 psig and at the separation temperature (39°C).
We measure the mass of the pycnometer after the transfer. The
obtained results are shown in Table-4.
1
2
average
848.93
848.63
(c
m pv
10.68
10.38
Vlt
14.90
14.50
(g/c
838.25
838.25
m pr
m3)
m pr
3
m pv
m)
(g)
Test N°
The validated separator gas sample was analyzed using gas
phase chromatography.
The obtained results concerning the composition in molar
percentage, mass molar and density are shown in Table-3.
(g)
Table-4: Separator Liquid Mass Density
2. PVT STUDY OF SEPARATOR GAS
0.717
0.716
0.7165
The density of separator liquid at the saturation point is
deduced from that measured at 3000 psig and at the separation
temperature (39°C).
5
C17
C18
C19
C20
C21
C22
C23
C24
C25
C26
C27
C28
C29
C30+
The separator liquid sample had a flash from the separation
conditions to ambient conditions, the gas effluents and obtained
liquid (gas flash and liquid flash) are analyzed by gas
chromatography. The flash separation is performed in the Jefri
GOR Apparatus (DPR Company).
The obtained results are shown in table Table-5.
Table-5: Composition of Liquid flash and Gas flash
Components
N2
CO2
C1
C2
C3
iC4
nC4
iC5
nC5
C6
C7
C8
C9
C10
C11
C12
C13
C14
C15
C16
C17
C18
C19
C20
C21
C22
C23
C24
C25
C26
C27
C28
C29
C30+
Molar Mass "Mi
"(g/mole)
Flash Gas Molar
Composition (%)
Flash Liquid Molar
Composition (%)
28.014
44.010
16.043
30.070
44.097
58.124
58.124
72.151
72.151
86.178
96.000
107.00
121.00
134.00
147.00
161.00
175.00
190.00
206.00
222.00
237.00
251.00
263.00
275.00
291.00
305.00
318.00
331.00
345.00
359.00
374.00
388.00
402.00
580.00
4.25
1.39
31.56
27.90
20.37
3.33
6.55
1.86
1.45
0.88
0.36
0.07
0.02
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.01
0.05
0.36
1.96
5.59
2.49
7.02
5.38
5.74
12.32
17.33
11.76
10.00
6.09
3.84
2.58
1.99
1.40
1.05
0.77
0.58
0.44
0.34
0.25
0.19
0.14
0.10
0.08
0.06
0.04
0.02
0.01
0.01
0.01
Total
100.00
N2
CO2
C1
C2
C3
iC4
nC4
iC5
nC5
C6
C7
C8
C9
C10
C11
C12
C13
C14
C15
C16
Liquid
flash
"xiMi"
Separator Liquid Molar
Composition (%)
28.014
44.010
16.043
30.070
44.097
58.124
58.124
72.151
72.151
86.178
96.000
107.00
121.00
134.00
147.00
161.00
175.00
190.00
206.00
222.00
0.18
0.02
9.96
7.79
4.15
0.11
0.43
0.03
0.02
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.02
0.06
0.59
2.47
1.44
4.08
3.88
4.14
10.62
16.63
12.58
12.10
8.16
5.65
4.15
3.48
2.67
2.16
1.72
0.69
0.26
5.33
6.09
7.95
2.62
6.95
4.82
5.06
10.50
14.63
9.90
8.41
5.12
3.23
2.17
1.67
1.18
0.88
0.65
0.49
0.37
0.29
0.21
0.16
0.12
0.08
0.07
0.05
0.03
0.02
0.01
0.01
0.01
Total
100.00
Average Mass Molar "Mm" (g/mole)
91.74
Components
N2
CO2
C1
C2
C3
iC4
nC4
iC5
nC5
C6
C7
C8
C9
C10
C11
C12
C13
C14
C15
C16
C17
C18
C19
C20
C21
C22
C23
C24
C25
C26
C27
C28
C29
C30+
Table-6: Molar Composition of obtained Separator Liquid by
Mathematical Recombination of gas flash and Liquid flash
Gas flash
"yi.Mi"
1.38
1.10
0.91
0.69
0.55
0.44
0.30
0.28
0.21
0.13
0.09
0.05
0.05
0.07
The molar composition of the reservoir fluid obtained by
mathematical recombination is shown in Table-7.
100.00
Molar Mass "Mi
"(g/mole)
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
4. RECOMBINATION OF SEPARATOR LIQUID AND
SEPARATOR GAS
The purpose of the mathematical recombination of liquid
flash and gas flash is to reconstitute the separator liquid. The
composition of the separator liquid obtained by mathematical
recombination is shown in the Table-6.
