close

Вход

Забыли?

вход по аккаунту

?

Optimizing separator pressures in the multistage crude oil production unit.

код для вставкиСкачать
ASIA-PACIFIC JOURNAL OF CHEMICAL ENGINEERING
Asia-Pac. J. Chem. Eng. 2008; 3: 380–386
Published online 10 July 2008 in Wiley InterScience
(www.interscience.wiley.com) DOI:10.1002/apj.159
Research Article
Optimizing separator pressures in the multistage crude oil
production unit
Alireza Bahadori,1 * Hari B. Vuthaluru1 and Saeid Mokhatab2
1
2
Department of Chemical Engineering, Curtin University of Technology, Perth, Australia
Process Technology Department, Tehran Raymand Consulting Engineers, Tehran, Iran
Received 30 October 2007; Revised 21 February 2008; Accepted 18 April 2008
ABSTRACT: To achieve good separation between gas and liquid mixture coming out of a crude oil production system
and to maximize hydrocarbon liquid recovery, it is necessary to use several separation stages at decreasing pressures
and then adapting the pressure set-points to improve product separation and recovery at minimum cost. The aim
of this study is to present an accurate methodology for optimizing separator pressures in the crude oil production
unit. The new proposed methodology determines the optimum pressures of separators in different stages of separation
and consequently optimizes the operating conditions. Using this new method, the optimum separator pressures for
a 5724-m3 /day oil production unit were determined. As a result, the oil recovery was increased by 6 and 5 m3 /day
during summer and winter seasons, respectively. In this work, the C7 + fraction was also treated as one cut and then
breakdown of heavy fraction cuts (C7 + splitting) with respect to the most widely used distribution function (gamma
probability function). The results obtained showed that the calculations with C7 + fraction breakdown is more accurate
than definition of feed stream a with single C7 + fraction.  2008 Curtin University of Technology and John Wiley &
Sons, Ltd.
KEYWORDS: optimization; crude oil; multistage separation; production unit
INTRODUCTION
At high pressures existing at the bottom of the producing well, crude oil contains great quantities of dissolved
gases. When crude oil is brought to the surface, it is at a
much lower pressure. Consequently, the dissolved gases
will be released from the liquid. Some means must be
provided to separate the gas from oil without losing too
much oil. In fact, in carrying out the gas–oil separation process, the main target is to try to achieve the
following objectives (Abdel-Aal et al ., 2003):
• Separate the light components (methane and ethane)
from oil.
• Maximize the recovery of heavy components of
the intermediate components (propane, butane, and
pentane) in crude oil.
• Save the heavy components (which are the bulk of
crude oil) in liquid product.
Two methods for the separation of the light and
heavy constituents can be considered: ‘differential’
or ‘enhanced separation’ and ‘flash’ or ‘equilibrium
*Correspondence to: Alireza Bahadori, Department of Chemical Engineering, Curtin University of Technology, Perth, WA
6845, Australia. E-mail: alireza.bahadori@postgrad.curtin.edu.au
 2008 Curtin University of Technology and John Wiley & Sons, Ltd.
separation’. In differential separation, the yield of
heavy hydrocarbons (intermediate and heavy groups)
recovery is high, because most of the light gases
are released at the earlier high-pressure separation
stages; and therefore, losing heavy components with
the light gases in the following low-pressure stages is
less likely. By comparison, in flash separation more
of the heavy hydrocarbons will be carried away with
the light gases during separation at the equilibrium
conditions. In practice, industrial separation of light and
heavy components of crude oil by using the differential
process is not cost effective as a large number of stages
would be required. This leaves the flash process as the
only viable crude oil treatment method.
