Multiphase Flow Evaluations and Slug Calculation

Multiphase Flow Evaluations and Slug Calculation

Rev. Status Date Prep. Check. Approved Checked Approved Date

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 

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 description

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 2 to manifold 11720 8 8 3 1 Well 3 to manifold 16371 8 8 3 1 Well 4 to manifold 2575.5 8 8 3 1 Well 5 to manifold 10727 8 8 3 1 Well 6 to manifold 17889 8 8 3 1 Well 7 to manifold 10013 8 8 3 1 Well 8 to manifold 14292 8 8 3 1 Well 9 to manifold 17889 8 8 3 1 Well 10 to manifold 17889 8 8 3 1 Pipe 16" to station 10022 16 14.4 3 1

(*): 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.

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.

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

0.19

Pseudo 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

Table 3 . Pressure / production data

With Natural Depletion With Compressor Station

Year Q cumulative (MMSCM) Q(MMSCMD) WHP(bar) Q cumulative (MMSCM) Q(MMSCMD) WHP (bar) 11405.56 11.00 119.50944 11435.31 11 119.80944 1388 14091.80 9.57 117 15481.00 11 118.03846 1389 15770.11 5.75 117 19514.86 11 114.03391 1390 16952.20 3.76 117 23498.10 11 110.05894 1391 17874.00 2.63 117 27496.76 11 106.17686 1392 18536.48 2.25 117 31508.06 11 102.33836 1393 0.00 1.84 117 35517.79 11 98.364365 1394 0.00 0.00 0.00 39.576.60 11 94.532982 1395 0.00 0.00 0.00 43593.73 11 90.655968 1396 0.00 0.00 0.00 47578.62 11 85.818512 1397 0.00 0.00 0.00 51597.65 11 83.007187 1398 0.00 0.00 0.00 55812.68 11 79.134186 1399 0.00 0.00 0.00 59693.19 11 75.192062 1400 0.00 0.00 0.00 63688.92 11 71.134247 1401 0.00 0.00 0.00 67687.53 11 67.124039 1402 0.00 0.00 0.00 71699.57 11 63.083519 1403 0.00 0.00 0.00 75742.00 11 58.959484 1404 0.00 0.00 0.00 79716.25 11 54.779591 1405 0.00 0.00 0.00 83370.03 11 50.539505 1406 0.00 0.00 0.00 86100.71 8.62 50 1407 0.00 0.00 0.00 88185.01 6.51 50 1408 0.00 0.00 0.00 89755.60 4.94 50 1409 0.00 0.00 0.00 90994.88 3.86 50 1410 0.00 0.00 0.00 91880.23 2.98 50 1411 0.00 0.00 0.00 92743.03 2.38 50 1412 0.00 0.00 0.00 93371.20 1.88 50 1413

3.3.

Assumptions for simulation

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.

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 (without loop) 107.8 43 108.9 32 1401 (without loop) 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

Table 5. results for steady state simulation-station inlet

YEAR SUMMER WINTER

P (BARG) T (0C) P (BARG) T (0C) 1391 (without loop) 104.2 42 106.2 30.4 1401 (without loop) 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).

Table 6. Steady state results (Winter case) Steady state total

liquid flow at 16” line outlet (m3/hr) Steady state condensate flow at 16” outlet (m3/hr) Steady state water flow at 16” outlet (m3/hr) 1391 (without loop) 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

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

Figure 5. Average liquid flow rate into the slug catcher for normal operation at year 1413

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 m3 for 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.

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 indicator for 16” line- 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 Vsurge  (m3) Time (hr) 1391‐W‐normal operation 1406‐W‐normal operation 1413‐W‐normal operation

Figure 8. Flow regime indicator for 16” line- winter 1406

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.

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

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

Figure 13. Liquid rates into the slug-catcher during production increase from 1.88 to 11 MMSCMD in 24 hours (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 m3 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 Vsurge  (m3) Time (hr)

Ramp up scenario‐1391 winter

drain rate equal to liquid average flow  drain rate equal to maximum drain rate

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 m

3

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  surge  (m3) Time (hr)

Ramp up scnario‐1406  winter

drain rate equal to liquid average flow drain rate equal to maximum drain rate

Figure 16. Liquid rates into the slug-catcher during production decrease from 11 to 1.88 MMSCMD in 24 hours (winter case 1391)

Figure 17. Liquid rates into the slug-catcher during production decrease from 11 to 1.88 MMSCMD in 24 hours (winter case 1406)

For slug catcher liquid drain rate, two cases are taken into consideration: 1) average liquid flow rate into it (5 m3 and 10 m3 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 Vsurge  (m3) Time (hr)

Turn down scenario‐1391 winter

drain rate equal to average liquid flow drain rate equal to maximum drain rate 0 5 10 15 20 25 30 35 40 45 50 0 5 10 15 20 25 30 35 V  surge  (m3) Time (hr)

Turn down scenario‐1406 winter

drain rate equal to maximum drain rate drain rate equal to average drain rate

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 m

3

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.

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 rate 14 0.25 Average drain rate 11.9 0.85 Average drain rate 6 0 Maximum drain rate 56 0 Maximum drain rate 56 0 Maximum drain rate 56 0 Production increase Average drain rate 31.4 48.3 Average drain rate 31.2 53.4 Average drain rate -- -- Maximum drain rate 56 1.39 Maximum drain rate 56 0 Maximum drain rate -- -- Production decrease Average drain rate 5 42.2 Average drain rate 10 46.1 Average drain rate -- -- Maximum drain rate 56 0 Maximum drain rate 56 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.

The supporting charts are attached as per attachment-2

11. ATTACHMENT # 1: PVT DATA

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

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)

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 at steady state slug flow is not observed.

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

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

Figure-B5. Flow regime Indicator along the 16” pipe profile for SS- 1406 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-B5 shows the flow regime indicator along the pipe profile. At the outlet of the pipeline at steady state slug flow is not observed.

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

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

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 the pipeline, stratified flow is faced.

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