Components
237.00
251.00
263.00
275.00
291.00
305.00
318.00
331.00
345.00
359.00
374.00
388.00
402.00
580.00
Mass Molar "Mi
"(g/mole)
Separator Gas
Molar
Composition
(%)
Separator
Liquid
Molar
Composition
(%)
Reservoir fluid
Molar
Composition (%)
28.014
44.010
16.043
30.070
44.097
58.124
58.124
72.151
72.151
86.178
96.000
107.00
121.00
134.00
147.00
161.00
175.00
190.00
206.00
222.00
237.00
251.00
263.00
275.00
291.00
305.00
318.00
331.00
345.00
359.00
374.00
388.00
402.00
580.00
1.17
1.59
81.35
10.31
3.54
0.49
0.86
0.27
0.23
0.13
0.06
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.69
0.26
5.33
6.09
7.95
2.62
6.95
4.82
5.06
10.50
14.63
9.90
8.41
5.12
3.23
2.17
1.67
1.18
0.88
0.65
0.49
0.37
0.29
0.21
0.16
0.12
0.08
0.07
0.05
0.03
0.02
0.01
0.01
0.01
1.16
1.55
79.07
10.18
3.67
0.55
1.04
0.41
0.38
0.44
0.50
0.30
0.25
0.15
0.10
0.07
0.05
0.04
0.03
0.02
0.02
0.01
0.01
0.01
0.01
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
100.00
100.00
100.00
20.05
91.74
22.21
Total
Average Molar Mass "Mm"
(g/mole)
O
MESURMENT OF GAS HYDRATE FORMATION
CONDITIONS
This step consists of the following:
Measurement of gas hydrate formation temperature
Measurement of gas hydrate formation temperature
with increasing of produced water amount
Measurement of gas hydrate formation temperature
with addition of different inhibitors
6
5000
1- MESUREMENT OF GAS HYDRATE FORMATION
TEMPERATURE
4500
4000
3500
(a)
(c)
(b)
(d)
Fig.7: Hydrates formation process in the visual high
pressure cell at a pressure of 3000 psig and a temperature
of 24°C. (a) Initiation, (b) after 7 minutes, (c) after 12
minutes and (d) after 13 minutes.
Pressure (psig)
We introduce a volume of 60cm³ of reservoir fluid (gas) at
a pressure of 5000 psig in the visual high pressure cell to the
reservoir temperature (104°C) in an air bath, set up to ± 0.2°C,
then we inject a volume of 3cm³ of separator water at the base
of the PVT cell using the volumetric pump and after stabilizing
on temperature and pressure by a magnetic stirrer; we reduce
the pressure.
The increase in pressure is done by the positive
displacement pump driving back special oil (its freezing
temperature is less than -40 ° C).
For each pressure level, we reduce the temperature of the fluid
with agitating the high pressure cell fluid (gas + separator
water) until the hydrate formation (Fig.7).
Unsafe region
(hydrate zone)
3000
2500
2000
1500
Safe region
(no hydrate)
1000
500
0
10
15
25
30
Fig.8: Hydrate phase equilibrium curve of reservoir
fluid (gas condensate)
2- MESUREMENT OF GAS HYDRATE FORMATION
TEMPERATURE WITH INCREASING OF
PRODUCED WATER AMOUNT
It should be noted that during the field exploitation, the
produced water amount increases with the time.
We transfer into the visual high pressure cell at a pressure
of 5000 psig and at reservoir temperature (104°C) a volume of
60 cm³ of reservoir gas, then we inject at the bottom of the cell
using the volumetric pump a volume of 3 cm³ (5% vol), 6 cm³
(10% vol), 9 cm³ (15% vol) and 12 cm³ (20% vol) of produced
water for the last test. After temperature stabilization by a
magnetic stirring, we noticed a decrease in pressure. Then, we
cool the fluid of the cell with agitation until formation of
hydrates. The obtained results are shown in Fig.9.
5000
5% vol separator water
4500
10% vol separator water
15% vol separator water
4000
20% vol separator water
3500
Pressure (psig)
Hydrate formation causes a rapid decrease in pressure in
the visual high pressure cell.
For each pressure level and after the formation of hydrates,
we proceed with dissociation of formed hydrates by increasing
temperature in the high pressure cell.
20
Temperature (°C)
3000
2500
Unsafe region
(hydrate zone)
2000
1500
The obtained results are shown on Fig.8.
1000
Safe region
(no hydrate)
500
0
-10
-5
0
5
10
15
20
25
30
Temperature (°C)
Fig.9: Hydrate phase equilibrium curves of reservoir
fluid (gas condensate) with increasing of produced
water amount
7
3- MESUREMENT OF GAS HYDRATE FORMATION
TEMPERATURE WITH ADDITION OF DIFFERENT
INHIBITORS
5000
0% vol de DEG
4500
25% vol de DEG
50% vol de DEG
4000
75% vol de DEG
3500
Pressure (psig)
Hydrate formation is generally stopped by several
methods: temperature control, pressure reduction, dehydration
and use of chemical inhibitors such as alcohols, glycols etc.
The influence of some inhibitors on reducing the hydrate
formation temperature has been studied. The obtained results
are shown in Fig.10, Fig.11 and Fig.12.