The flash separation process for recovering crude oil
from high-pressure well streams consists of a series of
flash separators operating over a pressure range from
wellhead pressure to atmospheric pressure. However,
with the increased desirability of recovering natural
gas and natural gas liquids, other methods have been
proposed as modification to the basic flash separation
technique.[1]
The main objective of stage separation is to provide
maximum stabilization to the resultant phases (gas and
liquid) leaving the final separator, which means that
considerable amounts of gas or liquid will not evolve
Asia-Pacific Journal of Chemical Engineering
OPTIMIZING SEPARATOR PRESSURES IN CRUDE OIL PRODUCTION UNIT
from the final liquid and gas phases, respectively. The
quantities of gas and liquid recovered at a given pressure
are determined by equilibrium flash calculations using
an appropriate equation of state (EOS). This helps
optimize the pressure that is set for each separator.[2]
Several stages operated at successively lower pressures affect the separation of oil from gas, thus increasing the oil recovery. The number of stages in a multistage conventional separation process is a function
of American Petroleum Institute (API) gravity of the
oil, gas–oil ratio (GOR), and the wellhead flowing
pressure.[3,4] In general, a surface separation unit with
four stages is usually the most optimal. It allows 2–12%
higher liquid recovery in comparison with three-stage
separation and, in some cases, recoveries up to 25%
higher.[4] Although five-stage (or more) separation units
would yield more liquid recovery at the stock tank in
comparison to the three or four-stage separation systems, the small incremental liquid yield would rarely
pay out the cost (in capital investment and maintenance)
associated with a larger number of separators.
The selection of operating pressures in surface separators can have a remarkable impact on the quantity
and quality of oil produced in the sock tank. If the
separator pressure is high, large amounts of light components will remain in the liquid phase at the separator
and will be lost along with other valuable components
to the gas phase at the stock tank. On the other hand,
if the pressure is too low, large amounts of light components will be separated from the liquid and they will
attract substantial quantities of intermediates and heavier components, so it is necessary to optimize separator
pressures in winter and summer seasons. Considerable
gains could be realized by performing process simulation to optimize the separator pressure for maximum
oil recovery. Apart from obtaining a high recovery of
oil, operating pressures have other important considerations in the processing of the separated streams. A
minimum pressure has to be maintained for the oil to
be delivered to the next processing stage. In addition,
using high pressure will deliver the gas stream for sales
at higher output pressure, thus reducing the compressor
horsepower used for gas pumping. Therefore, it may
be concluded that a proper operating pressure has to
be selected and its value has to be between the two
extreme cases (high-pressure/low-pressure operations)
in order to maximize the oil yield.
OPTIMIZATION METHODS FOR STAGE
SEPARATION
Surface separation pressure and temperature conditions
play a major role in the amount of liquid recovery that
is realized at the stock tank. Although temperature of
separation is a function of the ambient temperature,
which is difficult to control, however, since separators
 2008 Curtin University of Technology and John Wiley & Sons, Ltd.
usually work at about the same (surface) temperature,
pressure is typically the key player in optimization
studies.
Empirical and quasi-empirical approaches are more
popular in determining the middle-stage separation pressure. These approximations do not take into account the
entire chemical composition of the crude oil or any other
property of the mixture. Another suggested calculation
method for optimizing the surface separation operations
focuses on the maximum production of the liquid and
minimum gas re-compression costs associated with the
selection of a low middle-stage operating pressure. This
method is based on the minimization of the required
compressor horsepower. When produced gas must be
compressed to pipeline pressures, minimizing compressor horsepower may yield the most economic option.[5]
However, experience shows that horsepower optimization may not be as simple as maximizing stock tank oil
recovery and it has very little effect on oil production
and API gravity.[3]
The most accurate method for the optimization of the
middle-stage separator pressure is applying vapor/liquid
equilibrium thermodynamics in order to model the
behavior of crude oil through the separation process.
This defines the middle-stage pressure, which maximizes oil accumulation in the stock tank (i.e. minimizes GOR) while enhancing its API. Although naturally occurring reservoir hydrocarbons are commonly
described by a number of discrete components and component groups, gamma probability function can be used
to improve and extend fluid characterization through
describing the plus fraction by a number of single
and multiple carbon number groups as proposed by
Whitson.[6] The distribution function is generally used
to describe the C7+ fraction with its parameters determined by group experimental data. In this study, Twu,[7]
and Kesler and Lee[8] methods are used to predict the
critical properties and molecular weight of the C7+
fraction, respectively.
