Multiphase Flow Evaluations and Slug Calculation

8/13/2019 Multiphase Flow Evaluations and Slug Calculation

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Document Number Class Document Title Rev. Page Number

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Multiphase Flow Evaluations and Slug Calculation

Rev. Status DatePrep. Check. Approved Checked Approved Date

Contractor Client



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TABLE OF CONTENTS

TABLE OF CONTENTS .......................................................................................................................................... 2

1. INTRODUCTION .............................................................................................................................................. 3

2. PURPOSE ........................................................................................................................................................ 3

3. DESIGN BASIS ................................................................................................................................................ 3

3.1.

Pipeline geometry and wall description ................................................................................................... 3

3.2. Input Data ................................................................................................................................................ 5

3.3. Assumptions for simulation ...................................................................................................................... 8

a. Inlet pipe lines condition .............................................................................................................................. 8

b. Ambient conditions for the pipeline .............................................................................................................. 9

5. STEADY STATE SIMULATION RESULTS ..................................................................................................... 9

6. DYNAMIC OPERATIONAL EVALUATIONS ................................................................................................ 11

7.

NORMAL OPERATION ................................................................................................................................. 11

8. PRODUCTION INCREASE ............................................................................................................................ 16

9. PRODUCTION DECREASE .......................................................................................................................... 19

10. CONCLUSION ........................................................................................................................................... 23

11. ATTACHMENT # 1: PVT DATA ............................................................................................................... 24

12. ATTACHMENT # 2: SUPPORTING CHARTS FOR STEADY STATE AND DYNAMIC SIMULATIONS 24



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1. INTRODUCTION

The objective of project is to overcome field natural pressure drop by establishing a compressor

station downstream of the field. This aids to reach maximum gas production rate of 11MMSCM/D. The

required pressure at the downstream battery limit will be achieved by establishing the new compressor

station.

2. PURPOSE

The purpose of this study is to perform multiphase flow simulations and evaluate the operations of the

gas gathering system to give input for the final design of the compressor station and slug-catcher

facilities. The study will show the results of the steady state and dynamic simulation of different

production rates and operational procedures for the 10 wells of the field as well as 16" line. Input for

slug-catcher design and design of operational procedures for the pipeline system will be given. OLGA

software (version 6.0.2.807) has been used for slug calculation. Pipesim 2008 has been used in

hydraulic calculation of the gas field.

3. DESIGN BASIS

3.1. Pipeline geometry and wall descript ion

Pipeline profiles are applied based on official charts received from client for the flow lines from well

heads to the manifold and from the manifold to the station.

Table 1. Pipeline information

Pipe name Total

Length [m]

Pipe Diameter

[inch]

Wall Thickness

(mm)

Coating *

(mm)

Burial Depth

(m)

Well 1 to manifold 821 8 8 3 1



Well 4 to manifold 2575.5 8 8 3 1







Pipe 16" to station 10022 16 14.4 3 1



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(*): The coating media is Poly Ethylene.

The model for the evaluation of the multiphase flow behavior of the gas gathering is represented in

figure 1.

Figure 1. OLGA Model for the Gas Gathering

For the 16" pipeline, the profile is represented in Figure 3.1-2. The pipe is buried in soil to a depth of 1

m.



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Figure 2. 16” pipeline profile

3.2. Input Data

3.2.1. PVT Data

The PVT data for well 7 has been utilized for evaluation of the multiphase flow in the pipeline network.

Fluid composition is represented in table 2. Water cut is considered to be 5% for pressure prediction at

manifold/station during project years.



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Table 2. Average Gas Composition

Component Mol %

N2 3.13

CO2 1.04

H2S 0.00

CH4 89.63

C2H6 3.62

C3H8 0.98

iC4H10 0.27

nC4H10 0.32

iC5H12 0.17

nC5H12 0.13

Pseudo C6 0.21

Pseudo C7 0.19Pseudo C8 0.14

Pseudo C9 0.07

Pseudo C10 0.04

Pseudo C11 0.03

C12+ 0.03

Water cut 5%

For the work presented in this report, PVTsim v. 18.0 is used for the fluid property and flash simulations.

Three-phase table was generated for OLGA to cover the range of physical properties within the boundary

of the operating and environmental conditions.