3000
2500
2000
1500
1000
500
0
5000
0
0% vol methanol
4500
10
15
50% vol methanol
25
30
Fig.12: Hydrate phase equilibrium curves of reservoir
fluid (gas condensate) in presence of DEG as inhibitor
75% vol methanol
3500
20
Temperature (°C)
25% vol methanol
4000
Pressure (psig)
5
3000
2500
COMPARATIVE STUDY
2000
1500
1000
500
0
-10
-5
0
5
10
15
20
25
30
Temperature (°C)
Fig.10: Hydrate phase equilibrium curves of reservoir fluid
(gas condensate) in presence of methanol as inhibitor
5000
25% vol TEG
4000
50% vol TEG
75% vol TEG
Pressure (psig)
3500
F ( P,V , T , X )
0
Using hydrates models exist in the PVTsim, it is possible to
simulate and predict the hydrate formation conditions in
mixtures of gas and oil. The decrease in temperature of hydrate
formation due to the addition of inhibitors (MeOH, EtOH,
MEG, DEG and TEG) can be simulated.
0% vol TEG
4500
In order to confirm the experimental results of temperature
measurements of hydrate formation of fluid reservoir (gas
condensate), we used the numerical simulation tool
(commercial software PVTsim du Laboratoire PVT CRD
Sonatrach).
The PVTsim software is a tool used to model the
volumetric properties of petroleum fluids using a mathematical
expression:
3000
To perform these computations, PVTsim software requires
the following data:
2500
2000
1500
The temperature and/or pressure.
The composition of mixture (fluid) to study
The water content and composition
The type and content of added inhibitor.
1000
500
0
0
5
10
15
20
25
30
Temperature (°C)
Fig.11: Hydrate phase equilibrium curves of reservoir
fluid (gas condensate) in presence of TEG as inhibitor
8
5000
Model (PVT sim)
4500
Experiment
4000
2 5% vo l M eOH_ PVTs im
50 % vo lM eOH_ PVTs im
75% vo l M eOH_ PVTs im
0 % vo l M eOH_ Exp eriment
2 5% vo l M eOH_ Exp eriment l
50 % vo l M eOH_ Exp eriment l
75% vo l M eOH_ Exp eriment l
5000
4500
3500
4000
3000
3500
Pressure (psig)
Pressure (psig)
0 % vo l M eOH_ PVTs im
2500
2000
1500
1000
3000
2500
2000
1500
1000
500
500
0
0
10
15
20
25
-15
30
-5
5
15
25
35
Température (°C)
Temperature (°C)
Fig.13: Comparison between the experimental and
simulation results for gas hydrate formation temperature
Fig.15: Comparison between the experimental and
simulation results for gas hydrate formation
temperature in presence of methanol as inhibitor
5% vo l wa te r s e p_P VTs im
5000
5% vo l s e p wa te r_Expe rime nt
2 5% vo l TEG_ PVTs im
50 % vo l TEG_ PVTs im
75% vo l TEG_ PVTs im
0 % vo l TEG_ Exp eriment
2 5% vo l TEG_ Exp eriment
50 % vo l TEG_ Exp eriment
75% vo l TEG_ Exp eriment
10% vo l s e p wa te r_P VTs im
4500
5000
10% vo l s e p wa te r_Expe rim e nt
4000
15% vo l s e p wa te r_P VTs im
4500
3500
15% vo l s e p wa te r_Expe rim e nt
3000
20% vo ls e p wa te r_P VTs im
4000
20% vo l s e p wa te r_Expe rim e ntl
2500
3500
Pressure (psig)
Pressure (psig)
0 % vo l TEG_ PVTs im
2000
1500
1000
500
3000
2500
2000
1500
0
10
12
14
16
18
20
22
24
26
28
1000
30
Température (°C)
500
0
Fig.14: Comparison between the experimental and
simulation results for gas hydrate formation temperature
with increasing of produced water amount
-10
-5
0
5
10
15
20
25
30
Temp érature (°C)
Fig.16: Comparison between the experimental and
simulation results for gas hydrate formation temperature
in presence of TEG as inhibitor
9
0 % vo l DEG_ PVTs im
2 5% vo l DEG_ PVTs im
50 % vo l DEG_ PVTs im
75% vo l DEG_ PVTs im
0 % vo l DEG_ Exp eriment
2 5% vo l DEG_ Exp eriment
50 % vo l DEG_ Exp eriment
75% vo l DEG_ Exp eriment
5000
4500
4000
Pressure (psig)
3500
3000
2500
2000
1500
1000
500
0
-10
0
10
20
30
Temp erature (°C)
Fig.17: Comparison between the experimental and
simulation results for gas hydrate formation temperature
in presence of DEG as inhibitor
CONCLUSIONS
The problems posed by the presence of hydrates in the
pipes during the operation of a natural gas field have currently
taken a large scale worldwide. Several studies and techniques
have been developed to explain the process of hydrates
formation on the one hand and on the other hand proposed
appropriate solutions to stop this formation.
Our work was carried on a real case of condensate gas field
located in southern Algeria. For this purpose, we studied
experimentally in laboratory in a visual high pressure cell the
formation and stability conditions of gas hydrates and
established hydrate formation curves identifying safety zones
allowing operators to work outside of these conditions as well
as the influence of inhibitors on this formation.
To confirm these experimental results, we performed a
numerical study using PVTsim commercial software. The
experimental results are reasonable and are in line with those
obtained by simulation.
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