SOLUTION METHODOLOGY
The computational steps of the separator calculation
are described below in conjunction with Fig. 1, which
schematically shows a bubble point reservoir fluid
flowing into a surface separation unit consisting four
stages operating at successively lower pressures.
Step 1: Given the composition of the feed stream (Zi) to
the first separator and the operating conditions of the
separator (i.e. separator pressure and temperature),
calculate the equilibrium ratios of the hydrocarbon
mixture by a pretuned EOS. In this work, the Peng
and Robinson[9] EOS was used.
Step 2: Assuming a total of F moles of the feed entering the first separator and using the above calculated equilibrium ratios, perform flash calculations
Asia-Pac. J. Chem. Eng. 2008; 3: 380–386
DOI: 10.1002/apj
381
382
A. BAHADORI, H. B. VUTHALURU AND S. MOKHATAB
Asia-Pacific Journal of Chemical Engineering
Figure 1. Schematic illustration of four-stage oil production unit.
to obtain the compositions and quantities (in moles)
of the gas and the liquid leaving the first separator.
Designating these moles as NL1 and NV1 , the actual
number of moles of the liquid and gas leaving the
first separation stage are:
Total moles of liquid remaining in the stock tank can
also be calculated as:
NLT = F
N
nLi
(7)
i=1
NL1 = FnL1
(1)
NV1 = FnV1
(2)
where, nL1 and nv1 represent the liquid and vapor
fraction of the feed.
Step 3: Using the composition of the liquid leaving the
first separator as the feed for the second separator,
calculate the equilibrium ratios of the hydrocarbon
mixture at the prevailing pressure and temperature
of the separator.
Step 4: On the basis of 1 mol of the feed, perform
flash calculation to determine the compositions and
quantities of the gas and liquid leaving the second
separation stage. The actual numbers of moles of the
two phases are then calculated as:
Step 6: Determine the volume of stock tank oil occupied
by moles of liquid from:
VOST =
(NLT )(MWOST )
ρOST
(8)
Step 7: Calculate the specific gravity and the API
gravity of the stock tank oil by applying:
ρOST
1000
141.5
◦
API =
− 131.5
γo
γo =
(9)
(10)
Step 8: Calculate the total GOR:
NL2 = NL1 nL2 = FnL1 nL2
(3)
NV2 = NL1 nV2 = FnL1 nV2
(4)
Step 5: The previously outlined procedure is repeated
for each separation stage, including the stock tank
stage, and the calculated moles and compositions are
recorded. The total number of moles of the gas given
off in all stages is then calculated as:
NVT =
N
NVi = NV1 + NV2 + NV3 + NV4
i
= FnV1 + FnL1 nV2 + FnL1 nL2 nV3
+ FnL1 nL2 nL3 nV4
(5)
In a more compact form, the above expression can be
written as:


i −1
N
nVi
nLj 
NVT = F nV1 +
(6)
i =2
j =1
 2008 Curtin University of Technology and John Wiley & Sons, Ltd.
VG
(ρOST )(NVT )
=
Vo
(NLT )(MWOST )
(ρOST NVT )
(stdm 3 /m 3 )
=
(NLT )(MWOST )
GOR =
(11)
In the above equation, VG and VO are the volume of
gas (scf/mol) and volume of stock tank oil (bbl),
respectively; and MWOST is the apparent molecular
weight of stock tank oil.
The separator pressure can be optimized by calculating
the API gravity and GOR in the manner outlined
above at different assumed pressures. The optimum
pressure corresponds to a maximum in the API
gravity and a minimum in GOR.
CASE STUDY
The data in Table 1 are fluid properties of PazananAsmari reservoir located in Iran.[10] Table 2 shows
Asia-Pac. J. Chem. Eng. 2008; 3: 380–386
DOI: 10.1002/apj
Asia-Pacific Journal of Chemical Engineering
OPTIMIZING SEPARATOR PRESSURES IN CRUDE OIL PRODUCTION UNIT
Table 1. Pazanan-Asmari reservoir fluid composition.