3.2.2. Pressure production data

The field wells gas production rates during project years are summarized as below table:



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Table 3 . Pressure / production data

With Natural DepletionWith Compressor Station

Year Q cumulative(MMSCM)

Q(MMSCMD) WHP(bar)Q cumulative(MMSCM)

Q(MMSCMD)WHP(bar)

11405.5611.00119.5094411435.3111119.809441388

14091.809.5711715481.0011118.03846 1389

15770.115.7511719514.8611114.033911390

16952.203.7611723498.1011110.05894 1391

17874.002.6311727496.7611106.176861392

18536.482.2511731508.0611102.338361393

0.001.8411735517.791198.3643651394 0.000.000.0039.576.601194.5329821395

0.000.000.0043593.731190.6559681396

0.000.000.0047578.621185.8185121397

0.000.000.0051597.651183.0071871398

0.000.000.0055812.681179.134186 1399 0.000.000.0059693.191175.1920621400

0.000.000.0063688.921171.1342471401

0.000.000.0067687.531167.1240391402

0.000.000.0071699.571163.0835191403

0.000.000.0075742.001158.959484 14040.000.000.0079716.251154.779591 1405

0.000.000.0083370.031150.539505 1406

0.000.000.0086100.718.62501407

0.000.000.0088185.016.51501408

0.000.000.0089755.604.94501409

0.000.000.0090994.883.86501410

0.000.000.0091880.232.98501411

0.000.000.0092743.032.38501412

0.000.000.0093371.201.88501413



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3.3. Assumptions for simulat ion

Following assumptions were taken for simulation of upstream pipelines:

• Soil conductivity is considered to be 1.65 W/m.K, as the worst condition.

• Pipe material conductivity for carbon steel is assumed to be 54 W/m.k.

• Pipe coating conductivity for poly ethylene is assumed to be 0.3 W/m.k.

• Process design wind velocity is considered to be 27 m/s according to site condition data.

• Due to lack of information, there was not any pipeline profile available for wells No. 9 & 10;

thus, profiles for these pipelines were selected similar to the longest existing well pipeline (well #

6).

• The hydrate formation was not studied according to accurate methanol injection at well

heads which is being performed.

• The turn down capacity of the total 10 production wells is 1.88 MMSCM/D which occurs at

year 1413.

• It was assumed that the maximum production capacity of each well is 1.5 MMSCM/D.

Besides, if the minimum flow passes through a well cause slug flow regime, the subject well will be

ignored.

• Source pressure for OLGA simulation is assumed to be well head chock valves downstream.

Source temperature is assumed to be temperature of well head chock valves upstream.

• Soil temperature for summer and winter case is assumed to be 30 and 15 ˚C, respectively.

• The network was simulated without considering any loop for the existing 16" pipeline for

phase -1, one 12" line for year 1413 and 16" pipeline with 12" loop for year 1406.

• Due to lack of information for well #9 and #10, pressure, temperature, and average flow is

considered the same as those of well #6.

a. Inlet pipe lines condition

In the existing facilities, gas from 8 production wells with the total flow rate of 8.5 MMSCM/D is collected

in a gathering center and being sent to downstream refinery battery limit. By establishing the new

compressor station, the production rate will be increased to 11 MMSCM/D. According to client decision

for establishing the station at selected location (location six, around 5.21 km from MFD), the existing 16"

line and a new 12" loop (for phase #2) is reasonable according to the design criteria and client official

letter.



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b. Ambient conditions for the pipeline

The ambient temperatures for the pipeline are assumed to be the same as those of the soil around the

pipeline for summer and winter case. As mentioned before, winter soil temperature is assumed 15 ˚ C

and summer soil temperature is assumed 30 ˚C.

5. STEADY STATE SIMULATION RESULTS

The simulation of the model built in PIPESIM 2008 was run for steady state conditions at different flow

rates to predict the pressure reached at manifold and station inlet during project years. The tables below

summarize and the results for pressure temperature at manifold and station inlet for location six (final

location around 5.21 km from MFD).

Table 4. results for steady state simulation- Manifold

YEAR

SUMMER WINTER

P (BARG) T (0C) P (BARG) T (0C)

1391 (withoutloop)

107.8 43 108.9 32

1401 (withoutloop)

67 43 66.6 33

1406 (with 12"loop)

38 42 42.1 30.8

1413 (12" loop) 49.73 33.5 49.7 19.8



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Table 5. results for steady state simulation-station inlet

YEARSUMMER WINTER

P (BARG) T (0C) P (BARG) T (0C)

1391 (withoutloop)

104.2 42 106.2 30.4

1401 (withoutloop)

57.4 40.8 57.6 30.2

1406 (with 12"loop)

29.5 38.8 35.5 27.9

1413 (12" loop) 49.7 33.3 49.9 19.2

Considering the pressures and temperatures at station inlet, obtained from Pipesim 2008, slug calculation

has been investigated for different scenarios, using OLGA dynamic calculation.