Component
C1
C2
C3
IC4
NC4
IC5
NC5
NC6
H2 S
CO2
C7 + C7+ (SP. GR. = 0.8646, MW = 236)
mol
(%)
52.510
6.242
4.237
0.855
2.213
1.124
1.271
2.289
0.084
1.587
27.55
cuts, which can lead to differences in predicting the fluid
properties when we define single or splitted heavy cuts
during simulation and optimization of the oil production
unit.
RESULTS
Figures 4–9 show the optimum pressures of the separators in different stages of separation for summer and
winter conditions without installing any new separators
or equipment. These figures illustrate that the accuracy
of calculation results is reduced by use of single C7+
cut instead of using splitted C7+ cuts.
Reservoir pressure (psig) 3700, bottom hole temperature 208 ◦ F.
mol (%)
C1
C2
C3
IC4
NC4
IC5
NC5
NC6
H2 S
CO2
C7+ CUT1
C7+ (SP. GR. = 0.7411, MW = 108.47)
C7+ CUT2
C7+ (SP. GR. = 0.755, MW = 120.4)
C7+ CUT3
C7+ (SP. GR. = 0.7695, MW = 133.63
C7+ CUT4
C7+ (SP. GR. = 0.799, MW = 164.78
C7+ CUT5
C7+ (SP. GR. = 0.8387, MW = 215.94
C7+ CUT6
C7+ (SP. GR. = 0.8754, MW = 274.34
C7+ CUT7
C7+ (SP. GR. = 0.9073, MW = 334.92
C7+ CUT8
C7+ (SP. GR. = 0.9575, MW = 412.79
52.5100
6.2420
4.2370
0.8550
2.2130
1.1240
1.2710
2.2890
0.0840
1.5870
0.8501
1.2802
1.6603
6.5311
Pressure (psig)
Component
-200
0
200
400
600
800
1000
Temperature, °F
Figure 2. Phase envelope of Pazanan fluid based on
single heavy cut (C7+).
6000
5000
Pressure, psig
Table 2. Pazanan-Asmari reservoir fluid composition
with splitted C7+ cut.
5000
4500
4000
3500
3000
2500
2000
1500
1000
500
0
4000
3000
2000
1000
6.3311
0
-200
0
200
2.9105
400
600
800
1000
Temperature, °F
4.9618
Figure 3. Phase envelope of Pazanan fluid based on
splitted heavy cut (C7+).
the composition of Pazanan fluid with splitted C7+
cuts.
Given the composition of the feed stream and applying the new proposed methodology, we can optimize the
separator pressure in the four - stage oil separation unit
as shown in Fig. 1. The HYSYS simulation software[11]
was used in this study to carry out the simulation of
separation.
Figures 2 and 3 show the phase envelope of Pazanan
reservoir fluid based on the single and splitted C7+
 2008 Curtin University of Technology and John Wiley & Sons, Ltd.
Gas Oil Ratio (scf/bbl)
3.0505
36.8
1078
1076
1074
1072
1070
1068
1066
1064
1062
1060
36.75
36.7
36.65
36.6
36.55
36.5
0
200
400
600
800
Separator Pressure (psig)
GOR ( C7+ splitting)
GOR
1000
API (C7+ splitting)
36.45
1200
API
Figure 4. Optimum pressures of first-stage separator for
single heavy cut and splitted C7+ cuts (summer case).
Asia-Pac. J. Chem. Eng. 2008; 3: 380–386
DOI: 10.1002/apj
383
A. BAHADORI, H. B. VUTHALURU AND S. MOKHATAB
Gas Oil Ratio (scf/bbl)
1080
1075
1070
1065
1060
0
50
100
150
Asia-Pacific Journal of Chemical Engineering
1040
Gas Oil Ratio (scf/bbl)
36.8
36.75
36.7
36.65
36.6
36.55
36.5
36.45
36.4
36.35
200
1085
1035
1030
1025
1020
1015
1010
0
Separator Pressure (Psig)
GOR
GOR (C7+ splitting)
API
API (C7+splitting)
GOR
36.8
1076
36.75
1074
1072
36.7
1070
36.65
1068
1066
36.6
1064
36.55
1062
1060
36.5
10
20
30
GOR (C7+ splitting)
40
API
50
API (C7+ splitting)
38
37.95
1030
37.9
1025
37.85
1020
37.8
37.75
1015
37.7
1010
400
600
800
1000
37.65
1200
Separator Pressure (Psig)
GOR
GOR (C7+ spliting)
API
API (C7+splitting)
38
37.95
1030
37.9
1025
37.85
1020
37.8
37.75
1015
37.7
1010
37.65
10
20
30
40
50
Separator Pressure (Psig)
1035
200
API
1035
0
Figure 6. Optimum pressures of third-stage separator
for single heavy cut and splitted C7+ cuts (summer case).