The simulation of the model built in OLGA was then run for steady state conditions at years 1391, 1406,

and 1413 to evaluate the total liquid inventory in the pipelines. This forms a basis for evaluating different

operational procedures and also gives design input for the design of the slug-catcher regarding required

liquid surge volume capacities. The table below summarizes the results of the steady state simulations for

different years. For conservative calculations regarding liquid accumulation in the flow lines, 15 ºC is used

as ambient temperature (winter case).



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Table 6. Steady state results (Winter case)

Steady state totalliquid flow at 16”line outlet (m3/hr)

Steady statecondensate flow at16” outlet (m3/hr)

Steady statewater flow at 16”

outlet (m3/hr)

1391 (withoutloop)

14 9.9 4.1

1406 (16“ line) 17.28 14.57 2.71

1406 (12“ line) 1.62 0.31 1.31

1413 (12" loop) 3.65 2.95 0.7

For main parameters variation in the pipeline, refer to attachment 2.

6. DYNAMIC OPERATIONAL EVALUATIONS

Pipeline operational scenarios are evaluated to give the multiphase flow input for the slug-catcher design.

For slug calculation, the following equation is applied.

Eq. (1)

In which Vsurge is the calculated slug volume, ACCLIQ is the accumulated total liquid volume flow across a

pipe section boundary; For Qdrain (the assumed slug catcher liquid drain rate), one can use the average

liquid flow rate into it or if known, the maximum drain capacity of the slug catcher.

For normal operation of the gas compressor station, one 4” line is suitable for slug catcher liquid outlet.

Moreover, considering maximum velocity of liquid lines equal to 2 m/s, maximum drain capacity from the

slug-catcher for liquid phase is calculated to be 56 m3/hr.

Covered cases for slug calculations include normal operation, production increase, and production

decrease.

7. NORMAL OPERATION

For normal operation scenario, the OLGA models for year 1391, 1406 and 1413 have been run for a

period of time in which steady state condition could be achieved and low fluctuations in main parameters



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are obtained. Consequently, following results are obtained for liquid volume flow rate and accumulated

liquid volume flow at slug catcher inlet.

Figure 3. Average liquid flow rate into the slug catcher for normal operation at year 1391




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For charts of variations of total liquid/oil/water volume flow at the outlet of the 16” pipeline (12” pipeline for

year 1413) with time, during normal operation at different years, refer to attachment 2.

For normal operation, average liquid flow rate into the slug catcher is used as its liquid drain rate (14 m3,

11.9 m3 and 6 m

3for winter of 1391, 1406 and 1413, respectively). Using data obtained from figure 3

through 5 and using equation (1), the slug volume calculated for different years are presented at figure 6.



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Figure 6. Slug volume for normal operation

As can be observed from figure 6, slug established in normal operation is not significant. This is in line with flow

regime indicator presented in figure 7 through 10 in which flow regime in main line and 12 “ loop at different

years is stratified which means no slug is faced at normal operation.

Figure 7. Flow regime ind icator for 16” l ine- winter 1391

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 0.5 1 1.5 2 2.5 3

V s u r g e ( m 3 )

Time (hr)

1391‐W‐normal operation





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Figure 8. Flow regime ind icator for 16” l ine- winter 1406

Figure 9. Flow regime ind icator for 12” loop- winter 1406



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Figure 10. Flow regime indicator for 12” loop- winter 1413

8. PRODUCTION INCREASE

Production increase is simulated in order to evaluate the surge volumes of liquid in the slug-catcher. The

slug-catcher design must take into account the large liquid volumes transported into the slug-catcher.

During a production increase the surge volumes in the slug-catcher can be reduced by increasing the

production slowly or by increasing the drain rates from the slug-catcher.

Prior to production increase it is assumed that liquid phase has been accumulated to a quasi-steady state

condition at the low rate. That will give largest surge volume of total liquid in the slug-catcher. The

production increase has been occurred over a period of 24 hours.