0
150
GOR (C7+ splitting)
Separator Pressure (Psig)
GOR
100
Figure 8. Optimum pressures of second-stage separator
for single heavy cut and splitted C7+ cuts (winter case).
Gas Oil Ratio (scf/bbl)
Gas Oil Ratio (scf/bbl)
1078
0
50
38
37.95
37.9
37.85
37.8
37.75
37.7
37.65
37.6
37.55
37.5
37.45
200
Separator Pressure (Psig)
Figure 5. Optimum pressures of second-stage separator
for single heavy cut and splitted C7+ cuts (summer case).
Gas Oil Ratio (scf/bbl)
384
GOR
GOR (C7+ splitting)
API
API (C7+ splitting)
Figure 9. Optimum pressures of third-stage separator
for single heavy cut and splitted C7+ cuts (winter case).
using splitted C7+ cuts. This increases the produced oil
quality around 0.4◦ and 0.5◦ API for summer and winter
seasons, respectively. As can be seen from Figs 4–6,
total gas–oil ratio in summer case is higher than its
value in winter case (Figs 7–9), since in the summer
case more gas is liberated from the liquid phase. In the
meantime, the oil production rate in the winter case is
higher than in summer and the quality of produced crude
oil is also much better in comparison with the summer
season. API in summer case is 36.7 in average, whereas
it is 38◦ API in winter.
API (C7+ splitting)
Figure 7. Optimum pressures of first-stage separator for
single heavy cut and splitted C7+ cuts (winter case).
Table 3 presents the optimum pressures of each separation stage in summer and winter conditions. Table 4
presents the liquid production rates at the optimum pressures using HYSYS software.
As shown in Table 4, the rate of oil production
was increased by 6 and 5 m3 /day during summer and
winter conditions by applying optimum pressures on
each separator in different stages of separation based on
 2008 Curtin University of Technology and John Wiley & Sons, Ltd.
CONCLUSIONS
In the present work, an accurate methodology is presented for optimizing separator pressures in a crude
oil production unit without installing any additional
equipment and without any added cost. The new proposed methodology determines the optimum pressures
of separators in different stages of separation and
consequently optimizes the operating conditions. Using
this new method, the optimum separator pressures for a
5724 m3 /day oil production unit were determined. As a
Asia-Pac. J. Chem. Eng. 2008; 3: 380–386
DOI: 10.1002/apj
Asia-Pacific Journal of Chemical Engineering
OPTIMIZING SEPARATOR PRESSURES IN CRUDE OIL PRODUCTION UNIT
Table 3. Operating and optimum pressures at different stages of separation unit.
Summer
Winter
Optimum pressure (kPa)
Separation
stage
First
Second
Third
Fourth
Operating
pressure
(kPa)
Temperature
(◦ C)
Single C7+ cut
2586
690
221
110
46.1
44.4
43.3
42.2
4380
827
234
110
Optimum pressure (kPa)
Temperature (◦ C)
C7+ Splitting
4170
793
227
110
23.9
21.1
18.3
17.2
Single C7+ cut
C7+ Splitting
4240
862
241
110
4103
841
234
110
Table 4. Liquid flow rates at different stages of separation unit (feed rate = 2791 kg mol/h or 8178 m3 /day).