Production increase in 24 hours



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Figure 11. Liquid rates into the slug-catcher during production increase from 1.88 to 11 MMSCMD in 24hours (winter case 1391).

Figure 12. Liquid rates into the slug-catcher during production increase from 1.88 to 11 MMSCMD in 24hours (winter case 1406-16“ line)



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Figure 13. Liquid rates into the slug-catcher during production increase from 1.88 to 11 MMSCMD in 24hours (winter case 1406-12“loop)

For slug catcher liquid drain rate, two cases are taken into consideration: 1) average liquid flow rate into it

(31.4 m3 and 31.2 m

3 for winter 1391 and 1406, respectively) 2) maximum drain capacity from the slug-

catcher (56 m3). Consequently, the following charts are obtained for slug volume.

Figure 14. Slug volume into the slug catcher due to ramp up in 24 hours-winter 1391

0

10

20

30

40

50

60

0 5 10 15 20 25 30

V s u r g e ( m

3 )

Time (hr)

Ramp up scenario‐1391 winter

drain rate equal to liquid average flow

drain rate equal to maximum drain rate



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Figure 15. Slug volume into the slug catcher due to ramp up in 24 hours -winter 1406

As can be observed from figures 14 and 15, the total liquid surge volumes in case of a

production increase from 1.88 to 11 MMSCMD in 24 hours is 48.3 and 53.4 m3 for winter case

of years 1391 and 1406, considering average liquid flow rate as the slug catcher drain rate. With

maximum drain rate from slug catcher (56 m3), calculated surge volumes for years 1391 and

1406 are 1.39 and 0 m3, respectively.

9. PRODUCTION DECREASE

Production decrease is also simulated in order to evaluate the surge volumes of liquid in the

slug-catcher. During a production decrease the surge volumes in the slug-catcher can be

reduced by decreasing the production slowly or by increasing the drain rates from the slug-

catcher.

Prior to production decrease it is assumed that liquid phase has been accumulated to a quasi-

steady state condition at the low rate. That will give largest surge volume of total liquid in the

slug-catcher. The production decrease has been occurred over a period of 24 hours.

0

10

20

30

40

50

60

0 5 10 15 20 25 30

V s u r g e ( m 3 )

Time (hr)

Ramp up scnario‐1406 winter

drain rate equal to liquid average flow




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Figure 16. Liqu id rates into the slug-catcher during product ion decrease from 11 to 1.88 MMSCMD in 24

hours (winter case 1391)

Figure 17. Liqu id rates into the slug-catcher during product ion decrease from 11 to 1.88 MMSCMD in 24

hours (winter case 1406)



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For slug catcher liquid drain rate, two cases are taken into consideration: 1) average liquid flow rate into it

(5 m3 and 10 m

3 for winter 1391 and 1406, respectively) 2) maximum drain capacity from the slug-catcher

(56 m3). Consequently, the following charts are obtained for slug volume.

Figure 18. Slug volume into the slug catcher due to production decrease in 24 hours-winter 1391

Figure 19. Slug volume into the slug catcher due to production decrease in 24 hours-winter 1406

0

5

10

15

20

25

30

35

40

45

0 5 10 15 20 25 30 35

V s u r g e ( m

3 )

Time (hr)

Turn down scenario‐1391 winter

drain rate equal to average liquid flow


0

5

10

15

20

25

30

35

40

45

50

0 5 10 15 20 25 30 35

V s u

r g e ( m 3 )

Time (hr)

Turn down scenario‐1406 winter


drain rate equal to average drain rate



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As can be observed from figures 18 and 19, the total liquid surge volumes in case of a

production decrease from 11 to 1.88 MMSCMD in 24 hours is 42.2 and 46.11 m3

for winter case

of years 1391 and 1406, considering average liquid flow rate as the slug catcher drain rate. With

maximum drain rate from slug catcher (56 m3), no slug will be faced in slug catcher for years

1391 and 1406.



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10. CONCLUSION

The following conclusions are drawn from the various simulations carried out:

Scenario

Year 1391 Year 1406 Year 1413

Drain rate (m3/hr)

Slug

volume

(m3)

Drain rate

(m3/hr)

Slug

volume

(m3)

Drain rate

(m3/hr)

Slug

volume

(m3)

Normal

operation

Average drain

rate14 0.25

Average

drain rate11.9 0.85

Average

drain rate6 0

Maximum

drain rate56 0

Maximum

drain rate56 0

Maximum

drain rate56 0

Production

increase

Average drain

rate31.4 48.3

Average

drain rate31.2 53.4

Average

drain rate-- --

Maximum

drain rate56 1.39

Maximum

drain rate56 0

Maximum

drain rate-- --

Production

decrease

Average drain

rate5 42.2

Average

drain rate10 46.1

Average

drain rate-- --

Maximum drain

rate56 0

Maximum

drain rate56 0

Maximum

drain rate-- --

• It can be seen from the above table that the slug-catcher should be able to handle a peak total

surge volume of 53.4 m3 considering ramp up case in 24 hours. However, considering

maximum liquid velocity in slug catcher liquid outlet line and the selected size for this line (4

inch), more drainage is achievable (up to 56 m3/hr) and consequently total surge volume can

be decreased with increasing liquid drainage (up to 56 m3/hr). Considering 20% overdesign

factor for surge volume, the slug catcher should be able to handle 64 m3 of slug.

• There are no liquid slugs transported in the slug-catcher during normal operation mainly due to

the pipeline terrain. There are flow rate fluctuations into the slug-catcher resulting in small

surge volumes, which are not significant.



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The supporting charts are attached as per attachment-2

11. ATTACHMENT # 1: PVT DATA

12. ATTACHMENT # 2: SUPPORTING CHARTS FOR STEADY STATE AND DYNAMICSIMULATIONS



Attachment 1



PVT Data

Fluid Composition for Well 7

Component (%) mol Mw Sp.Gr

N2 3.13 -- --

CO2 1.04 -- --

H2S 0.00 -- --

CH4 89.63 -- --

C2H6 3.62 -- --

C3H8 0.98 -- --

i C4H10 0.27 -- --

n C4H10 0.32 -- --

i C5H12 0.17 -- --

n C5H12 0.13 -- --

Pseudo C6 0.21 86.11 0.66

Pseudo C7 0.19 94.62 0.73

Pseudo C8 0.14 110.42 0.73

Pseudo C9 0.07 121.20 0.76

Pseudo C10 0.04 132.04 0.78

Pseudo C11 0.03 136.93 0.84

C12 + 0.03 176.12 0.91

Water cut = 5 % (for pressure prediction)

ATTACHMENT # 2



Attachment 2



Steady state results for 16” pipleline at year 1391-winter case-normaloperation:

Figure-B1 Flow regime Indicator along the 16” pipe profile for SS- 1391 winter-normal operation

The numbers on the y-axis signify the following flow regime :

1: Stratified flow

2: Annular

3: Slug flow

4: Bubble

Figure-B1 shows the flow regime indicator along the pipe profile. At the outlet of the pipeline atsteady state slug flow is not observed.



Figure-B2 Pressure and temperature profiles at the 16” pipe for SS- 1391 winter-normaloperation

Figure-B3 Gas and liquid velocity profiles at the 16” pipe for SS- 1391 winter-normal operation



Dynamic Evaluation of the 16” pipeline at winter 1391-normal operation

Figure-B4. Total liquid/oil/water volume flow at the outlet of the 16” pipeline-winter 1391-normaloperation





Figure-B6 Pressure and temperature profiles at the 16” pipe for SS- 1406 winter-normaloperation

Figure-B7 Gas and liquid velocity profiles at the 16” pipe for SS- 1406 winter-normal operation



Dynamic Evaluation of the 16” pipeline at winter 1406

Figure-B8. Total liquid/oil/water Volume flow at the outlet of the 16” pipeline-winter 1406-normaloperation



Steady state results for 12” pipleline at year 1413-winter case-normaloperation:

Figure-B9. Flow regime Indicator along the 12” loop profile for SS- 1413 winter

The numbers on the y-axis signify the following flow regime:

1: Stratified flow

2: Annular

3: Slug flow

4: Bubble

Figure-B9 shows the flow regime indicator along the pipe profile which in most part of thepipeline, stratified flow is faced.



Figure-B10 Pressure and temperature profiles at the 12” loop for SS- 1413 winter

Figure-B11 Gas and liquid velocity profiles at the 12” pipe for SS- 1413 winter



Dynamic Evaluation of the 12” pipeline at winter 1413

Figure-B12. Total liquid/oil/water Volume flow at the outlet of the 12” pipeline-winter 1413

Documents

Multiphase Flow Evaluations and Slug Calculation