Summer (kg mol/h)
Separation
stage
First
Second
Third
Fourth
Winter (kg mol/h)
Original
Optimum
(single cut)
Optimum
(C7+ splitting)
Original
Optimum
(single cut)
Optimum
(C7+ splitting)
1188
1070
1022
996
1325
1096
1033
1003
1306
1089
1028
1000
1257
1110
1074
1049
1397
1153
1085
1054
1381
1148
1081
1051
Liquid production
Original
Optimized (Single C7+ cut)
Optimized (Splitting C7+ cut)
Liquid production
kg mol/h
m /day
kg mol/h
m3 /day
996
1003
1000
5734
5774
5740
1049
1054
1051
5834
5872
5839
result, the oil recovery was increased by 6 and 5 m3 /day
during summer and winter seasons, respectively, which
is equivalent to 3600 $/day and 3000 $/day, respectively. In the meantime, we have a huge amount of crude
oil (more than 5724 m3 /day) in 0.5 API higher gravity,
which is a considerable improvement for crude oil quality without installing any new equipment in production
unit. In this work, the C7 + fraction was also treated
as one cut and then breakdown of heavy fraction cuts
(C7 + splitting) with respect to the most widely used
distribution function (gamma probability function). The
results obtained showed that the accuracy of calculations with C7 + fraction breakdown is more accurate
than definition of feed stream with single C7 + fraction.
3
of Technology, Perth, Western Australia for providing Curtin University postgraduate Research Scholarship.
NOMENCLATURE
NV
NL
VG
Number of vapor moles
Number of liquid moles
Volume of gas
VO
MWOST
ρO
γO
GOR
Volume of stock tank oil
Apparent molecular weight
Stock tank oil density
Oil specific gravity
Gas–oil ratio
mol
mol
Scm/
mol
m3
kg/m3
Scm/m3
Subscripts
Acknowledgements
The lead author acknowledges the Australian Government’s Department of Education, Employment and
workplace relations for Endeavor International Postgraduate Research Scholarship (EIPRS), and the Office
of Research & Development at the Curtin University
 2008 Curtin University of Technology and John Wiley & Sons, Ltd.
1, 2, 3, 4, . . ., N
G
L
O
ST
T
V
Number of stage
Gas
Liquid
Oil
Stock tank
Total
Vapor
Asia-Pac. J. Chem. Eng. 2008; 3: 380–386
DOI: 10.1002/apj
385
386
A. BAHADORI, H. B. VUTHALURU AND S. MOKHATAB
REFERENCES
[1] H.K. Abdel-Aal, M. Aggour, M.A. Fahim. Petroleum and Gas
Field Processing, 1st edn, Marcel Dekker Inc: New York,
2003.
[2] S. Mokhatab, W.A. Poe, J.G. Speight. Handbook of Natural
Gas Transmission & Processing, Gulf Professional Publishing:
Burlington, MA, 2006.
[3] F.S. Manning, R.E. Thompson. Oilfield Processing of
Petroleum, Vol 2: Crude Oil, PennWell Books: Tulsa, OK,
1995.
[4] A. Rojey, C. Jaffret, S. Cornot-Gandolphe, B. Durand,
S. Julian, M. Valais. Natural Gas Production, Processing,
Transport, Editions Technip: Paris, 1997.
 2008 Curtin University of Technology and John Wiley & Sons, Ltd.
Asia-Pacific Journal of Chemical Engineering
[5] T.B. Kryska, K.B. Lindsey, J.W. Hasz. Oil Gas J., 1976; 12,
129–135.
[6] C.H. Whitson. SPE J., 1983; 3, 683–694.
[7] C.H. Twu. Fluid Phase Equilib., 1984; 16, 137–150.
[8] M.G. Kesler, B.I. Lee. Hydrocarbon Process., 1976; 3,
153–158.
[9] D.Y. Peng, D.B. Robinson. Ind. Eng. Chem., 1976; 15, 59–64.
[10] A. Bahadori, S. Mokhatab. World Oil, 2007; 6, 101–105.
[11] HYSYS Software. Revision (3.1), Hyprotech, Ltd., Calgary,
AB, Canada, 2002.
Asia-Pac. J. Chem. Eng. 2008; 3: 380–386
DOI: 10.1002/apj
Документ
Категория
Без категории
Просмотров
5
Размер файла
133 Кб
Теги
unit, production, crude, multistage, separators, oil, pressure, optimizing
1/--страниц
Пожаловаться на содержимое документа